Filed Pursuant to Rule 424(b)(3)

Registration No. 333-279741

PROSPECTUS

IPALCO Enterprises, Inc.

Offer to Exchange

5.750% Senior Secured Notes due 2034

for

New 5.750% Senior Secured Notes due 2034

We are offering to exchange up to $400,000,000 of our new registered 5.750% Senior Secured Notes due 2034 (the “new notes” or “notes”) for up to $400,000,000 of our existing unregistered 5.750% Senior Secured Notes due 2034 (the “old notes”). The terms of the new notes are identical in all material respects to the terms of the old notes, except that the new notes have been registered under the Securities Act of 1933, as amended (the “Securities Act”), and the transfer restrictions and registration rights relating to the old notes do not apply to the new notes. The new notes will represent the same debt as the old notes and we will issue the new notes under the same indenture.

To exchange your old notes for new notes:

● you are required to make the representations described on page 3 to us; and

● you should read the section called “The Exchange Offer” starting on page 124 for further information on how to exchange your old notes for new notes.

The exchange offer will expire at 5:00 P.M. New York City time on July 8, 2024 unless it is extended.

No public market currently exists for the old notes and we cannot assure you that any public market for the new notes will develop. The new notes will not be listed on any national securities exchange.

See “Risk Factors” beginning on page 6 of this prospectus for a discussion of risk factors that should be considered by you prior to tendering your old notes in the exchange offer.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of the securities to be issued in the exchange offer or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

June 6, 2024

table of contents

Page

Glossary of Terms	ii
Summary	1
Risk Factors and Risk Factor Summary	6
Cautionary Note Regarding Forward-Looking Statements	25
Use of Proceeds	27
Capitalization	28
Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
Business	55
Management	70
Compensation Discussion and Analysis	75
Certain Relationships, Related Transactions and Director Independence	101
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	104
Description of the Notes	106
The Exchange Offer	124
Material United States Tax Consequences of the Exchange Offer	131
Plan of Distribution	131
Validity of Securities	132
Experts	132
Where You Can Find More Information	132
Index to Financial Statements	F-1

We have not authorized anyone to provide you with any information other than that contained in this prospectus or to which we have referred you. We take no responsibility for and can provide no assurance as to the reliability of, any other information that others may give you. You should assume that the information appearing in this prospectus is accurate only as of the date on the front cover of this prospectus. Our business, financial condition, results of operations and prospects may have changed since that date.

This prospectus is based on information provided by us and by other sources that we believe are reliable. We cannot assure you that this information is accurate or complete. This prospectus summarizes certain documents and other information and we refer you to them for a more complete understanding of what we discuss in this prospectus. In making an investment decision, you must rely on your own examination of our company and the terms of the offering and the notes, including the merits and risks involved.

We are not making any representation to any purchaser of the notes regarding the legality of an investment in the notes by such purchaser under any legal investment or similar laws or regulations. You should not consider any information in this prospectus to be legal, business or tax advice. You should consult your own attorney, business advisor and tax advisor for legal, business and tax advice regarding an investment in the notes.

Neither the Securities and Exchange Commission (“SEC”) nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

i

Glossary of Terms

The following is a list of frequently used terms, abbreviations or acronyms that are found in this prospectus.

Term	Definition
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
2034 IPALCO Notes	$400 million of 5.75% IPALCO Enterprises, Inc. Senior Secured Notes due April 1, 2034
$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
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

ii

Term	Definition
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
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FGD	Flue Gas Desulfurization
Financial Statements	Audited and Unaudited Consolidated Financial Statements of IPALCO included herein
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

iii

Term	Definition
SO2	Sulfur Dioxide
SOFR	Secured Overnight Financing Rate
Supplemental Retirement Plan	Supplemental Retirement Plan of AES Indiana
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.

iv

Summary

This summary highlights information contained elsewhere in this prospectus. This summary may not contain all of the information that may be important to you. You should read this entire prospectus before making a decision to exchange your old notes for new notes, including the section entitled “Risk Factors” in this prospectus. Unless otherwise indicated or the context otherwise requires, the terms “IPALCO,” we,” “our,” “us,” and “the Company” refer to IPALCO Enterprises, Inc., including all of its subsidiaries, collectively. The term “IPALCO Enterprises, Inc.” refers only to IPALCO Enterprises, Inc., excluding its subsidiaries and affiliates

OUR COMPANY

IPALCO is a holding company incorporated under the laws of the state of Indiana whose principal subsidiary is Indianapolis Power & Light Company, which does business as 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 audited Consolidated Financial Statements of IPALCO and related notes included elsewhere in this prospectus.

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 524,000 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 2024.

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.

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 incorporated by reference into this prospectus.

1

SUMMARY OF THE EXCHANGE OFFER

Securities Offered	We are offering up to $400 million aggregate principal amount of our new 5.750% Senior Secured Notes due 2034, which will be registered under the Securities Act.
The Exchange Offer	We are offering to issue the new notes in exchange for a like principal amount of your old notes. We are offering to issue the new notes to satisfy our obligations contained in the registration rights agreement entered into when the old notes were sold in transactions permitted by Rule 144A and Regulation S under the Securities Act and therefore not registered with the SEC. For procedures for tendering, see “The Exchange Offer.”
Tenders, Expiration Date, Withdrawal	The exchange offer will expire at 5:00 p.m. New York City time on July 8, 2024 unless it is extended. If you decide to exchange your old notes for new notes, you must acknowledge that you are not engaging in, and do not intend to engage in, a distribution of the new notes. If you decide to tender your old notes in the exchange offer, you may withdraw them at any time prior to July 8, 2024. If we decide for any reason not to accept any old notes for exchange, your old notes will be returned to you without expense to you promptly after the exchange offer expires. You may only exchange old notes in denominations of $2,000 and integral multiples of $1,000 in excess thereof.
Federal Income Tax Consequences	Your exchange of old notes for new notes in the exchange offer will not result in any income, gain or loss to you for federal income tax purposes. See “Material United States Tax Consequences of the Exchange Offer.”
Use of Proceeds	We will not receive any proceeds from the issuance of the new notes in the exchange offer.
Exchange Agent	U.S. Bank Trust Company, National Association is the exchange agent for the exchange offer.
Failure to Tender Your Old Notes	If you fail to tender your old notes in the exchange offer, you will not have any further rights under the registration rights agreement, including any right to require us to register your old notes or to pay you additional interest or liquidated damages. All untendered old notes will continue to be subject to the restrictions on transfer set forth in the old notes and in the indenture. In general, the old notes may not be offered or sold, unless registered under the Securities Act, except pursuant to an exemption from, or in a transaction not subject to, the Securities Act and applicable state securities laws. We do not currently anticipate that we will register such untendered old notes under the Securities Act and, following this exchange offer, will be under no obligation to do so.

2

You will be able to resell the new notes without registering them with the SEC if you meet the requirements described below.

Based on interpretations by the SEC’s staff in no-action letters issued to third parties, we believe that new notes issued in exchange for the old notes in the exchange offer may be offered for resale, resold or otherwise transferred by you without registering the new notes under the Securities Act or delivering a prospectus, unless you are a broker-dealer receiving securities for your own account, so long as:

● you are not one of our “affiliates,” which is defined in Rule 405 of the Securities Act;

● you acquire the new notes in the ordinary course of your business;

● you do not have any arrangement or understanding with any person to participate in the distribution of the new notes; and

● you are not engaged in, and do not intend to engage in, a distribution of the new notes.

If you are an affiliate of IPALCO Enterprises, Inc., or you are engaged in, intend to engage in or have any arrangement or understanding with respect to, the distribution of new notes acquired in the exchange offer, you (1) should not rely on our interpretations of the position of the SEC’s staff and (2) must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale transaction.

If you are a broker-dealer and receive new notes for your own account in the exchange offer and/or in exchange for old notes that were acquired for your own account as a result of market-making or other trading activities:

● you must represent that you do not have any arrangement or understanding with us or any of our affiliates to distribute the new notes;

● you must acknowledge that you will deliver a prospectus in connection with any resale of the new notes you receive from us in the exchange offer; and

● you may use this prospectus, as it may be amended or supplemented from time to time, in connection with the resale of new notes received in exchange for old notes acquired by you as a result of market-making or other trading activities.

For a period of 90 days after the expiration of the exchange offer, we will make this prospectus available to any broker-dealer for use in connection with any resale described above.

3

SUMMARY DESCRIPTION OF THE NOTES

The terms of the new notes and the old notes are identical in all material respects, except that the new notes have been registered under the Securities Act, and the transfer restrictions and registrations rights relating to old notes do not apply to the new notes. The new notes will represent the same debt as the old notes and will be governed by the same indenture under which the old notes were issued.

Issuer	IPALCO Enterprises, Inc.
Notes Offered	$400 million aggregate principal amount of new 5.75% senior secured notes due 2034.
Maturity	April 1, 2034.
Interest Payment Dates	Interest will be payable semiannually on April 1 and October 1 of each year.
Denominations	Minimum denominations of $2,000 and integral multiples of $1,000 in excess thereof.
Collateral	The notes are secured by our pledge of all of the outstanding common stock of AES Indiana. The lien on the pledged shares will be shared equally and ratably with our existing senior secured notes, and, subject to certain limitations, we may secure other Indebtedness (as defined herein) equally and ratably with the notes.
Ranking	The notes will be secured and rank equally with our senior secured indebtedness secured by a pledge of the same assets. The notes will rank senior, to the extent of the assets securing such indebtedness, to our senior unsecured indebtedness and senior to our subordinated indebtedness. The notes will effectively rank junior to our subsidiaries’ liabilities. As of March 31, 2024: ●     IPALCO had outstanding $1,280 million of senior secured indebtedness; and ●    AES Indiana had total long-term debt and current liabilities of approximately $3,467 million.
Optional Redemption	We may redeem some or all of the notes at any time or from time to time at a redemption price as described under the caption “Description of Notes—Optional Redemption.”
Change of Control	When a Change of Control Triggering Event (as defined herein) occurs, each holder of notes may require us to repurchase all or a portion of its notes at a purchase price equal to 101% of the principal amount of the notes, plus accrued interest. See “Description of Notes—Repurchase at the Option of Holders.”

4

Covenants	The indenture governing the notes contains covenants that, among other things, will limit our ability and, in the case of restrictions on liens, the ability of our significant subsidiaries to: ●     create certain liens on assets and properties; and ●     consolidate or merge, or convey, transfer or lease all or substantially all of our consolidated properties and assets These covenants are subject to important exceptions and qualifications, which are described in “Description of Notes—Covenants.” The indenture does not restrict or prevent AES Indiana or any other subsidiary from incurring unsecured indebtedness.
Book-Entry Form	The notes will be issued in registered book-entry form represented by one or more global notes to be deposited with or on behalf of DTC or its nominee. Transfers of the notes will be effected only through the facilities of DTC. Beneficial interests in the global notes may not be exchanged for certificated notes except in limited circumstances. See “Description of Notes—Form, Denomination and Registration of Notes.”
Further Issues	We may from time to time, without notice to or the consent of the holders of the notes, create and issue additional debt securities under the indenture governing the notes having the same terms as, and ranking equally with, the notes in all respects (except for the offering price and issue date), as described more fully in “Description of Notes—Basic Terms of Notes.”
Trustee, Registrar and Paying Agent	U.S. Bank Trust Company, National Association
Governing Law	The indenture and the notes are governed by, and construed in accordance with, the laws of the State of New York.

5

Risk Factors and Risk Factor Summary

If any of the following risks occur, our business, results of operations or financial condition could be materially adversely affected. You should also read the section captioned “Cautionary Note Regarding Forward-Looking Statements” for a discussion of what types of statements are forward-looking as well as the significance of such statements in the context of this prospectus. The risks described below are not the only ones we face. Additional risks of which we are not presently aware or that we currently believe are immaterial may also harm our business, results of operations or financial condition.

Risk Factor Summary

● If you choose not to exchange your old notes in the exchange offer, the transfer restrictions currently applicable to your old notes will remain in force and the market price of your old notes could decline.

● You must follow the exchange offer procedures carefully in order to receive the new notes.

● There are state securities law restrictions on the resale of the new notes.

● The notes will be structurally subordinated to claims of creditors of our current and future subsidiaries.

● We may incur additional indebtedness, which may affect our financial health and our ability to repay the notes.

● We are a holding company and are dependent on AES Indiana for dividends to meet our debt service obligations.

● We may not be able to repurchase the notes upon a change of control triggering event.

● Redemptions may adversely affect your return on the notes.

● Regulatory considerations may affect the ability of the collateral agent to exercise certain rights with respect to the collateral securing the notes.

● Credit rating downgrades could adversely affect the trading price of the notes.

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

● 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.

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

● Our business is sensitive to weather and seasonal variations.

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

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

● 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.

6

● 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.

● 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.

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

● 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.

● 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.

● We are subject to collective bargaining agreements that could adversely affect our business, 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.

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

● 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.

● 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.

● 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.

● 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.

● 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.

● 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.

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

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

● 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.

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

7

RISK FACTORS

Risks Related to the Exchange Offer

If you choose not to exchange your old notes in the exchange offer, the transfer restrictions currently applicable to your old notes will remain in force and the market price of your old notes could decline.

If you do not exchange your old notes for new notes in the exchange offer, then you will continue to be subject to the transfer restrictions on the old notes as set forth in the offering memorandum distributed in connection with the private offering of the old notes. In general, the old notes may not be offered or sold unless they are registered or exempt from registration under the Securities Act and applicable state securities laws. Except as required by the registration rights agreement entered into in connection with the private offering of the old notes, we do not intend to register resales of the old notes under the Securities Act. The tender of old notes under the exchange offer will reduce the principal amount of the old notes outstanding, which may have an adverse effect upon, and increase the volatility of, the market price of the old notes due to reduction in liquidity.

You must follow the exchange offer procedures carefully in order to receive the new notes.

If you do not follow the procedures described in this prospectus, you will not receive any new notes. If you want to tender your old notes in exchange for new notes, you will need to contact a DTC participant to complete the book-entry transfer procedures, as described under “The Exchange Offer,” prior to the expiration date, and you should allow sufficient time to ensure timely completion of these procedures to ensure delivery. No one is under any obligation to give you notification of defects or irregularities with respect to tenders of old notes for exchange. For additional information, see the section captioned “The Exchange Offer” in this prospectus.

There are state securities law restrictions on the resale of the new notes.

In order to comply with the securities laws of certain jurisdictions, the new notes may not be offered or resold by any holder, unless they have been registered or qualified for sale in such jurisdictions or an exemption from registration or qualification is available and the requirements of such exemption have been satisfied. We currently do not intend to register or qualify the resale of the new notes in any such jurisdictions. However, generally an exemption is available for sales to registered broker-dealers and certain institutional buyers. Other exemptions under applicable state securities laws also may be available.

Risks Related to the Notes

The notes will be structurally subordinated to claims of creditors of our current and future subsidiaries.

The notes will be structurally subordinated to indebtedness and other liabilities of our subsidiaries, including AES Indiana. Our subsidiaries may also incur additional indebtedness in the future. Any right that we have to receive any assets of any of our subsidiaries upon the liquidation or reorganization of those subsidiaries, and the consequent rights of holders of the notes to realize proceeds from the sale of any of those subsidiaries’ assets, will be effectively subordinated to the claims of those subsidiaries’ creditors, including trade creditors and holders of preferred equity interests of those subsidiaries. Accordingly, in the event of a bankruptcy, liquidation or reorganization of any of our subsidiaries, these subsidiaries will pay the holders of their debts, holders of their preferred equity interests and their trade creditors before they will be able to distribute any of their assets to us. The security interest in the common stock of AES Indiana pledged by us to secure the notes will not alter the effective subordination of the notes to the creditors of our subsidiaries.

8

We may incur additional indebtedness, which may affect our financial health and our ability to repay the notes.

As of March 31, 2024, we had on a consolidated basis $4,321.3 million of indebtedness and total common shareholders’ equity of $1,074.3 million. Our indebtedness includes $1,280.0 million aggregate principal of senior secured notes. AES Indiana had $2,769.2 million of First Mortgage Bonds outstanding as of March 31, 2024, 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. The indenture governing the notes does not restrict AES Indiana’s or any of our subsidiaries’ ability to incur unsecured indebtedness. As of March 31, 2024, AES Indiana had $195.0 million outstanding borrowings under its $350 million revolving Credit Agreement. This level of indebtedness and related security could have 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 or AES Indiana 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.

We are a holding company and are dependent on AES Indiana for dividends to meet our debt service obligations.

We are a holding company with no material assets other than the common stock of our subsidiaries, and accordingly substantially all cash is generated by the operating activities of our subsidiaries, principally AES Indiana. None of our subsidiaries, including AES Indiana, is obligated to make any payments with respect to the notes, and none of our subsidiaries will guarantee the notes; however, the common stock of AES Indiana is pledged to secure payment of these notes. Accordingly, our ability to make payments on the notes is dependent not only on the ability of our subsidiaries to generate cash in the future, but also on the ability of our subsidiaries to distribute cash to us. AES Indiana’s mortgage and deed of trust, its amended articles of incorporation and its Credit Agreement contain restrictions on AES Indiana’s ability to issue certain securities or pay cash dividends to us under certain circumstances.

We may not be able to repurchase the notes upon a change of control triggering event.

Upon the occurrence of specific kinds of change of control triggering events, we will be required to offer to repurchase all outstanding notes at 101% of their principal amount plus accrued and unpaid interest (see “Description of Notes-Repurchase at the Option of Holders”). The source of funds for any such purchase of the notes will be our available cash or cash generated from our subsidiaries’ operations or other sources, including borrowings, sales of assets or sales of equity. We may not be able to satisfy our obligations to repurchase the notes upon a change of control triggering event because we may not have sufficient financial resources to purchase all of the notes that are tendered upon a change of control triggering event.

Redemptions may adversely affect your return on the notes.

The notes are redeemable at our option, and therefore we may choose to redeem the notes at times when the prevailing interest rates are relatively low. As a result, you may not be able to reinvest the proceeds you receive from the redemption in a comparable security at an effective interest rate as high as the interest rate on your notes being redeemed.

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Regulatory considerations may affect the ability of the collateral agent to exercise certain rights with respect to the collateral securing the notes.

Regulatory considerations may affect the ability of the collateral agent to exercise certain rights with respect to the common stock of AES Indiana pledged by us to secure the notes upon the occurrence of an event of default under the indenture governing the notes. Because AES Indiana is a regulated public utility, foreclosure proceedings and the enforcement of the pledge agreement and the right to take other actions with respect to the pledged shares of AES Indiana common stock may be limited and subject to regulatory approval. AES Indiana is subject to regulation at the state level by the IURC. At the federal level, it is subject to regulation by the FERC. See “Business—Regulation.” Regulation by the IURC and FERC includes regulation with respect to the change of control, transfer or ownership of utility property. In particular, foreclosure proceedings and the enforcement of the pledge agreement and the right to take other actions with respect to the pledged shares of AES Indiana common stock would require (i) FERC approval to the extent such actions resulted in a change in control or a transfer of the ownership of the pledged shares of AES Indiana common stock and (ii) IURC approval to the extent such actions resulted in a transfer of the ownership of the pledged shares of AES Indiana common stock to another Indiana utility. There can be no assurance that any such regulatory approval can be obtained on a timely basis, or at all.

Credit rating downgrades could adversely affect the trading price of the notes.

The trading price for the notes may be affected by our credit rating, and our credit rating may be affected by the credit rating of AES. Credit ratings are continually revised and there can be no assurance that our current credit rating or the current credit rating of AES will remain the same for any given period of time or that such ratings will not be downgraded or withdrawn entirely by a rating agency if, in that rating agency’s judgment, future circumstances relating to the basis of the rating, such as adverse changes, so warrant. Any downgrade in, or withdrawal of, our credit rating or the credit rating of AES could adversely affect the trading price of the notes or the trading markets for the notes to the extent trading markets for the notes develop. Credit ratings are not recommendations to purchase, hold or sell the notes. Additionally, credit ratings may not reflect the potential effect of risks related to the structure or marketing of the notes. One rating agency’s rating should be evaluated independently of any other rating agency’s rating.

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;

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● 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.

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.

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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 consolidated financial statements and related notes included elsewhere in this prospectus 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. As of December 31, 2023, while we had approximately 83% in total of our current coal requirements for the two-year period ending December 31, 2025 under long-term contracts, the balance was yet to be purchased and would 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.

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.

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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 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.

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.

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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 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 audited Consolidated Financial Statements of IPALCO and related notes included elsewhere in this prospectus for further discussion.

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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 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;

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● 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 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.

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.

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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, 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.

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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 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 consolidated financial statements and related notes included elsewhere in this prospectus 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.

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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, 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.

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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 “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 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.

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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 “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 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.

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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 consolidated financial statements and related notes included elsewhere in this prospectus 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.

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.

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See Note 6, “Debt” to the audited Consolidated Financial Statements of IPALCO included in this prospectus for information regarding indebtedness. See also “Management’s Discussion and Analysis of Financial Condition and Results of Operations—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 March 31, 2024, we had on a consolidated basis $4,321.3 million of indebtedness, including finance lease obligations, and total shareholders’ equity of $1,074.3 million. AES Indiana had $2,769.2 million of first mortgage bonds outstanding as of March 31, 2024, 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 and we expect AES Indiana to incur additional debt in the future, subject in each case to the terms of our respective debt agreements and regulatory approvals. 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 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 5, “Debt” to the unaudited Condensed Consolidated Financial Statements of IPALCO included elsewhere in this prospectus.

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 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 the rating agencies were to 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.

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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 and its Credit 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 “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 audited Consolidated Financial Statements of IPALCO included in this prospectus 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.

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Cautionary Note Regarding Forward-Looking Statements

This prospectus includes certain “forward-looking statements” that involve many risks and uncertainties. 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. These forward-looking statements are based on management’s present expectations and beliefs about future events. As with any projection or forecast, these statements are inherently susceptible to uncertainty and changes in circumstances. We are under no obligation to, and expressly disclaim any obligation to, update or alter the forward-looking statements whether as a result of such changes, new information, subsequent events or otherwise. 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:

Important 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 include, but are not limited to, the following:

● 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;

● 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;

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● 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 prospectus 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 “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” 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.

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Use of Proceeds

We will not receive any cash proceeds from the issuance of the new notes. The new notes will be exchanged for old notes as described in this prospectus upon our receipt of old notes. We will cancel all of the old notes surrendered in exchange for the new notes.

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Capitalization

The following table sets forth a summary of IPALCO’s consolidated capitalization as of March 31, 2024. This table should be read in conjunction with the discussions under Management’s Discussion and Analysis of Financial Condition and Results of Operations and the consolidated financial statements and related notes, included herein.

	March 31, 2024
	(in thousands)
	(Unaudited)
Common shareholders’ equity:
Paid in capital	$	1,022,018
Accumulated other comprehensive loss		36,680
Retained Earnings		15,624
Total common shareholders’ equity		1,074,322
Noncontrolling interests		50,650
Long-term debt (less current maturities)(1)		3,593,698
Total capitalization	$	4,718,670

(1) As of March 31, 2024, the current portion of long-term debt was $445.0 million.

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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 and the notes thereto included elsewhere in this prospectus. The following discussion contains forward-looking statements. Our actual results may differ materially from the results suggested by these forward-looking statements. Please see “Cautionary Note Regarding Forward-Looking Statements” and “Risk Factors” in this prospectus.

IPALCO is a holding company incorporated under the laws of the state of Indiana whose principal subsidiary is Indianapolis Power & Light Company, which does business as 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 audited Consolidated Financial Statements of IPALCO and related notes included elsewhere in this prospectus.

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 524,000 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 2024.

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.

Additional information relating to our risks is contained in “Risk Factors” elsewhere in this prospectus.

The following discussion should be read in conjunction with the accompanying Financial Statements and related notes included elsewhere in this prospectus.

Overview

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 “Business—Regulation” and “Business—Environmental Matters” in this prospectus.

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 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.

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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.

Results of Operations

The electric utility business is affected by seasonal weather patterns throughout the year and, therefore, operating revenues and associated expenses are not generated evenly by month during the year.

Statements of Operations Highlights

Years Ended December 31, 2023, 2022 and 2021

	Years Ended December 31,									Change 2023 vs. 2022						Change 2022 vs. 2021
	2023			2022			2021			$			%			$			%
	(In Thousands)
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	)%

30

Three Months Ended March 31, 2024 and March 31, 2023

	Three Months Ended March 31,
	2024			2023			$ Change			% Change
	$ in Thousands
REVENUE	$	407,801		$	491,386		$	(83,585	)		(17.0	)%
OPERATING COSTS AND EXPENSES:
Fuel		102,919			189,730			(86,811	)		(45.8	)%
Power purchased		38,633			49,890			(11,257	)		(22.6	)%
Operation and maintenance		115,368			117,899			(2,531	)		(2.1	)%
Depreciation and amortization		80,433			69,852			10,581			15.1	%
Taxes other than income taxes		7,895			7,430			465			6.3	%
Loss on asset disposal		1,523			—			1,523			100.0	%
Total operating costs and expenses		346,771			434,801			(88,030	)		(20.2	)%
OPERATING INCOME		61,030			56,585			4,445			7.9	%
OTHER (EXPENSE) / INCOME, NET:
Allowance for equity funds used during construction		831			1,570			(739	)		(47.1	)%
Interest expense		(43,648	)		(34,843	)		(8,805	)		25.3	%
Other income, net		306			1,017			(711	)		(69.9	)%
Total other expense, net		(42,511	)		(32,256	)		(10,255	)		31.8	%
INCOME BEFORE INCOME TAX		18,519			24,329			(5,810	)		(23.9	)%
Income tax expense		3,909			5,214			(1,305	)		(25.0	)%
NET INCOME		14,610			19,115			(4,505	)		(23.6	)%
Net loss attributable to noncontrolling interests		(2,552	)		—			(2,552	)		(100.0	)%
NET INCOME ATTRIBUTABLE TO COMMON STOCK	$	17,162		$	19,115		$	(1,953	)		(10.2	)%

31

2023 versus 2022

Revenues

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.

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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:

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

	2023 vs. 2022
	$ in millions
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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Comparison of three months ended March 31, 2024 and three months ended March 31, 2023

Revenue during the three months ended March 31, 2024 decreased $83.6 million compared to the same period in 2023, which resulted from the following changes (dollars in thousands):

	Three Months Ended March 31,
	2024		2023		$ Change			% Change
Revenue:
Retail revenue	$	391,914	$	460,615	$	(68,701	)		(14.9	)%
Wholesale revenue		12,622		24,251		(11,629	)		(48.0	)%
Miscellaneous revenue		3,265		6,520		(3,255	)		(49.9	)%
Total revenue	$	407,801	$	491,386	$	(83,585	)		(17.0	)%
Heating degree days:
Actual		2,329		2,267		62			2.7	%
30-year average		2,713		2,738

The following table presents additional data on kWh sold:

	Three Months Ended March 31,
	2024		2023		kWh Change			% Change
kWh Sales (In Millions):
Residential		1,431		1,342		89			6.6	%
Small commercial and industrial		471		451		20			4.4	%
Large commercial and industrial		1,399		1,417		(18	)		(1.3	)%
Public lighting		5		5		—			—%
Sales - retail customers		3,306		3,215		91			2.8	%
Wholesale		360		709		(349	)		(49.2	)%
Total kWh sold		3,666		3,924		(258	)		(6.6	)%

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The following graph shows the percentage changes in weather-normalized and actual retail electric sales volumes by customer class for the three months ended March 31, 2024 as compared to the same period in the prior year:

During the three months ended March 31, 2024, revenue decreased $83.6 million compared to the same period of the prior year primarily due to the following:

	Three Months Ended March 31, 2024 vs. 2023
	$ in millions
Retail revenue:
Volume:
Net increase in the volume of kWh sold primarily due to weather and demand in our service territory versus the comparable period	$	14.6
Price:
Net decrease in the weighted average price of retail kWh sold primarily due to lower fuel revenue		(78.8	)
Other:		(4.5	)
Net change in retail revenue		(68.7	)
Wholesale revenue:
Volume:
Net increase 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.		0.3
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		(11.9	)
Net change in wholesale revenue		(11.6	)

Miscellaneous revenue		(3.3	)
Net change in revenue	$	(83.6	)

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Operating Costs and Expenses

2023 versus 2022

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:

	2023 vs. 2022
	$ in millions
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:

	2023 vs. 2022
	$ in millions
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 audited Consolidated Financial Statements of IPALCO included in this prospectus.

Operation and Maintenance

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

	2023 vs. 2022
	$ in millions
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	)

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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 audited Consolidated Financial Statements of IPALCO included in this prospectus, partially offset by (ii) an increase in property tax expense of $4.3 million primarily as a result of higher assessed values.

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 audited Consolidated Financial Statements of IPALCO included in this prospectus.

Comparison of Three Months Ended March 31, 2024 and Three Months Ended March 31, 2023

The following table illustrates our changes in Operating costs and expenses during the three months ended March 31, 2024 compared to the same period in 2023 (in thousands):

	Three Months Ended March 31,
	2024		2023		$ Change			% Change
Operating costs and expenses:
Fuel	$	102,919	$	189,730	$	(86,811	)		(45.8	)%
Power purchased		38,633		49,890		(11,257	)		(22.6	)%
Operation and maintenance		115,368		117,899		(2,531	)		(2.1	)%
Depreciation and amortization		80,433		69,852		10,581			15.1	%
Taxes other than income taxes		7,895		7,430		465			6.3	%
Loss on asset disposal		1,523		—		1,523			100.0	%
Total operating costs and expenses	$	346,771	$	434,801	$	(88,030	)		(20.2	)%

Fuel

The decrease in fuel costs of $86.8 million during the three months ended March 31, 2024 compared to the same period of the prior year was primarily due to the following changes:

	Three Months Ended March 31, 2024 vs. 2023
	$ in millions
Volume:
Coal	$	(19.1	)
Natural gas		24.4
Oil		(0.2	)
Net change in volume		5.1
Price:
Coal		9.2
Natural gas		(21.9	)
Oil		(0.3	)

Deferred fuel		(78.9	)
Net change in price		(91.9	)
Net change in fuel expense	$	(86.8	)

38

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.

Power Purchased

The decrease in power purchased of $11.3 million during the three months ended March 31, 2024 compared to the same period of the prior year was primarily due to the following changes:

	Three Months Ended March 31, 2024 vs. 2023
	$ in millions
Volume:
Net decrease in volume of power purchased primarily due to acquisition of the Hoosier Wind Project	$	(2.1	)
Price:
Market prices		7.4
Deferred purchased power		(18.4	)
Net change in price		(11.0	)
Other, net (mostly due to changes in capacity purchases)		1.8
Net change in power purchased costs	$	(11.3	)

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.

Operation and Maintenance

The decrease in Operation and maintenance of $2.5 million during the three months ended March 31, 2024 compared to the same period of the prior year was primarily due to the following changes:

	Three Months Ended March 31, 2024 vs. 2023
	$ in millions
Decrease in contracted services expenses primarily due to lower generation maintenance and outage costs	$	(4.2	)
Other, net		1.7
Net change in operation and maintenance costs	$	(2.5	)

39

Depreciation and Amortization

The increase in Depreciation and amortization expense of $10.6 million during the three months ended March 31, 2024 compared to the same period of the prior year was mostly attributed to the impact of additional assets placed in service and higher amortization of regulatory assets.

Other (Expense) / Income, Net

2023 Versus 2022

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.

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 audited Consolidated Financial Statements of IPALCO included in this prospectus.

40

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 audited Consolidated Financial Statements of IPALCO included in this prospectus.

Comparison of Three Months Ended March 31, 2024 and Three Months Ended March 31, 2023

The following table illustrates our changes in Other (expense) / income, net during the three months ended March 31, 2024 compared to the same period in 2023 (in thousands):

	Three Months Ended March 31,
	2024			2023			$ Change			% Change
Other (expense) / income, net:
Allowance for equity funds used during construction	$	831		$	1,570		$	(739	)		(47.1	)%
Interest expense		(43,648	)		(34,843	)		(8,805	)		25.3	%
Other income, net		306			1,017			(711	)		(69.9	)%
Total other expense, net	$	(42,511	)	$	(32,256	)	$	(10,255	)		31.8	%

Interest Expense

The increase in Interest expense of $8.8 million during the three months ended March 31, 2024 compared to the same period of the prior year was primarily due to (i) higher interest expense on debt of $11.6 million (mostly due to new debt issuances and higher borrowings on the committed Credit Agreement), partially offset by (ii) an increase in the allowance for borrowed funds used during construction of $2.3 million.

Income Tax Expense

The following table illustrates our changes in Income tax expense during the three months ended March 31, 2024 compared to the same period of the prior year (in thousands):

	Three Months Ended March 31,
	2024		2023		$ Change			% Change
Income tax expense	$	3,909	$	5,214	$	(1,305	)		(25.0	)%

The decrease in Income tax expense of $1.3 million during the three months ended March 31, 2024 was primarily driven by lower pre-tax income as compared to the comparable period of the prior year.

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Net Loss Attributable to Noncontrolling Interests

The following table illustrates changes in Net loss attributable to noncontrolling interests during the three months ended March 31, 2024 compared to the same period of the prior year (in thousands):

	Three Months Ended March 31,
	2024			2023		$ Change			% Change
Net loss attributable to noncontrolling interests	$	(2,552	)	$	—	$	(2,552	)		(100.0	)%

The Net loss attributable to noncontrolling interests of $2.6 million for the three months ended March 31, 2024 relates to the allocation of earnings using the HLBV method for the Hardy Hills Solar Project, which began initial operations in December 2023. See Note 2, “Regulatory Matters—IRP Filings and Replacement Generation—Hardy Hills Solar Project” to the audited Consolidated Financial Statements of IPALCO included in this prospectus.

Key Trends and Uncertainties

During the remainder of 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 prospectus 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 “Business” and “Risk Factors” elsewhere in this prospectus.

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 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.

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On April 24, 2024, new Commerce regulations with respect to the administration of AD/CVD cases went into effect, including regulations pertaining to transnational subsidization and particular market situations. On the same day, several companies filed a petition requesting that Commerce initiate an investigation into whether new AD/CVD duties should be imposed on cells and modules imported from Thailand, Cambodia, Malaysia and Vietnam. If Commerce initiates such an investigation, it could cause disruptions to the import of solar cells and panels from such countries.

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 new Commerce investigations or any adverse Commerce determinations or other tariff disputes or litigation, the impact of the UFLPA, potential future disruptions to the solar panel supply chain and their effect on AES Indiana’s solar project development and construction activities remain 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 “Capital Resources and Liquidity” in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

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, direct transfers and/or new tax credits for wind, solar, and storage. We expect that the extension of the current solar ITCs, as well as higher credits available 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 audited Consolidated Financial Statements of IPALCO included in this prospectus.

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 in recent years. This could result in significant impacts to future tax law.

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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 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 since 2021, and interest rates are expected to remain volatile 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. For future IPALCO debt financings, IPALCO manages a hedging program and evaluates pre-issuance hedges to reduce uncertainty and exposure to future interest rates.

Regulatory

Regulatory Rate Review

On April 17, 2024, the IURC issued an order (the “2024 Rate Order”) approving the Stipulation and Settlement Agreement that AES Indiana entered into on November 22, 2023, with the OUCC and the other intervening parties in AES Indiana’s base rate case filing. Please see Note 2, “Regulatory Matters—Regulatory Rate Review” to the unaudited Condensed Consolidated Financial Statements of IPALCO included in this prospectus.

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. Please see Note 2, “Regulatory Matters” to the audited Consolidated Financial Statements of IPALCO included in this prospectus and Note 2, “Regulatory Matters” to the audited Consolidated Financial Statements of IPALCO included in this prospectus for further discussion of these and other regulatory matters.

Environmental

We are subject to numerous environmental and climate change laws and regulations in the jurisdictions in which we operate. We face certain risks and uncertainties related to these environmental and climate change laws and regulations, including existing and potential GHG legislation or regulations, and actual or potential laws and regulations pertaining to water discharges, waste management (including disposal or beneficial reuse of CCR) and certain air emissions, such as SO₂, NO_x, particulate matter and mercury and other hazardous air pollutants, and species and habitat protections. Such risks and uncertainties could result in increased capital expenditures or other compliance costs which could have a material adverse effect on our consolidated results of operations. The following discussion of the impact of environmental laws and regulations on the Company updates the discussion provided in “Business—Environmental Matters” elsewhere in this prospectus.

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.

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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. On April 25, 2024, EPA released a pre-publication version of the final MATS RTR Rule. We are currently reviewing the rule and it is too early to predict any potential impact. However, the existing requirements of MATS 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

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

The EPA has indicated that they will implement a phased approach to amending the CCR Rule, which is ongoing.

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. On April 25, 2024, EPA released the pre-publication version of the final rule which we are currently reviewing. It is too early to predict 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 IPALCO’s 2023 Form 10-K for further discussion.

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 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.

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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. On April 25, 2024, EPA released a prepublication version of the final NSPSs for GHGs for new, modified, and reconstructed fossil-fuel fired EGUs, Emissions Guidelines for existing fossil fuel-fired EGUs, and the Repeal of the ACE Rule. We are currently reviewing these rules.

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.

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.

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 and NOx.

On April 15, 2024, EPA published a proposed rule to retain the secondary NOx NAAQS.

Fine Particulate Matter.

On April 15, 2024, EPA published a proposed rule to retain the current secondary PM NAAQS.

SO₂.

On April 15, 2024, EPA published a proposed rule to revise the secondary SO₂ NAAQS.

Based on 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 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.

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. On March 28, 2024, the EPA published in the Federal Register the final CWA Hazardous Substance Facility Response Plans rule. The final rule will become effective on May 27, 2024. It is too early to determine whether this final rule may have a material impact on our business, financial condition or results of operation.

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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. On April 25, 2024, EPA issued a pre-publication version of the final rule. We are currently reviewing this rule and it is too early to determine whether any outcome of this final rule, litigation or future revisions to the ELG rule might have a material impact on our business, financial condition and results of operations.

CWA — NPDES Permits

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, 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 July 26, 2024 (extended from April 16, 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.

Capital Resources and Liquidity

Overview

As of March 31, 2024, we had unrestricted cash and cash equivalents of $435.2 million and available borrowing capacity of $155 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 February 2024, AES Indiana received an order from the IURC granting authority through December 31, 2026 to, among other things, issue up to $1 billion in aggregate principal amount of long-term debt, of which $350 million remains available under the order as of March 31, 2024. 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 $400 million remains available under the order as of March 31, 2024. 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 March 31, 2024. The amount of new debt that we issue is additionally restricted as a result of contractual obligations of AES and by the covenants included in 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. 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.

