EDGAR 10-K Filing

Company CIK: 728391
Filing Year: 2025
Filename: 728391_10-K_2025_0000728391-25-000017.json

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ITEM 1. BUSINESS
ITEM 1. BUSINESS
OVERVIEW
IPALCO is a holding company incorporated under the laws of the state of Indiana whose principal subsidiary is AES Indiana. AES Indiana is a regulated electric utility operating in the state of Indiana. Substantially all of our business consists of the generation, transmission, distribution and sale of electric energy conducted through AES Indiana. Our business segments are “utility” and “other.” All of our operations are conducted within the U.S. and principally within the state of Indiana. Please see Note 13, “Business Segments” to the Financial Statements of this Annual Report on Form 10-K.
AES INDIANA
IPALCO owns all of the outstanding common stock of AES Indiana. AES Indiana was incorporated under the laws of the state of Indiana in 1926. AES Indiana is engaged primarily in generating, transmitting, distributing and selling electric energy to approximately 531,000 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 968,000. 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, 2024, AES Indiana had 1,175 employees, of whom 1,127 were full time. Of the total employees, 797 were represented by the IBEW in two bargaining units: a physical unit and a clerical-technical unit. In January 2025, the IBEW physical unit ratified a three-year agreement with AES Indiana that expires on December 5, 2027. 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, 2024, neither IPALCO nor any of its majority-owned subsidiaries, other than AES Indiana, had any employees.
Safety
As part of AES, safety is one of our core values. Conducting safe operations at our facilities, so that each person can return home safely, is the cornerstone of our daily activities and decisions. Safety efforts are led globally by the AES Chief Operating Officer and supported by safety committees that operate at the local site level. Hazards in the workplace are actively identified, and management tracks incidents so remedial actions can be taken to improve workplace safety.
We work with the Safety Management System (“SMS”), a Global Safety Standard that applies to all AES employees and employees of AES subsidiaries, as well as contractors working in AES facilities and construction projects. The SMS requires continuous safety performance monitoring, risk assessment and performance of periodic integrated environmental, health, and safety audits. The SMS provides a consistent framework for all AES operational businesses and construction projects to set expectations for risk identification and reduction, measure performance, and drive continuous improvements. The SMS standard is consistent with the OHSAS 18001/ISO 45001 standard.
Our safety performance is also measured by both leading and lagging metrics. Our leading safety metrics track safety observations, safety meeting engagement and the reporting of lost time incident (“LTI”) rates for our employees and contractors based on OSHA standards. Our lagging safety metrics track lost workday cases, severity rate, and recordable incidents. We are committed to excellence in safety and have implemented various programs to increase safety awareness and improve work practices.
Talent
We believe our success depends on our ability to attract, develop and retain key personnel. The skills, experience and industry knowledge of key employees significantly benefit our operations and performance. We have a comprehensive approach to managing our talent and developing our leaders in order to ensure our people have the right skills for today and tomorrow, whether that requires us to build new business models or leverage leading technologies.
We emphasize employee development and training. To empower employees, we provide a range of development programs and opportunities, skills, and resources they need to be successful by focusing on experience and exposure, as well as formal programs including the AES' ACE Academy for Talent Development, and our Trainee Program.
We believe that our individual differences make us stronger. Our Global Diversity and Inclusion Program is led by the AES Diversity and Inclusion Officer. Governance and standards are guided by the AES Chief Human Resources Officer, with input from members of AES' Global 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 12, “Related Party Transactions - Service Company” to the Financial Statements and “Item 13. Certain Relationships and Related Transactions, and Director Independence” of this Annual Report on Form 10-K for additional details.
PROPERTIES
Our executive offices are located at One Monument Circle, Indianapolis, Indiana. This facility and the remainder of our material properties in our business and operations are owned directly by AES Indiana. The following is a description of these material properties.
We own two distribution service centers in Indianapolis. We also own the building in Indianapolis that houses our customer back-office billing team.