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Cash Flows

The following table provides a summary of our cash flows (in thousands):

	Three Months Ended March 31,
	2024			2023			$ Change
Net cash (used in) / provided by operating activities	$	(48,133	)	$	152,252		$	(200,385	)
Net cash used in investing activities		(317,679	)		(154,942	)		(162,737	)
Net cash provided by / (used in) financing activities		772,450			(31,406	)		803,856
Net change in cash, cash equivalents and restricted cash		406,638			(34,096	)		440,734
Cash, cash equivalents and restricted cash at beginning of period		28,584			201,553			(172,969	)
Cash, cash equivalents and restricted cash at end of period	$	435,222		$	167,457		$	267,765

Operating Activities

The following table summarizes the key components of our consolidated operating cash flows (in thousands):

	Three Months Ended March 31,
	2024			2023			$ Change
Net income	$	14,610		$	19,115		$	(4,505	)
Depreciation and amortization		80,433			69,852			10,581
Deferred income taxes and investment tax credit adjustments – net		2,000			430			1,570
Other adjustments to net income		1,738			(621	)		2,359
Net income, adjusted for non-cash items		98,781			88,776			10,005
Net change in operating assets and liabilities(1)		(146,914	)		63,476			(210,390	)
Net cash provided by operating activities	$	(48,133	)	$	152,252		$	(200,385	)

(1) Refer to the table below for explanations of the variance in operating assets and liabilities.

The net change in operating assets and liabilities for the three months ended March 31, 2024 compared to the three months ended March 31, 2023 was driven by changes in the following (in thousands):

Increase from current and non-current regulatory assets and liabilities primarily due to lower FAC collections in the current year and the settlement of a pre-existing power purchase agreement	$	(170,143	)
Increase from accounts receivable driven primarily by the timing of the collections, including billing delays		(70,202	)
Increase in prepaid and other assets due to timing of payments and a decrease in advanced capacity purchases		31,439
Other		(1,484	)
Net change in operating assets and liabilities	$	(210,390	)

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Investing Activities

Net cash used in investing activities increased $162.7 million for the three months ended March 31, 2024 compared to the three months ended March 31, 2023, 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	$	(115,866	)
Payments for an acquisition made in the current year		(47,948	)
Other		1,077
Net change in investing activities	$	(162,737	)

Financing Activities

Net cash provided by financing activities increased $803.9 million for the three months ended March 31, 2024 compared to the three months ended March 31, 2023, which was primarily driven by (in thousands):

Increase due to long-term debt issuances at IPALCO and AES Indiana	$	1,050,000
Increase due to short-term borrowings		92,000
Increase due to higher net revolver draws on AES Indiana’s revolving credit facility		40,000
Decrease due to repayment of the term loan issued in 2023 and other short-term borrowings		(392,000	)
Other		13,856
Net change in financing activities	$	803,856

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. In 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.

Indebtedness

For further discussion of our significant debt transactions, please see Note 5, “Debt” to the unaudited Condensed Consolidated Financial Statements of IPALCO included in this prospectus.

Line of Credit

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

$ in millions	Type	Maturity	Commitment		Amounts available at March 31, 2024
AES Indiana	Revolving	December 2027	$	350.0	$	155.0

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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 (including amounts already expended in the first three months of 2024) is currently estimated to cost approximately $3.2 billion (excluding environmental compliance), and includes estimates as follows (amounts in millions):

	2024		2025		2026		For the three-year period 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 March 31, 2024 were $725.5 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 audited Consolidated Financial Statements of IPALCO included in this prospectus 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 “Business—Environmental Matters” of this prospectus for additional details.

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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Dividend Distributions

All of IPALCO’s outstanding common stock is held by AES U.S. Investments and CDPQ. During the first three months of 2024 and 2023, IPALCO paid $26.7 million and $31.4 million, respectively, in distributions to its shareholders. 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. Dividends from AES Indiana are affected by AES Indiana’s actual results of operations, financial condition, cash flows, capital requirements, regulatory and legal considerations, and such other factors as AES Indiana’s Board of Directors deems relevant.

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 audited Consolidated Financial Statements of IPALCO included in this prospectus. 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 audited Consolidated Financial Statements of IPALCO included in this prospectus.

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 audited Consolidated Financial Statements of IPALCO included in this prospectus.

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 audited Consolidated Financial Statements of IPALCO included in this prospectus 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 audited Consolidated Financial Statements of IPALCO included in this prospectus.

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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 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 audited Consolidated Financial Statements of IPALCO included in this prospectus 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 audited Consolidated Financial Statements of IPALCO included in this prospectus 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 audited Consolidated Financial Statements of IPALCO included in this prospectus for information about significant contingencies involving us.

New Accounting Standards

Please see Note 1, “Overview and Summary of Significant Accounting Policies” to the audited Consolidated Financial Statements of IPALCO included in this prospectus for a discussion of new accounting pronouncements and the potential impact to our results of operations, financial condition and cash flows.

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 NO_x 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.

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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.

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 included elsewhere in this prospectus, 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, as of December 31, 2023, 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 a long-term power purchase agreement to purchase all the wind-generated electricity from a project located in Minnesota that 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. 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 audited Consolidated Financial Statements of IPALCO included in this prospectus.

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 audited Consolidated Financial Statements of IPALCO included in this prospectus 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 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 audited Consolidated Financial Statements of IPALCO included in this prospectus.

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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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 audited Consolidated Financial Statements of IPALCO included in this prospectus.

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 524,000 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 2024.

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.

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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.

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 audited Consolidated Financial Statements of IPALCO included in this prospectus and “Certain Relationships, Related Transactions and Director Independence” included herein 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 Filing”) to the unaudited Condensed Consolidated Financial Statements of IPALCO included in this prospectus. 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”) to the unaudited Condensed Consolidated Financial Statements of IPALCO included in this prospectus.

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 audited Consolidated Financial Statements of IPALCO included in this prospectus:

Type	Project Name	Solar Capacity (MW)		Storage Capacity (MWh)		Date filed with IURC	Date of IURC approval	Estimated Completion		Location
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

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.

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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.

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 audited Consolidated Financial Statements of IPALCO included in this prospectus 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.

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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 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 elsewhere in this prospectus 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 elsewhere in this prospectus.

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.

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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” of the financial statements elsewhere in this prospectus.

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. On April 25, 2024, the EPA released a pre-publication version of the final MATS RTR Rule. We are currently reviewing the rule and it is too early to predict any potential impact. However, the existing requirements of MATS 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.

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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 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. On April 25, 2024, the EPA released the pre-publication version of the final rule which we are currently reviewing. It is too early to predict 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” to the audited Consolidated Financial Statements of IPALCO included in this prospectus for further information.

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;

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● 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.

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. On April 25, 2024, the EPA released a prepublication version of the final NSPSs for GHGs for new, modified, and reconstructed fossil-fuel fired EGUs, Emissions Guidelines for existing fossil fuel-fired EGUs, and the Repeal of the ACE Rule. We are currently reviewing these rules.

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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.

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. Construction was completed for the remaining MW and the project achieved full commercial operations in May 2024. For further discussion, see Note 2, “Regulatory Matters—IRP Filing” to the unaudited Condensed Consolidated Financial Statements of IPALCO included in this prospectus for additional details.

NSR and Other CAA NOVs

See Note 10, “Commitments and Contingencies—Contingencies—Environmental Matters—NSR and other CAA NOVs” to the Financial Statements 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, NO_x, 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. On April 15, 2024, the EPA published a proposed rule to retain the secondary NOx NAAQS.

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 NO_x 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.

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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. On April 15, 2024, the EPA published a proposed rule to retain the current secondary PM NAAQS.

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. On April 15, 2024, the EPA published a proposed rule to revise the secondary SO₂ NAAQs.

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 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. On March 28, 2024, the EPA published in the Federal Register the final CWA Hazardous Substance Facility Response Plans rule. The final rule will become effective on May 27, 2024. It is too early to determine whether this final rule may have a material impact on our business, financial condition or results of operation.

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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. On April 25, 2024, the EPA issued a pre-publication version of the final rule. We are currently reviewing this rule and it is too early to determine whether any outcome of this final rule, litigation 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, 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.

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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, 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 July 26, 2024 (extended from April 16, 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.

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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 audited Consolidated Financial Statements of IPALCO included in this prospectus for further information. 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 audited Consolidated Financial Statements of IPALCO included in this prospectus 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.

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 committed under a long-term power purchase agreement to purchase all the wind-generated electricity from a project located in Minnesota that 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, 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. On March 11, 2024, AES Indiana filed for approval of a CPCN with the IURC to convert Petersburg Units 3 and 4 from coal to natural gas and to recover costs through future rates. The conversion of Unit 3 is expected to begin in February 2026 and be completed by June 2026 and the conversion of Unit 4 is expected to begin in June 2026 and be completed by December 2026. A hearing for this case is expected to be held in August 2024, and we expect the IURC to issue an order on this proceeding during the fourth quarter 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., Petersburg Energy Center Project, Pike County BESS 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.

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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 audited Consolidated Financial Statements of IPALCO 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, 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. As such, costs, if any, that may be incurred in excess of those amounts provided for in our Financial Statements cannot be reasonably determined, but could be material.

Please see “Business-Environmental Matters,” Note 2, “Regulatory Matters” and Note 10, “Commitments and Contingencies” to the audited Consolidated Financial Statements of IPALCO, included in this prospectus, for a summary of significant legal proceedings involving us. We are also subject to routine litigation, claims and administrative proceedings arising in the ordinary course of business.

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Management

Directors

Set forth below is certain information regarding each of IPALCO’s current directors as of April 15, 2024, including the qualifications of such persons to serve as directors. Directors are elected annually to serve until their successors are duly elected and qualified or until their earlier death, disqualification, resignation or removal from office. Please see “Corporate Governance-Nomination of Directors” below for a discussion of certain rights with respect to the nomination and election of directors held by certain of IPALCO’s shareholders.

Stephen Coughlin, 52, has been a Director of IPALCO since November 2021. Mr. Coughlin has served as Executive Vice President and Chief Financial Officer of AES since October 2021. Prior to assuming his current position, he led AES’ Corporate Strategy and Financial Planning teams, and served as the Chair of the AES’ Investment Committee. Prior to that role, he served as the Chief Executive Officer of Fluence Energy, LLC, a subsidiary of Fluence Energy, Inc. (“Fluence”), a leader in energy storage products and services, and cloud-based software for renewables and storage assets. Mr. Coughlin joined AES in 2007 and spent his early years with the company leading Financial Planning & Analysis for AES’s renewables portfolio. Mr. Coughlin also serves as a director or officer of other AES affiliates, including as a Director of AES U.S. Investments. Mr. Coughlin brings extensive experience in finance and accounting to the Company’s Board of Directors (the “Board”). Mr. Coughlin received a bachelor’s degree in commerce and finance from the University of Virginia and a Master of Business Administration degree from the University of California at Berkeley.

Bernerd Da Santos, 60, has been a Director of IPALCO since January 2021. Mr. Da Santos has served as the Executive Vice President and President of the Renewables Strategic Business Unit of AES since June 2023. Previously, Mr. Da Santos held several positions at AES, including Chief Operating Officer and Executive Vice President from December 2017 to July 2023, Chief Operating Officer and Senior Vice President from 2014 to 2017, Chief Financial Officer, Global Finance Operations from 2012 to 2014, Chief Financial Officer of Global Utilities from 2011 to 2012, Chief Financial Officer of Latin America and Africa from 2009 to 2011, Chief Financial Officer of Latin America from 2007 to 2009, Managing Director of Finance for Latin America from 2005 to 2007, and VP and Controller of La Electricidad de Caracas (“EDC”) (Venezuela). Prior to joining AES in 2000, Mr. Da Santos held a number of financial leadership positions at EDC. Mr. Da Santos serves as a director or officer of other AES affiliates, including as a Director of Indianapolis Power & Light Company, doing business as AES Indiana (“AES Indiana”), AES Brasil Energia S.A., AES Mong Duong Power Co. Ltd., and Son My LNG Terminal LLC. Mr. Da Santos brings extensive industry operational and finance experience to the Board. Mr. Da Santos holds a bachelor’s degree with Cum Laude distinction in Business Administration and Public Administration from Universidad José Maria Vargas, a bachelor’s degree with Cum Laude distinction in Business Management and Finance, and an MBA with Cum Laude distinction from Universidad José Maria Vargas.

Ricardo Manuel Falú, 44, has been a Director of IPALCO since August 2023. Mr. Falú has served as Executive Vice President and Chief Operating Officer of AES since February 2024. Prior to assuming his current position, Mr. Falú was Senior Vice President and Chief Operating Officer of AES since July 2023 and Senior Vice President and Chief Strategy and Commercial Officer since August 2022. Since March 2023, Mr. Falú has also served as President of the New Energy Technologies Strategic Business Unit of AES. Mr. Falú joined AES in 2003 and, prior to his current roles, served as President of the Andes region from January 2022 to August 2022 and Chief Executive Officer of AES Andes from April 2018 to August 2022, which includes AES Chile, AES Colombia, and AES Argentina. Before that, Mr. Falú served as the Chief Financial Officer for AES’ businesses in the Andes region from 2014 to April 2018 and as Chief Financial Officer for AES’ businesses in the Mexico, Central American, and Caribbean region from 2012 to 2014. Mr. Falú serves as a director or officer of other AES affiliates, including as a Director of DPL Inc. (“DPL”), Fluence Energy, Inc., AES Andes, and AES Colombia. Mr. Falú brings to the Board his extensive experience in operations, strategic planning, and finance. Prior to joining AES, Mr. Falú worked as an external auditor, accounting analyst, and financial consultant in Argentina. He holds a Certified Public Accountant degree from the Universidad Nacional de Salta in Argentina and an Executive MBA, graduating Summa Cum Laude from the IAE Business School. He also holds a diploma from the Wharton Advanced Management Program, a Certificate in Management from Darden, and has completed other executive financial and management studies at Darden, Wharton, and Harvard.

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Paul L. Freedman, 54, has been a Director of IPALCO since February 2015. Mr. Freedman has served as Executive Vice President, General Counsel and Corporate Secretary of AES since February 2021. Prior to assuming his current position, Mr. Freedman was Senior Vice President and General Counsel of AES from February 2018, Corporate Secretary from October 2018, Chief of Staff to the Chief Executive Officer from April 2016 to February 2018, Assistant General Counsel from 2014 to 2016, and from 2007 to 2014 he held a variety of other positions in the AES legal group. Mr. Freedman serves as a director or officer of other AES affiliates, including as a Director of AES U.S. Investments and The Dayton Power and Light Company, doing business as AES Ohio (“AES Ohio”). Mr. Freedman brings to the Board his legal and industry experience together with his experience at AES in a wide range of areas, including commercial transactions, financings, corporate strategy, regulatory and environmental matters, and corporate governance. Prior to joining AES, Mr. Freedman was Chief Counsel for credit programs at the U.S. Agency for International Development, and he previously worked as an associate at the law firms of White & Case and Freshfields. Mr. Freedman received a B.A. from Columbia University and a J.D. from the Georgetown University Law Center. He is also currently on the board of directors of the Business Council for International Understanding and the Coalition for Integrity.

Gustavo Garavaglia, 38, has been a Director of IPALCO and Indiana since April 2024. Mr. Garavaglia has served as Vice President and Chief Financial Officer of IPALCO and AES Indiana since rejoining AES in April 2024. Mr. Garavaglia also serves as Vice President and Chief Financial Officer of the US and Utilities, including AES Ohio and DPL, and serves as director or officer of other AES affiliates, including as a Director of DPL, AES Ohio and AES U.S. Investments, and as Vice President and Chief Financial Officer of AES U.S. Investments. Mr. Garavaglia brings extensive experience in finance and accounting to the Board. Prior to rejoining AES, Mr. Garavaglia served as Chief Financial Officer of Vale Base Metals from April 2022 to April 2024. Prior to joining Vale, a mining company, Mr. Garavaglia spent twelve years at AES, serving as Chief Financial Officer of IPALCO and AES Indiana from November 2018 to March 2022. Mr. Garavaglia also served as a director of AES Indiana from March 2019 to April 2022, and as a director or officer of other AES affiliates, including as Chief Financial Officer of DPL and AES Ohio. Prior to that, Mr. Garavaglia held several other positions while at AES, including as the Director of Financial Planning & Analysis and Development & Transactions for AES Mexico, Central America and the Caribbean (“AES MCAC”), Senior Manager of Development & Transactions for AES MCAC, Investment Analysis and Risk Manager for AES Brazil, M&A Associate for AES, and Strategic Planning Specialist for AES Brazil. Mr. Garavaglia received a Bachelor’s degree in Electrical Engineering from University of Campinas (Unicamp) and a Master’s degree in Business from FGV Brazil, and is a CFA Charterholder.

Susan Harcourt, 41, has been a Director of IPALCO since November 2020. Ms. Harcourt has served as Vice President of Investor Relations at AES since March 2022. Previously, Ms. Harcourt held several positions with AES, including Chief of Staff to the CEO of AES from October 2018 to March 2022, Director, Mergers and Acquisitions from January 2012 through September 2018 and Project Manager, Business Development from July 2010 through December 2011. Ms. Harcourt is also a member of the Board of Directors of AES U.S. Investments and previously served as a Director of AES Brasil Energia S.A. and AES Brasil Operações S.A., formerly named AES Tietê. Ms. Harcourt brings extensive experience in business development and strategy to the Board. Ms. Harcourt holds a B.A. in Economics and International Studies from Yale University, a Master of Arts in Energy, Resources, and the Environment from The Johns Hopkins University – Paul H. Nitze School of Advance International Studies, and an M.B.A. in Finance from The Wharton School. She is also currently on the board of directors of Youth For Understanding USA.

Frédéric Lesage, 57 has been a Director of IPALCO since September 2017. Mr. Lesage is also a member of the Board of Directors of AES U.S. Investments. Mr. Lesage brings extensive experience in strategic planning, general management and post-merger integration to the Board. Mr. Lesage joined CDPQ in 2017 and is currently Managing Director, Infrastructure. From 2015 to 2017, Mr. Lesage was the Chief Executive Officer of FL Investments and Advisory Inc., assisting businesses with strategic and organizational matters, and, from 2007 to 2014, he held various positions within TAQA - ABU Dhabi National Energy Co., an international energy and water operator, including Chief Strategy Officer, Regional President and Managing Director, and Group Vice-President, and served on the company’s Executive Committee. Previously, Mr. Lesage served as management consultant and as lawyer. Mr. Lesage holds a Bachelor’s degree in Law from Université De Montréal and an M.B.A. from Richard Ivey School of Business at Western University.

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Letitia (Tish) Mendoza, 48, has served as a Director of IPALCO since February 2022. Ms. Mendoza has served as Executive Vice President and Chief Human Resources Officer of AES since February 2021. Prior to assuming her current position, Ms. Mendoza was Senior Vice President, Global Human Resources and Internal Communications and Chief Human Resources Officer from 2012, Vice President of Human Resources, Global Utilities from 2011 to 2012, Vice President of Global Compensation, Benefits and HRIS, including Executive Compensation, from 2008 to 2011, and acted in the same capacity as the Director of the function from 2006 to 2008. Ms. Mendoza serves as a director or officer of other AES affiliates, including as a Director of AES Ohio and Fluence Energy, Inc. and sits on AES’ employee compensation and benefits committees. Ms. Mendoza brings to the Board her extensive experience in human resource management and development and employee compensation. Prior to joining AES, Ms. Mendoza was Vice President of Human Resources for a product company in the Treasury Services division of JP Morgan Chase and Vice President of Human Resources and Compensation and Benefits at Vastera, Inc, a former technology and managed services company. Ms. Mendoza earned certificates in Leadership and Human Resource Management, and a bachelor’s degree in Business Administration and Human Resources.

Marc Michael, 50, has been a Director of IPALCO since April 2019. Mr. Michael has managed a broad range of disputes for AES since 2005. In his current role as VP & Chief Counsel, Global Dispute Resolution, of AES, Mr. Michael oversees material dispute resolution proceedings involving AES and its affiliates, including federal and state litigation, cross-border disputes, domestic and international commercial arbitration, and investment treaty arbitration. Mr. Michael also serves as a Director of AES U.S. Investments. Mr. Michael brings to the Board his legal and industry experience, including extensive experience in legal matters involving contractors and regulators. Prior to joining AES, Mr. Michael worked as a litigation associate at the law firm Winston & Strawn LLP from September 1998 to February 2005. Mr. Michael received a B.A. from The Catholic University of America and a J.D. from The Catholic University of America, Columbus School of Law.

Olivier Roy Durocher, 35, has been a Director of IPALCO since September 2022. Mr. Roy Durocher is also a member of the Board of Directors of AES U.S. Investments. Mr. Roy Durocher brings extensive experience in strategic planning and financial analysis to the Board. Mr. Roy Durocher has served as Director, Infrastructure Investments of CDPQ since February 2021 and previously served in various other positions in Infrastructure Investments since joining CDPQ in 2013, including as Senior Associate from November 2018 to February 2021, Associate from October 2015 to November 2018, and Analyst from August 2013 to October 2015. Mr. Roy Durocher holds Bachelor’s and Master’s degrees in Finance from HEC Montréal and is a CFA Charterholder. Mr. Roy Durocher also currently serves on the board of directors of Student Transportation of America.

Kenneth J. Zagzebski, 64, has been a Director of IPALCO and AES Indiana since March 2009 and has served as Chairman of the Boards of IPALCO and AES Indiana since August 2023. Mr. Zagzebski has served as President and Chief Executive Officer of IPALCO and Chief Executive Officer of AES Indiana since August 2023. Mr. Zagzebski also serves as Senior Vice President and President of the Utilities Strategic Business Unit of AES (as defined in “Executive Officers” below) and serves as a director or officer of other AES affiliates, including as a Director and the Chairman of the Boards of DPL, AES Ohio, and AES U.S. Investments, as President and Chief Executive Officer of DPL and AES U.S. Investments and as Chief Executive Officer of AES Ohio. Prior to rejoining the Utilities Strategic Business Unit as President in August 2023, Mr. Zagzebski served as Chief Operating Officer of AES Clean Energy since April 2022 and as Vice President, AES Southland Project Development, since August 2019. Prior to that, Mr. Zagzebski served as the Chairman of the Boards of IPALCO and AES Indiana from March 2018 to November 2020, President and Chief Executive Officer of IPALCO from April 2011 to March 2018, Interim President and Chief Executive Officer of AES Indiana from July 2015 to June 2016 and President and/or Chief Executive Officer of AES Indiana from April 2011 to March 2014. Mr. Zagzebski joined AES Indiana as Senior Vice President of Customer Operations in September 2007 and has held executive and other positions of increasing responsibility within AES. He brings to the Board more than 30 years of industry experience, including in strategic planning, diverse executive management and utilities field operations. Mr. Zagzebski has a Bachelor’s degree from the University of Wisconsin, Eau Claire, and an M.B.A. from the Carlson School of Management at the University of Minnesota. Mr. Zagzebski currently Chairs the Marian University Klipsch Educators College Board of Visitors and serves on the Executive Committee of the Greater Indianapolis Progress Committee.

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Executive Officers

Set forth below is certain information regarding each of our current executive officers as of April 15, 2024. IPALCO was acquired by AES in March 2001 and is currently a majority-owned subsidiary of AES U.S. Investments. AES Indiana is our primary operating subsidiary. AES utilities businesses, including IPALCO and AES Indiana, their Ohio sister companies, DPL and its primary operating subsidiary, AES Ohio (the “AES US Utilities”), and other generation companies in the United States (“AES US Generation”, and, together with the AES US Utilities, for purposes of this report, the “US and Utilities”) are part of AES’ strategic business units; however, the US and Utilities is not a legal entity. AES U.S. Services, LLC (the “Service Company”), another subsidiary of AES, is a service company established in late 2013 to provide operational and corporate services on behalf of companies that are part of the US and Utilities, including among other companies, IPALCO and AES Indiana. As a result of this structure, IPALCO and AES Indiana do not directly employ all of the executives responsible for the management of our business.

Once elected, officers hold office until a successor is duly elected and qualified or until earlier death, resignation or removal from office. There are no family relationships among our Directors and Executive Officers.

Name	Age		Position
Kenneth J. Zagzebski		64	President and Chief Executive Officer and Chairman of the Board, IPALCO Chief Executive Officer and Chairman of the Board, AES Indiana
Gustavo Garavaglia		38	Vice President and Chief Financial Officer
John Bigalbal		57	Vice President and Chief Operating Officer, Generation, AES Indiana
Jeremy Buchanan		39	Vice President, Human Resources
Brandi Davis-Handy		45	President, AES Indiana
Brian Hylander		50	Vice President, General Counsel and Secretary

Mr. Zagzebski and Mr. Garavaglia also serve on the Board of IPALCO, and their biographies are presented under “—Directors” above.

John Bigalbal, 57, has served as Vice President and Chief Operating Officer, Generation, of AES Indiana since February 2024, and has been managing generation for the US and Utilities since October 2020. Mr. Bigalbal also serves as a director or officer of other AES affiliates. Mr. Bigalbal has over 30 years of experience in the energy industry and prior to his current roles served as Managing Director of Fuels for AES from October 2008 to October 2020 and also led numerous significant commercial transactions for AES during that time. Mr. Bigalbal received an Associates Degree in Electrical Engineering from Thames Valley State Technical College.

Jeremy Buchanan, 39, has served as Vice President, Human Resources for the US and Utilities since April 2020 and previously served as the Director of Human Resources for the US and Utilities from June 2015 to April 2020. In addition, Mr. Buchanan has served as a Director of AES Indiana since May 2022. Prior to joining AES, Mr. Buchanan worked in Labor Relations for Norfolk Southern Corporation from September 2011 to June 2015, serving as Assistant Director from June 2014 to June 2015, and as Human Resources Manager for Georgia-Pacific LLC from March 2009 to September 2011. Mr. Buchanan received a B.S. in Marketing and a B.S. in Human Resources Management from Wright State University and a Masters of Professional Studies in Human Resources and Employment Relations from Penn State University. Mr. Buchanan serves on the board of directors for United Way of Central Indiana.

Brandi Davis-Handy, 45, has served as President of AES Indiana since February 2024 and previously served as Chief Customer Officer for the AES US Utilities, including AES Indiana and AES Ohio, from July 2022 to February 2024. Ms. Davis-Handy has also served as a Director of AES Indiana since June 2021. Previously, Ms. Davis-Handy served as Chief Public Relations Officer for the AES US Utilities since rejoining AES in February 2021. Prior to that, Ms. Davis- Handy served as Executive Vice President and Chief Marketing and Communications Officer for Project Lead the Way from August 2019 through January 2021 and as Vice President, Enterprise Communications and Events of OneAmerica from June 2018 to July 2019. Ms. Davis-Handy initially joined AES in 2013, serving as Director, External Communications for AES Indiana from February 2013 to June 2016 and as Communications Leader for the AES US Utilities from June 2016 to May 2018. She also previously served as Communications Manager for the Great Lakes Division of the American Cancer Society from June 2010 to February 2013. Ms. Davis-Handy received a B.A. from Hampton University. She also currently serves on the boards of directors of Indiana Energy Association, Indy Chamber, 500 Festival, Urban League of Indianapolis, Big Brothers Big Sisters of Central Indiana, and Indiana Sports Corporation.

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Brian Hylander, 50, has served as Vice President, General Counsel and Secretary of IPALCO and AES Indiana since June 2022. Mr. Hylander also serves as Vice President, General Counsel and Secretary of the US and Utilities, including AES Ohio and DPL, and serves as an officer of other AES affiliates, including as Vice President, General Counsel and Secretary of AES U.S. Investments. Prior to assuming his current position, Mr. Hylander served as Assistant General Counsel and Secretary for IPALCO, AES Indiana and the US and Utilities, including AES Ohio and DPL, from April 2015 through May 2022, and also served as senior counsel at AES Ohio for more than four years. Mr. Hylander also previously served for more than seven years as a corporate attorney at the Taft Stettinius & Hollister LLP law firm. Mr. Hylander received a B.A. from Providence College and a J.D. from University of Michigan. Mr. Hylander currently serves on the boards of trustees of the regional PBS organizations ThinkTV and Cincinnati Educational Television

Corporate Governance

Code of Ethics

The AES Code of Conduct (“Code of Conduct”), adopted by the AES Board of Directors, governs the actions of AES employees, including employees of its subsidiaries and affiliates, including the CEO, CFO and Controller of AES Indiana and IPALCO, and the directors of IPALCO. The Ethics and Compliance Department of AES provides training, information, and certification programs for employees of AES and its subsidiaries (including AES Indiana and IPALCO) related to the Code of Conduct. The Ethics and Compliance Department also has programs in place to prevent and detect criminal conduct, promote an organizational culture that encourages ethical behavior and a commitment to compliance with the law, and to monitor and enforce AES policies on corruption, bribery, money laundering and associations with terrorist groups. The Code of Conduct is located in its entirety on the AES website (https://www.aes.com/ethics-compliance). Any person may obtain a copy of the Code of Conduct without charge by making a written request to: Corporate Secretary, IPALCO Enterprises, Inc., One Monument Circle, Indianapolis, Indiana 46204. If any amendments to, or waivers from, the Code of Conduct are made, in each case relating to the CEO, CFO and Controller of AES Indiana and IPALCO, AES will disclose such amendments or waivers on its website (www.aes.com). Note, the information contained on or accessible through the AES website is not incorporated by reference into this prospectus.

Corporate Governance

The Board has not established any committees, including an audit committee, a compensation committee or a nominating committee, or any committee performing similar functions. The functions of those committees are undertaken by the Board. The Board may designate from among its members an executive committee and one or more other committees in the future.

IPALCO’s securities are not quoted on a securities exchange. IPALCO is not required by law, rule, or regulation to have a majority or any portion of the Board be independent. IPALCO is also not required by law, rule, or regulation to establish or maintain an audit committee or other Board committee and thus we do not have an “audit committee financial expert” as defined under applicable SEC rules.

Nomination of Directors

As of April 15, 2024, IPALCO had not effected any material changes to the procedures by which shareholders may recommend nominees to the Board. IPALCO’s Third Amended and Restated Articles of Incorporation and Amended and Restated By-Laws do not provide formal procedures for shareholders to recommend nominees to the Board. Except as described below, the Board has determined that it is in the best position to evaluate IPALCO’s requirements as well as the qualifications of each candidate when the Board considers a nominee for a position on the Board.

AES U.S. Investments, IPALCO and CDPQ are parties to a Shareholders’ Agreement dated February 11, 2015 (the “Shareholders’ Agreement”). The Shareholders’ Agreement provides AES U.S. Investments the right to nominate nine directors of the IPALCO Board and CDPQ the right to nominate two directors to the IPALCO Board. See Exhibit 10.8.

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Compensation Discussion and Analysis

The purpose of this compensation discussion and analysis (this “CD&A”) is to provide information about the material elements of compensation that were paid or awarded to, or earned by, our named executive officers (“NEOs”) in 2023. The compensation paid to our NEOs in 2023 is set forth in the Summary Compensation Table (2023, 2022 and 2021) (the “Summary Compensation Table”) below. Our NEOs for 2023 are:

● Kenneth J. Zagzebski, President and Chief Executive Officer and Chairman of the Board

● Kristina Lund, Former President and Chief Executive Officer and Chairman of the Board (served until July 21, 2023)

● Ahmed Pasha, Former Vice President and Chief Financial Officer (served in this role all of 2023 until January 1, 2024) and Acting President and Chief Executive Officer (from July 21, 2023 to August 11, 2023)

● Brandi Davis-Handy, President, AES Indiana (since February 28, 2024) and Chief Customer Officer (served in this role all of 2023 and until February 28, 2024)

● Brian Hylander, Vice President, General Counsel and Secretary

● Jeremy Buchanan, Vice President, Human Resources

In this CD&A, explanations of how non-GAAP measures are calculated from the audited financial statements are included under the heading “Non-GAAP Measures” or in the description of the applicable program in this prospectus.

Background

AES Family of Companies

In order to better understand our compensation programs for our NEOs, we think that it is helpful to describe how the management of IPALCO is operated within the AES family of companies. IPALCO was acquired by AES in March 2001, is a majority-owned subsidiary of AES U.S. Investments, and has a minority interest holder, CDPQ, as of February 11, 2015. AES Indiana is our primary operating subsidiary. Most of the key members of our management team are employed by other AES companies and perform roles for both IPALCO and other AES entities.

AES manages its business through strategic business units. The AES US Utilities, including IPALCO and AES Indiana, and AES US Generation are part of these strategic business units; however, the US and Utilities is not a legal entity. AES also has an indirectly wholly-owned subsidiary, the Service Company, which was established in late 2013. The Service Company provides services, including operations, accounting, legal, human resources, information technology and other corporate services on behalf of companies that are part of the US and Utilities, including, among other companies, IPALCO and AES Indiana. As a result of this structure, IPALCO and AES Indiana do not directly employ all of the executives responsible for the management of our business. In 2023, our NEOs were all executive officers of one or more of IPALCO, AES Indiana and the Service Company.

The Service Company allocates the costs for services provided based on cost drivers designed to result in fair and equitable allocations pursuant to a Cost Alignment and Allocation Manual (the “CAAM”). As a result, the costs associated with our executive compensation for those officers performing work for other entities are also allocated pursuant to the terms of the CAAM, based on the amount of time that each executive officer devotes to our business as described under “Certain Relationships, Related Transactions and Director Independence.” The executive compensation reported in this prospectus reflects the entire compensation paid or awarded to, or earned by, each NEO for their services on behalf of one or more of IPALCO, AES Indiana, the Service Company, AES and other AES affiliated entities and not just the portion of such compensation that is allocated to IPALCO and AES Indiana.

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Our Executive Compensation Philosophy and Objectives

Our compensation philosophy is consistent with AES’ compensation philosophy, which emphasizes pay-for-performance. Our compensation philosophy is to provide compensation opportunities to each of our NEOs that are commensurate with his or her position, experience, and scope of responsibilities, to furnish incentives sufficient for each NEO to meet and exceed short-term and long-term corporate objectives and to provide executive compensation and incentives that will attract, motivate, and retain a highly skilled management team.

Consistent with this philosophy and our goal of aligning our executives’ compensation with Company performance, the key features of our executive compensation program include the following:

● Our compensation program allocates a significant portion of each applicable NEO’s total compensation to short- and long-term performance goals. As such, payouts are dependent upon the strategic, financial, and operational performance of AES and the US and Utilities, which includes IPALCO and AES Indiana, and the performance of AES’ stock price;

● Our compensation program is continually reviewed to confirm that it meets our objectives and executive compensation philosophy and remains competitive; and

● We generally do not provide perquisites to our NEOs, with the exception of relocation-related benefits from time to time.

In order to meet these objectives, our total compensation structure includes a mix of short-term compensation, in the form of base salaries and annual cash bonuses, and long-term compensation, in the form of AES equity-based and cash-based performance awards.

Our Compensation Process

The Chief Executive Officer of AES (the “AES CEO”) and the Chief Human Resources Officer of AES (the “AES CHRO”, and together with the AES CEO, the “Executive Compensation Review Team”) have the responsibility of reviewing and administering compensation for the officers of the Service Company, IPALCO, and AES Indiana, including our NEOs. The Executive Compensation Review Team, with assistance from the US and Utilities human resources team, determines the appropriate pay grade for our NEOs at the date of hire based upon each individual’s position, responsibilities, skills and experience, and reassesses each NEO’s position within the applicable pay grade at the end of each year.

The pay grades comprising our compensation framework are established by the AES human resources team and include specific base salary ranges and short-term bonus and long-term compensation targets for each pay grade. The AES human resources team uses survey data from Willis Towers Watson and other sources in evaluating the overall pay structure at a high level. The structure is compared annually to market data from various sources, including Willis Towers Watson’s survey data, to assess the external competitiveness of the base salary ranges and incentive targets for the pay grades. During our performance review cycle, the Executive Compensation Review Team measures the specific amount and resulting incentive compensation for each of our NEOs based on (i) the operational and financial performance of the US and Utilities and AES and (ii) the NEO’s target opportunity for his or her applicable pay grade.

Awards of short-term compensation are made in the form of annual cash bonuses to our NEOs under the AES Performance Incentive Plan (the “PI Plan”) and are determined by the Executive Compensation Review Team in the first quarter. Awards of long-term compensation are made to our NEOs under the AES 2003 Long Term Compensation Plan, as amended and restated (the “LTC Plan”) and are determined by the Board of Directors of AES based upon the recommendations of the Executive Compensation Review Team made in the last quarter of each year as described below.

The use and weight of cash versus non-cash, fixed versus variable, and short- versus long-term components of executive compensation is generally dictated by the applicable pay grade for each NEO. As we are not subject to the federal proxy rules, we are not required to hold a shareholder advisory vote on our executive compensation, or a “Say-on-Pay” vote, or the related “Say-on-Frequency” vote.

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Elements of Compensation

The fundamental elements of our compensation program are:

● base salary;

● performance-based, short-term annual cash bonuses under the PI Plan;

● cash-based incentive awards granted under the LTC Plan;

● equity incentive awards granted under the LTC Plan in AES equity, for which there is a public market; and

● other broad-based benefits, such as retirement and health and welfare benefits.

The pay grades comprising our compensation framework provide allocations of cash versus equity compensation and short- and long-term compensation. The Executive Compensation Review Team sets each individual element of total compensation within the parameters of the pay grade applicable to each particular NEO, as set forth below.

2023 Compensation Determinations

Base Salary

Base salary represents the “fixed” component of our executive compensation program for our NEOs. We provide our NEOs with base salaries in order to provide fixed cash compensation that is competitive and reflects experience, responsibility, and expertise. Base salaries are reviewed annually in the last quarter of each year and are adjusted as appropriate within the base salary ranges of the applicable pay grade. Base salary is also reviewed for an executive officer if there is a promotion or a newly appointed executive officer. Internal company salary guidance regarding annual base pay adjustments is also taken into consideration, and adjustments to base salaries are made when needed to reflect individual performance and retention considerations, and to address internal equity. Please see the “Salary” column of the Summary Compensation Table below for the base salary amounts paid to our NEOs for the years indicated.

2023 Performance Incentive Plan Payouts

In addition to base salaries, in 2023 we provided performance-based, annual cash bonuses under the PI Plan. Each pay grade has a corresponding PI Plan target opportunity, which is assessed annually. Each NEO’s opportunity corresponds to the opportunity applicable to his or her pay grade. These awards are paid based on the achievement of AES and US and Utilities measures in strategic performance categories described in the tables below, which were established in early 2023. The PI Plan is structured in a manner that provides our NEOs with a direct incentive to achieve such objectives. Payout formulas under the PI Plan for each of our NEOs are based on the business functions and responsibilities for the NEO within the organization. For Mr. Zagzebski, the award is based on the achievement of the AES Corporate goals. For Mr. Buchanan and Mr. Hylander, the award is 25% based on the achievement of the AES Corporate goals and 75% based on the achievement of the US and Utilities goals with equal weight given to: (i) the achievement of the AES US Utilities goals, which includes IPALCO and AES Indiana and their Ohio sister companies, DPL and AES Ohio, and (ii) the achievement of AES US Generation goals, which includes other AES generation companies in the US. For Ms. Davis-Handy, the award is based 25% on the achievement of AES Corporate goals and 75% on the achievement of the AES US Utilities goals. Ms. Lund and Mr. Pasha forfeited the right to receive a 2023 PI Plan payout when they resigned from AES. Ms. Lund would have been eligible for an award based 50% on the achievement of AES Corporate goals and 50% on the achievement of AES US Utilities goals, and Mr. Pasha would have been eligible for an award based 25% on the achievement of AES Corporate goals and 75% on the achievement of US and Utilities goals with equal weight given to AES US Utilities goals and AES US Generation goals.

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In 2023, payments under the PI Plan were determined based on the AES and the US and Utilities 2023 performance measures as described in the tables below. The AES Corporate performance measures were approved by the AES Compensation Committee of its Board of Directors (the “AES Compensation Committee”). Performance measures for the US and Utilities were based upon the Executive Compensation Review Team’s and US and Utilities leadership’s business goals for AES US Generation and the AES US Utilities, including IPALCO and AES Indiana, for 2023. The Executive Compensation Review Team approved performance measures and objectives across all categories that it considered to be challenging, but achievable, with US and Utilities leadership and CDPQ providing input with regard to objectives applicable to IPALCO and AES Indiana. Targets for the 2023 financial measures for AES and the US and Utilities were based on the 2023 financial budget as well as strategic objectives. Individual awards are paid out at 0-200% of the target applicable to each pay grade depending on scores achieved relative to the performance measures.

AES Corporate 2023 Actual Results: The AES Compensation Committee determined the 2023 AES corporate performance score based on actual results of the pre-established performance measures as shown below. As a result, the AES Corporate performance score for 2023 was determined to be 127%, as follows:

Strategic Goal & Weight		Measure	2023 Target	2023 Result	Payout %
Safety	5%	Serious Safety Incidents	No Incidents	1 Incident	0%
	5%	Non-Injury SIP Rate	0.95	1.932	124%
		Safety Meeting	95.0%	98.3%
		Safety Walks	25,170	42,510
Financials (2)	55%	Adjusted Earnings Per Share (“EPS”) – 25%	$1.70	$1.76	135%
		Adjusted EBITDA – 15%	$2,769	$2,812	115%
		Parent Free Cash Flow – 15%	$975M	$1,003M	129%
Green Growth (3)	35%	Growth – 12.5% Commercial Operations Date (“COD”) – 12.5%	5,000 MW 3,476 MW	5,570 MWs 3,460 MWs	146% 99%
New Business Models		New Business or Products – 10%	Qualitative assessment by the AES Compensation Committee; review of financial and strategic metrics to determine achievement	Exceeded Expectations	200%(4)

AES Corporate Overall Performance Score – 127%⁽¹⁾

(1) The AES Corporate Performance score is rounded to the nearest whole number.

(2) Assuming the threshold financial requirement for each non-GAAP financial measure is met, the score ranges from 50% to 200%: 50% score corresponds to actual results at 90% of the target goal, and a 200% score corresponds to actual results at 110% of the target goal. See “Non-GAAP Measures” below for reconciliations of Adjusted EPS, Adjusted EBITDA and Parent Free Cash Flow to the most directly comparable GAAP measures, as applicable.

(3) Assuming the threshold requirement for the Green Growth and COD metrics are met, the score ranges from 50% to 200%: 50% score corresponds to actual results at 80% of the target goal, and a 200% score corresponds to actual results at 120% of the target goal.

(4) The 200% award in this category is based on the significant achievements AES made towards progressing Green Hydrogen as a business line. The following paragraph includes additional details.

The AES Compensation Committee approved a performance assessment of 200% for the New Business Models metric to recognize AES’ new business achievements and significant advancements. Some key achievements include:

● AES was part of a group that was awarded two of the seven Regional Clean Hydrogen Hubs by the US Department of Energy (“DOE”).

● AES was part of a group that was awarded the Alliance for Renewable Clean Energy System Hub in California, and the other group was awarded the HyVelocity Hub in the Gulf Coast of Texas and Louisiana, both of which were allocated up to $1.2 billion in DOE funding.

● AES’s green hydrogen projects have been designed to meet even the most stringent (hourly) matching requirements for renewable power.

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● Among the first in the industry to use transferability of tax credits for renewable energy projects, as authorized under the Inflation Reduction Act.

● Motor, a company majority-owned and incubated by AES that partners with utilities to promote electric vehicle adoption, raised $7M of external funding and secured its first non-AES utility customer in Green Mountain Power.

● AES US Utilities 2023 Performance: The Executive Compensation Review Team determined the 2023 AES US Utilities performance score based on actual results of the pre-established performance measures for the AES US Utilities as shown below. As a result, the AES US Utilities performance score for 2023 was determined to be 95%, as follows:

Strategic Goal & Weight		Measure	2023 Target	2023 Result	Payout %
Safety	5%	Serious Safety Incidents	No Incidents	No Incidents	100%
	5%	Non-Injury SIP Rate	1.200	1.603	112%
		Safety Meeting	95.0%	99.3%
		Safety Walks	3,938	6,164
Financials(2)	50%	Adjusted Pre-Tax Contribution ($M) – 20%	$141.8M	$111.2M	73%
		Subsidiary Distributions ($M) – 20%	$114.9M	$73.2M	55%
		Adjusted EBITDA ($M) – 10%	$536.9M	$534.9M	100%
Green Growth & Customer Centricity	40%	US Utility Regulatory  – 5% Continued Execution of US Utility Investment Initiatives – 5% AESI Fleet Transition – 5% Hardy Hills Solar Project – 5%	Utility regulatory orders as planned Planned investment amounts Projects and filings on track Achieve partial placed in service	136% Achieved Achieved Exceeded	136% 100% 100% 200%
Operations(3)		Operational KPIs – 5%	100% of Operational KPI targets	112.9%	113%
		Customer Experience – 5%	2023 Customer Satisfaction metric	98%	98%
Energy Star & Local Initiatives		Global Energy Star Program – 5%	$325M in global savings	$402.0M	124%
		Review, develop, and implement programs that promote diversity, equity and inclusion – 5%	Execute or launch planned programs	Achieved	100%

AES US Utilities Performance Score – 95%⁽¹⁾

(1) The AES US Utilities Performance score is rounded to the nearest whole number.

(2) Assuming the threshold financial requirement for each measure is met, the score ranges from 50% to 200%: 50% score corresponds to actual results at 60% of the target goal, and a 200% score corresponds to actual results at 140% of the target goal. Descriptions of how Adjusted Pre-Tax Contribution, Subsidiary Distributions, and Adjusted EBITDA are calculated from the audited financial statements are included in “Non-GAAP Measures” below.

(3) KPIs and weights for generation businesses are as follows: Commercial Availability 30%, Equivalent Forced Outage Factor 40%, Equivalent Availability Factor 20%, and Heat Rate 10%. KPIs and weights for distribution businesses are as follows: System Average Interruption Duration Index 50%, System Average Interruption Frequency Index 30%, Customer Satisfaction Index 10%, and Days Sales Outstanding 10%.

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AES US Generation 2023 Performance: The Executive Compensation Review Team determined the 2023 AES US Generation performance score based on actual results of the pre-established performance measures for AES US Generation as shown below. As a result, the AES US Generation performance score for 2023 was determined to be 104%, as follows:

Strategic Goal & Weight		Measure	2023 Target	2023 Result	Payout %
Safety	5%	Serious Safety Incidents	No Incidents	No Incidents	100%
	5%	Non-Injury SIP Rate	0.935	3.381	122%
		Safety Meeting	95.0%	100.0%
		Safety Walks	539	717
Financials(2)	50%	Adjusted Pre-Tax Contribution ($M) – 20%	$373.2M	$398.2M	117%
		Subsidiary Distributions ($M) – 20%	$292.9M	$256.0M	84%
		Adjusted EBITDA ($M) – 10%	$459.3M	$486.6M	115%
Operations(3)	40%	Operational KPIs – 15%	100% of Operational KPI targets	71.7%	72%
Energy Star & Local Initiatives		Global Energy Star Program – 5%	$325M in global savings	$402.0M	124%
		Southland legacy units – 5%	PTC contribution amounts of Alamitos and Huntington Beach units	Exceeded	175%
		Execute hedging strategy – 5%	Obtain incremental margin amounts	Achieved	100%
		Hawaii plant demolition – 5%	Obtain permits and commence demolition	Achieved	100%
		Warrior Run plant – 5%	Develop transition plan	Exceeded	100%

AES US Generation Overall Performance Score – 104%⁽¹⁾

(1) The AES US Generation Performance score is rounded to the nearest whole number.

(2) Assuming the threshold financial requirement for each measure is met, the score ranges from 50% to 200%: 50% score corresponds to actual results at 60% of the target goal, and a 200% score corresponds to actual results at 140% of the target goal. Description of how Adjusted Pre-Tax Contribution, Subsidiary Distributions, and Adjusted EBITDA are calculated from the audited financial statements are included in “Non-GAAP Measures” below.

(3) KPIs and weights for each generation business are as follows: Warrior Run: Commercial Availability 35%, Equivalent Forced Outage Factor 20%, Equivalent Availability Factor 35%, and Heat Rate 10%. Southland: Commercial Availability 70%, Equivalent Forced Outage Factor 30%.

As described above, Mr. Buchanan’s, and Mr. Hylander’s 2023 bonuses were earned based on the performance of AES Corporate (25%) and the US and Utilities (75%) (equally weighted between the AES US Utilities and AES US Generation). Ms. Davis-Handy’s 2023 bonus was earned based on the performance of AES Corporate (25%) and the AES US Utilities (75%). Mr. Zagzebski’s 2023 bonus was earned based on the performance of AES Corporate (100%).

The following table sets forth the amounts of the annual incentive cash awards under the PI Plan earned by our NEOs in 2023, which were paid in early 2024.

					Actual 2023 Annual Incentive Cash Award
NEO	2023 Target Annual Incentive ($)		2023 Target Annual Incentive (% of base salary)		Dollar Value ($)		% of Target Annual Incentive
Kenneth J. Zagzebski	$	417,728	85	%	$	530,514		127	%
Kristina Lund*	$	346,400	80	%		—		—
Ahmed Pasha*	$	253,694	60	%		—		—
Brandi Davis-Handy	$	160,000	50	%	$	164,800		103	%
Brian Hylander	$	133,560	45	%	$	142,909		107	%
Jeremy Buchanan	$	119,250	45	%	$	127,598		107	%

* As a result of Ms. Lund’s and Mr. Pasha’s resignation from AES, they each forfeited their right to receive a 2023 PI Plan Payout.

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2023 Discretionary Cash Bonuses

In connection with the performance of the US and Utilities and the individual contributions of the NEOs in 2023, the Executive Compensation Review Team determined it was appropriate to grant certain of the NEOs discretionary cash bonuses in the amounts as set forth in the table below. These discretionary cash bonuses were paid to the NEOs in the first quarter of 2024.

NEO	2023 Discretionary Cash Bonus Amount ($)
Kenneth J. Zagzebski	$	132,629
Brandi Davis-Handy	$	24,720
Jeremy Buchanan	$	25,520

Long Term Compensation Elements

AES grants a mix of cash- and equity-based awards under the LTC Plan. These awards help the Company to attract and retain key individuals who are critical to the success of our business and align the interests of our NEOs with those of AES’ stockholders over the long term. Grants to our NEOs under the LTC Plan, whether in cash or stock, vest ratably over a three-year period or based on a cumulative three-year performance period and are determined based on a percentage of the individual’s base salary. The mix of awards under the LTC Plan for each of our NEOs is based on the business functions and responsibilities for the NEO within the organization. In the first quarter of 2023, our NEOs other than Ms. Lund received awards as follows: 50% in the form of cash-settled Performance Units (“PUs”) and 50% in the form of AES stock-settled Restricted Stock Units (“RSUs”). Ms. Lund received awards as follows: 50% in the form of cash-settled Performance Cash Units (“PCUs”), 30% in the form of AES stock-settled Performance Stock Units (“PSUs”), and 20% in the form of AES stock-settled RSUs. In connection with Ms. Lund’s and Mr. Pasha’s resignations from AES, they each forfeited their respective 2023 LTC Plan awards. For a description of 2023 PCU, PSU and RSU awards granted to Ms. Lund that she forfeited upon her resignation from AES, see AES’ proxy statement filed on March 14, 2024.

Performance Units (PUs)

PUs represent the right to receive a cash-based payment subject to performance- and service-based vesting conditions. PUs granted in 2023 are eligible to vest subject to AES’ three-year cumulative Parent Free Cash Flow performance. Parent Free Cash Flow is a strategically important non-GAAP financial metric to AES as it reflects the ability of AES’ businesses to generate cash for AES’ investors that can be either reinvested in the business or paid to investors through dividends, and additionally is a key metric for ratings agencies. A description of how Parent Free Cash Flow is calculated from AES’ audited financial statements is described in “Non-GAAP Measures” below.

The Parent Free Cash Flow target is set for the three-year performance period and is subject to pre-defined, objective adjustments during the three-year performance period based on changes to AES’ portfolio, such as an asset divestiture or sale of a portion of equity in a subsidiary.

The value of each PU is equal to $1.00, and the number of PUs that vest depends upon the level of Parent Free Cash Flow achieved over the three-year measurement period. If a threshold level of Parent Free Cash Flow is achieved, a percentage of the PUs vest and are settled in cash in the calendar year that immediately follows the end of the performance period.

The following table illustrates the vesting percentage at each Parent Free Cash Flow level for targets set for the 2023-2025 performance period:

Performance Level	Vesting Percentage
Below 90% of Performance Target		0	%
Equal to 90% of Performance Target		50	%
Equal to 100% of Performance Target		100	%
Equal to or Greater than 110% of Performance Target		200	%

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Between the Parent Free Cash Flow levels listed in the above table, straight-line interpolation is used to determine the vesting percentage for the award. The ability to earn PUs is also generally subject to the continued employment of the NEO. The AES Compensation Committee approved a Parent Free Cash Flow target for the 2023 PUs that is believed by the AES Compensation Committee to be challenging, but achievable and requires growth over the prior year’s goals.

Restricted Stock Units (RSUs)

RSUs represent the right to receive a single share of AES Common Stock subject to service-based vesting conditions. AES grants RSUs to assist in retaining executives and also to increase their ownership of AES Common Stock, which further aligns executives’ interests with those of AES stockholders. RSUs generally vest based on continued service with AES and its subsidiaries in three equal installments, beginning on the first anniversary of the grant date.

2023 Long Term Compensation Grants

As in previous years, the allocation of long-term compensation components granted in 2023 was based on a review of market practice conducted by AES and is aligned with the objective of fostering the long-term corporate performance of AES, as our parent company, and rewarding individual performance.

The following table sets forth the aggregate target grant value for the 2023 LTC Plan awards made to our NEOs.

	February 2023 Long-Term Compensation Aggregate Target Grant Value
Name	As % of Base Salary(1)			Dollar Amount
Kenneth J. Zagzebski		100	%	$	463,619
Kristina Lund(2)		152	%	$	636,527
Ahmed Pasha(2)		80	%	$	319,123
Brandi Davis-Handy		50	%	$	129,996
Brian Hylander		50	%	$	140,010
Jeremy Buchanan		50	%	$	124,990

(1) Based on salary as of December 31, 2022.

(2) In connection with Ms. Lund’s and Mr. Pasha’s resignations from AES, they each forfeited their respective 2023 LTC Plan awards.

As discussed under “Our Compensation Process” above, grant values are generally guided by each NEO’s applicable AES pay grade (and, in the case of the RSUs, are rounded down to the nearest whole share at the time of grant). Further detail on all long-term compensation grants to our NEOs can be found in the Summary Compensation Table (2023, 2022, and 2021) and the Grants of Plan-Based Awards (2023) Table in this Amendment. For Ms. Lund, the value in the table above differs from the Stock Awards column in the Summary Compensation Table (2023, 2022, and 2021) because the PCUs contain a market condition which results in a fair market value, for financial accounting purposes, that differs from the $1 per unit value the Company uses to determine the grant.

Prior Year PUs Vesting in 2023

All of the NEOs, with the exception of Mr. Pasha (who was awarded a different mix of awards under the LTC Plan in 2021), received a grant of PUs in February 2021 for the January 1, 2021 through December 31, 2023 performance period (the “2021-2023 PUs”). For the 2021-2023 PUs, performance was based on AES’ cumulative Parent Free Cash Flow performance during the 2021-2023 period. See “Non-GAAP Measures” for a reconciliation of Parent Free Cash Flow to the most directly comparable GAAP measure.

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The 2021-2023 PUs paid out at 153.68% of target based on AES’ actual cumulative Parent Free Cash Flow results of $2,748M during the three-year performance period, which was 105.37% of the target cumulative Parent Free Cash Flow. As described above for the 2023 PUs and as previously disclosed, the performance scale for these awards was 100% vesting for performance equal to 100% of target, 50% vesting for performance equal to 90% of target, and 200% vesting for performance equal to or greater than 110% of target. The actual performance payout level is derived using straight-line interpolation: for every one percentage point performance is above the target goal, the payout is increased by approximately ten percentage points. The payouts for these awards for each NEO are shown in the following table:

NEO	Target Number of Performance Units		% of Target Value Based on Parent Free Cash Flow			Final Vested Value
Kenneth J. Zagzebski		222,106		153.68	%	$	341,333
Kristina Lund		166,256		—			—
Ahmed Pasha		—		—			—
Brandi Davis-Handy		44,000		153.68	%	$	67,619
Brian Hylander		43,184		153.68	%	$	66,365
Jeremy Buchanan		32,552		153.68	%	$	50,026

* In connection with her resignation from AES, Ms. Lund forfeited the entirety of her 2021-2023 PU awards.

Further details regarding the 2021-2023 PU payouts can be found in the Summary Compensation Table (2023, 2022, and 2021) in this Amendment.

Other Relevant Compensation Elements and Policies

Perquisites

We generally do not provide any perquisites to our NEOs, with the exception of relocation-related benefits from time to time.

Retirement and Other Broad-Based Employee Benefits

Our NEOs, as well as our other employees, are eligible for the following benefits: participation in a defined contribution (401(k)) plan, group health insurance (including medical, dental, and vision), long- and short-term disability insurance, basic life insurance and paid time off. Mr. Hylander previously participated in The Dayton Power and Light Company Retirement Income Plan (the “DP&L Retirement Income Plan”). Our NEOs are eligible to participate in the AES Restoration Supplemental Retirement Plan (the “RSRP”), a nonqualified deferred compensation plan, which is intended to restore benefits that are limited under our broad-based retirement plans due to statutory limits imposed by the United States Internal Revenue Code (the “Code”). The RSRP’s objective is consistent with our philosophy to provide competitive levels of retirement benefits and to retain talented executives. The RSRP does not contain any enhanced or special benefit formulas for our NEOs. Contributions to the RSRP made in 2023 are included in the All Other Compensation column of the Summary Compensation Table (2023, 2022 and 2021) in this prospectus. Additional information regarding the RSRP is contained in the “Narrative Disclosure Relating to the Non-Qualified Deferred Compensation Table” in this prospectus.

Severance and Change in Control Arrangements

AES maintains certain severance and change in control arrangements, including The AES Corporation Amended and Restated Severance Plan (the “Severance Plan”) and change-in-control provisions in the long-term compensation award agreements. Upon a change-in-control of AES, the unvested portion of all outstanding awards will vest only upon a double-trigger (at target performance levels for performance awards). The double-trigger only allows for vesting if a qualifying termination occurs in connection with the change-in-control. All unvested, outstanding awards include a double-trigger vesting provision. In addition, all NEOs are entitled to payments and benefits under the Severance Plan, in the event of qualifying terminations of employment, both related and unrelated to a change in control, as provided in the Benefits Schedule included therein. Finally, upon a termination of service (other than by reason of death) prior to reaching retirement eligibility, or in the event of a change-in-control, participants’ account balances in the RSRP (described in the Nonqualified Deferred Compensation (2023) Table below) would be paid in a lump sum. Please see “Potential Payments Upon Termination or Change in Control (2023)” below for a more detailed summary of these payments and benefits.

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Employment Agreements and Other Arrangements

Our NEOs do not have any employment agreements or other arrangements, except as disclosed herein or in “Potential Payments Upon Termination or Change in Control (2023).”

Prohibition Against Hedging and Pledging

AES’ Securities Trading Policy prohibits AES’ and its subsidiaries’ employees (including officers) and directors from engaging in hedging transactions with respect to AES’ equity securities including, without limitation, the purchase of financial instruments (including prepaid variable forward contracts, equity swaps, collars, and exchange funds), or otherwise engaging in transactions, that hedge or speculate, or are designed to hedge or speculate, on any change in the market value of AES’ equity securities. AES additionally prohibits AES’ and its subsidiaries’ employees (including officers) and directors from pledging AES securities in any circumstance, including by purchasing AES securities on margin or by holding AES securities in a margin account.

Non-GAAP Measures

In this CD&A, we reference certain non-GAAP measures, including Adjusted EPS, Adjusted Pre-Tax Contribution (“Adjusted PTC”), Subsidiary Distributions, and Parent Free Cash Flow. These measures are described below.

Adjusted Earnings Per Share (Adjusted EPS)

AES defines Adjusted EPS as diluted earnings per share from continuing operations excluding gains or losses of both consolidated entities and entities accounted for under the equity method due to (a) unrealized gains or losses related to derivative transactions and equity securities; (b) unrealized foreign currency gains or losses; (c) gains, losses, benefits and costs associated with dispositions and acquisitions of business interests, including early plant closures, the tax impact from the repatriation of sales proceeds, and gains and losses recognized at commencement of sales-type leases; (d) losses due to impairments; (e) gains, losses and costs due to the early retirement of debt; and (f) net gains at Angamos, one of AES’ businesses in its Energy Infrastructure strategic business unit (“SBU”), associated with the early contract terminations with Minera Escondida and Minera Spence.

The GAAP measure most comparable to Adjusted EPS is diluted earnings per share from continuing operations. AES believes that Adjusted EPS better reflects the underlying business performance of the company and is considered in AES’ internal evaluation of financial performance. Factors in this determination include the variability due to unrealized gains or losses related to derivative transactions or equity securities remeasurement, unrealized foreign currency gains or losses, losses due to impairments, strategic decisions to dispose of or acquire business interests or retire debt, and the non-recurring nature of the impact of the early contract terminations at Angamos, which affect results in a given period or periods. Adjusted EPS should not be construed as an alternative to diluted earnings per share from continuing operations, which is determined in accordance with GAAP.

Reconciliation of 2023 AES Adjusted EPS

	Year Ended Dec. 31, 2023
Diluted Earnings (Loss) Per Share From Continuing Operations	$	0.34
Unrealized derivative and equity security losses(1)	$	0.06
Unrealized foreign currency losses(2)	$	0.42
Disposition/acquisition losses (gains)(3)	$	(0.11	)
Impairment losses(4)	$	1.23
Loss on extinguishment of debt(5)	$	0.10
Less: Net income tax benefit(6)	$	(0.28	)
Adjusted EPS	$	1.76

(1) Amount primarily relates to unrealized derivative losses due to the termination of a power purchase agreement (“PPA”) of $72 million, or $0.10 per share and net unrealized derivative losses at AES Clean Energy of $20 million, or $0.03 per share, offset by net unrealized derivative gains at the Energy Infrastructure SBU of $46 million, or $0.06 per share.

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(2) Amount primarily relates to unrealized foreign currency losses in Argentina of $262 million, or $0.37 per share, mainly associated with the devaluation of long-term receivables denominated in Argentine pesos, and unrealized foreign currency losses at AES Andes of $25 million, or $0.03 per share.

(3) Amount primarily relates to the gain on sale of Fluence shares of $136 million, or $0.19 per share, partially offset by costs due to early plant closure at the Ventanas 2 and Norgener coal-fired plants in Chile of $37 million, or $0.05 per share, and at Warrior Run of $6 million, or $0.01 per share, and day-one losses recognized at commencement of sales-type leases at AES Renewable Holdings of $20 million, or $0.03 per share.

(4) Amount primarily relates to asset impairments at Warrior Run of $198 million, or $0.28 per share, at New York Wind of $139 million, or $0.20 per share, the Norgener coal-fired plant in Chile of $136 million, or $0.19 per share, at TEG and TEP of $76 million and $58 million, respectively, or $0.19 per share, AES Clean Energy development projects of $114 million, or $0.16 per share, at Mong Duong of $88 million, or $0.12 per share, at Jordan of $21 million, or $0.03 per share, and at the GAF Projects at AES Renewable Holdings of $18 million, or $0.03 per share, and a goodwill impairment at the TEG TEP reporting unit of $12 million, or $0.02 per share.

(5) Amount primarily relates to losses incurred at AES Andes due to early retirement of debt of $46 million, or $0.07 per share, and loss on early retirement of debt at AES Hispanola Holdings BV of $10 million, or $0.01 per share.

(6) Amount primarily relates to income tax benefits associated with the asset impairments at Warrior Run of $46 million, or $0.06 per share, at the Norgener coal-fired plant in Chile of $37 million, or $0.05 per share, at New York Wind of $32 million, or $0.05 per share, at TEG and TEP of $27 million, or $0.04 per share, and at AES Clean Energy development projects of $26 million, or $0.04 per share; income tax benefits associated with the recognition of unrealized losses due to the termination of a PPA of $17 million, or $0.02 per share; income tax benefits associated with losses incurred at AES Andes due to early retirement of debt of $13 million, or $0.02 per share; income tax benefits associated with early plant closure costs in Chile of $10 million, or $0.01 per share; and income tax benefits associated with unrealized foreign currency losses at AES Andes of $7 million, or $0.01 per share; partially offset by income tax expense associated with the gain on sale of Fluence shares of $31 million, or $0.04 per share.

Adjusted EBITDA

AES defines EBITDA as earnings before interest income and expense, taxes, depreciation, and amortization. AES defines Adjusted EBITDA as EBITDA adjusted for the impact of noncontrolling interest and interest, taxes, depreciation, and amortization of our equity affiliates, adding back interest income recognized under service concession arrangements, and excluding gains or losses of both consolidated entities and entities accounted for under the equity method due to (a) unrealized gains or losses related to derivative transactions and equity securities; (b) unrealized foreign currency gains or losses; (c) gains, losses, benefits and costs associated with dispositions and acquisitions of business interests, including early plant closures, and gains and losses recognized at commencement of sales-type leases; (d) losses due to impairments; (e) gains, losses and costs due to the early retirement of debt; and (f) net gains at Angamos, one of AES’ businesses in the Energy Infrastructure SBU, associated with the early contract terminations with Minera Escondida and Minera Spence.

In addition to the revenue and cost of sales reflected in Operating Margin, Adjusted EBITDA includes the other components of AES’ Consolidated Statement of Operations, such as general and administrative expenses in Corporate and Other as well as business development costs, other expense and other income, realized foreign currency transaction gains and losses, and net equity in earnings of affiliates.

The GAAP measure most comparable to Adjusted EBITDA is Net income. AES believes that Adjusted EBITDA better reflects the underlying business performance of the company. Adjusted EBITDA is the most relevant measure considered in AES’ internal evaluation of the financial performance of its segments. Factors in this determination include the variability due to unrealized gains or losses related to derivative transactions or equity securities remeasurement, unrealized foreign currency gains or losses, losses due to impairments, strategic decisions to dispose of or acquire business interests or retire debt, the non-recurring nature of the impact of the early contract terminations at Angamos, and the variability of allocations of earnings to tax equity investors, which affect results in a given period or periods. In addition, each of these metrics represent the business performance of AES before the application of statutory income tax rates and tax adjustments, including the effects of tax planning, corresponding to the various jurisdictions in which AES operates.

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Adjusted EBITDA should not be construed as an alternative to Net income, which is determined in accordance with GAAP.

Reconciliation of 2023 AES Adjusted EBITDA

	Year Ended Dec. 31, 2023
	$ in Millions
Net Income	$	(182	)
Income tax expense	$	261
Interest expense	$	1,319
Interest income	$	(551	)
Depreciation and amortization	$	1,128
EBITDA	$	1,975
Less: Income from discontinued operations	$	(7	)
Less: Adjustment for noncontrolling interests and redeemable stock subsidiaries(1)	$	(552	)
Less: Income tax expense (benefit), interest expense (income) and depreciation and amortization from equity affiliates	$	130
Interest income recognized under service concession arrangements	$	71
Unrealized derivative and equity securities losses	$	34
Unrealized foreign currency losses	$	301
Disposition/acquisition losses (gains)	$	(79	)
Impairment losses	$	877
Loss of extinguishment of debt	$	62
Adjusted EBITDA(1)	$	2,812

(1) The allocation of earnings and losses to tax equity investors from both consolidated entities and equity affiliates is removed from Adjusted EBITDA.

Parent Free Cash Flow

Reconciliation of 2023 and 2021-2023 AES Parent Free Cash Flow⁽¹⁾

	Year Ended Dec. 31, 2023			Three Years 2021 - 2023
	$ in Millions
Net Cash Provided by Operating Activities at the Parent Company(2)	$	608		$	1,612
Subsidiary Distributions to QHCs Excluded from Schedule 1(3)	$	247		$	551
Subsidiary Distributions Classified in Investing Activities(4)	$	179		$	835
Parent-Funded SBU Overheard and Other Expenses Classified in Investing Activities(5)	$	(31	)	$	(249	)
Other	$	—		$	(1	)
Parent Free Cash Flow(1)	$	1,003		$	2,748

(1) Parent Free Cash Flow (a non-GAAP financial measure that was used as a performance metric for both the 2023 Performance Incentive Plan awards and the 2021 PU awards) should not be construed as an alternative to Consolidated Net Cash Provided by Operating Activities, which is determined in accordance with U.S. GAAP. Parent Free Cash Flow is the primary, recurring source of cash that is available for use by the Parent Company (or AES). Parent Free Cash Flow is equal to Subsidiary Distributions less cash used for interest costs, development, general and administrative activities, and tax payments by the Parent Company. AES Management uses Parent Free Cash Flow to determine the cash available to pay dividends, repay recourse debt, make equity investments, fund share buybacks, pay Parent Company hedging costs and make foreign exchange settlements. AES believes that Parent Free Cash Flow is useful to investors because it better reflects the Parent Company’s cash available to make growth investments, pay shareholder dividends, and make principal payments on recourse debt. Factors in this determination include availability of subsidiary distributions to the Parent Company and the Company’s investment plan.

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(2) Refer to “Schedule 1—Condensed Financial Information of Registrant” accompanying financial statements included elsewhere in this prospectus.

(3) Subsidiary distributions received by Qualified Holding Companies (“QHCs”) excluded from Schedule 1. Subsidiary Distributions should not be construed as an alternative to Consolidated Net Cash Provided by Operating Activities for AES, which is determined in accordance with US GAAP. Subsidiary Distributions are important to the Parent Company because the Parent Company is a holding company that does not derive any significant direct revenues from its own activities but instead relies on its subsidiaries’ business activities and the resultant distributions to fund the debt service, investment and other cash needs of the holding company. The reconciliation of the difference between the Subsidiary Distributions and Consolidated Net Cash Provided by Operating Activities consists of cash generated from operating activities that is retained at the subsidiaries for a variety of reasons which are both discretionary and non-discretionary in nature. These factors include, but are not limited to, retention of cash to fund capital expenditures at the subsidiary, cash retention associated with non-recourse debt covenant restrictions and related debt service requirements at the subsidiaries, retention of cash related to sufficiency of local GAAP statutory retained earnings at the subsidiaries, retention of cash for working capital needs at the subsidiaries, and other similar timing differences between when the cash is generated at the subsidiaries and when it reaches the Parent Company and related holding companies.

(4) Subsidiary distributions that originated from the results of operations of an underlying investee but were classified as investing activities when received by the relevant holding company included in Schedule 1.

(5) Net cash payments for AES-funded SBU overhead, business development, taxes, transaction costs, and capitalized interest that are classified as investing activities or excluded from Schedule 1.

Adjusted Pre-Tax Contribution (“Adjusted PTC”). Adjusted PTC is pre-tax income from continuing operations attributable to AES excluding gains or losses of the consolidated entity due to (a) unrealized gains or losses related to derivative transactions and equity securities; (b) unrealized foreign currency gains or losses; (c) gains, losses, benefits and costs associated with dispositions and acquisitions of business interests, including early plant closures, and gains and losses recognized at commencement of sales-type leases; (d) losses due to impairments; (e) gains, losses and costs due to the early retirement of debt; and (f) net gains at Angamos, one of AES’ businesses in the Energy Infrastructure SBU, associated with the early contract terminations with Minera Escondida and Minera Spence. Adjusted PTC also includes net equity in earnings of affiliates on an after-tax basis adjusted for the same gains or losses excluded from consolidated entities.

Subsidiary Distributions. Subsidiary Distributions for a strategic business unit are the sum of the following amounts (a) dividends paid to the borrower by its subsidiaries during such period; (b) consulting and management fees paid to the borrower for such period; (c) tax sharing payments made to the borrower during such period; (d) interest and other distributions paid to the borrower during such period with respect to cash and other temporary cash investments of the borrower (other than with respect to amounts on deposit in the Revolving L/C Cash Collateral Account); (e) cash payments made to the borrower in respect of foreign exchange hedge agreements or other foreign exchange activities entered into by the borrower on behalf of any of its subsidiaries; and (f) other cash payments made to the borrower by its subsidiaries other than (i) returns of invested capital; (ii) payments of the principal of debt of any such subsidiary to the borrower and (iii) payments in an amount equal to the aggregate amount released from debt service reserve accounts upon the issuance of letters of credit for the account of the borrower and the benefit of the beneficiaries of such accounts.

Compensation Risk

We believe that the applicable compensation programs and policies are designed and administered with the appropriate mix of compensation elements and balance current and long-term performance objectives, cash and equity compensation, and risks and rewards associated with our executives’ roles. As a result, we believe that the risks arising from our employee compensation program are not reasonably likely to have a material adverse effect on the Company.

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SUMMARY COMPENSATION TABLE (2023, 2022 and 2021)⁽¹⁾

Name and Principal Position (a)	Year (b)	Salary ($) (c)(2)		Bonus ($) (d)		Stock Awards ($) (e)(3)		Non-Equity Incentive Plan Compensation ($) (g)(4)		Change In Pension Value and Nonqualified Deferred Compensation Earnings ($) (h)(5)		All Other Compensation ($) (i)(6)		Total ($) (j)
Kenneth J. Zagzebski	2023	$	500,895	$	132,629	$	231,805	$	871,847	$	—	$	200,934	$	1,938,110
Pres. and CEO	2022	$	448,172	$	61,871	$	226,103	$	698,720	$	—	$	175,128	$	1,609,996
	2021	$	452,208	$	—	$	222,120	$	731,496	$	—	$	65,871	$	1,471,695
Kristina Lund	2023	$	261,465	$	—	$	636,527	$	—	$	—	$	108,770	$	1,006,762
Former Pres and CEO	2022	$	420,009	$	—	$	277,270	$	386,189	$	—	$	45,648	$	1,129,116
	2021	$	369,666	$	66,528	$	1,166,253	$	312,978	$	—	$	92,108	$	2,007,533
Ahmed Pasha	2023	$	422,823	$	—	$	159,567	$	—	$	—	$	70,466	$	652,856
Former VP and CFO (until January 1, 2024)	2022	$	393,776	$	12,325	$	251,411	$	378,797	$	—	$	64,375	$	1,100,684
Brandi Davis-Handy	2023	$	291,823	$	24,720	$	64,996	$	232,419	$	—	$	14,941	$	628,899
President, AES Indiana; Chief Customer Officer (until February 28, 2024)	2022	$	243,889	$	11,349	$	93,994	$	113,490	$	—	$	13,892	$	476,614
Brian Hylander	2023	$	296,799	$	—	$	70,010	$	209,274	$	7,256	$	37,780	$	621,119
VP, General Counsel and Secretary	2022	$	260,308	$	6,489	$	43,953	$	185,689	$	—	$	31,592	$	528,031
Jeremy Buchanan	2023	$	265,000	$	25,520	$	62,490	$	177,624	$	—	$	29,700	$	560,334
VP, HR	2022	$	224,231	$	17,382	$	35,815	$	151,523	$	—	$	27,450	$	456,401
	2021	$	179,036	$	13,213	$	32,557	$	106,902	$	—	$	21,697	$	353,405

(1) The compensation disclosed in this table represents the full amount of compensation paid to each NEO and is not limited to the portion of each NEOs compensation allocated to and paid by IPALCO.

(2) The base salary earned by each NEO during fiscal years 2023, 2022, or 2021, as applicable.

(3) Aggregate grant date fair value of PSUs and PCUs granted to Ms. Lund and RSUs granted to all NEOs in the year, which are computed in accordance with Financial Accounting Standards Board (“FASB”), Accounting Standards Codification (“ASC”) Topic 718, “Compensation—Stock Compensation” (“FASB ASC Topic 718”), disregarding any estimate of forfeitures related to service-based vesting conditions and assuming a target level of performance. A discussion of the relevant assumptions made in the valuation may be found in the financial statements, footnotes to financial statements (footnote 19), or Management’s Discussion and Analysis of Financial Condition and Results of Operations, as appropriate. The 2023 amounts for Ms. Lund reflect the value of the PSUs, PCUs and RSUs at target. Assuming (i) the maximum market and financial performance conditions are achieved, (ii) in the case of PSUs, the share price at grant, and (iii) in the case of RSUs, an adjustment percentage of +15.0%, the maximum values of PSUs, PCUs, and RSUs granted to Ms. Lund in fiscal year 2023, and payable upon completion of the 2023-2025 performance period is $1,164,842 (PSUs - $381,927; PCUs - $636,510; and RSUs - $146,405). As a result of her resignation from AES in July 2023, Ms. Lund forfeited all of her unvested equity awards. Similarly, in connection with his resignation from AES in January 2024, Mr. Pasha forfeited his 2023 RSU award.

(4) The value of all non-equity incentive plan awards earned during the 2023 fiscal year and paid in 2024, which includes awards earned under the PI Plan (our annual incentive plan) and awards earned for the three-year performance period ended December 31, 2023 for our cash-based 2021-2023 PUs granted under the LTC Plan. The following chart shows the breakdown of awards under these two plans for each NEO. In connection with their resignations from AES, Ms. Lund and Mr. Pasha each forfeited their right to receive any 2023 Performance Incentive Plan payout, and Ms. Lund forfeited the entirety of her 2021-2023 Performance Units award.

Name	Year	Annual Incentive Plan Award		Payouts for Performance Unit Award		Total Non- Equity Incentive Plan Compensation
Kenneth J. Zagzebski	2023	$	530,514	$	341,333	$	871,847
Kristina Lund	2023	$	—	$	—	$	—
Ahmed Pasha	2023	$	—	$	—	$	—
Brandi Davis-Handy	2023	$	164,800	$	67,619	$	232,419
Brian Hylander	2023	$	142,909	$	66,365	$	209,274
Jeremy Buchanan	2023	$	127,598	$	50,026	$	177,624

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(5) Mr. Hylander previously participated in the DP&L Retirement Plan. Details of this pension plan (and related assumptions) are set forth in the Pension Benefits Table (2023). For Mr. Hylander, the pension value increased from December 31, 2022 to December 31, 2023 by $7,256 due to an decrease in the discount rate (27 basis points). Mr. Zagzebski, Mr. Pasha, Ms. Davis-Handy, Mr. Buchanan, and Ms. Lund do not participate in an employer sponsored pension plan.