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" to the Financial Statements of this Annual Report on Form 10-K). The second station, Harding Street, consists of three natural gas-fired boilers and steam turbines and uses natural gas and fuel oil to power five combustion turbines. In addition, AES Indiana operates a 20 MW battery energy storage unit at this location, which provides frequency response. The third station, Eagle Valley, is a CCGT natural gas plant. The fourth station, Georgetown, is a peaking station that uses natural gas to power combustion turbines. AES Indiana's net electric generation design capacity at these generating stations for winter is 3,070 MW and net summer 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.
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 placed in service during the fourth quarter of 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 placed in service during the first quarter of 2025.
Our sources of electric generation are as follows:
AES Indiana Generating Stations:
Winter Capacity Summer Capacity
Fuel Name Number of
Units Gross
(MW) Net
(MW) Gross
(MW) Net
(MW) Location
Gas Harding Street 6 1,053 1,026 990 963 Marion County, Indiana
Eagle Valley 1 735 719 705 689 Morgan County, Indiana
Georgetown 2 200 200 158 158 Marion County, Indiana
Total 9 1,988 1,945 1,853 1,810
Coal Petersburg(1)
2 1,152 1,064 1,152 1,064 Pike County, Indiana
Total 2 1,152 1,064 1,152 1,064
Oil Petersburg 3 8 8 8 8 Pike County, Indiana
Harding Street 3 53 53 43 43 Marion County, Indiana
Total 6 61 61 51 51
Total 17 3,201 3,070 3,056 2,925
AES Indiana Renewable Energy Projects(2):
Solar Hardy Hills Solar Project
1 195 195 195 195 Clinton County, Indiana
Wind
Hoosier Wind Project
1 106 106 106 106 Benton County, Indiana
Total 2 301 301 301 301
Grand Total 19 3,502 3,371 3,357 3,226
(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 Financial Statements of this Annual Report on Form 10-K).
(2) See Note 2, "Regulatory Matters - IRP Filings and Replacement Generation" to the Financial Statements of this Annual Report on Form 10-K for further discussion of our renewable projects that have been placed into service.
Net electrical generation during 2024 at our Eagle Valley, Harding Street, Petersburg and Georgetown plants accounted for approximately 41%, 32%, 23% and 1%, respectively, of our total net generation. Our renewable energy projects accounted for the remaining 3% of 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 our renewable projects under construction (see further discussion in Note 2, “Regulatory Matters - IRP Filings and Replacement Generation” to the Financial Statements of this Annual Report on Form 10-K):
Type Project Name Solar Capacity (MW) Storage Capacity (MWh) Date filed with IURC Date of IURC approval
Estimated Completion Location
Storage
Pike County BESS Project
- 800 7/19/2023
1/17/2024
Q1 2025
Pike County, Indiana
Solar & Storage Petersburg Energy Center Project 250 180 7/30/2021 11/24/2021 Q4 2025
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 5,392 circuit miles of underground primary and secondary cables and 6,085 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 130 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 76 bulk power substations and 109 distribution substations; 55 substations are considered both bulk power and distribution substations.
All critical facilities we own are well maintained, in good condition and meet our present needs. Our plants generally have enough capacity to meet the daily needs of our retail customers when all of our units are available. During periods when our generating capacity is not sufficient to meet our retail demand, or when MISO provides a lower cost alternative to some of our available generation, we purchase power on the MISO wholesale market.
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 2024, AES Indiana’s retail kWh sales have decreased at a compound annual rate of 0.8%. Conversely, the number of our retail customers grew at a compound annual rate of 1.0% during that same period. Please see Note 2, “Regulatory Matters - DSM” to the Financial Statements of this Annual Report on Form 10-K for more details. AES Indiana’s electricity sales for 2020 through 2024 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 $28.6 million (previously $16.3 million prior to the 2024 Base Rate Order) are passed back (or charged) to customers 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 2018 and 2024 Base Rate Orders, we received approval for a storm damage restoration reserve account that allows us to defer major storm costs over a benchmark that meet certain criteria considered to be severe, for recovery in a future basic rate proceeding. Because AES Indiana's basic rates and charges include an annual amount for recovery for such severe storm costs, if actual severe storm costs are below that level, AES Indiana will record a regulatory liability for the shortfall to be passed to customers in a future basic rate proceeding. Conversely, if AES Indiana's major storm costs are above the level in basic rates, AES Indiana will defer the excess for future recovery.