(6) All Other Compensation includes employer contributions to both qualified and nonqualified defined contribution retirement plans. The following chart shows the breakdown of contributions under these plans for each NEO. For 2023, All Other Compensation includes, in the case of Mr. Zagzebski, relocation-related benefits (further described below), and, in the case of Ms. Lund, payout of accrued paid time off.

Name	Year	Employer Contribution to Qualified Defined Contribution Plans		Employer Contribution to Nonqualified Defined Contribution Plans		Other		Total Other Compensation
Kenneth J. Zagzebski(a)	2023	$	29,700	$	60,971	$	110,263	$	200,934
Kristina Lund(b)	2023	$	29,700	$	22,448	$	56,622	$	108,770
Ahmed Pasha	2023	$	29,700	$	40,766	$	—	$	70,466
Brandi Davis-Handy	2023	$	13,200	$	1,741	$	—	$	14,941
Brian Hylander	2023	$	29,700	$	8,080	$	—	$	37,780
Jeremy Buchanan	2023	$	29,700	$	—	$	—	$	29,700

(a) Other Compensation for Mr. Zagzebski includes $76,901 for relocation expenses and $33,361 for related tax gross-up payments.

(b) Ms. Lund received a payout of $56,622 for paid time off accrued as of the date of her resignation from AES.

GRANTS OF PLAN-BASED AWARDS (2023)

The following table provides information about the plan based cash and equity awards granted to our NEOs in 2023.

				Estimated Future Payouts Under Non-Equity Incentive Plan Awards							Estimated Future Payouts Under Equity Incentive Plan Awards (3)			All Other Stock Awards: Number of Shares of Stock or		Grant Date Fair Value of Stock and Option
Name (a)	Grant Date (b)		Units	Threshold ($) (c)		Target ($) (d)		Maximum ($) (e)			Threshold (#) (f)	Target (#) (g)	Maximum (#) (h)	Units (#)(4) (i)		Awards ($)(5) (j)
Kenneth J. Zagzebski		—		$	—	$	417,728	$	835,456	(1)
		24-Feb-23		$	115,907	$	231,814	$	463,628	(2)
		24-Feb-23													9,155	$	231,805
Kristina Lund		—		$	—	$	346,400	$	692,800	(1)
		24-Feb-23									159,128	318,255	636,510			$	318,255
		24-Feb-23										7,542	15,084			$	190,963
		24-Feb-23									4,274	5,028	5,782			$	127,309
Ahmed Pasha		—		$	—	$	253,694	$	507,388	(1)
		24-Feb-23		$	79,778	$	159,556	$	319,112	(2)
		24-Feb-23													6,302	$	159,567
Brandi Davis-Handy		—		$	—		160,000		320,000	(1)
		24-Feb-23		$	32,500		65,000		130,000	(2)
		24-Feb-23													2,567	$	64,996
Brian Hylander		—		$	—		133,560		267,120	(1)
		24-Feb-23		$	35,000		70,000		140,000	(2)
		24-Feb-23													2,765	$	70,010
Jeremy Buchanan		—		$	—	$	119,250	$	238,500	(1)
		24-Feb-23		$	31,250	$	62,500	$	125,000	(2)
		24-Feb-23													2,468	$	62,490

(1) Amounts in the first row of data for each NEO reflect the threshold, target and maximum annual cash incentive amounts that could have been earned pursuant to 2023 awards granted under the PI Plan. The amounts of annual cash incentive awards earned in 2023 by our NEOs were determined and paid in the first quarter of 2024 to all NEOs with the exception of Mr. Pasha and Ms. Lund and the actual payout amounts are shown in footnote 4 to the Summary Compensation Table. For additional information, please see “2023 Compensation Determinations—2023 Performance Incentive Plan Payouts.”

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(2) Amounts in the second row of data for all NEOs with the exception of Ms. Lund reflect the threshold, target and maximum numbers of PUs granted under the LTC Plan. For additional information, please see “2023 Compensation Determinations—Long Term Compensation Elements.” As a result of Mr. Pasha’s resignation from AES, he forfeited his 2023 PU award.

(3) Amounts in the second, third, and fourth rows of data for Ms. Lund reflect the threshold, target, and maximum numbers of (i) PCUs, (ii) PSUs, and (iii) RSUs (with performance feature) respectively, granted under the LTC Plan. For additional information, please see “2023 Compensation Determinations—Long Term Compensation Elements.” As a result of Ms. Lund’s resignation from AES, she forfeited all of her unvested equity awards.

(4) The third row of data for each NEO with the exception of Ms. Lund reflects an RSU award granted under the LTC Plan. For additional information, please see “2023 Compensation Determinations—Long Term Compensation Elements.” In connection with his resignation from AES, Mr. Pasha forfeited all of his unvested equity awards.

(5) Aggregate grant date fair values of PCUs, PSUs and RSUs (with performance feature for Ms. Lund) granted in the year which are computed in accordance with FASB ASC Topic 718 disregarding any estimates of forfeitures related to service-based vesting conditions, assuming a target level of performance. Please reference footnote 3 of the “2023 Summary Compensation Table” for additional details.

Descriptions of the compensation elements included in the Summary Compensation Table (2023, 2022 and 2021) and Grants of Plan-Based Awards (2023) Table, including the PI Plan and LTC Plan and awards made thereunder, are set forth in the CD&A.

Outstanding Equity Awards at Fiscal Year-End (2023)

The following table contains information concerning unvested AES stock awards granted to the NEOs that were outstanding on December 31, 2023. The market value of stock awards is based on the closing price per share of AES Common Stock on December 29, 2023 of $19.25, the last business day of the 2023 fiscal year. The NEOs do not hold any equity in IPALCO.

	Option Awards					Stock Awards
Name (a)	Number of Securities Underlying Unexercised Options (#) Exercisable (b)	Number of Securities Underlying Unexercised Options (#) Unexercisable (c)	Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#) (d)	Option Exercise Price ($)(e)	Option Expiration Date (f)	Number of Shares or Units of Stock That Have Not Vested (#)(g)(1)	Market Value of Shares or Units of Stock That Have Not Vested ($)(h)		Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#)(i)		Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($)(j)
Kenneth J. Zagzebski	—	—				18,977	$	365,307	—			—
Kristina Lund(5)	—	—				—		—	—			—
Ahmed Pasha(5)	—	—				23,802	$	458,191	396	(2)	$	7,620
	—	—				—	$	—	7,518	(3)	$	144,722
	—	—				—		—	151,886	(4)	$	151,886
Brandi Davis-Handy	—	—				6,081	$	117,059	—			—
Brian Hylander	—	—				4,675	$	89,994	—			—
Jeremy Buchanan	—	—				3,994	$	76,885	—			—

(1) Included in this item are:

a. Grants of RSUs made to all NEOs that vest in three equal installments on the first three anniversaries of the grant date. These awards include:

(i) An RSU grant made on February 19, 2021 for which the final installment vested on February 19, 2024. For Mr. Pasha, a portion of this award was subject to a +/-15.0% modifier based on ESG goals. The full portion of the final installment is included.

(ii) An RSU grant made on February 24, 2022 for which the second installment vested on February 24, 2024, and the third installment will vest on February 24, 2025. For Mr. Pasha, a portion of this award is subject to a +/-15.0% modifier based on ESG goals. This portion of the award is shown in the “Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested” column and described in footnote 4 below.

(iii) An RSU grant made on February 24, 2023 for which the first installment vested on February 24, 2024, and the remaining two installments will vest on February 24, 2025 and February 24, 2026, respectively.

b. Grants of RSUs made to Mr. Pasha on November 19, 2021 that vest in four installments for which 10% vested on November 19, 2022, 15% vested on November 19, 2023, 25% would have vested on November 19, 2024, and 50% would have vested on November 19, 2025.

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(2) Included in this item are PSUs for Mr. Pasha granted on February 24, 2022 that would have vested if earned, upon final certification of results in the first quarter of 2025, based on the financial performance condition of AES’ three-year cumulative Parent Free Cash Flow, subject to AES Compensation Committee approval, and three-year service conditions (but only when and to the extent financial performance conditions are met). Based on AES’ performance through the end of fiscal year 2023 relative to the performance criteria, our current period to-date results for the 2022-2024 ongoing performance period is between target and maximum, and thus the maximum number of PSUs granted in 2022 are included above.

(3) Included in this item are PCUs granted to Mr. Pasha on February 24, 2022 which would have vested if earned, on February 24, 2025 based AES’ three-year cumulative Total Stockholder Return relative to peer indices and three-year service conditions (but only when and to the extent the market performance conditions are met). Based on AES’ performance through the end of fiscal year 2023 relative to the performance criteria, our current period to-date results for the 2022-2024 ongoing performance period is between threshold and target and thus the target number of PCUs granted in 2022 are included above.

(4) This item represents a portion of an RSU grant made to Mr. Pasha on February 24, 2022 for which the second installment would have vested on February 24, 2024, and the remaining installment would have vested on February 24, 2025. Portions of these awards that vest solely based on continued service with the Company are shown in the “Number of Shares or Units of Stock That Have Not Vested” column and described in footnote 2 above for Mr. Pasha. The portions of the awards shown in this column are subject to a +/-15.0% modifier of the target number of restricted stock units comprising the full award based on ESG goals. Based on AES’ performance through the end of the fiscal years relative to the ESG goals, our current period to-date results for the 2022- 2024 ongoing performance period is between threshold and target and thus the target numbers of RSUs granted in 2022 and subject to the +/-15.0% modifier is included above.

(5) In connection with Ms. Lund’s resignation from AES in July 2023, she forfeited all of her unvested equity at the time (including her 2023 LTC Plan awards). Similarly, in connection with Mr. Pasha’s resignation from AES in January 2024, he forfeited all of his unvested equity at the time.

Option Exercises and Stock Vested (2023)

The following table contains information concerning the vesting of RSU awards held by the NEOs during 2023.

	Option Awards		Stock Awards (1)
Name (a)	Number of Shares Acquired on Exercise (#)(b)	Value Realized on Exercise ($)(c)	Number of Shares Acquired on Vesting (#)(d)		Value Realized on Vesting ($)(e)
Kenneth J. Zagzebski	—	—	9,785	$	223,421
Kristina Lund	—	—	4,427	$	106,845
Ahmed Pasha	—	—	5,610	$	128,258
Brandi Davis-Handy	—	—	2,015	$	45,982
Brian Hylander	—	—	1,881	$	42,990
Jeremy Buchanan	—	—	1,382	$	31,669

(1) Vesting of stock awards in 2023 consisted of separate grants, as set forth in the following tables:

Number of Shares Acquired on Vesting (#)

Name	2/21/2020 RSUs (i)		2/19/2021 RSUs (ii)		2/24/2022 RSUs (iii)		2/24/2022 RSUs (iv)		11/19/2021 RSUs (v)		Total (#)
Kenneth J. Zagzebski		3,568		2,615		3,602		—		—		9,785
Kristina Lund		1,402		1,958		—		1,067		—		4,427
Ahmed Pasha		1,591		—		—		968		3,051		5,610
Brandi Davis-Handy		—		518		1,497		—		—		2,015
Brian Hylander		673		508		700		—		—		1,881
Jeremy Buchanan		429		383		570		—		—		1,382

Value Realized on Vesting ($)

Name	2/21/2020 RSUs (i)		2/19/2021 RSUs (ii)		2/24/2022 RSUs (iii)		2/24/2022 RSUs (iv)		11/19/2021 RSUs (v)		Total
Kenneth J. Zagzebski		74,036		74,031		75,354		—		—		223,421
Kristina Lund		29,092		55,431		—		22,322		—		106,845

Ahmed Pasha	33,013	—	—	20,251	74,994	128,258
Brandi Davis-Handy	—	14,665	31,317	—	—	45,982
Brian Hylander	13,965	14,381	14,644	—	—	42,990
Jeremy Buchanan	8,902	10,843	11,924	—	—	31,669

(i) The February 21, 2020 RSU grant vested in three equal installments beginning on the first anniversary of the grant date. The vesting of the third installment occurred on February 21, 2023 at a vesting price of $20.75.

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(ii) The February 19, 2021 RSU grant vests in three equal installments beginning on the first anniversary of the grant date. The vesting of the second installment occurred on February 19, 2023 at a vesting price of $28.31.

(iii) The February 24, 2022 RSU grant vests in three equal installments beginning on the first anniversary of the grant date. The vesting of the first installment occurred on February 24, 2023 at a vesting price of $20.92.

(iv) The February 24, 2022 RSU grant for Mr. Pasha and Ms. Lund vests in three equal installments beginning on the first anniversary of the grant date. The vesting of the first installment occurred on February 24, 2023 at a vesting price of $20.92.

(v) The November 19, 2021 RSU grant for Mr. Pasha vests in four installments beginning on the first anniversary of the grant date. The vesting of the second installment of 15% occurred on November 19, 2023 at a vesting price of $24.58.

Pension Benefits (2023)

The following table provides information with respect to the DP&L Retirement Income Plan which is the only defined benefit pension plan in which any of the NEOs participate.

Name (a)	Plan Name (b)		Number of Years Credited Service (#) (c)(2)		Present Value of Accumulated Benefit ($) (d)(3)(4)		Payments During Last Fiscal Year ($) (e)(5)
Kenneth J. Zagzebski(1)		—		—	$	—	$	—
Kristina Lund(1)		—		—	$	—	$	—
Ahmed Pasha(1)		—		—	$	—	$	—
Brandi Davis-Handy(1)		—		—	$	—	$	—
Brian Hylander		DP&L Retirement Income Plan		4.00	$	71,058	$	—
Jeremy Buchanan(1)		—		—	$	—	$	—

(1) Mr. Zagzebski, Mr. Pasha, Ms. Davis-Handy, Mr. Buchanan and Ms. Lund do not participate in an employer-sponsored pension plan.

(2) Assumes 1,000 hours earned in plan years 2009-2012.

(3) Based on the census data as reported by AES for valuation purposes and the following assumptions:

Measurement Date	12/31/2023	12/31/2022	12/31/2021
Discount Rate – DPL	5%	5.41%	2.83%
Post-retirement Mortality	PRI-2012 projected generationally with MSS-2023	PRI-2012 projected generationally with MSS-2022	PRI-2012 projected generationally with MSS-2021
Pre-retirement Mortality	Not applicable	Not applicable	Not applicable
Withdrawal	Not applicable	Not applicable	Not applicable
Retirement Age	62	62	62
Form of Payment	Single Life Annuity	Single Life Annuity	Single Life Annuity

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Additionally, these calculations assume census information as follows:

	Date of Birth	Date of Termination from Plan Participation
Mr. Hylander	8/8/1973	6/30/2012

(4) Accumulated Benefit calculations for Mr. Hylander include frozen accrued monthly benefit of $778.69 and the $187.50 monthly supplemental benefit payable from age 62 to age 65.

For Mr. Hylander, the pension value increased from December 31, 2022 to December 31, 2023 due to the decrease in discount rate (27 basis points).

Employee Retirement Plans

The DP&L Retirement Income Plan

The DP&L Retirement Income Plan is a qualified defined benefit plan that provides retirement benefits to employees of DP&L and its affiliates who are participating employers who meet the participation requirements. DP&L is a sister company to IPALCO and NEOs may receive benefits under DP&L plans if they were previously employed by DP&L. Mr. Hylander was eligible to participate in the DP&L Retirement Income Plan from 2009 to 2012 and has a frozen benefit as of 2012. The DP&L Retirement Income Plan covers both union (unit) and nonunion (management) employees. Plan provisions differ by union, management pre-2011 hires (Legacy), and management post-2010 hires. Mr. Hylander is in the management pre-2011 hires category. Mr. Hylander is not currently eligible for early retirement benefits under the DP&L Retirement Income Plan.

Management — Pre-2011 hires. Participants must be at least 21 years old and must have completed at least one year of service to be eligible for the DP&L Retirement Income Plan. Participants earn a year of service for each plan year during which they work 1,000 hours beginning with the plan year which includes their participation date. In general, employees receive pension benefits in an amount equal to (a) 1.25% of the average of the employee’s highest three consecutive annual base salaries for the five years immediately preceding the employee’s termination of employment, plus 0.45% of such average pay in excess of the employee’s 35-year average of Social Security wages, multiplied by (b) the employee’s years of service (not exceeding 30 years). Generally, an employee’s normal pension retirement benefits are fully available on his or her 65^th birthday. If an employee is no longer employed by a participating employer prior to vesting in the DP&L Retirement Income Plan (five years), the employee forfeits his or her pension benefits. Early retirement benefits are available to employees at any time once they reach age 55 and have completed 10 years of vesting service. However, if pension payments start before age 62, the monthly benefit is reduced by 3/12% for each month before age 62. Participants retiring early receive an additional $187.50 per month until age 65. Generally, pension benefits under the DP&L Retirement Income Plan are paid in monthly installments upon retirement; however, such benefits may be paid in a lump sum depending on the amount of pension benefits available to the employee. Employees have a right to choose a surviving spouse benefit option. If this option is chosen, pension benefits to the employee are reduced.

Nonqualified Deferred Compensation (2023)

The following table contains information for the NEOs for each of our plans that provides for the deferral of compensation that is not tax-qualified.

Name (a)(1)	Executive Contributions in Last Fiscal Year ($) (b)(1)		Registrant Contributions in Last Fiscal Year ($) (c)(2)		Aggregate Earnings in Last Fiscal Year ($) (d)(3)		Aggregate Withdrawals/Distributions ($) (e)(4)			Aggregate Balance at Last FYE ($) (f)(5)
Kenneth J. Zagzebski – RSRP	$	57,200	$	60,971	$	42,622	$	—		$	575,860
Kristina Lund – RSRP	$	170	$	22,448	$	799	$	(104,182	)	$	—
Ahmed Pasha – RSRP	$	15,600	$	40,766	$	35,680	$	—		$	336,463
Brandi Davis–Handy – RSRP	$	—	$	1,741	$	72	$	—		$	1,813
Brian Hylander – RSRP	$	19,813	$	8,080	$	14,356	$	(14,924	)	$	106,619
Jeremy Buchanan – RSRP	$	26	$	—	$	5	$	—		$	31

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(1) Amounts in this column represent elective contributions by the NEO to the RSRP in 2023.

(2) Amounts in this column represent employer contributions to the RSRP in 2023. The amount reported in this column and the employer’s additional contributions to the AES 401(k) plans are included in the amounts reported in the 2023 row of the “All Other Compensation” column of the Summary Compensation Table (2023, 2022 and 2021).

(3) Amounts in this column represent investment earnings under the RSRP.

(4) Amounts in this column represent distributions from the RSRP.

(5) Amounts in this column represent the balance of amounts in the RSRP at the end of 2023 and are included in the Summary Compensation Table as described in footnote 2 herein. In the 2022 and 2021 rows of the Summary Compensation Table, the amounts of $18,458 and $14,203 were previously reported for Ms. Lund. In the 2022 row of the Summary Compensation Table, the amounts $49,525 and $21,196 were previously reported for Mr. Pasha and Mr. Hylander, respectively. In connection with her resignation from AES, Ms. Lund received a lump sum distribution which brought her balance to zero.

Narrative Disclosure Relating to the Nonqualified Deferred Compensation Table

The AES Corporation Restoration Supplemental Retirement Plan (RSRP)

The Code places statutory limits on the amount that participants, such as our NEOs, can contribute to The AES Corporation Retirement Savings Plan (the “AES 401(k) Plan”). As a result of these regulations, matching contributions to the AES 401(k) Plan accounts of certain of our NEOs who participated in that plan in fiscal year 2023 were limited. To address the fact that participant and company contributions are restricted by the statutory limits imposed by the Code, our NEOs and other highly compensated employees are eligible to participate in the RSRP, which is designed primarily to restore benefits limited under our broad-based retirement plans due to statutory limits imposed by the Code.

Individuals who participate in the RSRP may defer up to 80% of their base salary and up to 100% of their annual bonus under the RSRP. AES provides a matching contribution to the RSRP for individuals who actively defer and who are also subject to statutory limits.

AES may maintain up to four separate deferral accounts for participants in the RSRP, each of which may have a different distribution date and a different distribution option. A participant in the RSRP may elect to have distributions made in a lump-sum payment or annually over a period of two to fifteen years. All RSRP distributions are made in cash.

Under the RSRP, individuals have the ability to select from a list of hypothetical investments. The investment options are functionally equivalent to the investments made available to all participants in the AES 401(k) Plan. Individuals may change their hypothetical investments within the time periods that are permitted by the AES Compensation Committee, provided that they are entitled to change such designations at least quarterly.

Earnings or losses are credited to the deferral accounts by the amount that would have been earned or lost if the amounts were actually invested.

Individual RSRP account balances are always 100% vested.

Potential Payments upon Termination or Change in Control (2023)

The following table contains estimated payments and benefits to each of the NEOs in connection with a termination of employment, both related and unrelated to a change in control, or a change in control of AES. The following amounts assume that a termination or change in control of AES occurred on December 31, 2023, and, where applicable, uses the closing price per share of AES Common Stock of $19.25 (as reported on the NYSE on December 29, 2023). None of the applicable NEOs would be entitled to compensation upon a change in control of IPALCO.

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For each applicable NEO, the payments and benefits detailed in the table below are in addition to any payments and benefits under our plans and arrangements that are offered or provided generally to all salaried employees on a non-discriminatory basis and any accumulated or accrued vested benefits for each NEO, including those set forth in the Pension Benefits (2023).

	Termination
Name (1)	Voluntary or for Cause		Without Cause		In Connection with Change in Control		Death		Disability		Change in Control Only (No Termination)
Kenneth J. Zagzebski
Cash Severance(2)	$	—	$	491,445	$	491,445	$	—	$	—	$	—
Accelerated Vesting of LTC(3)	$	—	$	—	$	823,225	$	823,225	$	823,225	$	—
Benefits Continuation(4)	$	—	$	19,016	$	19,016	$	—	$	—	$	—
Outplacement Assistance(5)	$	—	$	25,000	$	25,000	$	—	$	—	$	—
Total	$	—	$	535,461	$	1,358,686	$	823,225	$	823,225	$	—
Ahmed Pasha
Cash Severance(2)	$	—	$	422,823	$	422,823	$	—	$	—	$	—
Accelerated Vesting of LTC(3)	$	—	$	—	$	921,976	$	921,976	$	921,976	$	—
Benefits Continuation(4)	$	—	$	21,716	$	21,716	$	—	$	—	$	—
Outplacement Assistance(5)	$	—	$	25,000	$	25,000	$	—	$	—	$	—
Total	$	—	$	469,539	$	1,391,515	$	921,976	$	921,976	$	—
Brandi-Davis Handy
Cash Severance(1)	$	—	$	320,000	$	320,000	$	—	$	—	$	—
Accelerated Vesting of LTC(2)	$	—	$	—	$	276,059	$	276,059	$	276,059	$	—
Benefits Continuation(3)	$	—	$	13,960	$	13,960	$	—	$	—	$	—
Outplacement Assistance(4)	$	—	$	25,000	$	25,000	$	—	$	—	$	—
Total	$	—	$	358,960	$	635,019	$	276,059	$	276,059	$	—
Brian Hylander
Cash Severance(1)	$	—	$	188,354	$	188,354	$	—	$	—	$	—
Accelerated Vesting of LTC(2)	$	—	$	—	$	203,956	$	203,956	$	203,956	$	—
Benefits Continuation(3)	$	—	$	13,675	$	13,675	$	—	$	—	$	—
Outplacement Assistance(4)	$	—	$	—	$	—	$	—	$	—	$	—
Total	$	—	$	202,029	$	405,985	$	203,956	$	203,956	$	—
Jeremy Buchanan
Cash Severance(1)	$	—	$	168,173	$	168,173	$	—	$	—	$	—
Accelerated Vesting of LTC(2)	$	—	$	—	$	175,192	$	175,192	$	175,192	$	—
Benefits Continuation(3)	$	—	$	21,716	$	21,716	$	—	$	—	$	—
Outplacement Assistance(4)	$	—	$	—	$	—	$	—	$	—	$	—
Total	$	—	$	189,889	$	365,081	$	175,192	$	175,192	$	—

(1) In connection with Ms. Lunds’s resignation from AES on July 21, 2023, she did not receive any cash payments or continued benefits, and she forfeited all of her unvested equity and her right to receive any 2023 PI Plan payout. Similarly, Mr. Pasha resigned from AES on January 1, 2024, and did not receive any cash payments or continued benefits, and he forfeited all of his unvested equity.

(2) In addition to the amounts reflected in the above table, a pro rata bonus, to the extent earned, would be payable to Mr. Zagzebski, Mr. Pasha and Ms. Davis-Handy upon a termination without cause or a qualifying termination following a change in control. Pro rata bonus amounts are not included in the above table because, as of December 31, 2023, the service and performance conditions under AES’ 2023 PI Plan would have been satisfied, so such amounts would be paid irrespective of whether a termination or change in control occurs.

(3) Accelerated vesting of LTC Plan awards includes:

● The value of outstanding RSUs granted in February 2021, 2022 and 2023 (at the target payout level for RSUs with a performance feature);

● For Mr. Pasha the value of unvested PSUs granted in February 2022 at the target payout level;

● The value of unvested PUs granted in February 2022 and 2023 at the target payout level; and

● For Mr. Pasha the value of PCUs granted in February 2022 at the target payout level.

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The following table provides further detail on accelerated vesting of LTC Plan awards by award type.

Name	Zagzebski		Pasha		Davis-Handy		Hylander		Buchanan
Long-Term Award Type:
Performance Stock Units	$	—	$	144,722	$	—	$	—	$	—
Restricted Stock Units	$	365,307	$	465,812	$	117,059	$	89,994	$	76,885
Performance Units	$	457,918	$	159,556	$	159,000	$	113,962	$	98,307
Performance Cash Units	$	—	$	151,886	$	—	$	—	$	—
Total Accelerated LTC Vesting	$	823,225	$	921,976	$	276,059	$	203,956	$	175,192

(4) Upon a termination without cause or a qualifying termination following a change in control, the NEO may receive continued medical, dental and vision benefits. The value of this benefits continuation is based on the share of premiums paid by the employer on each NEO’s behalf in 2023, based on the coverage in place at the end of December 2023. For the benefit continuation period, each NEO is responsible for paying the portion of premiums previously paid as an employee.

(5) Upon a termination without cause or a qualifying termination following a change in control, Mr. Zagzebski, Mr. Pasha and Ms. Davis-Handy are eligible for outplacement benefits. The estimated value of this benefit is $25,000.

Additional Information Relating to Potential Payments upon Termination of Employment or Change in Control

The following narrative outlining our compensatory arrangements with our NEOs is in addition to other summaries of their terms found in the CD&A of this Amendment.

Potential Payments upon Termination Under the AES Corporation Severance Plan

The Severance Plan provides for certain payments and benefits to participants upon the Involuntary Termination or Termination for Good Reason of their employment under certain circumstances, including the execution of a release by the participant pursuant to the terms of the Severance Plan. As of December 31, 2023, all of our NEOs were entitled to the benefits provided by the Severance Plan in 2023 and are entitled to the applicable severance payments and benefits set forth on the benefits schedules included therein (except for Ms. Lund who resigned from AES in July 2023). The discussion below relates to the NEOs who were employees on December 31, 2023.

Certain employees, including the NEOs, are eligible for severance benefits, including salary continuation, applicable benefits and severance payments under the Severance Plan if the employee separates from service due to Involuntary Termination or for Good Reason (each as defined below). Benefits under the Severance Plan require a minimum one year of service eligibility, and are not available under the Severance Plan if the individual’s employment is terminated in connection with certain events as set forth in the Severance Plan, including, but not limited to, (a) an employee’s (i) voluntary resignation (other than for Good Reason), (ii) separation from service for Cause (or for reasons that the employer determines would be inconsistent with the purposes of the Severance Plan), or (iii) declining a new job position located within 50 miles of the employee’s current work site, or (b) due to death or disability, the sale of a business, or in connection with a voluntary transfer of employment.

Upon the termination of employment under the above circumstances, Mr. Zagzebski, Mr. Pasha and Ms. Davis-Handy would be entitled to receive the following:

● Salary continuation payments equal to their annual base salaries, which would be paid over time in accordance company payroll practices and the terms of the Severance Plan;

● An additional payment equal to a pro rata portion of their annual cash bonuses, to the extent earned, based upon the time they were employed during the year in which their employment terminates, provided that applicable performance conditions are met;

● In the event that they elect COBRA coverage under the health plan in which they participate, continuation of employer paid premiums for such coverage (for up to 12 months) in an amount equal to that paid for active employees under the same health plan. They would also receive continuation of dental and vision benefit programs, with Mr. Zagzebski, Mr. Pasha and Ms. Davis-Handy paying the same portion of the premiums as were previously paid as an employee;

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● They will be provided with outplacement services provided by an independent agency, provided that the benefit is incurred by and may not extend beyond December 31 of the second calendar year following the calendar year in which the termination occurred; and

● In the event that termination of their employment occurs due to the circumstances described above and within two years after a “change in control,” the amount of their salary continuation payment will be doubled, and the length of the healthcare benefit continuation period will be increased to 18 months.

In the event of a qualifying termination under the Severance Plan, Mr. Hylander and Mr. Buchanan would be entitled to 7-months prorated annual compensation and continuation of health, dental and vision benefits during this 7-month period. Mr. Pasha resigned from AES in January 2024 and did not receive any of the benefits described herein under the Severance Plan.

The obligation to provide these payments and benefits to the NEOs under the Severance Plan would be conditioned upon the execution and delivery of a written release of claims against the Company and AES. At our discretion, the release may also contain such noncompetition, nonsolicitation and nondisclosure provisions as we may consider necessary or appropriate.

Payment of Long-Term Compensation Awards in the Event of Termination or Change in Control as Determined by the Provisions Set Forth in the 2003 Long Term Compensation Plan (for all NEOs)

The vesting of PSUs, PCUs, RSUs and PUs and the ability of our NEOs to exercise or receive payments under those awards changes in the case of (1) termination of a NEO’s employment or (2) as a result of a change in control. The vesting conditions are defined by the provisions set forth in the 2003 LTC Plan as outlined below:

Performance Stock Units, Performance Cash Units, Restricted Stock Units and Performance Units. Except for Ms. Lund, all of our NEOs held RSUs and PUs as of December 31, 2023, and Mr. Pasha also held PSUs and PCUs as of December 31, 2023. If an NEO’s employment is terminated by reason of death or disability prior to the third anniversary of the grant date of a PSU, PCU or RSU, the PSUs (at target), the PCUs (at target) and/or RSUs (at target, in the case of RSUs with a performance feature) will immediately vest and be delivered. If a NEO separates from service prior to the end of a performance period due to death or disability, all PUs will vest on such termination date and a cash amount equal to $1 for each PU generally will be paid to the NEO on such date or as soon as practicable thereafter.

With PSUs, PCUs RSUs and PUs, voluntary termination or termination for cause prior to the end of the three-year performance period will result in the forfeiture of all outstanding units. Involuntary termination allows prorated time-vesting in increments of one-third or two-thirds vesting in the case of PSUs, PCUs and PUs. Under a qualified retirement, which requires approval of the AES Compensation Committee, the NEO must either reach i) 60 years of age and 7 years of service with the Company or an affiliate or ii) at least 57 years of age and at least 10 years of service with the Company or an affiliate, and, if the AES Compensation Committee so approves, such awards will be paid on the original schedule and, in the case of performance awards, subject to performance against the applicable goals of the awards. In the case of Mr. Zagzebski, he has reached both the age and years of service criteria to be eligible for qualified retirement. If he had retired on December 31, 2023, and if the AES Compensation Committee approved a qualified retirement, the aggregate value of his PUs (assuming target performance) and RSUs would have been $823,225.

If a change in control occurs prior to the end of the three-year performance period, outstanding PSUs, (at target), PCUs (at target), RSUs (at target performance, in the case of RSUs with a performance feature) and PUs (at target) will only become fully vested should a double-trigger occur. The double-trigger only allows for vesting if a qualifying termination occurs in connection with the change in control (other than for a qualifying retirement).

The AES Corporation Restoration Supplemental Retirement Plan (RSRP)

In the event of a termination of the applicable NEO’s employment (other than by reason of death) prior to reaching retirement eligibility, or, in the event of a change in control (defined in the same manner as the term “change-in-control” in the RSRP described below), the balances of all of the applicable NEO’s deferral accounts under the RSRP will be paid in a lump sum. In the event of such NEO’s death or retirement, the balances in the NEO’s deferral accounts will be paid according to his or her elections if such NEO was 59 1/2 or more years old at the time of his or her death or retirement. In the event of the NEO’s death or retirement before age 59 1/2, the value of the deferral account will be paid in a lump sum.

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Definition of Terms

The following definitions are provided in the Severance Plan and related Benefits Schedule used in this description:

“Cause” generally means termination of service due to the participant’s dishonesty, insubordination; continued and repeated failure to perform his or her assigned duties or willful misconduct in the performance of such duties; intentionally engaging in unsatisfactory job performance; failing to make a good faith effort to bring unsatisfactory job performance to an acceptable level; violation of the policies, procedures, work rules or recognized standards of behavior; misconduct related to his or her employment; or a charge, indictment or conviction of, or a plea of guilty or nolo contendere to, a felony, whether or not in connection with the performance of his or her duties.

“Change in Control” generally means the occurrence of one or more of the following events: (i) a transfer or sale of all or substantially all of AES’ assets, (ii) a person (other than someone in AES Management) becomes the beneficial owner of more than 35% of AES outstanding stock, (iii) during any one year period, individuals who at the beginning of such period constitute the Board of AES (together with any new Director whose election or nomination was approved by a majority of the Directors who were either in office at the beginning of such period or who were so approved, excluding anyone who became a Director as a result of a threatened or actual proxy contest or solicitation, including through the use of proxy access procedures as may be provided in the AES bylaws) cease to constitute a majority of the Board, or (iv) the consummation of a merger or similar transaction involving AES securities representing 65% or more of the then-outstanding voting stock of the corporation resulting from such transaction are held subsequent to such transaction by beneficial owners of AES immediately prior to such transaction in substantially the same proportions as their ownership immediately prior to such transaction.

“Good Reason” or “Good Reason Termination” generally means, without a participant’s written consent, his or her separation from service (for reasons other than death, disability or Cause) by a participant due to the following events, within two years of the consummation of a Change in Control: (i) the relocation of a participant’s principal place of employment to a location that is more than 50 miles from his or her previous principal place of employment; (ii) a material diminution in the duties or responsibilities of a participant; and (iii) a material reduction in the base salary or annual incentive opportunity of a participant.

“Involuntary Termination” generally means an involuntary separation from service (that is not otherwise an ineligible termination) due to a reduction in force, permanent job elimination, the restructuring or reorganization of a business unit, division, department, or other business segment, a termination by mutual consent where AES agrees that the participant is entitled to benefits, or declining an offer to relocate to a new job position more than 50 miles from the participant’s current location (provided, however, that if the participant is an executive of AES, he or she will not incur an Involuntary Termination if he or she declines a new job position, regardless of its location if such person’s existing job is being terminated).

The following definition is provided in the RSRP of the terms used in this description:

“Change-in-Control” means the occurrence of one or more of the following events: (i) any sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all, or substantially all, of the assets of AES to any person or group (as that term is used in Section 13(d)(3) of the Exchange Act) of persons; (ii) a person or group (as so defined) of persons (other than AES Management on the date of the adoption of the RSRP or their affiliates) shall have become the beneficial owner of more than 35% of the outstanding voting stock of AES; or (iii) during any one-year period, individuals who at the beginning of such period constitute the Board of AES (together with any new Director whose election or nomination was approved by a majority of the Directors then in office who were either Directors at the beginning of such period or who were previously so approved, but excluding under all circumstances any such new Director whose initial assumption of office occurs as a result of an actual or threatened election contest or other actual or threatened solicitation of proxies or consents by or on behalf of any individual, corporation, partnership or other entity or group) cease to constitute a majority of the Board of Directors. Notwithstanding the foregoing or any provision of the RSRP to the contrary, the foregoing definition of change-in-control shall be interpreted, administered and construed in manner necessary to ensure that the occurrence of any such event shall result in a change-in-control only if such event qualifies as a change in the ownership or effective control of a corporation, or a change in the ownership of a substantial portion of the assets of a corporation, as applicable, within the meaning of Treas. Reg. § 1.409A-3(i)(5).

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The following definition is provided in the 2003 Long Term Compensation Plan of the terms used in this description:

“Change-in-Control” means the occurrence of one or more of the following events: (i) any sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all, or substantially all, of the assets of AES to any person or group (as that term is used in Section 13(d) (3) of the Exchange Act) of persons, (ii) a person or group (as so defined) of persons (other than AES Management on the date of the adoption of the 2003 Long Term Compensation Plan or their affiliates) shall have become the beneficial owner of more than 35% of the outstanding voting stock of AES, or (iii) during any one-year period, individuals who at the beginning of such period constitute the Board of AES (together with any new Director whose election or nomination was approved by a majority of the Directors then in office who were either Directors at the beginning of such period or who were previously so approved, but excluding under all circumstances any such new Director whose initial assumption of office occurs as a result of an actual or threatened election contest or other actual or threatened solicitation of proxies or consents by or on behalf of any individual, corporation, partnership or other entity or group) cease to constitute a majority of the Board. Notwithstanding the foregoing or any provision of the 2003 Long Term Compensation Plan to the contrary, if an award is subject to Section 409A (and not excepted therefrom) and a change-in-control is a distribution event for purposes of an award, the foregoing definition of change-in-control shall be interpreted, administered and construed in manner necessary to ensure that the occurrence of any such event shall result in a change-in-control only if such event qualifies as a change in the ownership or effective control of a corporation, or a change in the ownership of a substantial portion of the assets of a corporation, as applicable, within the meaning of Treas. Reg. § 1.409A-3(i)(5).

Director Compensation

None of our current directors receives any compensation for his or her services on the Board. The compensation for our NEOs who also serve as directors is fully reflected in the Summary Compensation Table (2023, 2022 and 2021) and other tables set forth in this Amendment. No director who served on our Board for any part of 2023 that is or was also an employee of AES Indiana, AES, or any of its affiliates, received any additional payment for their services on the Board. Information regarding the compensation received by current and former directors in their capacities as employees of our affiliates is set forth in “Item 13. Certain Relationships and Related Transactions, and Director Independence” of this Amendment. We did not have any non-employee directors who received compensation for their services on the Board in 2023.

Compensation Committee Interlocks and Insider Participation

The Board of IPALCO does not have a compensation committee. Please see the CD&A in this Amendment for a discussion of the process undertaken in setting executive compensation, including the persons who, during the last completed fiscal year, participated in the NEO compensation process. The Executive Compensation Review Team (consisting of the AES CEO and the AES CHRO) is responsible for reviewing and administering compensation for our NEOs. Accordingly, none of our executive officers who are also members of our Board, participate in the deliberations and/or approvals regarding their own compensation.

For information regarding the board memberships and, officer and employee positions held by our executive officers and directors with AES and other companies affiliated with IPALCO, see the biographies of our executive officers and directors included under “Management” and the disclosures relating to these individuals included under “Certain Relationships, Related Transactions and Director Independence,” each set forth elsewhere in this prospectus and incorporated by reference herein as to this information.

CEO Pay Ratio

As required by SEC rules, we are disclosing the median of the annual total compensation of all employees of IPALCO (excluding the CEO), the annual total compensation of the CEO, and the ratio of the median of the annual total compensation of all employees to the annual total compensation of the chief executive officer.

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We may identify our median employee for purposes of providing pay ratio disclosure once every three years and calculate and disclose total compensation for that employee each year, provided that, during the last completed fiscal year, there has been no change in the employee population or employee compensation arrangements that we reasonably believe would result in a significant change to the prior year’s CEO pay ratio disclosure. We reviewed the changes in our employee population and employee compensatory arrangements and determined there has been no change that would significantly impact the 2021 CEO pay ratio disclosure and ultimately require us to identify a new median employee for 2023. As a result, we used the same median employee for the 2023 CEO pay ratio as we did for the 2021 CEO pay ratio disclosure.

For the pay ratio analysis of our employee population conducted in 2021, we chose December 1st as the determination date to identify our median employee, which date was within the last three months of our most recently completed fiscal year. As of December 1, 2021, the employee population consisted of approximately 1,170 individuals. The median employee was selected using data for the following elements of compensation: salary, equity grants, and non-equity incentive compensation, over a trailing 12-month period.

For purposes of reporting annual total compensation and the ratio of annual total compensation of the CEO to the median employee, both the CEO and median employee’s annual total compensation are calculated consistent with the disclosure requirements of executive compensation under Item 402(c)(2)(x) of Regulation S-K. In 2023, both Ms. Lund and Mr. Zagzebski served as CEO of IPALCO. We used Mr. Zagzebski’s annualized compensation, which is consistent with the 2023 values reflected in the Summary Compensation Table, to calculate the CEO pay ratio for IPALCO.

For fiscal 2023, the median employee’s annual total compensation was $189,134, and the total annual compensation of our President and CEO (Mr. Zagzebski) was $1,938,110. Based on this information, the ratio of the total annual compensation of our CEO to the total annual compensation of our median employee for fiscal 2023 is 10.25:1.

The Company has not made any of the adjustments permissible by the SEC, nor have any material assumptions or estimates been made to identify the median employee or to determine total annual compensation.

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Certain Relationships, Related Transactions and Director Independence

Insurance, Employee Benefit Plans and Tax Arrangements with AES

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 a 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 Costs and Expenses—Operation and Maintenance” included in this “Management’s Discussion and Analysis of Financial Condition and Results 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 Consolidated Balance Sheets accompanying the prospectus.

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, $25.3 million and $23.7 million in 2023, 2022 and 2021, respectively, and is recorded in “Operating Costs and Expenses—Operation and Maintenance” included in this “Management’s Discussion and Analysis of Financial Condition and Results 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 Consolidated Balance Sheets accompanying the audited Consolidated Financial Statements of IPALCO included elsewhere in this prospectus and Note 7, “Income Taxes” therein.

Long Term Compensation Plan

During 2023, 2022 and 2021, many of AES Indiana’s non-union employees received benefits under the AES LTC Plan. This type of plan is a common employee retention tool used in our industry. Benefits under this plan include awards granted in the form of PUs and PCUs payable in cash and AES RSUs and PSUs payable in AES Common Stock. RSUs vest ratably over a three-year period generally subject to continued employment, and PSUs vest, if earned, at the end of a three-year period based on performance and continued employment. The PUs and PCUs are payable in cash and 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 Costs and Expenses—Operation and Maintenance” included in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” herein. 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 accompanying audited Consolidated Financial Statements of IPALCO included elsewhere in this prospectus, in accordance with ASC 718 “Compensation—Stock Compensation.”

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

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Service Company

Effective January 1, 2014, the Service Company began providing certain services including operations, accounting, legal, human resources, information technology and other corporate services on behalf of companies that are part of the US Operations. 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 non-regulated businesses. 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 in charges from the Service Company. These costs were included in “Operating Costs and Expenses——Operation and Maintenance” included in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” herein. 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 Consolidated Balance Sheets accompanying the consolidated audited financial statements included elsewhere in this prospectus.

Shareholders’ Agreement

AES U.S. Investments, IPALCO and CDPQ are parties to a Shareholders’ Agreement dated February 11, 2015. The Shareholders’ Agreement established the general framework governing the relationship between CDPQ and AES U.S. Investments and their respective successors and transferees, as shareholders of IPALCO. The Shareholders’ Agreement provides AES U.S. Investments the right to nominate nine directors of the IPALCO Board and CDPQ the right to nominate two directors of the IPALCO Board. If the amount of outstanding IPALCO shares beneficially owned by CDPQ is equal to or less than the lesser of (A) 8.825% and (B) one-half of the Maximum Subscription Percentage (as defined in the Shareholders’ Agreement) but remains greater than the lesser of (x) one-third of 17.65% and (y) one-third of the Maximum Subscription Percentage, then CDPQ shall have the right to nominate one director. Additionally, if at any time the amount of outstanding IPALCO shares beneficially owned by CDPQ decreases to less than or equal to the lesser of (A) one-third of 17.65% and (B) one-third of the Maximum Subscription Percentage, then CDPQ shall cease to have any rights to nominate any directors. The Shareholders’ Agreement contains restrictions on IPALCO making certain major decisions without the prior affirmative vote of a majority of the IPALCO Board. In addition, for so long as CDPQ beneficially owns at least 5% of the total number of IPALCO shares outstanding, CDPQ will have review and consultation rights with respect to certain actions of IPALCO. Certain transfer restrictions and other transfer rights also apply to CDPQ and AES U.S. Investments under the Shareholders’ Agreement, including certain rights of first offer, drag along rights, tag along rights, put rights and rights of first refusal.

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.

Related Person Policies and Procedures

IPALCO is owned by two shareholders, one of which is wholly-owned by AES. As such, IPALCO does not maintain the type of separate related person transaction policy that is customarily maintained by more widely-held public companies. The US and Utilities has a designated compliance officer who ensures that the core values of AES and its subsidiaries are communicated to, and followed by, employees throughout the organization as set forth in the Code of Conduct and other policies adopted by IPALCO and its affiliated companies. The Code of Conduct expressly requires that employees avoid conflicts of interests and engage in fair dealing, among other requirements, to ensure that transactions entered into by IPALCO, and other affiliated companies are in the best interests of the organization.

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AES Indiana and IPALCO also utilize a due diligence questionnaire with certain business partners, vendors and suppliers as part of the corporate compliance program to ensure that the highest ethical and legal standards are upheld in all business transactions. The corporate compliance program includes a “know your business partner” program, which requires us to conduct due diligence on prospective business partners prior to entering into certain business agreements with an estimated value in excess of $250,000, for U.S. based transactions, or that are otherwise identified as high risk. Our compliance program requires that the due diligence questionnaires for all such business partners be updated prior to execution of any new agreement with AES Indiana or IPALCO if the questionnaire on file is more than two years old.

A due diligence questionnaire is also completed annually by directors and executive officers in order to determine if a related person transaction or other conflict of interest or potential conflict of interest may exist that should be brought to the attention of the designated compliance officer of the US and Utilities and/or the Office of the General Counsel for further investigation and analysis. The designated compliance officer of the US and Utilities and/or the Office of the General Counsel may take action to approve or recommend the approval of a related person transaction, or determine to take other appropriate actions, based on the facts and circumstances.

Employees of IPALCO and CDPQ Affiliated Companies

None of our Board members are directly employed by IPALCO. All of our Board members are employees of our two shareholders and/or their affiliated companies, and only receive compensation in their capacities as employees of these affiliated entities. The compensation paid to IPALCO directors that are also NEOs for services performed as employees of our affiliates for 2023 is set forth in “Management Compensation Discussion and Analysis” of this prospectus. None of our Board members are compensated for their service on our Board.

The compensation received by each of our executive officers and directors who are employees of companies affiliated with AES was in excess of $120,000 in 2023 for services performed on behalf of AES or the US and Utilities, including for services provided to IPALCO and AES Indiana. The components of the compensation paid to all of our executive officers in 2023 was consistent with the compensation elements for our NEOs as disclosed in “Management Compensation Discussion and Analysis” elsewhere in this prospectus.

For information regarding the board memberships and officer and employee positions held by our executive officers and directors with AES and other companies affiliated with IPALCO, see the biographies of our executive officers and directors included under “Management” set forth in this prospectus and incorporated by reference herein as to this information.

Director Independence

IPALCO does not have securities listed on a national securities exchange and is not required to have independent Directors. See “Management—Corporate Governance” elsewhere in this prospectus.

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Security Ownership of Certain Beneficial Owners and
Management and Related Stockholder Matters

The following two tables set forth information regarding the beneficial ownership of IPALCO’s Common Stock as of March 15, 2024 based on 108,907,318 shares outstanding as of such date, and AES’ Common Stock as of March 15, 2024 based on 710,808,795 shares outstanding as of such date by (a) each current Director of IPALCO and each NEO set forth in the Summary Compensation Table in this prospectus, (b) all Directors and Executive Officers of IPALCO as a group and (c) all persons who are known by IPALCO to be the beneficial owners of more than five percent (5%) of the Common Stock of IPALCO. Under SEC Rule 13d-3 of the Exchange Act, “beneficial ownership” includes shares for which the individual, directly or indirectly, has or shares voting power (which includes the power to vote or direct the voting of the shares) or investment power (which includes the power to dispose or direct the disposition of the shares), whether or not the shares are held for individual benefit. Under these rules, more than one person may be deemed the beneficial owner of the same securities and a person may be deemed to be a beneficial owner of securities as to which such person has no economic interest. Except as otherwise indicated in the footnotes below, each of the beneficial owners has, to the best of our knowledge, sole voting and investment power with respect to the indicated shares of IPALCO and AES Common Stock.

Except as otherwise indicated, the address for each person below is c/o IPALCO Enterprises, Inc. One Monument Circle, Indianapolis, Indiana 46204.

(a)       Common Stock of IPALCO⁽¹⁾

Name and Address of Beneficial Holder	Amount and Nature of Beneficial Ownership		Percent of IPALCO Common Stock Outstanding
AES U.S. Investments, Inc.		89,685,177		82.35	%
CDP Infrastructures Fund, L.P.
1000, Place Jean-Paul-Riopelle
Montréal (Québec) H2Z 2B3		19,222,141		17.65	%
All Directors and Executive Officers as a Group (15 people)		0		0	%

(b)       Common Stock of The AES Corporation

Name/Address	Position Held with the Company	Shares of Common Stock Beneficially Owned (2)(3)		Percent of Class (2)(3)
Jeremy Buchanan	NEO		11,657		*
Stephen Coughlin	Director		107,003		*
Bernerd Da Santos	Director		406,923		*
Brandi Davis-Handy	NEO		9,210		*
Ricardo Falú	Director		84,785		*
Paul L. Freedman	Director		106,838		*
Gustavo Garavaglia	Director		—		*
Susan Harcourt	Director		14,503		*
Brian Hylander	NEO		21,686		*
Frédéric Lesage	Director		—		*
Kristina Lund	NEO		9,000		*
Tish Mendoza	Director		298,902		*
Marc Michael	Director		12,813		*
Ahmed Pasha	NEO		—		*
Olivier Roy Durocher	Director		—		*
Kenneth J. Zagzebski	Director and NEO		47,338		*
All Directors and Executive Officers as a Group (15 people)			1,143,136		*

* Shares held represent less than 1% of the total number of outstanding shares of AES Common Stock.

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(1) Pursuant to the terms of the Shareholders’ Agreement, AES U.S. Investments and CDPQ have agreed that, during the term of the Shareholders’ Agreement, each of AES U.S. Investments and CDPQ shall vote, or act by written consent with respect to, all shares of IPALCO beneficially owned by them for the election to the Board of the individuals nominated by AES U.S. Investments and CDPQ. For additional information regarding the Shareholder’s Agreement, including the number of directors that may be nominated by AES and CDPQ, please refer to “Shareholders’ Agreement” attached as an exhibit hereto.

(2) The shares of AES Common Stock beneficially owned are reported on the basis of SEC regulations governing the determination of beneficial ownership of securities. Under the SEC rules, shares of AES Common Stock, which are subject to options, units or other securities that are exercisable or convertible into shares of AES Common Stock within 60 days of March 15, 2024, are deemed to be outstanding and beneficially owned by the persons holding such options, units or other securities. Such underlying shares of Common Stock are deemed to be outstanding for the purpose of computing such person’s ownership percentage, but not deemed to be outstanding for the purpose of computing the percentage ownership of any other person.

(3) Includes (a) the following shares issuable upon exercise of options outstanding as of March 15, 2024 that are able to be exercised within 60 days of March 15, 2024: Mr. Buchanan – 0 shares; Mr. Coughlin – 0 shares; Mr. Da Santos – 66,250 shares; Ms. Davis-Handy – 0 shares; Mr. Falú – 0 shares; Mr. Freedman – 0 shares; Mr. Garavaglia – 0 shares; Ms. Harcourt – 0 shares; Mr. Hylander – 0 shares; Mr. Lesage – 0 shares; Ms. Lund – 0 shares; Ms. Mendoza – 66,250 shares; Mr. Michael – 0 shares; Mr. Pasha – 0 shares; Mr. Roy Durocher – 0 shares; Mr. Zagzebski – 0 shares; all directors and executive officers as a group – 132,500 shares; (b) the following shares held in The AES Retirement Savings Plan: Mr. Buchanan – 1,106 shares; Mr. Coughlin – 0 shares; Mr. Da Santos – 30,211 shares; Ms. Davis-Handy – 0 shares; Mr. Falú – 0 shares; Mr. Freedman – 2,835 shares; Mr. Garavaglia – 0 shares; Ms. Harcourt - 0 shares; Mr. Hylander – 2,123 shares; Mr. Lesage – 0 shares; Ms. Lund – 0 shares; Ms. Mendoza – 27,276 shares; Mr. Michael – 14 shares; Mr. Pasha – 0 shares; Mr. Roy Durocher – 0 shares; Mr. Zagzebski – 0 shares; all directors and executive officers as a group – 63,565 shares. Data provided for Ms. Lund and Mr. Pasha is as of March 15, 2023, and is adjusted to reflect forfeiture of all of their unvested equity upon their resignation from AES.

Change in Control

IPALCO was acquired by AES in March 2001, and currently is majority-owned by AES U.S. Investments, with a minority interest held by CDPQ, a wholly owned subsidiary of La Caisse de dépȏt et placement du Québec. AES U.S. Investments is owned by AES U.S. Holdings, LLC (85%) and CDPQ (15%). AES U.S. Holdings, LLC is wholly owned by AES. A pledge by AES on its interests in AES U.S. Holdings, LLC would become effective under the terms of certain of AES’ credit arrangements if AES in the future did not meet certain investment grade credit ratings. Any exercise of remedies under such pledge could result at a subsequent date in a change in control of IPALCO.

Equity Securities Under Compensation Plans

As described in this prospectus, there are no equity compensation plans under which equity securities of IPALCO are authorized for issuance. All equity compensation plans provide for the issuance of AES Common Stock.

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Description of the Notes

In this Description of Notes, “IPALCO,” “the Company,” “we,” “us” and “our” refer only to IPALCO Enterprises, Inc., and any successor obligor on the notes, and not to any of its subsidiaries. You can find the definitions of certain terms used in this description under “—Certain Definitions.”

We will issue the notes under an indenture between us and U.S. Bank Trust Company, National Association, as trustee. The terms of the notes include those stated in the indenture and those made part of the indenture by reference to the Trust Indenture Act of 1939, as amended (the “Trust Indenture Act”).

The following is a summary of the material provisions of the indenture. Because this is a summary, it may not contain all the information that is important to you. You should read the indenture in its entirety. Copies of the indenture are available as described under “Where You Can Find More Information.”

Basic Terms of Notes

The Notes

● are secured by a pledge by us of all the outstanding common stock of Indianapolis Power & Light Company, doing business as AES Indiana, subject to any requirement that the IURC and FERC consent to or approve the exercise of remedies by the collateral agent, as described below under the caption
“—Collateral”;

● are our secured senior obligations;

● rank equally with all our other existing and future secured senior obligations (to the extent secured by the same collateral);

● rank senior, to the extent of the value of the collateral, to any of our existing and future unsubordinated and unsecured obligations;

● are senior to all our existing and future subordinated indebtedness;

● rank junior to all Indebtedness and other liabilities of AES Indiana and our other subsidiaries;

● are issued in an original aggregate principal amount of $400.0 million;

● mature on April 1, 2034; and

● bear interest commencing the date of issue at 5.750%, payable semiannually on each April 1 and October 1, commencing October 1, 2024, to holders of record on the March 15 or September 15 immediately preceding the interest payment date.

Interest will be computed on the basis of a 360-day year of twelve 30-day months.

Because we are a holding company, our rights and the rights of our creditors, including holders of the notes, in respect of claims on the assets of each of our subsidiaries upon any liquidation or administration are structurally subordinated to, and therefore will be subject to the prior claims of, each such subsidiary’s preferred stockholders and creditors (including trade creditors of and holders of debt issued by such subsidiary). At March 31, 2024, our direct and indirect subsidiaries had total long-term debt (including current maturities) of approximately $2.8 billion, all of which would be effectively senior to the notes.

Our ability to pay interest on the notes is dependent upon the receipt of dividends and other distributions from our direct and indirect subsidiaries, including AES Indiana in particular. The availability of distributions from our subsidiaries is subject to the satisfaction of various covenants and conditions contained in the applicable subsidiaries’ existing and future financing documents.

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We may from time to time, without notice to or the consent of the holders of the notes, create and issue additional debt securities under the indenture governing the notes having the same terms as, and ranking equally with, the notes in all respects (except for the offering price and issue date), provided that if any such additional notes are not fungible with the existing notes for United States federal income tax purposes, such additional notes will be issued with a different CUSIP number from the previously issued notes.

Collateral

The notes will be secured through a pledge by us of all the outstanding common stock of AES Indiana and any proceeds thereof (the “Pledged Stock”), subject to any requirement that the IURC and FERC consent to or approve the exercise of remedies by the collateral agent as described below. The lien on the Pledged Stock will be shared equally and ratably with our existing senior secured notes, and, subject to certain limitations, we may secure other Indebtedness equally and ratably with the notes. As of March 31, 2024, we had $1,280.0 million aggregate principal amount of senior secured notes outstanding.

We will be able to vote, as we see fit in our sole discretion, the Pledged Stock, unless an Event of Default (as defined herein) has occurred and is continuing.

If we meet the conditions to our defeasance option or our covenant defeasance option with respect to the notes, as described below under the caption “—Defeasance and Discharge,” or the indenture is otherwise discharged, the lien on the Pledged Stock will terminate with respect to the notes.

If an Event of Default occurs and is continuing under the indenture, the collateral agent, on behalf of the holders of the notes in addition to any rights or remedies available to it under the pledge agreement, may (but is not obligated to) take such action to protect and enforce its right in the collateral, including the institution of foreclosure proceedings, subject to any requirement that the IURC and FERC consent to or approve the exercise of remedies by the collateral agent as described below. Such foreclosure proceedings, the enforcement of the pledge agreement and the right to take other actions with respect to the Pledged Stock will be controlled by holders of a majority of the aggregate principal amount of the then outstanding obligations which are equally and ratably secured by the Pledged Stock. The proceeds received by the collateral agent from any foreclosure will be applied by the collateral agent, first, to pay the expenses of such foreclosure and fees and other amounts then payable to the collateral agent under the pledge agreement and, thereafter, to pay the notes on a pro rata basis based on the aggregate amount outstanding of the obligations that are equally and ratably secured by the Pledged Stock. There can be no assurance that any proceeds from the foreclosure of the Pledged Stock will be sufficient to satisfy the amounts due under the notes.

Regulatory considerations may affect the ability of the collateral agent to exercise certain rights with respect to the Pledged Stock upon the occurrence of an Event of Default. Because AES Indiana is a regulated public utility, such foreclosure proceedings, the enforcement of the pledge agreement and the right to take other actions with respect to the Pledged Stock may be limited and subject to regulatory approval. AES Indiana is subject to regulation at the state level by the IURC. At the federal level, it is subject to regulation by FERC. See “Business—Regulatory Matters” in this Prospectus. Regulation by the IURC and FERC includes regulation with respect to the change of control, transfer or ownership of utility property. In particular, such foreclosure proceedings, the enforcement of the pledge agreement and the right to take other actions with respect to the Pledged Stock could require (1) FERC approval to the extent such actions resulted in a change in control or a transfer of the ownership of the Pledged Stock and (2) IURC approval to the extent such actions resulted in a transfer of the ownership of the Pledged Stock to another Indiana utility. There can be no assurance that any such regulatory approval can be obtained on a timely basis, or at all.

The notes are not secured by any lien on, or other security interest in, any of our other properties or assets of our subsidiaries. The security interest in the Pledged Stock will not alter the effective subordination of the notes to the creditors of our subsidiaries.

Optional Redemption

Prior to January 1, 2034 (three months prior to their maturity date) (the “Par Call Date”), we may redeem the notes at our option, in whole or in part, at any time and from time to time, at a redemption price (expressed as a percentage of principal amount and rounded to three decimal places) equal to the greater of:

(1) (a) the sum of the present values of the remaining scheduled payments of principal and interest thereon discounted to the redemption date (assuming the notes matured on the Par Call Date) on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the Treasury Rate plus 30 basis points, less (b) interest accrued to the date of redemption, and

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(2) 100% of the principal amount of the notes to be redeemed,

plus, in either case, accrued and unpaid interest thereon to the redemption date.

On or after the Par Call Date, we may redeem the notes, in whole or in part, at any time and from time to time, at a redemption price equal to 100% of the principal amount of the notes being redeemed plus accrued and unpaid interest thereon to the redemption date.

“Treasury Rate” means, with respect to any redemption date, the yield determined by us in accordance with the following two paragraphs.

The Treasury Rate shall be determined by us after 4:15 p.m., New York City time (or after such time as yields on U.S. government securities are posted daily by the Board of Governors of the Federal Reserve System), on the third business day preceding the redemption date based upon the yield or yields for the most recent day that appear after such time on such day in the most recent statistical release published by the Board of Governors of the Federal Reserve System designated as “Selected Interest Rates (Daily)—H.15” (or any successor designation or publication) (“H.15”) under the caption “U.S. government securities—Treasury constant maturities—Nominal” (or any successor caption or heading) (“H.15 TCM”). In determining the Treasury Rate, we shall select, as applicable: (1) the yield for the Treasury constant maturity on H.15 exactly equal to the period from the redemption date to the Par Call Date (the “Remaining Life”); or (2) if there is no such Treasury constant maturity on H.15 exactly equal to the Remaining Life, the two yields – one yield corresponding to the Treasury constant maturity on H.15 immediately shorter than and one yield corresponding to the Treasury constant maturity on H.15 immediately longer than the Remaining Life – and shall interpolate to the Par Call Date on a straight-line basis (using the actual number of days) using such yields and rounding the result to three decimal places; or (3) if there is no such Treasury constant maturity on H.15 shorter than or longer than the Remaining Life, the yield for the single Treasury constant maturity on H.15 closest to the Remaining Life. For purposes of this paragraph, the applicable Treasury constant maturity or maturities on H.15 shall be deemed to have a maturity date equal to the relevant number of months or years, as applicable, of such Treasury constant maturity from the redemption date.

If on the third business day preceding the redemption date H.15 TCM is no longer published, we shall calculate the Treasury Rate based on the rate per annum equal to the semi-annual equivalent yield to maturity at 11:00 a.m., New York City time, on the second business day preceding such redemption date of the United States Treasury security maturing on, or with a maturity that is closest to, the Par Call Date, as applicable. If there is no United States Treasury security maturing on the Par Call Date but there are two or more United States Treasury securities with a maturity date equally distant from the Par Call Date, one with a maturity date preceding such Par Call Date and one with a maturity date following the Par Call Date, we shall select the United States Treasury security with a maturity date preceding the Par Call Date. If there are two or more United States Treasury securities maturing on the Par Call Date or two or more United States Treasury securities meeting the criteria of the preceding sentence, we shall select from among these two or more United States Treasury securities the United States Treasury security that is trading closest to par based upon the average of the bid and asked prices for such United States Treasury securities at 11:00 a.m., New York City time. In determining the Treasury Rate in accordance with the terms of this paragraph, the semi-annual yield to maturity of the applicable United States Treasury security shall be based upon the average of the bid and asked prices (expressed as a percentage of principal amount) at 11:00 a.m., New York City time, of such United States Treasury security, and rounded to three decimal places.

Our actions and determinations in determining the redemption price shall be conclusive and binding for all purposes, absent manifest error, and the trustee shall have no duty to calculate or verify the calculation of the redemption price.

Notice of any redemption will be mailed or electronically delivered (or otherwise transmitted in accordance with the depositary’s procedures) at least 10 days but not more than 60 days before the redemption date to each holder of notes to be redeemed, with a copy to the trustee. 

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Notice of any redemption of the notes may, at our discretion, be given prior to the completion of a corporate transaction (including a sale of our common stock, an incurrence of Indebtedness, a Change of Control (as defined herein) or other corporate transaction) and any redemption notice may, at our discretion, be subject to one or more conditions precedent, including, but not limited to, completion of a related transaction. If such redemption or purchase is so subject to satisfaction of one or more conditions precedent, such notice shall describe each such condition, and if applicable, shall state that, in our discretion, the redemption date may be delayed until such time (including more than 60 days after the date the notice of redemption was mailed or delivered, including by electronic transmission) as any or all such conditions shall be satisfied, or such redemption or purchase may not occur and such notice may be rescinded in the event that any or all such conditions shall not have been satisfied by the redemption date, or by the redemption date as so delayed. In addition, we may provide in such notice that payment of the redemption price and performance of our obligations with respect to such redemption may be performed by another person.

In the case of a partial redemption, selection of the notes for redemption will be made pro rata, by lot or by such other method as the trustee in its sole discretion deems appropriate and fair. No notes of a principal amount of $2,000 or less will be redeemed in part. If any note is to be redeemed in part only, the notice of redemption that relates to the note will state the portion of the principal amount of the note to be redeemed. A new note in a principal amount equal to the unredeemed portion of the note will be issued in the name of the holder of the note upon surrender for cancellation of the original note. For so long as the notes are held by DTC (or another depositary), the redemption of the notes shall be done in accordance with the policies and procedures of the depositary.

Unless we default in payment of the redemption price, on and after the redemption date interest will cease to accrue on the notes or portions thereof called for redemption..

No Mandatory Redemption or Sinking Fund

There will be no mandatory redemption or sinking fund payments for the notes.

Repurchase at the Option of Holders

If a Change of Control Triggering Event (as defined herein) occurs, unless we have exercised our right to redeem the notes as described above, holders of notes will have the right to require us to repurchase all or any part (no note of a principal amount of $2,000 or less will be repurchased in part) of their notes pursuant to the offer described below (the “Change of Control Offer”) on the terms set forth in the notes. In the Change of Control Offer, we will be required to offer payment in cash equal to 101% of the aggregate principal amount of notes repurchased plus accrued and unpaid interest, if any, on the notes repurchased, to, but not including, the date of purchase (the “Change of Control Payment”). Within 30 days following any Change of Control Triggering Event, we will be required to send a notice to holders of notes describing the transaction or transactions that constitute the Change of Control Triggering Event and offering to repurchase the notes on the date specified in the notice, which date will be no earlier than 30 days and no later than 60 days from the date such notice is mailed (the “Change of Control Payment Date”), pursuant to the procedures required by the notes and described in such notice. We must comply with the requirements of Rule 14e-1 under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) and any other securities laws and regulations thereunder to the extent those laws and regulations are applicable in connection with the repurchase of the notes as a result of a Change of Control Triggering Event. To the extent that the provisions of any securities laws or regulations conflict with the Change of Control provisions of the notes, we will be required to comply with the applicable securities laws and regulations and will not be deemed to have breached our obligations under the Change of Control provisions of the notes by virtue of such conflicts.

On the Change of Control Payment Date, we will be required, to the extent lawful, to:

● accept for payment all notes or portions of notes properly tendered pursuant to the Change of Control Offer;

● deposit with the paying agent, which shall initially be the trustee, an amount equal to the Change of Control Payment in respect of all notes or portions of notes properly tendered; and

● deliver or cause to be delivered to the trustee the notes properly accepted.

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The definitions of Change of Control (as defined herein) and Parent Company Change of Control (as defined herein) include a phrase relating to the direct or indirect sale, lease, transfer, conveyance or other disposition of “all or substantially all” of the properties or assets of us and our subsidiaries taken as a whole. Although there is a limited body of case law interpreting the phrase “substantially all,” there is no precise established definition of the phrase under applicable law. Accordingly, the ability of a holder of notes to require us to repurchase its notes as a result of a sale, lease, transfer, conveyance or other disposition of less than all of the assets of us and our subsidiaries taken as a whole to another person may be uncertain.

For purposes of the foregoing discussion of a repurchase at the option of holders, the following definitions are applicable:

“Change of Control” means the occurrence of any of the following: (1) the direct or indirect sale, transfer, conveyance or other disposition (other than by way of merger or consolidation), in one or a series of related transactions, of all or substantially all of the properties or assets of the Company and its subsidiaries taken as a whole to any person (as such term is used in Section 13(d) of the Exchange Act) other than the Company or one of its subsidiaries; (2) the consummation of any transaction (including, without limitation, any merger or consolidation), other than any transaction the result of which is a Parent Company Change of Control, the result of which is that any person (as such term is used in Section 13(d) of the Exchange Act) other than a Permitted Holder (as defined herein) becomes the beneficial owner, directly or indirectly, of more than 50% of the then outstanding number of shares of the Company’s Voting Stock; or (3) the first day on which a majority of the members of the Company’s Board of Directors are not Continuing Directors of the Company.

“Change of Control Triggering Event” means (x) the occurrence of a Rating Event and (y) either (a) a Change of Control, or (b) a Parent Company Change of Control.

“Continuing Directors” means, as of any date of determination, any member of the applicable Board of Directors who (1) was a member of such Board of Directors on the date of the issuance of the notes; or (2) was nominated for election or elected to such Board of Directors with the approval of a majority of the Continuing Directors who were members of such Board of Directors at the time of such nomination or election (either by vote of the Board of Directors or by approval of the stockholders, or, if applicable, after receipt of a proxy statement in which such member was named as a nominee for election as a director, without objection to such nomination).

“Fitch” means Fitch Ratings, Inc. and any successor to its ratings agency business.

“Moody’s” means Moody’s Investors Service, Inc. and any successor to its ratings agency business.

“Parent Company” means The AES Corporation, a Delaware corporation.

“Parent Company Change of Control” means the occurrence of any of the following: (1) the direct or indirect sale, transfer, conveyance or other disposition (other than by way of merger or consolidation), in one or a series of related transactions, of all or substantially all of the properties or assets of the Parent Company and its subsidiaries taken as a whole to any person (as such term is used in Section 13(d) of the Exchange Act) other than the Parent Company or one of its subsidiaries; (2) the consummation of any transaction (including, without limitation, any merger or consolidation) the result of which is that any person (as such term is used in Section 13(d) of the Exchange Act) becomes the beneficial owner, directly or indirectly, of more than 50% of the then outstanding number of shares of the Parent Company’s Voting Stock; or (3) the first day on which a majority of the members of the Parent Company’s Board of Directors are not Continuing Directors of the Parent Company.

“Permitted Holder” means, at any time, the Parent Company and its affiliates. In addition, any person or group whose acquisition of beneficial ownership constitutes a Change of Control in respect of which a Change of Control Offer is made in accordance with the requirements of the indenture will thereafter, together with its affiliates, constitute an additional Permitted Holder.

“Rating Agencies” means (a) each of Fitch, Moody’s and S&P, and (b) if any of Fitch, Moody’s or S&P ceases to rate the notes or fails to make a rating of the notes publicly available for reasons outside of our control, a “nationally recognized statistical rating organization” (within the meaning of Rule 15c3-1(c)(2)(vi)(F) under the Exchange Act) selected by us as a replacement Rating Agency for a former Rating Agency.

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“Rating Event” means (x) the rating on the notes is lowered and (y) the notes are rated below an investment grade rating, in either case, by two of the three Rating Agencies on any day within the period (the “Trigger Period”) commencing on the earlier of (a) the occurrence of a Change of Control or a Parent Company Change of Control and (b) public notice of the occurrence of a Change of Control or a Parent Company Change of Control or our intention to effect a Change of Control or the Parent Company’s intention to effect a Parent Company Change of Control and ending 60 days following the consummation of such Change of Control or Parent Company Change of Control (which Trigger Period will be extended so long as the rating of the notes is under publicly announced consideration for a possible downgrade by any of the Rating Agencies); provided, however, that a Rating Event otherwise arising by virtue of a particular reduction in rating will not be deemed to have occurred in respect of a particular Change of Control or a particular Parent Company Change of Control (and thus will not be deemed a Rating Event for purposes of the definition of Change of Control Triggering Event) if the Rating Agency making the reduction in rating to which this definition would otherwise apply publicly announces or informs the trustee in writing at our request that the reduction was not the result, in whole or in part, of any event or circumstance comprised of or arising as a result of, or in respect of, the applicable Change of Control or Parent Company Change of Control (whether or not the applicable Change of Control or Parent Company Change of Control has occurred at the time of the Rating Event).

“S&P” means S&P Global Ratings, a division of S&P Global Inc., and any successor thereto.

“Voting Stock” of any specified person means the capital stock of such person that is at the time entitled to vote generally in the election of the Board of Directors of such person.

Ranking

Substantially all of our operations are conducted through our subsidiaries. Claims of creditors of our subsidiaries, including trade creditors, secured creditors and creditors holding debt and guarantees issued by those subsidiaries, and claims of preferred and minority stockholders (if any) of those subsidiaries generally will have priority with respect to the assets and earnings of those subsidiaries over the claims of our creditors, including holders of the notes. The notes therefore will be effectively subordinated to creditors (including trade creditors) and preferred and minority stockholders (if any) of our subsidiaries. As of March 31, 2024, our direct and indirect subsidiaries had total long-term debt (including current maturities) of approximately $2.8 billion, all of which would be effectively senior to the notes. Moreover, the indenture does not impose any limitation on the incurrence by subsidiaries of additional liabilities or the issuance of additional preferred stock or minority interests.

The notes will rank equally in right of payment with all existing and future secured senior obligations and, to the extent of the value of the collateral, senior to any of our existing or future unsecured obligations and our subordinated obligations.

Moreover, as a holding company, we do not directly own any assets, other than our ownership interests in our subsidiaries. None of our subsidiaries is obligated under the notes and none of our subsidiaries will guarantee the notes. Our principal asset is our ownership interest in AES Indiana. AES Indiana is a regulated public utility, and is subject to regulation at both the state and federal level. At the state level, it is subject to regulation by the IURC. At the federal level, it is subject to regulation by FERC. See “Business—Regulatory Matters” in this Prospectus. Regulation by the IURC and FERC includes regulation with respect to the change of control, transfer or ownership of utility property. Accordingly, if the trustee under the indenture or the holders of the notes institute proceedings against us with respect to the notes, the remedies available to them may be limited and may be subject to the approval by the IURC and FERC.

Covenants

Except as otherwise set forth under “—Defeasance and Discharge” below, for so long as any notes remain outstanding or any amount remains unpaid on any of the notes, we will comply with the terms of the covenants set forth below.

Payment of Principal and Interest

We will duly and punctually pay the principal of and interest on the notes in accordance with the terms of the notes and the indenture.

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Merger, Consolidation, Sale, Lease or Conveyance

The indenture will provide that we will not (i)(a) consolidate with or merge with or into any other person, or permit any person to merge into or consolidate with us, or convey, transfer or lease our consolidated properties and assets substantially as an entirety (in one transaction or in a series of related transactions), (b) convey, transfer or lease our consolidated electric transmission and distribution assets and operations substantially as an entirety (in one transaction or in a series of related transactions), or (c) convey, transfer or lease all or substantially all of our consolidated electric generation assets and operations (in one transaction or a series of transactions), to any person or (ii) permit any of our subsidiaries to enter into any such transaction or series of transactions if it would result in the disposition of (x) our consolidated properties and assets substantially as an entirety, (y) our consolidated electric transmission and distribution assets and operations substantially as an entirety or (z) all or substantially all of our consolidated electric generation assets and operations unless, in each case:

● we will be the surviving entity; or

● the successor corporation or person that acquires all or substantially all of our assets:

● will be an entity organized under the laws of the United States of America, one of its States or the District of Columbia; and

● expressly assumes by supplemental indenture our obligations under the notes and the indenture; provided, however, that in the event following a conveyance, transfer or lease of our consolidated properties and assets substantially as an entirety or a conveyance, transfer or lease of all or substantially all of our consolidated electric generation assets and operations, we continue to own, directly or indirectly, our consolidated electric transmission and distribution assets and operations that we held immediately preceding such conveyance, transfer or lease substantially as an entirety, the notes and the indenture shall remain the obligations of us and shall not be assumed by the surviving person; and,

● in each case, immediately after the merger, consolidation, sale, lease or conveyance, we, that person or the surviving entity will not be in default under the indenture.

In addition to the indenture limitations, regulatory approval would be required for such transactions.

Limitations on Liens

Liens on AES Indiana Stock. We may not secure any Indebtedness of any person, other than IPALCO Indebtedness, by a Lien (as defined herein) upon any common stock of AES Indiana.

Liens on Property or Assets Other than the AES Indiana Stock. Neither we nor any Significant Subsidiary (as defined herein) may issue, assume or guarantee any Indebtedness secured by a Lien upon any property or assets (other than any capital stock of AES Indiana or cash or cash equivalents) of us or such Significant Subsidiary, as applicable, without effectively providing that the outstanding notes (together with, if we so determine, any other indebtedness or obligation then existing or thereafter created ranking equally with the notes) will be secured equally and ratably with (or prior to) such Indebtedness so long as such Indebtedness is so secured.