MISO OPERATIONS
AES Indiana is one of many transmission system owner members in MISO. MISO is a RTO which maintains functional control over the combined transmission systems of its members and manages one of the largest energy and ancillary services markets in the U.S. MISO policies are developed, in part, through a stakeholder process in
which we are an active participant. We focus our participation in this process primarily on items that could impact our customers, shared cost of transmission expansion, resource adequacy, results of operations, financial condition and cash flows. Additionally, we participate in the process to impact MISO and FERC policy by filing comments with MISO, the FERC, or the IURC.
MISO has functional control of our transmission facilities and our transmission operations are integrated with those of MISO. Our participation and authority to sell wholesale power at market-based rates are subject to the FERC jurisdiction. Transmission service over our facilities is provided through MISO’s tariff.
As a member of MISO, we offer our available electricity production of each of our generation assets into the MISO day-ahead and real-time markets. MISO dispatches generation assets in economic order considering transmission constraints and other reliability issues to meet the total demand in the MISO region. MISO settles hourly offers and bids based on locational marginal prices, which is pricing for energy at a given location based on a market clearing price that takes into account physical limitations, generation and demand throughout the MISO region. MISO evaluates the market participants’ energy offers and demand bids optimizing for energy and ancillary services products to economically and reliably dispatch the entire MISO system. The IURC has authorized AES Indiana to 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 $25.5 million and $30.6 million as of December 31, 2024 and 2023, respectively.
We have preserved our right to withdraw from MISO by tendering our Notice of Withdrawal (subject to the FERC and the IURC approval). We have made no decision to seek withdrawal from MISO at this time. We will continue to assess the relative costs and benefits of being a MISO member, as well as actively advocate for our positions through the existing MISO stakeholder process and in filings with the FERC or IURC.
See also Note 2, “Regulatory Matters” to the Financial Statements of this Annual Report on Form 10-K for additional details on the regulatory oversight of the FERC and the IURC.
REGULATION
General
AES Indiana is a regulated public utility principally engaged in providing electric service to the Indianapolis metropolitan area. An inherent business risk facing any regulated public utility is that of unexpected or adverse regulatory action. Regulatory discretion is reasonably broad in Indiana, as it is elsewhere. We attempt to work cooperatively with regulators and those who participate in the regulatory process, while remaining vigilant in protecting or asserting our legal rights in the regulatory process. We take an active role in addressing regulatory policy issues in the current regulatory environment. Additionally, there is increased activity by environmental regulators which has had and will continue to have a significant impact on our operations and financial statements for the foreseeable future. We maintain our books and records consistent with GAAP reflecting the impact of regulation. See Note 1, “Overview and Summary of Significant Accounting Policies” to the Financial Statements of this Annual Report on Form 10-K.
Retail Ratemaking
AES Indiana’s tariff rates for electric service to retail customers consist of basic rates and charges which are set and approved by the IURC after public hearings. In addition, AES Indiana’s rates include various adjustment mechanisms including, but not limited to:
•a rider to reflect changes in fuel and power purchased 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 and investments in renewable energy projects, and recovery of costs related to generation consumables and environmental allowance expenses, referred to as the ECCRA;
•a rider to reflect changes in ongoing MISO costs and revenue, referred to as the RTO Adjustment;
•a rider to reflect changes in net capacity sales and expenses above and below an established annual revenue benchmark of $11.3 million (until May 8, 2024) and an expense benchmark of $19.0 million (beginning May 9, 2024), referred to as the Capacity Adjustment;
•a rider for passing through to customers wholesale sales margins above and below an established annual margin benchmark of $16.3 million (until May 8, 2024) and $28.6 million (beginning May 9, 2024), referred to as the Off-System Sales Margin Adjustment;
•a rider for the timely recovery of costs (including a return) incurred on investments for eligible TDSIC improvements; and
•cost recovery, lost margin recoveries and performance incentives from our DSM programs.