The foregoing limitation on Liens will not, however, apply to:

(1) Liens in existence on the date of original issue of the notes;

(2) any Lien created or arising over any property which is acquired, constructed or created by us or any of our Significant Subsidiaries, but only if:

(a) such Lien secures only principal amounts (not exceeding the cost of such acquisition, construction or creation) raised for the purposes of such acquisition, construction or creation, together with any costs, expenses, interest and fees incurred in relation to that property or a guarantee given in respect of that property;

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(b) such Lien is created or arises on or before 180 days after the completion of such acquisition, construction or creation; and

(c) such Lien is confined solely to the property so acquired, constructed or created;

(3) (a) rights of financial institutions to offset credit balances in connection with the operation of cash management programs established for our benefit and/or a Significant Subsidiary or in connection with the issuance of letters of credit for our benefit and/or a Significant Subsidiary;

(b) any Lien on accounts receivable securing our Indebtedness and/or a Significant Subsidiary incurred in connection with the financing of such accounts receivable;

(c) any Lien incurred or deposits made in the ordinary course of business, including, but not limited to, (1) any mechanic’s, materialmen’s, carrier’s, workmen’s, vendors’ and other like Liens and (2) any Liens securing amounts in connection with workers’ compensation, unemployment insurance and other types of social security;

(d) any Lien upon specific items of inventory or other goods of us and/or a Significant Subsidiary and the proceeds thereof securing obligations of us and/or a Significant Subsidiary in respect of bankers’ acceptances issued or created for the account of such person to facilitate the purchase, shipment or storage of such inventory or other goods;

(e) any Lien incurred or deposits made securing the performance of tenders, bids, leases, trade contracts (other than for borrowed money), statutory obligations, surety bonds, appeal bonds, government contracts, performance bonds, return-of-money bonds, letters of credit not securing borrowings and other obligations of like nature incurred in the ordinary course of business;

(f) any Lien created by us or a Significant Subsidiary under or in connection with or arising out of a Currency, Interest Rate or Commodity Agreement (as defined herein) or any transactions or arrangements entered into in connection with the hedging or management of risks relating to the electricity or natural gas distribution industry, including a right of set off or right over a margin call account or any form of cash or cash collateral or any similar arrangement for obligations incurred in respect of Currency, Interest Rate or Commodity Agreements;

(g) any Lien arising out of title retention or like provisions in connection with the purchase of goods and equipment in the ordinary course of business; and

(h) any Lien securing reimbursement obligations under letters of credit, guaranties and other forms of credit enhancement given in connection with the purchase of goods and equipment in the ordinary course of business;

(4) Liens in favor of us or a subsidiary of ours;

(5) (a) Liens on any property or assets acquired from an entity which is merged with or into us or a Significant Subsidiary or any Liens on the property or assets of any entity existing at the time such entity becomes a subsidiary of ours and, in either case, is not created in anticipation of the transaction, unless the Lien was created to secure or provide for the payment of any part of the purchase price of that entity;

(b) any Lien on any property or assets existing at the time of its acquisition and which is not created in anticipation of such acquisition, unless the Lien was created to secure or provide for the payment of any part of the purchase price of such property or assets; and

(c) any Lien created or outstanding on or over any asset of any entity which becomes a Significant Subsidiary on or after the date of the issuance of the notes, where the Lien is created prior to the date on which that entity becomes a Significant Subsidiary;

(6) (a) Liens required by any contract, statute or regulation in order to permit us or a Significant Subsidiary to perform any contract or subcontract made by it with or at the request of a governmental entity or any governmental department, agency or instrumentality, or to secure partial, progress, advance or any other payments by us or a Significant Subsidiary to such governmental unit under the provisions of any contract, statute or regulation;

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(b) any Lien securing industrial revenue, development, pollution control, solid waste disposal or similar bonds issued by or for our benefit or a Significant Subsidiary, provided that such industrial revenue, development, pollution control or similar bonds do not provide recourse generally to us and/or such Significant Subsidiary; and

(c) any Lien securing taxes or assessments or other applicable governmental charges or levies;

(7) any Lien which arises under any order of attachment, restraint or similar legal process arising in connection with court proceedings and any Lien which secures the reimbursement obligation for any bond obtained in connection with an appeal taken in any court proceeding, so long as the execution or other enforcement of such Lien arising under such legal process is effectively stayed and the claims secured by that Lien are being contested in good faith and, if appropriate, by appropriate legal proceedings, and any Lien in favor of a plaintiff or defendant in any action before a court or tribunal as security for costs and/or expenses;

(8) any extension, renewal or replacement (or successive extensions, renewals or replacements), as a whole or in part, of any Liens referred to in the foregoing clauses, for amounts not exceeding the principal amount of the Indebtedness secured by the Lien so extended, renewed or replaced, provided that such extension, renewal or replacement Lien is limited to all or a part of the same property or assets that were covered by the Lien extended, renewed or replaced (plus improvements on such property or assets);

(9) any Lien created in connection with Project Finance Debt (as defined herein);

(10) any Lien created by AES Indiana or its subsidiaries securing Indebtedness of AES Indiana or its subsidiaries;

(11) any Lien created in connection with the securitization of some or all of the assets of AES Indiana and the associated issuance of Indebtedness as authorized by applicable state or federal law in connection with the restructuring of jurisdictional electric or gas businesses; and

(12) any Lien on stock created in connection with a mandatorily convertible or exchangeable stock or debt financing, provided that any such financing may not be secured by or otherwise involve the creation of a Lien on any capital stock of AES Indiana or any successor entity to AES Indiana.

Reports and Other Information

At any time that we are not subject to the reporting requirements of Section 13 or 15(d) of the Exchange Act, or do not otherwise report on an annual and quarterly basis on forms provided for such annual and quarterly reporting pursuant to rules and regulations promulgated by the SEC, the indenture requires us to make available to the trustee and to holders of the notes, without cost to any holder:

(1) within 90 days after the end of each fiscal year, audited financial statements; and

(2) within 45 days after the end of each of the first three fiscal quarters of each fiscal year, quarterly unaudited financial statements.

Events of Default

An Event of Default with respect to the notes is defined in the indenture as being:

(1) default for 30 days in the payment of any interest on the notes;

(2) default in the payment of principal of or any premium on, the notes at maturity, upon redemption, upon required purchase, upon acceleration or otherwise;

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(3) default in the performance, or breach, of any covenant or obligation in the indenture and continuance of the default or breach for a period of 30 days after written notice specifying the default is given to us by the trustee or to us and the trustee by the holders of at least 25% in aggregate principal amount of the notes;

(4) default in the payment of the principal of any bond, debenture, note or other evidence of indebtedness, in each case for money borrowed, issued by us, or in the payment of principal under any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any Indebtedness for Borrowed Money, of us or any Significant Subsidiary if such Indebtedness for Borrowed Money is not Project Finance Debt and provides for recourse generally to us or any Significant Subsidiary, which default for payment of principal is in an aggregate principal amount exceeding $40.0 million when such indebtedness becomes due and payable (whether at maturity, upon redemption or acceleration or otherwise), if such default shall continue unremedied or unwaived for more than 30 business days and the time for payment of such amount has not been expressly extended (until such time as such payment default is remedied, cured or waived);

(5) a court having jurisdiction enters a decree or order for:

● relief in respect of us or any of our Significant Subsidiaries in an involuntary case under any applicable bankruptcy, insolvency, or other similar law now or hereafter in effect;

● appointment of a receiver, liquidator, assignee, custodian, trustee, sequestrator, or similar official of us or any of our Significant Subsidiaries or for all or substantially all of the property and assets of us or any of our Significant Subsidiaries; or

● the winding up or liquidation of our affairs or any of our Significant Subsidiaries;

● and, in either case, such decree or order remains unstayed and in effect for a period of 60 consecutive days;

(6) we or any of our Significant Subsidiaries:

● commences a voluntary case under any applicable bankruptcy, insolvency, or other similar law now or hereafter in effect, or consents to the entry of an order for relief in an involuntary case under any such law;

● consents to the appointment of or taking possession by a receiver, liquidator, assignee, custodian, trustee, sequestrator, or similar official of us or any of our Significant Subsidiaries or for all or substantially all of the property and assets of us or any of our Significant Subsidiaries; or

● effects any general assignment for the benefit of creditors; or

(7) the collateral agent fails to have a perfected security interest in the Pledged Stock of AES Indiana for a period of 10 days.

If an Event of Default (other than an Event of Default specified in clause (5) or (6) with respect to us) occurs with respect to the notes and continues, then the trustee or the holders of at least 25% in principal amount of the notes then outstanding may, by written notice to us, and the trustee at the request of at least 25% in principal amount of the notes then outstanding will, declare the principal, premium, if any, and accrued interest on the outstanding notes to be immediately due and payable. Upon a declaration of acceleration, the principal, premium, if any, and accrued interest shall be immediately due and payable.

If an Event of Default specified in clause (5) or (6) above occurs with respect to us, the principal, premium, if any, and accrued interest on the notes shall be immediately due and payable, without any declaration or other act on the part of the trustee or any holder.

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The holders of at least a majority in principal amount of the notes may, by written notice to us and to the trustee, waive all past defaults with respect to the notes and rescind and annul a declaration of acceleration with respect to the notes and its consequences if:

● all existing Events of Default applicable to the notes other than the nonpayment of the principal, premium, if any, and interest on the notes that have become due solely by that declaration of acceleration, have been cured or waived; and

● the rescission would not conflict with any judgment or decree of a court of competent jurisdiction.

No holder of the notes will have any right to institute any proceeding, judicial or otherwise, with respect to the indenture, or for the appointment of a receiver or trustee, or for any other remedy under the indenture, unless:

● such holder has previously given written notice to the trustee of a continuing Event of Default with respect to the notes;

● the holders of not less than 25% in principal amount of the notes shall have made written request to a responsible officer of the trustee to institute proceedings in respect of such Event of Default in its own name as trustee;

● such holder or holders have offered the trustee indemnity satisfactory to the trustee against the costs, expenses and liabilities to be incurred in compliance with such request;

● the trustee, for 60 days after its receipt of such notice, request and offer of indemnity, has failed to institute any such proceeding; and

● no direction inconsistent with such written request has been given to the trustee during such 60-day period by the holders of a majority in principal amount of the outstanding notes.

However, these limitations do not apply to the right of any holder of a note to receive payment of the principal, premium, if any, or interest on, that note or to bring suit for the enforcement of any payment, on or after the due date expressed in the notes, which right shall not be impaired or affected without the consent of the holder.

The indenture requires that certain of our officers certify, on or before a date not more than 120 days after the end of each fiscal year, that to the best of those officers’ knowledge, we have fulfilled all our obligations under the indenture. We are also obligated to notify the trustee of any default or defaults in the performance of any covenants or agreements under the indenture; provided, however, that a failure by us to deliver such notice of a default shall not constitute a default under the indenture, if we have remedied such default within any applicable cure period.

No Liability of Directors, Officers, Employees, Incorporators and Stockholders

No director, officer, employee, incorporator or stockholder of us, as such, will have any liability for any of our obligations under the notes or the indenture or for any claim based on, in respect of, or by reason of, such obligations. Each holder of notes by accepting a note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the notes. This waiver may not be effective to waive liabilities under the federal securities laws and it is the view of the SEC that such a waiver is against public policy.

Amendments and Waivers

Amendments Without Consent of Holders. We and the trustee may amend or supplement the indenture or the notes without notice to or the consent of any holder:

(1) to cure any ambiguity, defect or inconsistency in the indenture or the notes;

(2) to comply with “—Merger, Consolidation, Sale, Lease or Conveyance;”

(3) to comply with any requirements of the SEC in connection with the qualification of the indenture under the Trust Indenture Act;

(4) to evidence and provide for the acceptance of appointment hereunder by a successor trustee;

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(5) to provide for any guarantee of the notes, to secure the notes or to confirm and evidence the release, termination or discharge of any guarantee of or lien securing the notes when such release, termination or discharge is permitted by the indenture;

(6) to provide for or confirm the issuance of additional notes; or

(7) to make any other change that does not materially and adversely affect the rights of any holder.

Amendments With Consent of Holders. (a) Except as otherwise provided in “—Events of Default” or paragraph (b), we and the trustee may amend the indenture with respect to the notes with the written consent of the holders of a majority in principal amount of the outstanding notes and the holders of a majority in principal amount of the outstanding notes may waive future compliance by us with any provision of the indenture with respect to the notes.

(b) Notwithstanding the provisions of paragraph (a), without the consent of each holder of notes, an amendment or waiver may not:

(1) reduce the principal amount of or change the stated maturity of any installment of principal of the notes;

(2) reduce the rate of or change the stated maturity of any interest payment on the notes;

(3) reduce the amount payable upon the redemption of the notes, in respect of an optional redemption, change the times at which the notes may be redeemed or, once notice of redemption has been given, the time at which they must thereupon be redeemed;

(4) make the notes payable in money other than that stated in the notes;

(5) impair the right of any holder of notes to receive any principal payment or interest payment on such holder’s notes, on or after the stated maturity thereof, or to institute suit for the enforcement of any such payment;

(6) make any change in the percentage of the principal amount of the notes required for amendments or waivers; or

(7) modify or change any provision of the indenture affecting the ranking of the notes in a manner adverse to the holders of the notes.

It is not necessary for holders to approve the particular form of any proposed amendment, supplement or waiver, but is sufficient if their consent approves the substance thereof.

Neither we nor any of our Subsidiaries or affiliates may, directly or indirectly, pay or cause to be paid any consideration, whether by way of interest, fee or otherwise, to any holder for or as an inducement to any consent, waiver or amendment of any of the terms or provisions of the indenture or the notes unless such consideration is offered to be paid or agreed to be paid to all holders of the notes that consent, waive or agree to amend such term or provision within the time period set forth in the solicitation documents relating to the consent, waiver or amendment.

Defeasance and Discharge

The indenture provides that we are deemed to have paid and will be discharged from all obligations in respect of the notes on the 123rd day after the deposit referred to below has been made, and that the provisions of the indenture will no longer be in effect with respect to the notes (except for, among other matters, certain obligations to register the transfer or exchange of the notes, to replace stolen, lost or mutilated notes, to maintain paying agencies, to hold monies for payment in trust and the rights, obligations and immunities of the trustee) if, among other things,

(1) we have deposited with the trustee, in trust, money and/or U.S. Government Obligations (as defined herein) that, through the payment of interest and principal in respect thereof, will provide money in an amount sufficient to pay the principal, premium, if any, and accrued interest on the notes, on the due date thereof or earlier redemption (irrevocably provided for under arrangements satisfactory to the trustee), as the case may be, in accordance with the terms of the indenture;

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(2) we have delivered to the trustee either:

● an opinion of counsel to the effect that beneficial owners of notes will not recognize income, gain or loss for federal income tax purposes as a result of the exercise of our option under this “Defeasance and Discharge” provision and will be subject to federal income tax on the same amount and in the same manner and at the same times as would have been the case if the deposit, defeasance and discharge had not occurred, which opinion of counsel must be based upon a ruling of the Internal Revenue Service to the same effect unless there has been a change in applicable federal income tax law or related treasury regulations after the date of the indenture, or

● a ruling directed to the Company received from the Internal Revenue Service to the same effect as the aforementioned opinion of counsel;

(3) we have delivered to the trustee an opinion of counsel to the effect that the creation of the defeasance trust does not violate the Investment Company Act of 1940, as amended, and after the passage of 123 days following the deposit, the trust fund will not be subject to the effect of Section 547 of the U.S. Bankruptcy Code or Section 15 of the New York Debtor and Creditor Law;

(4) immediately after giving effect to that deposit on a pro forma basis, no Event of Default has occurred and is continuing on the date of the deposit or during the period ending on the 123rd day after the date of the deposit, and the deposit will not result in a breach or violation of, or constitute a default under, any other agreement or instrument to which we are a party or by which we are bound; and

(5) if at that time any notes are listed on a national securities exchange, we have delivered to the trustee an opinion of counsel to the effect that the notes will not be delisted as a result of a deposit, defeasance and discharge.

As more fully described in the indenture, the indenture also provides for defeasance of certain covenants.

Concerning the Trustee

U.S. Bank Trust Company, National Association is the trustee under the indenture. An affiliate of the trustee is a full service financial institution which currently lends to affiliates of the Company. An affiliate of the trustee also provides various investment banking services to certain of our affiliates in the ordinary course of business.

Except during the continuance of an Event of Default, the trustee needs to perform only those duties that are specifically set forth in the indenture and no others, and no implied covenants or obligations will be read into the indenture against the trustee. In case an Event of Default has occurred and is continuing, the trustee shall exercise those rights and powers vested in it by the indenture and use the same degree of care and skill in their exercise as a prudent man would exercise or use under the circumstances in the conduct of his own affairs. No provision of the indenture will require the trustee to expend or risk its own funds or otherwise incur any financial liability in the performance of its duties or in the exercise of its rights or powers thereunder. The trustee shall be under no obligation to exercise any of the rights or powers vested in it by the indenture at the request or direction of any of the holders pursuant to the indenture, unless such holders shall have offered to the trustee security or indemnity satisfactory to the trustee against the costs, expenses and liabilities which might be incurred by it in compliance with such request or direction.

The indenture and provisions of the Trust Indenture Act incorporated by reference therein contain limitations on the rights of the trustee, should it become a creditor of us, to obtain payment of claims in certain cases, or to realize on certain property received in respect of any such claim as security or otherwise. The trustee is permitted to engage in other transactions with us and our affiliates; provided that if it acquires any conflicting interest it must either eliminate the conflict within 90 days, apply to the SEC for permission to continue or resign.

Form, Denomination and Registration of Notes

Except as set forth below, the notes will be issued in registered, global form in minimum denominations of $2,000 and integral multiples of $1,000 in excess thereof.

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The Global Notes will be deposited upon issuance with the trustee as custodian for DTC and registered in the name of DTC or its nominee, in each case for credit to an account of a direct or indirect participant in DTC as described below. The Global Notes may be transferred, in whole and not in part, only to another nominee of DTC or to a successor of DTC or its nominee. Beneficial interests in the Regulation S Global Notes may be held through the Euroclear System (“Euroclear”) and Clearstream Banking, S.A. (“Clearstream”) (as indirect participants in DTC). Beneficial interests in the Global Notes may be exchanged for Notes in certificated form. See “—Exchange of Global Notes for Certificated Notes.”

In addition, transfers of beneficial interests in the Global Notes will be subject to the applicable rules and procedures of DTC and its direct or indirect participants (including, if applicable, those of Euroclear and Clearstream), which may change from time to time.

Depository Procedures

The following description of the operations and procedures of DTC, Euroclear and Clearstream are provided solely as a matter of convenience. These operations and procedures are solely within the control of the respective settlement systems and are subject to changes by them. We take no responsibility for these operations and procedures and urge investors to contact the system or their participants directly to discuss these matters.

DTC has advised us that DTC is a limited-purpose trust company created to hold securities for its participating organizations (collectively, the “Participants”) and to facilitate the clearance and settlement of transactions in those securities between Participants through electronic book-entry changes in accounts of its Participants. The Participants include securities brokers and dealers (including the initial purchasers), banks, trust companies, clearing corporations and certain other organizations. Access to DTC’s system is also available to other entities such as banks, brokers, dealers and trust companies that clear through or maintain a custodial relationship with a Participant, either directly or indirectly (collectively, the “Indirect Participants”). Persons who are not Participants may beneficially own securities held by or on behalf of DTC only through the Participants or the Indirect Participants. The ownership interests in, and transfers of ownership interests in, each security held by or on behalf of DTC are recorded on the records of the Participants and Indirect Participants. DTC has also advised us that, pursuant to procedures established by it:

(1) upon deposit of the Global Notes, DTC will credit the accounts of Participants designated by the initial purchasers with portions of the principal amount of the Global Notes; and

(2) ownership of these interests in the Global Notes will be shown on, and the transfer of ownership thereof will be effected only through, records maintained by DTC (with respect to the Participants) or by the Participants and the Indirect Participants (with respect to other owners of beneficial interest in the Global Notes).

The laws of some states require that certain persons take physical delivery in definitive form of securities that they own. Consequently, the ability to transfer beneficial interests in a Global Note to such persons will be limited to that extent. Because DTC can act only on behalf of the Participants, which in turn act on behalf of the Indirect Participants, the ability of a person having beneficial interests in a Global Note to pledge such interests to persons that do not participate in the DTC system, or otherwise take actions in respect of such interests, may be affected by the lack of a physical certificate evidencing such interests.

Except as described below, owners of interests in the Global Notes will not have notes registered in their names, will not receive physical delivery of notes in certificated form and will not be considered the registered owners or “holders” thereof under the indenture for any purpose.

Payments in respect of the principal of, and interest and premium, if any, on a Global Note registered in the name of DTC or its nominee will be payable to DTC in its capacity as the registered holder under the indenture. Under the terms of the indenture, we and the trustee will treat the persons in whose names the notes, including the Global Notes, are registered as the owners thereof for the purpose of receiving payments and for all other purposes. Consequently, neither we, the trustee, nor any agent of ours or the trustee’s has or will have any responsibility or liability for:

(1) any aspect of DTC’s records or any Participant’s or Indirect Participant’s records relating to or payments made on account of beneficial ownership interest in the Global Notes or for maintaining, supervising or reviewing any of DTC’s records or any Participant’s or Indirect Participant’s records relating to the beneficial ownership interests in the Global Notes; or

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(2) any other matter relating to the actions and practices of DTC or any of its Participants or Indirect Participants.

DTC has advised us that its current practice, upon receipt of any payment in respect of securities such as the notes (including principal and interest), is to credit the accounts of the relevant Participants with the payment on the payment date unless DTC has reason to believe it will not receive payment on such payment date. Each relevant Participant is credited with an amount proportionate to its beneficial ownership of an interest in the principal amount of the relevant security as shown on the records of DTC. Payments by the Participants and the Indirect Participants to the beneficial owners of the notes will be governed by standing instructions and customary practices and will be the responsibility of the Participants or the Indirect Participants and will not be the responsibility of DTC, the trustee or us. Neither we nor the trustee will be liable for any delay by DTC or any of its Participants in identifying the beneficial owners of the notes, and we and the trustee may conclusively rely on and will be protected in relying on instructions from DTC or its nominee for all purposes. Subject to the transfer restrictions set forth under “Notice to Investors,” transfers between Participants in DTC will be effected in accordance with DTC’s procedures, and will be settled in same-day funds, and transfers between participants in Euroclear and Clearstream will be effected in accordance with their respective rules and operating procedures.

Subject to compliance with the transfer restrictions applicable to the notes described herein, crossmarket transfers between the Participants in DTC, on the one hand, and Euroclear or Clearstream participants, on the other hand, will be effected through DTC in accordance with DTC’s rules on behalf of Euroclear or Clearstream, as the case may be, by its respective depositary; however, such cross-market transactions will require delivery of instructions to Euroclear or Clearstream, as the case may be, by the counterparty in such system in accordance with the rules and procedures and within the established deadlines (Brussels time) of such system. Euroclear or Clearstream, as the case may be, will, if the transaction meets its settlement requirements, deliver instructions to its respective depositary to take action to effect final settlement on its behalf by delivering or receiving interests in the relevant Global Note in DTC, and making or receiving payment in accordance with normal procedures for same-day funds settlement applicable to DTC. Euroclear participants and Clearstream participants may not deliver instructions directly to the depositories for Euroclear or Clearstream.

DTC has advised us that it will take any action permitted to be taken by a holder of the notes only at the direction of one or more Participants to whose account DTC has credited the interests in the Global Notes and only in respect of such portion of the aggregate principal amount of the notes as to which such Participant or Participants has or have given such direction. However, if there is an Event of Default under the notes, DTC reserves the right to exchange the Global Notes for legended notes in certificated form, and to distribute such notes to its Participants.

Exchange of Global Notes for Certificated Notes

A Global Note is exchangeable for definitive notes in registered certificated form (“Certificated Notes”) if:

(1) DTC (a) notifies us that it is unwilling or unable to continue as depositary for the Global Notes or (b) has ceased to be a clearing agency registered under the Exchange Act, and in each case we fail to appoint a successor depositary within 90 days of that notice or becoming aware that DTC is no longer so registered or willing or able to act as a depositary;

(2) we determine not to have the Notes represented by a Global Note and provide written notice thereof to the trustee; provided that in no event shall a Temporary Regulation S Global Note be exchanged for certificated Notes prior to the expiration of the distribution compliance period and the receipt of any required Regulation S Certification; or

(3) there shall have occurred and be continuing a Default or Event of Default with respect to the notes.

In all cases, certificated Notes delivered in exchange for any Global Note or beneficial interests in Global Notes will be in registered form, registered in the names, and issued in any approved denominations, requested by or on behalf of the depositary (in accordance with its customary procedures) and will bear the applicable restrictive legend referred to in “Notice to Investors,” unless that legend is not required by applicable law.

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Governing Law

The indenture and the notes shall be governed by, and construed in accordance with, the laws of the State of New York.

Certain Definitions

Set forth below are certain defined terms used in the indenture. We refer you to the indenture for a full disclosure of all such terms, as well as any other capitalized terms used in this section of the prospectus for which no definition is provided.

“Capitalized Lease Obligations” means all lease obligations of us and our subsidiaries which, under GAAP, are or will be required to be capitalized, in each case taken at the amount of the lease obligation accounted for as indebtedness in conformity with those principles.

“Currency, Interest Rate or Commodity Agreements” means an agreement or transaction involving any currency, interest rate or energy price or volumetric swap, cap or collar arrangement, forward exchange transaction, option, warrant, forward rate agreement, futures contract or other derivative instrument of any kind for the hedging or management of foreign exchange, interest rate or energy price or volumetric risks, it being understood, for purposes of this definition, that the term “energy” will include, without limitation, coal, gas, oil and electricity.

“DTC” means The Depository Trust Company.

“Excluded Subsidiary” means any subsidiary of us:

(1) in respect of which neither we nor any subsidiary of ours (other than another Excluded Subsidiary) has undertaken any legal obligation to give any guarantee for the benefit of the holders of any Indebtedness for Borrowed Money (other than to another member of the Group) other than in respect of any statutory obligation and the subsidiaries of which are all Excluded Subsidiaries; and

(2) which has been designated as such by us by written notice to the trustee; provided that we may give written notice to the trustee at any time that any Excluded Subsidiary is no longer an Excluded Subsidiary whereupon it shall cease to be an Excluded Subsidiary.

“GAAP” means generally accepted accounting principles in the United States as in effect from time to time.

“Group” means IPALCO and its subsidiaries and “member of the Group” shall be construed accordingly.

“Indebtedness” means, with respect to us or any of our subsidiaries at any date of determination (without duplication):

(1) all Indebtedness for Borrowed Money (excluding any credit which is available but undrawn);

(2) all obligations in respect of letters of credit (including reimbursement obligations with respect to letters of credit);

(3) all obligations to pay the deferred and unpaid purchase price of property or services, which purchase price is due more than six months after the date of placing such property in service or taking delivery and title to the property or the completion of such services, except trade payables;

(4) all Capitalized Lease Obligations;

(5) all indebtedness of other persons secured by a mortgage, charge, lien, pledge or other security interest on any asset of us or any of our subsidiaries, whether or not such indebtedness is assumed; provided that the amount of such Indebtedness must be the lesser of: (a) the fair market value of such asset at such date of determination and (b) the amount of the secured indebtedness;

(6) all indebtedness of other persons of the types specified in the preceding clauses (1) through (5), to the extent such indebtedness is guaranteed by us or any of our subsidiaries; and

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(7) to the extent not otherwise included in this definition, net obligations under Currency, Interest Rate or Commodity Agreements.

The amount of Indebtedness at any date will be the outstanding balance at such date of all unconditional obligations as described above and, upon the occurrence of the contingency giving rise to the obligation, the maximum liability of any contingent obligations of the types specified in the preceding clauses (1) through (7) at such date; provided that the amount outstanding at any time of any Indebtedness issued with original issue discount is the face amount of such Indebtedness less the remaining unamortized portion of the original issue discount of such Indebtedness at such time as determined in conformity with GAAP.

“Indebtedness for Borrowed Money” means any indebtedness (whether being principal, premium, interest or other amounts) for:

● money borrowed;

● payment obligations under or in respect of any trade acceptance or trade acceptance credit; or

● any notes, bonds, loan stock or other debt securities offered, issued or distributed whether by way of public offer, private placement, acquisition consideration or otherwise and whether issued for cash or in whole or in part for a consideration other than cash;

provided, however, in each case, that such term will exclude:

● any indebtedness relating to any accounts receivable securitizations;

● any Indebtedness of the type permitted to be secured by Liens pursuant to clause (12) under the caption
“—Limitation on Liens” described above; and

● any Preferred Securities which are issued and outstanding on the date of original issue of the notes or any extension, renewal or replacement (or successive extensions, renewals or replacements), as a whole or in part, of any such existing Preferred Securities, for amounts not exceeding the principal amount or liquidation preference of the Preferred Securities so extended, renewed or replaced.

“IPALCO Indebtedness” means any Indebtedness of the Company; provided that the aggregate outstanding principal amount of such Indebtedness that is secured by a Lien upon any common stock of AES Indiana may not exceed $1.6 billion and that the proceeds of such secured Indebtedness may not be used to pay any dividend to the Parent Company and, provided further, that the aggregate outstanding principal amount of such Indebtedness shall be calculated exclusive of secured Indebtedness that is being concurrently redeemed, repaid, defeased or otherwise retired with the proceeds of an offering of secured Indebtedness.

“Lien” means any mortgage, lien, pledge, security interest or other encumbrance; provided, however, that the term “Lien” does not mean any easements, rights-of-way, restrictions and other similar encumbrances and encumbrances consisting of zoning restrictions, leases, subleases, restrictions on the use of property or defects in title.

“Preferred Securities” means, without duplication, any trust preferred or preferred securities or related debt or guaranties of us or any of our subsidiaries.

“Project Finance Debt” means:

● any Indebtedness to finance or refinance the ownership, acquisition, development, design, engineering, procurement, construction, servicing, management and/or operation of any project or asset which is incurred by an Excluded Subsidiary; and

● any Indebtedness to finance or refinance the ownership, acquisition, development, design, engineering, procurement, construction, servicing, management and/or operation of any project or asset in respect of which the person or persons to whom any such Indebtedness is or may be owed by the relevant borrower (whether or not a member of the Group) has or have no recourse whatsoever to any member of the Group (other than an Excluded Subsidiary) for the repayment of that Indebtedness other than: (i) recourse to such member of the Group for amounts limited to the cash flow or net cash flow (other than historic cash flow or historic net cash flow) from, or ownership interests or other investments in, such project or asset; and/or (ii) recourse to such member of the Group for the purpose only of enabling amounts to be claimed in respect of such Indebtedness in an enforcement of any encumbrance given by such member of the Group over such project or asset or the income, cash flow or other proceeds deriving from the project (or given by any shareholder or the like, or other investor in, the borrower or in the owner of such project or asset over its shares or the like in the capital of, or other investment in, the borrower or in the owner of such project or asset) to secure such Indebtedness, provided that the extent of such recourse to such member of the Group is limited solely to the amount of any recoveries made on any such enforcement; and/or (iii) recourse to such borrower generally, or directly or indirectly to a member of the Group, under any form of assurance, indemnity, undertaking or support, which recourse is limited to a claim for damages (other than liquidated damages and damages required to be calculated in a specified way) for breach of an obligation (not being a payment obligation or an obligation to procure payment by another or an indemnity in respect of a payment obligation, or any obligation to comply or to procure compliance by another with any financial ratios or other tests of financial condition) by the person against which such recourse is available.

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“Significant Subsidiary” means, at any particular time, any subsidiary of ours whose gross assets or gross revenue (having regard to our direct and/or indirect beneficial interest in the shares, or the like, of that subsidiary) represent at least 25% of the consolidated gross assets or, as the case may be, consolidated gross revenue of us.

“Subsidiary” means, with respect to any person, any corporation, association, partnership, limited liability company or other business entity of which 50% or more of the total voting power of shares of capital stock or other interests (including partnership interests) entitled (without regard to the occurrence of any contingency) to vote in the election of directors, managers or trustees is at the time owned, directly or indirectly, by (1) such person, (2) such person and one or more subsidiaries of such person or (3) one or more subsidiaries of such person.

“U.S. Government Obligation” means any:

(1) security which is: (a) a direct obligation of the United States for the payment of which the full faith and credit of the United States is pledged or (b) an obligation of a person controlled or supervised by and acting as an agency or instrumentality of the United States the payment of which is unconditionally guaranteed as a full faith and credit obligation by the United States, which, in the case of clause (a) or (b), is not callable or redeemable at the option of the issuer of the obligation, and

(2) depositary receipt issued by a bank (as defined in the Securities Act) as custodian with respect to any security specified in clause (1) above and held by such bank for the account of the holder of such depositary receipt or with respect to any specific payment of principal of or interest on any such security held by any such bank, provided that (except as required by law) such custodian is not authorized to make any deduction from the amount payable to the holder of such depositary receipt from any amount received by the custodian in respect of the U.S. Government Obligation or the specific payment of interest on or principal of the U.S. Government Obligation evidenced by such depositary receipt.

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The Exchange Offer

General

We hereby offer to exchange a like principal amount of new notes for any or all outstanding old notes on the terms and subject to the conditions set forth in this prospectus. We often refer to this offer as the “exchange offer.” You may tender some or all of your outstanding old notes pursuant to this exchange offer. As of the date of this prospectus, $400,000,000 aggregate principal amount of the old notes are outstanding. Our obligation to accept old notes for exchange pursuant to the exchange offer is subject to certain conditions set forth hereunder.

Purpose and Effect of the Exchange Offer

In connection with the offering of the old notes, which was consummated on March 14, 2024, we entered into a registration rights agreement with the initial purchasers of the old notes, under which we agreed:

(1) to use our reasonable best efforts to cause to be filed a registration statement with respect to an offer to exchange the old notes for a new issue of securities, with terms substantially the same as of the old notes but registered under the Securities Act;

(2) to use our reasonable best efforts to cause the registration statement to be declared effective by the SEC on or prior to 365 days after the closing of the old notes offering and remain effective until the closing of the exchange offer; and

(3) to use our reasonable best efforts to consummate the exchange offer and issue the new notes within 30 business days after the registration statement is declared effective.

The registration rights agreement provides that, in the event that the registration statement is not effective on or prior to the date that is 365 days after the closing date of the old notes offering or consummate the exchange offer within 30 days after the effectiveness of the registration statement for the exchange offer, the interest rate for the notes will increase by a rate of 0.50% per annum from the effectiveness deadline until the exchange offer registration statement or the shelf registration statement is declared effective. Once we complete this exchange offer, we will no longer be required to pay additional interest on the old notes. The additional interest rate for the old notes will not any time exceed 0.50% per annum notwithstanding our failure to meet more than one of these requirements.

The exchange offer is not being made to, nor will we accept tenders for exchange from, holders of old notes in any jurisdiction in which the exchange offer or acceptance of the exchange offer would violate the securities or blue sky laws of that jurisdiction. Furthermore, each holder of old notes that wishes to exchange their old notes for new notes in this exchange offer will be required to make certain representations as set forth herein.

Terms of the Exchange Offer; Period for Tendering Old Notes

This prospectus contains the terms and conditions of the exchange offer. Upon the terms and subject to the conditions included in this prospectus, we will accept for exchange old notes which are properly tendered on or prior to the expiration date, unless you have previously withdrawn them.

● When you tender to us old notes as provided below, our acceptance of the old notes will constitute a binding agreement between you and us upon the terms and subject to the conditions in this prospectus.

● For each $2,000 principal amount of old notes (and $1,000 principal amount of old notes in excess thereof) surrendered to us in the exchange offer, we will give you $2,000 principal amount of new notes (and $1,000 principal amount of new notes in excess thereof). Outstanding notes may only be tendered in denominations of $2,000 and integral multiples of $1,000 in excess thereof, provided that no notes of $2,000 or less will be redeemed in part.

● We will keep the exchange offer open for not less than 20 business days, or longer if required by applicable law, after the date that we first mail notice of the exchange offer to the holders of the old notes. We are sending this prospectus on or about the date of this prospectus to all of the registered holders of old notes at their addresses listed in the trustee’s security register with respect to the old notes.

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● The exchange offer expires at 5:00 P.M., New York City time, on July 8, 2024; provided, however, that we, in our sole discretion, may extend the period of time for which the exchange offer is open. The term “expiration date” means July 8, 2024 or, if extended by us, the latest time and date to which the exchange offer is extended.

● As of the date of this prospectus, $400,000,000 aggregate principal amount of the old notes were outstanding. The exchange offer is not conditioned upon any minimum principal amount of old notes being tendered.

● Our obligation to accept old notes for exchange in the exchange offer is subject to the conditions that we describe in the section called “Conditions to the Exchange Offer” below.

● We expressly reserve the right, at any time, to extend the period of time during which the exchange offer is open, and thereby delay acceptance of any old notes, by giving oral or written notice of an extension to the exchange agent and notice of that extension to the holders as described below. During any extension, all old notes previously tendered will remain subject to the exchange offer unless withdrawal rights are exercised. Any old notes not accepted for exchange for any reason will be returned without expense to the tendering holder promptly following the expiration or termination of the exchange offer.

● We expressly reserve the right to amend or terminate the exchange offer, and not to accept for exchange any old notes that we have not yet accepted for exchange, if any of the conditions of the exchange offer specified below under “Conditions to the Exchange Offer” are not satisfied. In the event of a material change in the exchange offer, including the waiver of a material condition, we will extend the offer period if necessary so that at least five business days remain in the exchange offer following notice of the material change.

● We will give oral or written notice of any extension, amendment, termination or non-acceptance described above to holders of the old notes promptly. If we extend the expiration date, we will give notice by means of a press release or other public announcement no later than 9:00 a.m., New York City time, on the business day after the previously scheduled expiration date. Without limiting the manner in which we may choose to make any public announcement and subject to applicable law, we will have no obligation to publish, advertise or otherwise communicate any public announcement other than by issuing a release to Dow Jones and Company News Agency and/or other similar news service.

● Holders of old notes do not have any appraisal or dissenters’ rights in connection with the exchange offer.

● Old notes which are not tendered for exchange or are tendered but not accepted in connection with the exchange offer will remain outstanding and be entitled to the benefits of the indenture, but will not be entitled to any further registration rights under the registration rights agreement.

● We intend to conduct the exchange offer in accordance with the applicable requirements of the Exchange Act and the rules and regulations of the SEC thereunder.

Important Rules Concerning the Exchange Offer

You should note that:

● All questions as to the validity, form, eligibility, time of receipt and acceptance of old notes tendered for exchange will be determined by IPALCO Enterprises, Inc. in our sole discretion, which determination shall be final and binding.

● We reserve the absolute right to reject any and all tenders of any particular old notes not properly tendered or to not accept any particular old notes which acceptance might, in our judgment or the judgment of our counsel, be unlawful.

● We also reserve the absolute right to waive any defects or irregularities or conditions of the exchange offer as to any particular old notes either before or after the expiration date, including the right to waive the ineligibility of any holder who seeks to tender old notes in the exchange offer. Unless we agree to waive any defect or irregularity in connection with the tender of old notes for exchange, you must cure any defect or irregularity within any reasonable period of time as we shall determine.

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● Our interpretation of the terms and conditions of the exchange offer as to any particular old notes either before or after the expiration date shall be final and binding on all parties.

● Neither IPALCO Enterprises, Inc., the exchange agent nor any other person shall be under any duty to give notification of any defect or irregularity with respect to any tender of old notes for exchange, nor shall any of them incur any liability for failure to give any notification.

Procedures for Tendering Old Notes

What to submit and how

If you, as the registered holder of an old note, wish to tender your old notes for exchange in the exchange offer, you must contact a DTC participant to complete the book-entry transfer procedures described below on or prior to the expiration date.

In addition,

(1) a timely confirmation of a book-entry transfer of old notes, if such procedure is available, into the exchange agent’s account at DTC using the procedure for book-entry transfer described below, must be received by the exchange agent prior to the expiration date, or

(2) you must comply with the guaranteed delivery procedures described below.

The method of delivery of notices of guaranteed delivery is at your election and risk. In all cases, sufficient time should be allowed to assure timely delivery.

How to sign your documents

Signatures on a notice of withdrawal, as the case may be, must be guaranteed unless the old notes being surrendered for exchange are tendered for the account of an eligible institution.

If signatures on a notice of withdrawal are required to be guaranteed, the guarantees must be by any of the following eligible institutions:

● a firm which is a member of a registered national securities exchange or a member of the Financial Industry Regulatory Authority, Inc. or

● a commercial bank or trust company having an office or correspondent in the United States.

Acceptance of Old Notes for Exchange; Delivery of New Notes

Once all of the conditions to the exchange offer are satisfied or waived, we will accept, promptly after the expiration date, all old notes properly tendered and will issue the new notes promptly after the expiration of the exchange offer. See “—Conditions to the Exchange Offer” below. For purposes of the exchange offer, our giving of oral or written notice of our acceptance to the exchange agent will be considered our acceptance of the exchange offer.

In all cases, we will issue new notes in exchange for old notes that are accepted for exchange only after timely receipt by the exchange agent of a timely book-entry confirmation of transfer of old notes into the exchange agent’s account at DTC using the book-entry transfer procedures described below.

If we do not accept any tendered old notes for any reason included in the terms and conditions of the exchange offer, non-exchanged old notes will be credited to an account maintained with DTC promptly following the expiration or termination of the exchange offer.

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Book-Entry Transfer

The exchange agent will make a request to establish an account with respect to the old notes at DTC for purposes of the exchange offer promptly after the date of this prospectus. Any financial institution that is a participant in DTC’s systems may make book-entry delivery of old notes by causing DTC to transfer old notes into the exchange agent’s account in accordance with DTC’s Automated Tender Offer Program procedures for transfer. However, the exchange for the old notes so tendered will only be made after timely confirmation of book-entry transfer of old notes into the exchange agent’s account, and timely receipt by the exchange agent of an agent’s message, transmitted by DTC and received by the exchange agent and forming a part of a book-entry confirmation. The agent’s message must state that DTC has received an express acknowledgment from the participant tendering old notes that are the subject of that book-entry confirmation that the participant has received and agrees to be bound by the terms of the prospectus, and that we may enforce the agreement against that participant.

Although delivery of old notes may be effected through book-entry transfer into the exchange agent’s account at DTC, an agent’s message, properly completed and duly executed, with any required signature guarantees, must in any case be delivered to and received by the exchange agent at its address listed under “—Exchange Agent” on or prior to the expiration date.

If your old notes are held through DTC, you must complete a form called “instructions to registered holder and/or book-entry participant,” which will instruct the DTC participant through whom you hold your securities of your intention to tender your old notes or not tender your old notes. Please note that delivery of documents to DTC in accordance with its procedures does not constitute delivery to the exchange agent and we will not be able to accept your tender of notes until the exchange agent receives an agent’s message and a book-entry confirmation from DTC with respect to your notes. A copy of that form is available from the exchange agent.

Guaranteed Delivery Procedures

If you are a registered holder of old notes and you want to tender your old notes but your old notes are not immediately available, or time will not permit an agent’s message or your old notes to reach the exchange agent before the expiration date, or the procedure for book-entry transfer cannot be completed on a timely basis, a tender may be effected if:

● the tender is made through an eligible institution,

● prior to the expiration date, the exchange agent receives, by facsimile transmission, mail or hand delivery, from that eligible institution a properly completed and duly executed notice of guaranteed delivery, substantially in the form provided by us, stating:

1. the name and address of the holder of old notes;

2. the amount of old notes tendered;

3. the tender is being made by delivering that notice; and

4. guaranteeing that within three New York Stock Exchange trading days after the date of execution of the notice of guaranteed delivery, a book-entry confirmation will be deposited by that eligible institution with the exchange agent, and

5. a book-entry confirmation is received by the exchange agent within three New York Stock Exchange trading days after the date of execution of the Notice of Guaranteed Delivery.

Withdrawal Rights

You can withdraw your tender of old notes at any time on or prior to the expiration date.

For a withdrawal to be effective, a written notice of withdrawal must be received by the exchange agent at one of the addresses listed below under “Exchange Agent.” Any notice of withdrawal must specify: 

1. the name of the person having tendered the old notes to be withdrawn

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2. the old notes to be withdrawn

3. the principal amount of the old notes to be withdrawn; and

4. any notice of withdrawal must specify the name and number of the account at DTC to be credited with the withdrawn old notes and otherwise comply with the procedures of that facility.

Please note that all questions as to the validity, form, eligibility and time of receipt of notices of withdrawal will be determined by us, and our determination shall be final and binding on all parties. Any old notes so withdrawn will be considered not to have been validly tendered for exchange for purposes of the exchange offer. If you have properly withdrawn old notes and wish to re-tender them, you may do so by following one of the procedures described under “Procedures for Tendering Old Notes” above at any time on or prior to the expiration date.

Conditions to the Exchange Offer

Notwithstanding any other provisions of the exchange offer, we will not be required to accept for exchange, or to issue new notes in exchange for, any old notes and may terminate or amend the exchange offer, if at any time before the expiration of the exchange offer:

1. that acceptance or issuance would violate applicable law or any interpretation of the staff of the SEC; or

2. any holder of the old notes exchanged in the exchange offer has not represented that all new notes to be received by it shall be acquired in the ordinary course of its business and that at the time of the consummation of the exchange offer it shall have no arrangement or understanding with any person to participate in the distribution (within the meaning of the Securities Act) of the new notes and shall have made such other representations as may be reasonably necessary under applicable SEC rules, regulations or interpretations to render the use of Form S-4 or other appropriate form under the Securities Act available.

The conditions described above are for our sole benefit and may be asserted by us regardless of the circumstances giving rise to that condition. Our failure at any time to exercise the foregoing rights shall not be considered a waiver by us of that right. Our rights described in the prior paragraph are ongoing rights which we may assert at any time and from time to time prior to the expiration of the exchange offer.

In addition, we will not accept for exchange any old notes tendered, and no new notes will be issued in exchange for any old notes, if at that time any stop order shall be threatened or in effect with respect to the exchange offer to which this prospectus relates or the qualification of the indenture under the Trust Indenture Act.

Exchange Agent

U.S. Bank Trust Company, National Association has been appointed as the exchange agent for the exchange offer. Questions and requests for assistance, requests for additional copies of this prospectus and requests for notices of guaranteed delivery should be directed to the exchange agent, addressed as follows:

Deliver To:

By Registered, Regular or Certified Mail or Overnight Delivery:

U.S. Bank Trust Company, National Association

Attn: Specialized Finance

111 Fillmore Avenue E

St. Paul, Minnesota 55107

Facsimile Transmissions:

(Eligible Institutions Only)

(651) 466-7372

Attn: Specialized Finance

To Confirm by Telephone or for Information:

(800)-934-6802

Delivery to an address other than as listed above or transmission of instructions via facsimile other than as listed above does not constitute a valid delivery.

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Fees and Expenses

The principal solicitation is being made by mail; however, additional solicitation may be made by telegraph, telephone or in person by our officers, regular employees and affiliates. We will not pay any additional compensation to any of our officers and employees who engage in soliciting tenders. We will not make any payment to brokers, dealers, or others soliciting acceptances of the exchange offer. However, we will pay the exchange agent reasonable and customary fees for its services and will reimburse it for its reasonable out-of-pocket expenses in connection with the exchange offer.

The estimated cash expenses to be incurred in connection with the exchange offer, including legal, accounting, SEC filing, printing and exchange agent expenses, will be paid by us and are estimated in the aggregate to be $270,000.

Accounting Treatment

We will record the new notes in our accounting records at the same carrying value as the old notes, which is the aggregate principal amount as reflected in our accounting records on the date of exchange. Accordingly, we will not recognize any gain or loss for accounting purposes upon the consummation of this exchange offer. We will capitalize the expenses of this exchange offer and amortize them over the life of the notes.

Transfer Taxes

Holders who tender their old notes for exchange will not be obligated to pay any transfer taxes in connection therewith, except that holders who instruct us to register new notes in the name of, or request that old notes not tendered or not accepted in the exchange offer be returned to, a person other than the registered tendering holder will be responsible for the payment of any applicable transfer tax thereon.

Resale of the New Notes

Under existing interpretations of the staff of the SEC contained in several no-action letters to third parties, the new notes would in general be freely transferable after the exchange offer without further registration under the Securities Act. The relevant no-action letters include the Exxon Capital Holdings Corporation letter, which was made available by the SEC on May 13, 1988, and the Morgan Stanley & Co. Incorporated letter, made available on June 5, 1991.

However, any purchaser of old notes who is an “affiliate” of IPALCO Enterprises, Inc. or who intends to participate in the exchange offer for the purpose of distributing the new notes

(1) will not be able to rely on the interpretation of the staff of the SEC,

(2) will not be able to tender its old notes in the exchange offer and

(3) must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any sale or transfer of the securities unless that sale or transfer is made using an exemption from those requirements.

129

In addition, in connection with any resales of new notes, any broker-dealer participating in the exchange offer who acquired securities for its own account as a result of market-making or other trading activities must deliver a prospectus meeting the requirements of the Securities Act. The SEC has taken the position in the Shearman & Sterling no-action letter, which it made available on July 2, 1993, that participating broker-dealers may fulfill their prospectus delivery requirements with respect to the new notes, other than a resale of an unsold allotment from the original sale of the old notes, with the prospectus contained in the exchange offer registration statement. Under the registration rights agreement, we are required to allow participating broker-dealers and other persons, if any, subject to similar prospectus delivery requirements to use this prospectus as it may be amended or supplemented from time to time, in connection with the resale of new notes.

Failure to Exchange

Holders of old notes who do not exchange their old notes for new notes under the exchange offer will remain subject to the restrictions on transfer of such old notes as set forth in the legend printed on the notes as a consequence of the issuance of the old notes pursuant to the exemptions from, or in transactions not subject to, the registration requirements of the Securities Act and applicable state securities laws, and otherwise set forth in the confidential offering memorandum distributed in connection with the private offering of the old notes.

Other

Participating in the exchange offer is voluntary, and you should carefully consider whether to accept. You are strongly urged to consult your financial, legal and tax advisors in making your own decision on what action to take.

130

Material United States Tax Consequences of the Exchange Offer

The exchange of old notes for new notes in the exchange offer will not result in any United States federal income tax consequences to holders. When a holder exchanges an old security for a new security in the exchange offer, the holder will have the same adjusted basis and holding period in the new security as in the old security immediately before the exchange.

Persons considering the exchange of outstanding notes for exchange notes should consult their own tax advisors concerning the United States federal income tax consequences in light of their particular situations as well as any consequences arising under the laws of any other taxing jurisdiction.

Plan of Distribution

Each broker-dealer that receives new notes for its own account in the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of new notes. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of new notes received in exchange for old notes where old notes were acquired as a result of market-making activities or other trading activities. We have agreed that, for a period of 90 days after the expiration date, we will make this prospectus, as amended or supplemented, available to any broker-dealer for use in connection with any resale of new notes received by it in exchange for old notes.

We will not receive any proceeds from any sale of new notes by broker-dealers.

New notes received by broker-dealers for their own account in the exchange offer may be sold from time to time in one or more transactions:

● in the over-the-counter market;

● in negotiated transactions;

● through the writing of options on the new notes; or

● a combination of those methods of resale,

● at market prices prevailing at the time of resale, at prices related to prevailing market prices or negotiated prices.

Any resale may be made:

● directly to purchasers; or

● to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any broker-dealer or the purchasers of any new notes.

Any broker-dealer that resells new notes that were received by it for its own account in the exchange offer and any broker or dealer that participates in a distribution of those new notes may be considered to be an “underwriter” within the meaning of the Securities Act. Any profit on any resale of those new notes and any commission or concessions received by any of those persons may be considered to be underwriting compensation under the Securities Act. The letter of transmittal states that, by acknowledging that it will deliver and by delivering a prospectus, a broker-dealer will not be considered to admit that it is an “underwriter” within the meaning of the Securities Act.

For a period of 90 days after the expiration date, we will promptly send additional copies of this prospectus and any amendment or supplement to this prospectus to any broker-dealer that requests those documents in the letter of transmittal. We have agreed to pay all expenses incident to the exchange offer, other than commissions or concessions of any brokers or dealers and will indemnify the holders of the securities, including any broker-dealers, against some liabilities, including liabilities under the Securities Act.

131

Validity of Securities

Davis Polk & Wardwell LLP will opine for us on whether the new notes are valid and binding obligations of IPALCO Enterprises, Inc. and will rely on the opinion of Barnes & Thornburg LLP, with respect to certain matters under the laws of the State of Indiana.

Experts

The consolidated financial statements of IPALCO Enterprises, Inc. and subsidiaries at December 31, 2023 and 2022, and for each of the three years in the period ended December 31, 2023, and the related notes and schedules appearing in this registration statement have been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

The consolidated financial statements of Indianapolis Power & Light Company and subsidiaries, d/b/a AES Indiana, at December 31, 2023 and 2022, and for each of the three years in the period ended December 31, 2023, and the related notes and schedule appearing in this registration statement have been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

Where You Can Find More Information

We have filed with the SEC, Washington, D.C. 20549, a registration statement on Form S-4 under the Securities Act with respect to our offering of the new notes. This prospectus does not contain all of the information set forth in the registration statement and the exhibits and schedules thereto. For further information with respect to the company and the new notes, reference is made to the registration statement and the exhibits and any schedules filed therewith. Statements contained in this prospectus as to the contents of any contract or other document referred to are not necessarily complete and in each instance, if such contract or document is filed as an exhibit, reference is made to the copy of such contract or other document filed as an exhibit to the registration statement, each statement being qualified in all respects by such reference. A copy of the registration statement, including exhibits and schedules thereto, is available to the public on the SEC’s website at https://www.sec.gov.

If for any reason we are not required to comply with the reporting requirements of the Securities Exchange Act of 1934, as amended, or we do not otherwise report on an annual or quarterly basis on forms provided for such annual and quarterly reporting pursuant to rules and regulations promulgated by the SEC, we are still required under the indenture to deliver (which may be accomplished through posting on the internet) to the trustee and to holders of the notes, without any cost to any holder: (1) within 90 days after the end of each fiscal year, audited financial statements and (2) within 45 days after the end of each of the first three fiscal quarters of each fiscal year, quarterly unaudited financial statements. We are also required under the indenture to provide without charge upon the written request of (1) a holder of any notes or (2) a prospective holder of any of the notes who is a “qualified institutional buyer” within the meaning of Rule 144A and is designated by an existing holder of any of the notes with the information with respect to the Company required to be delivered under Rule 144A(d)(f) under the Securities Act to enable resales of the notes to be made pursuant to Rule 144A.

Any such requests should be directed to us at: IPALCO Enterprises, Inc., One Monument Circle, Indianapolis, Indiana 46204, Phone: (317) 864-5307, Attention: Treasury Department.

We also maintain an Internet site at http://www.aesindiana.com. Our website and the information contained therein or connected thereto shall not be deemed to be a part of this prospectus or the registration statement of which it forms a part.

132

Index to Financial Statements AND SCHEDULES

Page No.

IPALCO Enterprises, Inc. and Subsidiaries – Consolidated Financial Statements (as of December 31, 2023)
Report of Independent Registered Public Accounting Firm (PCAOB ID: 42)	F-1
Consolidated Statements of Operations for the Years Ended December 31, 2023, 2022 and 2021	F-4
Consolidated Statements of Comprehensive Income/(Loss) for the Years Ended December 31, 2023, 2022 and 2021	F-5
Consolidated Balance Sheets as of December 31, 2023 and 2022	F-6
Consolidated Statements of Cash Flows for the Years Ended December 31, 2023, 2022 and 2021	F-7
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2023, 2022 and 2021	F-8
Notes to Consolidated Financial Statements	F-9
AES Indiana and Subsidiaries – Consolidated Financial Statements (as of December 31, 2023)
Report of Independent Registered Public Accounting Firm (PCAOB ID: 42)	F-51
Consolidated Statements of Operations for the Years Ended December 31, 2023, 2022 and 2021	F-53
Consolidated Balance Sheets as of December 31, 2023 and 2022	F-54
Consolidated Statements of Cash Flows for the Years Ended December 31, 2023, 2022 and 2021	F-55
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2023, 2022 and 2021	F-56
Notes to Consolidated Financial Statements	F-57
IPALCO Enterprises, Inc. and Subsidiaries – Condensed Consolidated Financial Statements (as of March 31, 2024)
Unaudited Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2024 and 2023	F-96
Unaudited Condensed Consolidated Balance Sheets as of March 31, 2024 and 2023	F-98
Unaudited Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2024 and 2023	F-99
Unaudited Condensed Consolidated Statements of Changes in Equity For the Three Months Ended March 31, 2024 and 2023	F-100
Notes to Unaudited Condensed Consolidated Financial Statements for the Three Months Ended March 31, 2024 and 2023	F-101
AES Indiana and Subsidiaries – Condensed Consolidated Financial Statements (as of March 31, 2024)
Unaudited Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2024 and 2023	F-116
Unaudited Condensed Consolidated Balance Sheets as of March 31, 2024 and 2023	F-117
Unaudited Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2024 and 2023	F-118
Unaudited Condensed Consolidated Statements of Changes in Equity For the Three Months Ended March 31, 2024 and 2023	F-119
Notes to Unaudited Condensed Consolidated Financial Statements for the Three Months Ended March 31, 2024 and 2023	F-120
IPALCO Enterprises, Inc. and Subsidiaries – Financial Statement Schedules
Schedule I – Condensed Financial Information of Registrant	F-131
Schedule II – Valuation and Qualifying Accounts and Reserves	F-140
AES Indiana and Subsidiaries – Financial Statement Schedule
Schedule II – Valuation and Qualifying Accounts and Reserves	F-141

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.

F-1

	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.
	Asset Retirement Obligations
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.

F-2

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

F-3

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.

F-4

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.

F-5

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.

F-6

IPALCO ENTERPRISES, INC. 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	$	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.

F-7

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
	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
	(in Thousands)
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.

F-8

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

F-9

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.

F-10

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.

F-11

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.

F-12

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,
	Weighted average amortization periods (in years)		2023			2022
	$ in thousands
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.

F-13

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.

F-14

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):

	Affected line item in the	For the Years Ended December 31,
Details about AOCI / (AOCL) components	Consolidated Statements of Operations	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.

F-15

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 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.

F-16

ASU Number and Name	Description	Date of Adoption	Effect on the Financial Statements upon adoption
	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.
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.

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.

F-17

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.

F-18

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.

F-19

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.

F-20

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.

F-21

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.

F-22

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.

F-23

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.

F-24

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.

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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.

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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.

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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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.

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.

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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.

F-29

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.

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.

F-30

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,
	2023			2022			2021
	$ in thousands (net of tax)
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

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

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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.

F-33

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.

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.

F-34

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

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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.

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.

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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.

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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.

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	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.

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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%

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	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.

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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:

	Pension Benefits
Year	(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.

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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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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:

	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.

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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 NO_x 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 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.

F-45

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.

F-46

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.

F-47

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.

F-48

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):

	December 31, 2023			December 31, 2022
Property, Plant and Equipment, Net
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

F-50

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.

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.

F-51

	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.
	Asset Retirement Obligations
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

F-52

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.

F-53

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.

F-54

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.

F-55

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
	Outstanding Shares		Amount		Paid in Capital		Retained Earnings			Total Common Shareholder’s Equity			Cumulative Preferred Stock			Noncontrolling Interests
	(in Thousands)
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.

F-56

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 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.

F-57

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.

F-58

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.

F-59

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.

F-60

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:

	Weighted	December 31,
	average amortization periods (in
$ in thousands	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.

F-61

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.

F-62

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.

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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.

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ASU Number and Name	Description	Date of Adoption	Effect on the Financial Statements upon Adoption
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.

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. 

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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. 

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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. 

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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. 

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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. 

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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. 

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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

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(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. 

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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. 

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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.

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. 

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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.

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. 

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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

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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(1)	Unit	Notional (in thousands)		Sales (in thousands)		Net Notional (in thousands)
FTRs	Not Designated	MWh		3,919		—		3,919

(1) 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.

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. 

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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

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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.

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.

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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.

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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	%

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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.

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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
			Quoted Prices in Active Markets for Identical Assets		Significant Observable Inputs
Asset Category	Total		(Level 1)		(Level 2)		%
			(in thousands)
Common collective trusts:
Equities(1)	$	82,652	$	2,267	$	80,385		14	%
Debt securities(2)		387,979		1,168		386,811		66	%
Government debt securities(3)		117,397		178		117,219		20	%
Total common collective trusts		588,028		3,613		584,415		100	%
Cash and cash equivalents(4)		2,791		2,791		—		—	%
Total pension plan assets	$	590,819	$	6,404	$	584,415		100	%

(1) 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.

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(2) 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.

(3) 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.

(4) 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
			Quoted Prices in Active Markets for Identical Assets		Significant Observable Inputs
Asset Category	Total		(Level 1)		(Level 2)		%
			(in thousands)
Common collective trusts:
Equities (1)	$	85,341	$	2,017	$	83,324		14	%
Debt securities (2)		400,291		1,254		399,037		66	%
Government debt securities (3)		122,704		420		122,284		20	%
Total common collective trusts		608,336		3,691		604,645		100	%
Cash and cash equivalents (4)		2,789		2,789		—		—	%
Total pension plan assets	$	611,125	$	6,480	$	604,645		100	%

(1) 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.

(2) 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.

(3) 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.

(4) 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.

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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

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.

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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.

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.

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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.

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 NO_x 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 Statement of AES Indiana for a description of benefits awarded to AES Indiana employees by AES under the RSP.

F-91

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.

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.

F-92

 

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.

F-93

 

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.

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.

F-94

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

F-95

 

IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Condensed Consolidated Statements of Operations
(Unaudited)

	Three Months Ended March 31,
	2024			2023
	(in thousands)
REVENUE	$	407,801		$	491,386
OPERATING COSTS AND EXPENSES:
Fuel		102,919			189,730
Power purchased		38,633			49,890
Operation and maintenance		115,368			117,899
Depreciation and amortization		80,433			69,852
Taxes other than income taxes		7,895			7,430
Loss on asset disposal		1,523			—
Total operating costs and expenses		346,771			434,801
OPERATING INCOME		61,030			56,585
OTHER (EXPENSE) / INCOME, NET:
Allowance for equity funds used during construction		831			1,570
Interest expense		(43,648	)		(34,843	)
Other income, net		306			1,017
Total other expense, net		(42,511	)		(32,256	)
INCOME BEFORE INCOME TAX		18,519			24,329
Income tax expense		3,909			5,214
NET INCOME		14,610			19,115
Net loss attributable to noncontrolling interests		(2,552	)		—
NET INCOME ATTRIBUTABLE TO COMMON STOCK	$	17,162		$	19,115

See Notes to Condensed Consolidated Financial Statements.

F-96

IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Condensed Consolidated Statements of Comprehensive Income
(Unaudited)

	Three Months Ended March 31,
	2024			2023
	(in thousands)
NET INCOME	$	14,610		$	19,115
Derivative activity:
Change in derivative fair value, net of income tax effect of $(2,193) and $2,824, for each respective period		6,626			(8,532	)
Reclassification to earnings, net of income tax effect of $(252) and $(449), for each respective period		760			1,358
Net change in fair value of derivatives		7,386			(7,174	)
Other comprehensive income / (loss)		7,386			(7,174	)
Comprehensive income		21,996			11,941
Less: comprehensive loss attributable to noncontrolling interests		(2,552	)		—
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON STOCK	$	24,548		$	11,941

See Notes to Condensed Consolidated Financial Statements.

F-97

IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Condensed Consolidated Balance Sheets
(Unaudited)

	March 31, 2024		December 31, 2023
	(in thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	435,217	$	28,579
Accounts receivable, net of allowance for credit losses of $3,765 and $2,283, respectively		293,660		233,921
Inventories		137,005		143,590
Regulatory assets, current		112,121		89,419
Taxes receivable		34,802		36,481
Derivative assets, current		393		15,682
Prepayments and other current assets		26,911		26,358
Total current assets		1,040,109		574,030
NON-CURRENT ASSETS:
Property, plant and equipment		7,210,985		7,082,443
Less: Accumulated depreciation		2,997,620		2,954,555
		4,213,365		4,127,888
Construction work in progress		637,018		359,014
Total net property, plant and equipment		4,850,383		4,486,902
OTHER NON-CURRENT ASSETS:
Intangible assets - net		232,998		235,656
Regulatory assets, non-current		574,181		541,784
Pension plan assets		40,616		41,172
Other non-current assets		277,926		301,979
Total other non-current assets		1,125,721		1,120,591
TOTAL ASSETS	$	7,016,213	$	6,181,523
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Short-term debt and current portion of long-term debt (see Notes 5 and 11)	$	643,922	$	899,159
Accounts payable		282,966		292,851
Accrued taxes		29,022		22,580
Accrued interest		53,667		33,639
Customer deposits		27,594		29,308
Regulatory liabilities, current		3,956		23,371
Accrued and other current liabilities		20,135		27,547
Total current liabilities		1,061,262		1,328,455
NON-CURRENT LIABILITIES:
Long-term debt (see Notes 5 and 11)		3,677,403		2,576,798
Deferred income tax liabilities		368,960		361,488
Regulatory liabilities, non-current		507,764		527,224
Accrued other postretirement benefits		2,832		2,776
Asset retirement obligations		267,872		249,930
Other non-current liabilities		5,148		5,130
Total non-current liabilities		4,829,979		3,723,346
TOTAL LIABILITIES		5,891,241		5,051,801

COMMITMENTS AND CONTINGENCIES (see Note 8)
EQUITY:
Common shareholders’ equity
Common stock (no par value, 290,000,000 shares authorized; 108,907,318 shares issued and outstanding at March 31, 2024 and December 31, 2023)		—		—
Paid in capital		1,022,018		1,021,992
Accumulated other comprehensive income		36,680		29,294
Retained earnings		15,624		25,182
Total common shareholders’ equity		1,074,322		1,076,468
Noncontrolling interests		50,650		53,254
Total equity		1,124,972		1,129,722
TOTAL LIABILITIES AND EQUITY	$	7,016,213	$	6,181,523

See Notes to Condensed Consolidated Financial Statements.

F-98

IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Condensed Consolidated Statements of Cash Flows
(Unaudited)

	Three Months Ended March 31,
	2024			2023
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	14,610		$	19,115
Adjustments to reconcile net income to net cash (used in) / provided by operating activities:
Depreciation and amortization		80,433			69,852
Amortization of deferred financing costs and debt discounts		1,046			949
Deferred income taxes and investment tax credit adjustments - net		2,000			430
Allowance for equity funds used during construction		(831	)		(1,570	)
Loss on asset disposal		1,523			—
Change in certain assets and liabilities:
Accounts receivable		(59,739	)		10,463
Inventories		3,967			(411	)
Prepayments and other current assets		(782	)		(32,221	)
Accounts payable		(20,692	)		(15,339	)
Accrued and other current liabilities		(9,126	)		(4,090	)
Accrued taxes payable/receivable		8,429			8,034
Accrued interest		20,028			16,617
Pension and other postretirement benefit assets and liabilities		613			536
Current and non-current regulatory assets and liabilities		(86,217	)		83,926
Other - net		(3,395	)		(4,039	)
Net cash (used in) / provided by operating activities		(48,133	)		152,252
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(259,124	)		(143,258	)
Project development costs		(339	)		(1,166	)
Acquisitions		(47,948	)		—
Cost of removal payments		(10,268	)		(10,518	)
Net cash used in investing activities		(317,679	)		(154,942	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under revolving credit facilities		190,000			—
Repayments under revolving credit facilities		(150,000	)		—
Short-term borrowings from affiliate		92,000			—
Repayments of short-term borrowings		(392,000	)		—
Long-term borrowings		1,050,000			—
Distributions to shareholders		(26,720	)		(31,395	)
Distributions to noncontrolling interests		(52	)		—
Payments for financing fees		(13,892	)		(11	)
Proceeds received from termination of interest rate swaps		23,114			—
Net cash provided by / (used in) financing activities		772,450			(31,406	)
Net change in cash, cash equivalents and restricted cash		406,638			(34,096	)
Cash, cash equivalents and restricted cash at beginning of period		28,584			201,553
Cash, cash equivalents and restricted cash at end of period	$	435,222		$	167,457

Supplemental isclosures of cash flw information:
Cash paid during the period for:
Interest (net of amount capitalized)	$	20,885		$	14,562
Non-cash investing activities:
Accruals for capital expenditures	$	135,433		$	53,587
Changes to right-of-use assets - finance leases	$	72,008		$	899
Non-cash financing activities:
Changes to financing lease liabilities	$	(69,858	)	$	(899	)

See Notes to Condensed Consolidated Financial Statements.

F-99

 IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Condensed Consolidated Statements of Changes in Equity
For the Three Months Ended March 31, 2024 and 2023
(Unaudited)

	Common Shareholders’ Equity
	Common Stock
	Outstanding Shares		Amount		Paid in Capital			Accumulated Other Comprehensive Income			Retained Earnings /(Accumulated Deficit)			Total Common Shareholders’ Equity			Noncontrolling Interests
	(in thousands)
2024
Beginning Balance		108,907	$	—	$	1,021,992		$	29,294		$	25,182		$	1,076,468		$	53,254
Net income / (loss)						—			—			17,162			17,162			(2,552	)
Other comprehensive income						—			7,386			—			7,386			—
Distributions to shareholders						—			—			(26,720	)		(26,720	)		—
Distributions to noncontrolling interests						—			—			—			—			(52	)
Other						26			—			—			26			—
Balance at March 31, 2024		108,907	$	—	$	1,022,018		$	36,680		$	15,624		$	1,074,322		$	50,650
2023
Beginning Balance		108,907	$	—	$	1,068,357		$	22,269		$	(108	)	$	1,090,518		$	—
Net income						—			—			19,115			19,115			—
Other comprehensive loss						—			(7,174	)		—			(7,174	)		—
Distributions to shareholders(1)						(12,280	)		—			(19,115	)		(31,395	)		—
Other						31			—			—			31			—
Balance at March 31, 2023		108,907	$	—	$	1,056,108		$	15,095		$	(108	)	$	1,071,095		$	—

(1) IPALCO made return of capital payments of $12.3 million during the three months ended March 31, 2023 for the portion of current year distributions to shareholders in excess of current year net income at the time of distribution.

See Notes to Condensed Consolidated Financial Statements.

F-100

 

IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
For the Three Months Ended March 31, 2024 and 2023
(Unaudited)

1. OVERVIEW AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

IPALCO is a holding company incorporated under the laws of the state of Indiana. IPALCO 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 524,000 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”). 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 March 31, 2024, AES Indiana’s net electric generation capacity for winter is 3,070 MW and net summer capacity is 2,925 MW.

AES Indiana also owns and operates two renewable energy projects, including a 195 MW solar project located in Clinton County, Indiana (the “Hardy Hills Solar Project”), which achieved full commercial operations in May 2024, and a 106 MW wind facility located in Benton County, Indiana (the “Hoosier Wind Project”), which was acquired in February 2024. See Note 2, “Regulatory Matters — IRP Filings and Replacement Generation” for further information.

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. 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” to the audited Consolidated Financial Statements of IPALCO included in this prospectus.

F-101

Consolidation

The accompanying Financial Statements include the accounts of IPALCO Enterprises, Inc., AES Indiana and Mid-America Capital Resources, Inc., a non-regulated wholly-owned subsidiary of IPALCO. Furthermore, VIEs in which the Company has an ownership interest and is the primary beneficiary, thus controlling the VIE, have been consolidated. All significant intercompany amounts have been eliminated in consolidation.

Interim Financial Presentation

The accompanying unaudited condensed consolidated financial statements and footnotes have been prepared in accordance with GAAP, as contained in the FASB ASC, for interim financial information and Article 10 of Regulation S-X issued by the SEC. Accordingly, they do not include all the information and footnotes required by GAAP for annual fiscal reporting periods. In the opinion of management, the interim financial information includes all adjustments of a normal recurring nature necessary for a fair presentation of the results of operations, financial position, comprehensive income, changes in equity, and cash flows. The results of operations for the three months ended March 31, 2024 are not necessarily indicative of expected results for the year ending December 31, 2024. The accompanying condensed consolidated financial statements are unaudited and should be read in conjunction with the 2023 audited consolidated financial statements and notes thereto, which are included elsewhere in this prospectus.

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 revenues 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.

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Cash, Cash Equivalents and Restricted Cash

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

	March 31, 2024		December 31, 2023
	(in thousands)
Cash, cash equivalents and restricted cash:
Cash and cash equivalents	$	435,217	$	28,579
Restricted cash (included in Prepayments and other current assets)		5		5
Total cash, cash equivalents and restricted cash	$	435,222	$	28,584

Accounts Receivable and Allowance for Credit Losses

The following table summarizes our accounts receivable balances at March 31, 2024 and December 31, 2023:

	March 31, 2024			December 31, 2023
	(in thousands)
Accounts receivable, net:
Customer receivables	$	166,812		$	125,715
Unbilled revenue		108,806			91,463
Amounts due from related parties		6,434			5,178
Other		15,373			13,848
Allowance for credit losses		(3,765	)		(2,283	)
Total accounts receivable, net	$	293,660		$	233,921

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

	For the Three Months Ended March 31,
	2024			2023
	(in thousands)
Allowance for credit losses:
Beginning balance	$	2,283		$	1,117
Current period provision		1,022			983
Write-offs charged against allowance		(159	)		(1,522	)
Recoveries collected		619			485
Ending Balance	$	3,765		$	1,063

Inventories

The following table summarizes our inventories balances at March 31, 2024 and December 31, 2023:

	March 31, 2024		December 31, 2023
	(in thousands)
Inventories:
Fuel	$	69,185	$	77,198
Materials and supplies, net		67,820		66,392
Total inventories	$	137,005	$	143,590

ARO

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 for the three months ended March 31, 2024 and 2023, respectively:

	For the Three Months Ended March 31,
	2024			2023
	(in thousands)
Balance as of January 1		249,930			218,729
Liabilities incurred		7,778			69
Liabilities settled		(1,098	)		(3,025	)
Revisions to cash flow and timing estimates		8,525			—
Accretion expense		2,737			2,639
Balance as of March 31		267,872			218,412

ARO liabilities incurred in 2024 primarily relate to decommissioning costs for AES Indiana’s renewable projects, including liabilities incurred through acquisition of Hoosier Wind Project, LLC. Revisions to AES Indiana’s ARO liabilities during 2024 primarily relate to groundwater treatment measures for Eagle Valley ash ponds. As of March 31, 2024 and December 31, 2023, AES Indiana did not have any assets that are legally restricted for settling its ARO liability. For further information on AES Indiana’s ARO, see Note 3, “Property, Plant and Equipment—ARO” to the audited Consolidated Financial Statements of IPALCO included in this prospectus.

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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. AFUDC equity and AFUDC debt were as follows for the periods indicated:

	For the Three Months Ended March 31,
	2024		2023
	(in thousands)
AFUDC equity		831		1,570
AFUDC debt		5,276		2,985

Intangible Assets

Finite-lived intangible assets primarily include capitalized software and project development intangible assets amortized over their useful lives. These capitalized software and project development intangible assets range from 7 to 35 year-weighted average amortization periods, respectively.

The following table presents information related to the Company’s intangible assets, including the gross amount capitalized and related amortization:

	March 31, 2024		December 31, 2023
	(in thousands)
Capitalized software	$	265,224	$	261,872
Project development intangible assets		83,940		84,097
Other		797		797
Less: Accumulated amortization		116,963		111,110
Intangible assets – net	$	232,998	$	235,656

	For the Three Months Ended March 31,
	2024		2023
Amortization expense	$	6,940	$	2,987

Accumulated Other Comprehensive Income

The amounts reclassified out of AOCI by component during the three months ended March 31, 2024 and 2023 are as follows (in Thousands):

	Affected line item in the Condensed Consolidated	Three Months Ended March 31,
Details about AOCI components	Statements of Operations		2024			2023
Net losses on cash flow hedges (Note 4):	Interest expense	$	1,012		$	1,807
	Income tax effect		(252	)		(449	)
Total reclassifications for the period, net of income taxes		$	760		$	1,358

See Note 4, “Derivative Instruments and Hedging Activities - Cash Flow Hedges” for further information on the changes in the components of AOCI.

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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
2023-07 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.	This ASU only affects disclosures, which will be provided when the amendment becomes effective.
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.	This ASU only affects disclosures, which will be provided when the amendment becomes effective.

2. REGULATORY MATTERS

Regulatory Rate Review

On April 17, 2024, the IURC issued an order (the “2024 Rate Order”) approving the Stipulation and Settlement Agreement that AES Indiana entered into on November 22, 2023, with the OUCC and the other intervening parties in AES Indiana’s base rate case filing. Among other matters and consistent with the Stipulation and Settlement Agreement, the 2024 Rate Order approves an increase in AES Indiana’s total annual operating revenue of $71 million for AES Indiana’s electric service and provides a return on common equity of 9.9% and cost of long-term debt of 4.90% on a rate base of approximately $3.5 billion. Updated customer rates and charges are expected to be effective in May 2024.

Storm Outage Restoration Inquiry

On July 11, 2023, the OUCC and the Citizens Action Coalition of Indiana (“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. In its 2024 Rate Order, the IURC stated, "The uncontested evidence established that AES Indiana’s response to the June 29 storm was equal to or better than the response provided by other utilities, as evidenced by a comparison of storm response with the information other utilities provided at a September 28, 2023 technical conference regarding their respective response. The evidence also established that the priorities used to guide each utility’s restoration efforts and overall effort were the same." Contemporaneous with the 2024 Rate Order, this Joint Petition was dismissed with prejudice.

IRP Filings and Replacement Generation

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.

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Petersburg Repowering

On March 11, 2024, AES Indiana filed for approval of a CPCN with the IURC to convert Petersburg Units 3 and 4 from coal to natural gas and to recover costs through future rates. The conversion of Unit 3 is expected to begin in February 2026 and be completed by June 2026 and the conversion of Unit 4 is expected to begin in June 2026 and be completed by December 2026. A hearing for this case is expected to be held in August 2024, and we expect the IURC to issue an order on this proceeding during the fourth quarter of 2024.

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. Construction was completed for the remaining MW and the project achieved full commercial operations in May 2024.

Hoosier Wind Project

In August 2023, AES Indiana filed for IURC issuance of a CPCN approving the acquisition of 100% of the membership interests in Hoosier Wind Project, LLC (the “Hoosier Wind Project”), which is an existing 106 MW wind facility located in Benton County, Indiana. IURC approval was received on January 24, 2024, and the transaction closed on February 29, 2024. Immediately following the acquisition of the Hoosier Wind Project, the legal entity was dissolved by AES Indiana. The transaction was accounted for as an asset acquisition that did not meet the definition of a business. Of the total consideration transferred of $92.6 million, including transaction costs, approximately $48.8 million was allocated to the identifiable assets acquired on a relative fair value basis, primarily consisting of tangible wind farm assets and typical working capital items. The remaining consideration was allocated to the termination of the pre-existing power purchase agreement between AES Indiana and the Hoosier Wind Project, which was deferred as a long-term regulatory asset.

3. 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. For further information on our valuation techniques and policies, see Note 4, “Fair Value” to the audited Consolidated Financial Statements of IPALCO included in this prospectus.

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 Condensed 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 periods covered by this report. Any unrealized gains or losses are recorded in “Other (expense) / income, net” on the accompanying Condensed Consolidated Statements of Operations.

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 revenues or costs will be flowed through to customers through the FAC. As such, there is no impact on our Condensed Consolidated Statements of Operations.

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Interest Rate Hedges

In March 2024, IPALCO’s interest rate hedges with a combined notional value of $400.0 million were terminated in conjunction with the issuance of the 2034 IPALCO Notes. See also Note 4, “Derivative Instruments and Hedging Activities - Cash Flow Hedges” for further information.

Recurring Fair Value Measurements

The fair value of assets and liabilities at March 31, 2024 and December 31, 2023 measured on a recurring basis and the respective category within the fair value hierarchy for IPALCO was determined as follows:

	Fair Value as of March 31, 2024								Fair Value as of December 31, 2023
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
	(in thousands)
Financial assets:
VEBA investments:
Money market funds	$	86	$	—	$	—	$	86	$	127	$	—	$	—	$	127
Mutual funds		3,560		—		—		3,560		3,425		—		—		3,425
Total VEBA investments		3,646		—		—		3,646		3,552		—		—		3,552
FTRs		—		—		393		393		—		—		1,388		1,388
Interest rate hedges		—		—		—		—		—		14,294		—		14,294
Total financial assets measured at fair value	$	3,646	$	—	$	393	$	4,039	$	3,552	$	14,294	$	1,388	$	19,234

The following table presents 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):

	Three Months Ended March 31,
	2024			2023
	(in thousands)
Beginning Balance	$	1,388		$	7,545
Settlements		(995	)		(4,986	)
Ending Balance	$	393		$	2,559

Financial Instruments not Measured at Fair Value in the Condensed 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:

	March 31, 2024				December 31, 2023
	Face Value		Fair Value		Face Value		Fair Value
	(in thousands)
Fixed-rate	$	4,083,800	$	3,875,858	$	3,033,800	$	2,860,467
Variable-rate		195,000		195,000		455,000		455,000
Total indebtedness	$	4,278,800	$	4,070,858	$	3,488,800	$	3,315,467

F-108

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

● unamortized deferred financing costs of $36.4 million and $24.8 million at March 31, 2024 and December 31, 2023, respectively; and

● unamortized discounts of $9.7 million and $6.8 million at March 31, 2024 and December 31, 2023, respectively.

4. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

For further information on the Company’s derivative and hedge accounting policies, see Note 1, “Overview and Summary of Significant Accounting Policies—Financial Derivatives” and Note 5, “Derivative Instruments and Hedging Activities” to the audited Consolidated Financial Statements of IPALCO included in this prospectus.

At March 31, 2024, AES Indiana’s outstanding derivative instruments were as follows:

Commodity	Accounting Treatment	Unit	Notional		Sales		Net Notional
			(in thousands)
FTRs	Not Designated	MWh		1,399		—		1,399

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 are determined by current public market prices. IPALCO’s three forward-starting interest rate swaps with a combined notional value of $400 million were terminated for total cash proceeds of $23.1 million, in conjunction with the issuance of the 2034 IPALCO Notes in March 2024. The AOCI associated with the interest rate swaps through the date of the termination will be amortized out of AOCI into interest expense over the 10-year life of the 2034 IPALCO Notes.

The following table provides information on gains or losses recognized in AOCI for the cash flow hedges for the periods indicated:

	Interest Rate Hedges for the Three Months Ended March 31,
	2024		2023
	$ in thousands (net of tax)
Beginning accumulated derivative gain	$	29,294	$	22,269
Net gains / (losses) associated with current period hedging transactions		6,626		(8,532	)
Net losses reclassified to interest expense, net of tax		760		1,358
Ending accumulated derivative gain in AOCI	$	36,680	$	15,095
Net gain expected to be reclassified to earnings in the next twelve months	$	1,737

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 Condensed 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.

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 Condensed Consolidated Statements of Operations on an accrual basis.

F-109

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 March 31, 2024 and December 31, 2023, 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):

Commodity	Hedging Designation	Balance sheet classification	March 31, 2024		December 31, 2023
FTRs	Not a Cash Flow Hedge	Derivative assets, current	$	393	$	1,388
Interest rate hedges	Cash Flow Hedge	Derivative assets, current	$	—	$	14,294

5. DEBT

Long-Term Debt

The following table presents our long-term debt:

Series	Due	March 31, 2024			December 31, 2023
		(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
5.70%	April 2054		650,000			—
Unamortized discount – net			(8,266	)		(6,449	)
Deferred financing costs			(26,369	)		(19,058	)
Total AES Indiana first mortgage bonds			2,769,165			2,128,293
Total long-term debt – AES Indiana			2,769,165			2,128,293
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
5.75% Senior Secured Notes	April 2034		400,000			—
Unamortized discount – net			(1,423	)		(319	)
Deferred financing costs			(9,044	)		(4,554	)
Total long-term debt – IPALCO			1,269,533			875,127
Total consolidated IPALCO long-term debt			4,038,698			3,003,420
Less: current portion of long-term debt			445,000			445,000
Net consolidated IPALCO long-term debt		$	3,593,698		$	2,558,420

(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

As of March 31, 2024 and December 31, 2023, AES Indiana had $195.0 million and $155.0 million in outstanding borrowings on the committed Credit Agreement, respectively.

Significant Transactions

AES Indiana First Mortgage Bonds and AES Indiana Term Loan

In March 2024, AES Indiana issued $650 million aggregate principal amount of first mortgage bonds, 5.70% Series, due April 2054, pursuant to Rule 144A and Regulation S under the Securities Act. The net proceeds from this offering of approximately $640.5 million, after deducting the initial purchasers’ discounts and fees and expenses for the offering, were used to repay the $300 million Term Loan Agreement, outstanding borrowings on the Credit Agreement and for general corporate purposes.

IPALCO’s Senior Secured Notes

In March 2024, IPALCO completed the sale of the 2034 IPALCO Notes pursuant to Rule 144A and Regulation S under the Securities Act of 1933, as amended. The net proceeds from this offering of $394.0 million, together with cash on hand, were used to redeem the 2024 IPALCO Notes on April 13, 2024, and to pay certain related fees and expenses.

Other

In February 2024, AES Indiana received a $92 million short-term loan from AES. This loan was fully repaid in March 2024.

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. In addition, IPALCO’s outstanding debt obligations are secured by its pledge of all of the outstanding common stock of AES Indiana.

6. INCOME TAXES

IPALCO’s provision for income taxes is based on the estimated annual effective tax rate, plus discrete items. The effective combined state and federal income tax rate was 21.1% for the three months ended March 31, 2024, as compared to 21.4% for the three months ended March 31, 2023. The rate for the three months ended March 31, 2024 is different from the combined federal and state statutory rate of 24.9% primarily due to the flowthrough of the net tax benefit related to the reversal of excess deferred taxes of AES Indiana, which was partially offset by the net tax expense related to the amortization of allowance for equity funds used during construction.

IPALCO’s income tax expense for the three months ended March 31, 2024, was calculated using the estimated annual effective income tax rate for 2024 of 21.4% on ordinary income. Management estimates the annual effective tax rate based on its forecast of annual pre-tax income or loss. Starting in the second quarter of 2024, the annual effective tax rate is expected to increase due to the timing of the implementation of base rates in the 2024 Rate Order and the resulting change to pre-tax income and the flowthrough of the reversal of excess deferred taxes. See Note 2, “Regulatory Matters - Regulatory Rate Review” for further information.

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.

F-111

7. BENEFIT PLANS

The following table presents the net periodic benefit cost of the Pension Plans combined:

	For the Three Months Ended March 31,
	2024			2023
	(in thousands)
Components of net periodic benefit cost:
Service cost	$	1,253		$	1,297
Interest cost		6,739			7,455
Expected return on plan assets		(7,443	)		(8,276	)
Amortization of prior service cost		475			543
Amortization of actuarial loss		1,207			1,536
Net periodic benefit cost	$	2,231		$	2,555

The components of net periodic benefit cost other than service cost are included in “Other (expense) / income, net” in the Condensed Consolidated Statements of Operations.

In addition, AES Indiana provides postretirement health care benefits to certain active or retired employees and the spouses of certain active or retired employees. These postretirement health care benefits and the related unfunded obligation were not material to the Financial Statements in the periods covered by this report.

8. COMMITMENTS AND CONTINGENCIES

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 March 31, 2024 and December 31, 2023, respectively.

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 CCR; 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 March 31, 2024 and December 31, 2023, respectively.

9. BUSINESS SEGMENTS

IPALCO manages its business through one reportable operating segment, the Utility segment. The primary segment performance measure is income / (loss) 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. The “Other” nonutility category primarily includes the 2024 IPALCO Notes, 2030 IPALCO Notes, 2034 IPALCO Notes and related interest expense, balances 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. See Note 1, "Overview and Summary of Significant Accounting Policies" to the audited Consolidated Financial Statements of IPALCO included in this prospectus for further information.

F-112

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

	Three Months Ended March 31, 2024							Three Months Ended March 31, 2023
	Utility		Other			Total		Utility		Other			Total
Revenue	$	407,801	$	—		$	407,801	$	491,386	$	—		$	491,386
Depreciation and amortization	$	80,433	$	—		$	80,433	$	69,852	$	—		$	69,852
Interest expense	$	32,377	$	11,271		$	43,648	$	23,875	$	10,968		$	34,843
Income/(loss) before income tax	$	28,971	$	(10,452	)	$	18,519	$	35,502	$	(11,173	)	$	24,329

	As of March 31, 2024						As of December 31, 2023
	Utility		Other		Total		Utility		Other		Total
Total assets	$	6,570,826	$	445,387	$	7,016,213	$	6,129,581	$	51,942	$	6,181,523

10. 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. Please see Note 13, “Revenue” to the audited Consolidated Financial Statements of IPALCO included in this prospectus for further discussion of our retail, wholesale and miscellaneous revenue.

AES Indiana’s revenue from contracts with customers were $401.2 million and $482.9 million for the three months ended March 31, 2024 and 2023, respectively. The following table presents our revenue from contracts with customers and other revenue (in thousands):

	For the Three Months Ended March 31,
	2024		2023
Retail Revenue
Retail revenue from contracts with customers:
Residential	$	180,969	$	204,748
Small commercial and industrial		63,196		69,879
Large commercial and industrial		125,209		170,978
Public lighting		14,655		2,614
Other(1)		2,179		4,657
Total retail revenue from contracts with customers		386,208		452,876
Alternative revenue programs		5,706		7,739
Wholesale Revenue
Wholesale revenue from contracts with customers		12,622		24,251
Miscellaneous Revenue
Capacity revenue		7		4,848
Transmission and other revenue		2,380		906
Total miscellaneous revenue from contracts with customers		2,387		5,754
Other miscellaneous revenue(2)		878		766
Total Revenue	$	407,801	$	491,386

(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.

F-113

The balances of receivables from contracts with customers were $276.1 million and $218.8 million as of March 31, 2024 and December 31, 2023, respectively. Payment terms for all receivables from contracts with customers typically do not extend beyond 30 days, unless a customer qualifies for payment extension.

11. 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 Condensed Consolidated Balance Sheets related to lease asset and liability balances as of the periods indicated (in thousands):

	Consolidated Balance Sheet Classification	March 31, 2024		December 31, 2023
Assets:
Right-of-use assets — finance leases	Other non-current assets	$	88,249	$	16,357
Liabilities:
Finance lease liabilities (current)	Short-term debt and current portion of long-term debt	$	4,312	$	—
Finance lease liabilities (noncurrent)	Long-term debt		83,315		17,769
Total finance lease liabilities		$	87,627	$	17,769

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

Lease Term and Discount Rate	March 31, 2024	December 31, 2023
Weighted-average remaining lease term — finance leases	36 years	35 years
Weighted-average discount rate — finance leases	5.54%	5.30%

The following table summarizes the components of lease expense recognized in “Operating Costs and Expenses” on the accompanying Condensed Consolidated Statements of Operations for the periods indicated (in thousands):

	Three Months Ended March 31,
	2024		2023
Components of Lease Cost:
Finance lease cost:
Amortization of right-of-use assets	$	116	$	102
Interest on lease liabilities		241		226
Total lease cost	$	357	$	328

Operating cash outflows from finance leases were $2.1 million and $0.0 million for the three months ended March 31, 2024 and 2023, respectively.

F-114

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

	Finance Leases
2024	$	1,687
2025		4,446
2026		4,535
2027		4,625
2028		4,718

Thereafter		315,194
Total	$	335,205
Less: Imputed interest		(247,578	)
Present value of lease payments	$	87,627

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 revenues 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):

	Three Months Ended March 31,
	2024		2023
Total lease revenue	$	533	$	401

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):

	March 31, 2024			December 31, 2023
Property, Plant and Equipment, Net:
Gross assets		4,341			4,341
Less: Accumulated depreciation		(1,264	)		(1,222	)
Net assets		3,077			3,119

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

The following table shows the future lease receipts as of March 31, 2024 for the remainder of 2024 through 2028 and thereafter (in thousands):

	Operating Leases
2024	$	408
2025		553
2026		554
2027		554
2028		354
Thereafter		891
Total	$	3,314

F-115

AES INDIANA and SUBSIDIARIES

Condensed Consolidated Statements of Operations
(Unaudited)

	Three Months Ended March 31,
	2024			2023
	(In Thousands)
REVENUE	$	407,801		$	491,386
OPERATING COSTS AND EXPENSES:
Fuel		102,919			189,730
Power purchased		38,633			49,890
Operation and maintenance		115,246			117,722
Depreciation and amortization		80,433			69,852
Taxes other than income taxes		7,895			7,430
Loss on asset disposal		1,523			—
Total operating costs and expenses		346,649			434,624
OPERATING INCOME		61,152			56,762
OTHER (EXPENSE) / INCOME, NET:
Allowance for equity funds used during construction		831			1,570
Interest expense		(32,377	)		(23,875	)
Other (expense) / income, net		(634	)		1,045
Total other expense, net		(32,180	)		(21,260	)
INCOME BEFORE INCOME TAX		28,972			35,502
Income tax expense		5,688			6,545
NET INCOME		23,284			28,957
Net loss attributable to noncontrolling interests		(2,552	)		—
NET INCOME APPLICABLE TO COMMON STOCK	$	25,836		$	28,957

See Notes to Condensed Consolidated Financial Statements.

F-116

AES INDIANA and SUBSIDIARIES

Condensed Consolidated Balance Sheets
(Unaudited)

	March 31, 2024		December 31, 2023
ASSETS	(In Thousands)
CURRENT ASSETS:
Cash and cash equivalents	$	23,513	$	25,767
Accounts receivable, net of allowance for credit losses of $3,765 and $2,283, respectively		293,725		233,970
Inventories		137,005		143,590
Regulatory assets, current		112,121		89,419
Taxes receivable		4,735		5,140
Prepayments and other current assets		27,255		27,741
Total current assets		598,354		525,627
NON-CURRENT ASSETS:
Property, plant and equipment		7,210,985		7,082,443
Less: Accumulated depreciation		2,997,620		2,954,555
		4,213,365		4,127,888
Construction work in progress		637,018		359,014
Total net property, plant and equipment		4,850,383		4,486,902
OTHER NON-CURRENT ASSETS:
Intangible assets – net		232,998		235,656
Regulatory assets, non-current		574,181		541,784
Pension plan assets		40,616		41,172
Other non-current assets		274,294		298,439
Total other non-current assets		1,122,089		1,117,051
TOTAL ASSETS	$	6,570,826	$	6,129,580
LIABILITIES AND SHAREHOLDER’S EQUITY
CURRENT LIABILITIES:
Short-term debt and current portion of long-term debt (see Notes 5 and 10)	$	239,251	$	494,685
Accounts payable		282,184		292,835
Accrued taxes		29,022		22,580
Accrued interest		42,887		25,245
Customer deposits		27,594		29,308
Regulatory liabilities, current		3,956		23,371
Accrued and other current liabilities		29,936		34,748
Total current liabilities		654,830		922,772
NON-CURRENT LIABILITIES:
Long-term debt (see Notes 5 and 10)		2,812,541		2,106,146
Deferred income tax liabilities		350,636		342,557
Regulatory liabilities, non-current		507,764		527,224
Accrued other postretirement benefits		2,832		2,776
Asset retirement obligations		267,872		249,930
Other non-current liabilities		5,147		5,129
Total non-current liabilities		3,946,792		3,233,762
Total liabilities		4,601,622		4,156,534
COMMITMENTS AND CONTINGENCIES (see Note 8)
EQUITY:
Common shareholder’s equity
Common stock (no par value, 20,000,000 shares authorized; 17,206,630 shares issued and outstanding at March 31, 2024 and December 31, 2023)		324,537		324,537
Paid in capital		1,193,224		1,193,199
Retained earnings		400,793		402,056
Total shareholder’s equity		1,918,554		1,919,792
Noncontrolling interests		50,650		53,254
Total equity		1,969,204		1,973,046
TOTAL LIABILITIES AND EQUITY	$	6,570,826	$	6,129,580

 

See Notes to Condensed Consolidated Financial Statements.

F-117

AES INDIANA and SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows

(Unaudited)

	Three Months Ended
	March 31,
	2024			2023
	(In Thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	23,284		$	28,957
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		80,433			69,852
Amortization of deferred financing costs and debt discounts		666			580
Deferred income taxes and investment tax credit adjustments - net		5,052			459
Allowance for equity funds used during construction		(831	)		(1,570	)
Loss on asset disposal		1,523			—
Change in certain assets and liabilities:
Accounts receivable		(59,754	)		10,453
Inventories		3,967			(411	)
Prepayments and other current assets		(739	)		(32,198	)
Accounts payable		(21,458	)		(15,453	)
Accrued and other current liabilities		(9,126	)		(4,090	)
Accrued taxes payable/receivable		7,155			9,336
Accrued interest		17,642			15,316
Pension and other postretirement benefit assets and liabilities		613			536
Current and non-current regulatory assets and liabilities		(86,217	)		83,926
Other		(5,490	)		(5,884	)
Net cash (used in) / provided by operating activities		(43,280	)		159,809
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(259,124	)		(143,258	)
Project development costs		(339	)		(1,166	)
Acquisitions		(47,948	)		—
Cost of removal payments		(10,268	)		(10,518	)
Net cash used in investing activities		(317,679	)		(154,942	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under revolving credit facilities		190,000			—
Repayments under revolving credit facilities		(150,000	)		—
Short-term borrowings from affiliate		92,000			—
Repayments of short-term borrowings		(392,000	)		—
Long-term borrowings		650,000			—
Dividends on common stock		(24,500	)		(39,000	)
Distributions to noncontrolling interests		(52	)		—
Payments for financing fees		(6,743	)		(11	)
Net cash provided by / (used in) financing activities		358,705			(39,011	)
Net change in cash, cash equivalents and restricted cash		(2,254	)		(34,144	)
Cash, cash equivalents and restricted cash at beginning of period		25,772			199,108
Cash, cash equivalents and restricted cash at end of period	$	23,518		$	164,964
Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest (net of amount capitalized)	$	13,392		$	7,069
Non-cash investing activities:
Accruals for capital expenditures	$	135,433		$	53,257
Changes to right-of-use assets - finance leases	$	72,008		$	899
Non-cash financing activities:
Changes to financing lease liabilities	$	(69,858	)	$	(899	)

See Notes to Condensed Consolidated Financial Statements.

F-118

AES INDIANA and SUBSIDIARIES

Consolidated Statements of Changes in Equity

For the Three Months Ended March 31, 2024 and 2023

	Common Shareholder’s Equity
	Common Stock
	Outstanding Shares		Amount		Paid in Capital		Retained Earnings			Total Common Shareholder’s Equity			Noncontrolling Interests
	(in Thousands)
2024
Balance at January 1, 2024		17,207	$	324,537	$	1,193,199	$	402,056		$	1,919,792		$	53,254
Net income				—		—		25,836			25,836			(2,552	)
Cash dividends declared on common stock				—		—		(27,099	)		(27,099	)		—
Distributions to noncontrolling interests						—		—			—			(52	)
Other				—		25		—			25			—
Balance at March 31, 2024		17,207	$	324,537	$	1,193,224	$	400,793		$	1,918,554		$	50,650
2023
Balance at January 1, 2023		17,207	$	324,537	$	1,193,107	$	426,066		$	1,943,710		$	—
Net income				—		—		28,957			28,957			—
Cash dividends declared on common stock				—		—		(41,600	)		(41,600	)		—
Other				—		30		—			30			—
Balance at March 31, 2023		17,207	$	324,537	$	1,193,137	$	413,423		$	1,931,097		$	—

See Notes to Condensed Consolidated Financial Statements.

F-119

AES INDIANA and SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

For the Three Months Ended March 31, 2024 and 2023

(Unaudited)

For a list of certain abbreviations or acronyms used in the Notes to Condensed Consolidated Financial Statements, see “Glossary of Terms” included in the beginning of this report.

1. OVERVIEW AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

IPL (“the Company”), 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 524,000 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”). 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 March 31, 2024, AES Indiana’s net electric generation capacity for winter is 3,070 MW and net summer capacity is 2,925 MW.

AES Indiana also owns and operates two renewable energy projects, including a 195 MW solar project located in Clinton County, Indiana (the “Hardy Hills Solar Project”), which achieved full commercial operations in May 2024, and a 106 MW wind facility located in Benton County, Indiana (the “Hoosier Wind Project”), which was acquired in February 2024. See Note 2, “Regulatory Matters - IRP Filings and Replacement Generation” for further information.

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. 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” to the audited Consolidated Financial Statements of IPALCO included in this prospectus.

Consolidation

The accompanying 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, have been consolidated. All significant intercompany amounts have been eliminated in consolidation.

Interim Financial Presentation

The accompanying unaudited condensed consolidated financial statements and footnotes have been prepared in accordance with GAAP, as contained in the FASB ASC, for interim financial information and Article 10 of Regulation S-X issued by the SEC. Accordingly, they do not include all the information and footnotes required by GAAP for annual fiscal reporting periods. In the opinion of management, the interim financial information includes all adjustments of a normal recurring nature necessary for a fair presentation of the results of operations, financial position, comprehensive income, changes in equity, and cash flows. The results of operations for the three months ended March 31, 2024 are not necessarily indicative of expected results for the year ending December 31, 2024. The accompanying condensed consolidated financial statements are unaudited and should be read in conjunction with the 2023 audited Consolidated Financial Statements and notes thereto, which are included in this prospectus. AES Indiana has evaluated subsequent events through May 2, 2024, the date of this report.

F-120

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 revenues 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, Cash Equivalents and Restricted Cash

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

	March 31, 2024		December 31, 2023
	(In Thousands)
Cash, cash equivalents and restricted cash
Cash and cash equivalents	$	23,513	$	25,767
Restricted cash (included in Prepayments and other current assets)		5		5
Total cash, cash equivalents and restricted cash	$	23,518	$	25,772

Accounts Receivable and Allowance for Credit Losses

The following table summarizes our accounts receivable balances at March 31, 2024 and December 31, 2023:

	March 31, 2024			December 31, 2023
	(In Thousands)
Accounts receivable, net
Customer receivables	$	166,812		$	125,715
Unbilled revenue		108,806			91,463
Amounts due from related parties		6,499			5,227
Other		15,373			13,848
Allowance for credit losses		(3,765	)		(2,283	)
Total accounts receivable, net	$	293,725		$	233,970

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

	For the Three Months Ended March 31,
	2024			2023
	($ in Thousands)
Allowance for credit losses:
Beginning balance	$	2,283		$	1,117
Current period provision		1,022			983
Write-offs charged against allowance		(159	)		(1,522	)
Recoveries collected		619			485
Ending Balance	$	3,765		$	1,063

F-121

Inventories

The following table summarizes our inventories balances at March 31, 2024 and December 31, 2023:

	March 31, 2024		December 31, 2023
	(In Thousands)
Inventories
Fuel	$	69,185	$	77,198
Materials and supplies, net		67,820		66,392
Total inventories	$	137,005	$	143,590

ARO

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 for the three months ended March 31, 2024 and 2023, respectively:

	For the Three Months Ended March 31,
	2024			2023
	(In Thousands)
Balance as of January 1	$	249,930		$	218,729
Liabilities incurred		7,778			69
Liabilities settled		(1,098	)		(3,025	)
Revisions to cash flow and timing estimates		8,525			—
Accretion expense		2,737			2,639
Balance as of March 31	$	267,872		$	218,412

ARO liabilities incurred in 2024 primarily relate to decommissioning costs for AES Indiana’s renewable projects, including liabilities incurred through acquisition of Hoosier Wind Project, LLC. Revisions to AES Indiana’s ARO liabilities during 2024 primarily relate to groundwater treatment measures for Eagle Valley ash ponds. As of March 31, 2024 and December 31, 2023, AES Indiana did not have any assets that are legally restricted for settling its ARO liability. For further information on AES Indiana’s ARO, see Note 3, “Property, Plant and Equipment—ARO” to the audited Consolidated Financial Statements of IPALCO included in this prospectus.

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. AFUDC equity and AFUDC debt were as follows for the periods indicated:

	For the Three Months Ended March 31,
	2024		2023
	(In Thousands)
AFUDC equity	$	831	$	1,570
AFUDC debt	$	5,276	$	2,985

Intangible Assets

Finite-lived intangible assets primarily include capitalized software and project development intangible assets amortized over their useful lives. These capitalized software and project development intangible assets range from 7 to 35 year-weighted average amortization periods, respectively.

F-122

The following table presents information related to the Company’s intangible assets, including the gross amount capitalized and related amortization:

	March 31, 2024		December 31, 2023
	$ in thousands
Capitalized software	$	265,224	$	261,872
Project development intangible assets		83,940		84,097
Other		797		797
Less: Accumulated amortization		116,963		111,110
Intangible assets – net	$	232,998	$	235,656

	For the Three Months Ended March 31,
	2024		2023
Amortization expense	$	6,940	$	2,987

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
2023-07 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.	This ASU only affects disclosures, which will be provided when the amendment becomes effective.
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.	This ASU only affects disclosures, which will be provided when the amendment becomes effective.

2. REGULATORY MATTERS

Regulatory Rate Review

On April 17, 2024, the IURC issued an order (the “2024 Rate Order”) approving the Stipulation and Settlement Agreement that AES Indiana entered into on November 22, 2023, with the OUCC and the other intervening parties in AES Indiana’s base rate case filing. Among other matters and consistent with the Stipulation and Settlement Agreement, the 2024 Rate Order approves an increase in AES Indiana’s total annual operating revenue of $71 million for AES Indiana’s electric service and provides a return on common equity of 9.9% and cost of long-term debt of 4.90% on a rate base of approximately $3.5 billion. Updated customer rates and charges are expected to be effective in May 2024.

Storm Outage Restoration Inquiry

On July 11, 2023, the OUCC and the Citizens Action Coalition of Indiana (“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. In its 2024 Rate Order, the IURC stated, “The uncontested evidence established that AES Indiana’s response to the June 29 storm was equal to or better than the response provided by other utilities, as evidenced by a comparison of storm response with the information other utilities provided at a September 28, 2023 technical conference regarding their respective response. The evidence also established that the priorities used to guide each utility’s restoration efforts and overall effort were the same.” Contemporaneous with the 2024 Rate Order, this Joint Petition was dismissed with prejudice.

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IRP Filings and Replacement Generation

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.

Petersburg Repowering

On March 11, 2024, AES Indiana filed for approval of a CPCN with the IURC to convert Petersburg Units 3 and 4 from coal to natural gas and to recover costs through future rates. The conversion of Unit 3 is expected to begin in February 2026 and be completed by June 2026 and the conversion of Unit 4 is expected to begin in June 2026 and be completed by December 2026. A hearing for this case is expected to be held in August 2024, and we expect the IURC to issue an order on this proceeding during the fourth quarter of 2024.

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. Construction was completed for the remaining MW and the project achieved full commercial operations in May 2024.

Hoosier Wind Project

In August 2023, AES Indiana filed for IURC issuance of a CPCN approving the acquisition of 100% of the membership interests in Hoosier Wind Project, LLC (the “Hoosier Wind Project”), which is an existing 106 MW wind facility located in Benton County, Indiana. IURC approval was received on January 24, 2024, and the transaction closed on February 29, 2024. Immediately following the acquisition of the Hoosier Wind Project, the legal entity was dissolved by AES Indiana. The transaction was accounted for as an asset acquisition that did not meet the definition of a business. Of the total consideration transferred of $92.6 million, including transaction costs, approximately $48.8 million was allocated to the identifiable assets acquired on a relative fair value basis, primarily consisting of tangible wind farm assets and typical working capital items. The remaining consideration was allocated to the termination of the pre-existing power purchase agreement between AES Indiana and the Hoosier Wind Project, which was deferred as a long-term regulatory asset.

3. 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. For further information on AES Indiana’s valuation techniques and policies, see Note 4, “Fair Value” to the audited Consolidated Financial Statements of IPALCO included in this prospectus.

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 revenues or costs will be flowed through to customers through the FAC. As such, there is no impact on our Condensed Consolidated Statements of Operations.

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Recurring Fair Value Measurements

The fair value of assets and liabilities at March 31, 2024 and December 31, 2023 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 March 31, 2024								Fair Value as of December 31, 2023
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
	(In Thousands)
Financial assets:
FTRs	$	—	$	—	$	393	$	393	$	—	$	—	$	1,388	$	1,388
Total financial assets measured at fair value	$	—	$	—	$	393	$	393	$	—	$	—	$	1,388	$	1,388

The following table presents 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):

	Three Months Ended March 31,
	2024			2023
Beginning Balance	$	1,388		$	7,545
Settlements		(995	)		(4,986	)
Ending Balance	$	393		$	2,559

Financial Instruments Not Measured at Fair Value in the Condensed 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:

	March 31, 2024				December 31, 2023
	Face Value		Fair Value		Face Value		Fair Value
	(In Thousands)
Fixed-rate	$	2,803,800	$	2,629,354	$	2,153,800	$	2,020,997
Variable-rate		195,000		195,000		455,000		455,000
Total indebtedness	$	2,998,800	$	2,824,354	$	2,608,800	$	2,475,997

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

● unamortized deferred financing costs of $27.4 million and $20.2 million at March 31, 2024 and December 31, 2023, respectively; and

● unamortized discounts of $8.3 million and $6.4 million at March 31, 2024 and December 31, 2023, respectively.

4. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

For further information on the Company’s derivative and hedge accounting policies, see Note 1, “Overview and Summary of Significant Accounting Policies—Financial Derivatives” and Note 5, “Derivative Instruments and Hedging Activities” to the audited Consolidated Financial Statements of IPALCO included in this prospectus.

At March 31, 2024, AES Indiana’s outstanding derivative instruments were as follows:

Commodity	Accounting Treatment(a)	Unit	Notional		Sales		Net Notional
			(in thousands)
FTRs	Not Designated	MWh		1,399		—		1,399

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

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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 Condensed 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.

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 Condensed 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 March 31, 2024 and December 31, 2023, 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):

Commodity	Hedging Designation	Balance sheet classification	March 31, 2024		December 31, 2023
FTRs	Not a Cash Flow Hedge	Prepayments and other current assets	$	393	$	1,388

5. DEBT

Long-Term Debt

The following table presents our long-term debt:

		March 31,			December 31,
Series	Due	2024			2023
		(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
5.70%	April 2054		650,000			—
Unamortized discount – net			(8,266	)		(6,449	)
Deferred financing costs			(26,369	)		(19,058	)
Total AES Indiana first mortgage bonds			2,769,165			2,128,293
Total Long-term debt – AES Indiana			2,769,165			2,128,293
Less: current portion of long-term debt			40,000			40,000
Net consolidated AES Indiana long-term debt		$	2,729,165		$	2,088,293

(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

As of March 31, 2024 and December 31, 2023, AES Indiana had $195.0 million and $155.0 million in outstanding borrowings on the committed Credit Agreement, respectively.

Significant Transactions

AES Indiana First Mortgage Bonds and AES Indiana Term Loan

In March 2024, AES Indiana issued $650 million aggregate principal amount of first mortgage bonds, 5.70% Series, due April 2054, pursuant to Rule 144A and Regulation S under the Securities Act. The net proceeds from this offering of approximately $640.5 million, after deducting the initial purchasers’ discounts and fees and expenses for the offering, were used to repay the $300 million Term Loan Agreement, outstanding borrowings on the Credit Agreement and for general corporate purposes.

Other

In February 2024, AES Indiana received a $92 million short-term loan from AES. This loan was fully repaid in March 2024.

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.

6. INCOME TAXES

AES Indiana’s provision for income taxes is based on the estimated annual effective tax rate, plus discrete items. The effective combined state and federal income tax rate was 19.6% for the three months ended March 31, 2024, as compared to 18.4% for the three months ended March 31, 2023. The rate for the three months ended March 31, 2024 is different from the combined federal and state statutory rate of 24.9% primarily due to the flowthrough of the net tax benefit related to the reversal of excess deferred taxes of AES Indiana, which was partially offset by the net tax expense related to the amortization of allowance for equity funds used during construction.

Management estimates the annual effective tax rate based on its forecast of annual pre-tax income or loss. Starting in the second quarter of 2024, the annual effective tax rate is expected to increase due to the timing of the implementation of base rates in the 2024 Rate Order and the resulting change to pre-tax income and the flowthrough of the reversal of excess deferred taxes. See Note 2, “Regulatory Matters — Regulatory Rate Review” for further information.

AES files federal and state income tax returns which consolidate AES Indiana and its subsidiaries. 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.

7. BENEFIT PLANS

The following table presents the net periodic benefit cost of the Pension Plans combined:

	For the Three Months Ended March 31,
	2024			2023
	(In Thousands)
Components of net periodic benefit cost:
Service cost	$	1,253		$	1,297
Interest cost		6,739			7,455
Expected return on plan assets		(7,443	)		(8,276	)
Amortization of prior service cost		475			543
Amortization of actuarial loss		1,207			1,536
Net periodic benefit cost	$	2,231		$	2,555

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The components of net periodic benefit cost other than service cost are included in “Other (expense) / income, net” in the Condensed Consolidated Statements of Operations.

In addition, AES Indiana provides postretirement health care benefits to certain active or retired employees and the spouses of certain active or retired employees. These postretirement health care benefits and the related unfunded obligation were not material to the Financial Statements in the periods covered by this report.

8. COMMITMENTS AND CONTINGENCIES

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 March 31, 2024 and December 31, 2023, respectively.

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 CCR; 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. 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 March 31, 2024 and December 31, 2023, respectively.

9. 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. Please see Note 13, “Revenue” to the audited Consolidated Financial Statements of IPALCO included in this prospectus for further discussion of our retail, wholesale and miscellaneous revenue.

AES Indiana’s revenue from contracts with customers were $401.2 million and $482.9 million for the three months ended March 31, 2024 and 2023, respectively. The following table presents our revenue from contracts with customers and other revenue (in thousands):

	For the Three Months Ended March 31,
	2024		2023
Retail Revenue
Retail revenue from contracts with customers:
Residential	$	180,969	$	204,748
Small commercial and industrial		63,196		69,879
Large commercial and industrial		125,209		170,978
Public lighting		14,655		2,614
Other(1)		2,179		4,657
Total retail revenue from contracts with customers		386,208		452,876
Alternative revenue programs		5,706		7,739
Wholesale Revenue
Wholesale revenue from contracts with customers:		12,622		24,251
Miscellaneous Revenue
Capacity revenue		7		4,848
Transmission and other revenue		2,380		906
Total miscellaneous revenue from contracts with customers		2,387		5,754

Other miscellaneous revenue(2)		878		766
Total Revenue	$	407,801	$	491,386

(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.

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The balances of receivables from contracts with customers were $276.1 million and $218.8 million as of March 31, 2024 and December 31, 2023, respectively. Payment terms for all receivables from contracts with customers typically do not extend beyond 30 days, unless a customer qualifies for payment extension.

10. 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 Condensed Consolidated Balance Sheets related to lease asset and liability balances as of the periods indicated (in thousands):

	Consolidated Balance Sheet Classification	March 31, 2024		December 31, 2023
Assets
Right-of-use assets — finance leases	Other non-current assets	$	88,249	$	16,357
Liabilities
Finance lease liabilities (current)	Short-term debt and current portion of long-term debt	$	4,312	$	—
Finance lease liabilities (noncurrent)	Long-term debt		83,315		17,769
Total finance lease liabilities		$	87,627	$	17,769

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

Lease Term and Discount Rate	March 31, 2024			December 31, 2023
Weighted-average remaining lease term — finance leases		36 years			35 years
Weighted-average discount rate — finance leases		5.54	%		5.30	%

The following table summarizes the components of lease expense recognized in “Operating Costs and Expenses” on the accompanying Condensed Consolidated Statements of Operations for the periods indicated (in thousands):

	Three Months Ended March 31,
Components of Lease Cost	2024		2023
Finance lease cost:
Amortization of right-of-use assets	$	116	$	102
Interest on lease liabilities		241		226
Total lease cost	$	357	$	328

Operating cash outflows from finance leases were $2.1 million and $0.0 million for the three months ended March 31, 2024 and 2023, respectively.

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

	Finance Leases
2024	$	1,687
2025		4,446
2026		4,535
2027		4,625
2028		4,718

Thereafter		315,194
Total	$	335,205
Less: Imputed interest		(247,578	)
Present value of lease payments	$	87,627

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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):

	Three Months Ended March 31,
	2024		2023
Total lease revenue	$	533	$	401

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	March 31, 2024			December 31, 2023
Gross assets	$	4,341		$	4,341
Less: Accumulated depreciation		(1,264	)		(1,222	)
Net assets	$	3,077		$	3,119

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

The following table shows the future lease receipts as of March 31, 2024 for the remainder of 2024 through 2028 and thereafter (in thousands):

	Operating Leases
2024	$	408
2025		553
2026		554
2027		554
2028		354
Thereafter		891
Total	$	3,314

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Financial Statement Schedules

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.

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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.

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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.

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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.

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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.

F-135

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.

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.

F-136

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.

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.

F-137

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,
	2023			2022			2021
	$ in thousands (net of tax)
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

F-138

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.

F-139

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

F-140

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

F-141

IPALCO ENTERPRISES, INC.

Offer to Exchange
5.750% Senior Secured Notes due 2034 for
New 5.750% Senior Secured Notes due 2034

Through and including September 5, 2024 all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters with respect to their unsold allotments or subscriptions.

PROSPECTUS

June 6, 2024