Each of these tariff rate components may be set and approved by the IURC in separate proceedings at different points in time (currently the FAC proceedings occur on a quarterly basis and AES Indiana's other rider proceedings all occur on an annual basis). These components function somewhat independently of one another, but the overall structure of our rates and charges would be subject to review at the time of any review of our basic rates and charges.
For additional discussion of the regulatory environment related to our business, see the discussion in Note 2, “Regulatory Matters” to the Financial Statements of this Annual Report on Form 10-K, which is incorporated by reference herein.
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; species and habitat protections 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, 2024.
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.
Trump Administration Actions Affecting Environmental Regulations
On January 20, 2025, President Trump issued an Executive Order titled “Unleashing American Energy” directing Agencies to, among other tasks, review regulations issued under the prior Administration to determine whether they should be suspended, revised, or rescinded. The Trump Administration also issued a Memorandum titled “Regulatory Freeze Pending Review” directing Agencies to refrain from proposing or issuing any rules until the Trump Administration has reviewed and approved those rules. These actions may have an impact on regulations and permitting processes that may affect our business, financial condition, or results of operations.
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.
On May 7, 2024, EPA published a final rule to revise MATS for coal and oil-fired EGUs which lowers certain emissions limits and revises certain other aspects of MATS. The requirements of MATS would not apply to AES Indiana upon conversion of the remaining two coal-fired units at Petersburg to natural gas. The May 2024 rule to revise MATS is subject to legal challenges. On October 4, 2024, the U.S. Supreme Court denied emergency stay applications.
Further rulemakings and/or proceedings are possible; however, in the meantime, MATS remains in effect. We currently cannot predict the outcome of the regulatory or judicial process, or its impact, if any, on our MATS compliance planning or ultimate costs.
Waste Management and CCR
In the course of operations, our facilities generate solid and liquid waste materials requiring eventual disposal or processing. Waste materials generated at our electric power and distribution facilities include asbestos, CCR, oil, scrap metal, rubbish, small quantities of industrial hazardous wastes such as spent solvents, tree-and-land-clearing wastes and polychlorinated biphenyl contaminated liquids and solids. We endeavor to ensure that all our solid and liquid wastes are disposed of in accordance with applicable national, regional, state and local regulations. With the 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. On August 7, 2024, in response to changes to Indiana statute, as well as comments received during the Second Notice of Comment Period, IDEM published a Continuation of the Second Notice of Comment Period for proposed amendments to the draft rule language for a State CCR Permitting Program. On December 11, 2024, the Indiana Environmental Rules Board preliminarily adopted the State CCR Permitting Program Draft Rule.
The EPA has indicated that they will implement a phased approach to amending the CCR Rule, which is ongoing. On May 8, 2024, EPA published final revisions to the CCR Rule which expand the scope of CCR units regulated by the CCR Rule to include legacy surface impoundments, inactive surface impoundments, and CCR management units. The May 8, 2024 revisions to the CCR Rule are currently subject to legal challenges and on November 1, 2024, the D.C. Circuit Court denied a motion to stay these revisions to the CCR Rule. On November 5, 2024, an application for stay of the CCR Rule revisions was filed with the United States Supreme Court, which was denied by the Court on December 11, 2024. It is too early to determine any potential impact from these revisions to the CCR Rule.
The CCR Rule, current or future 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", Note 4, "ARO" and Note 11, "Commitments and Contingencies - Contingencies - Legal Matters - Coal Ash Insurance Litigation" to the Financial Statements of this Annual Report on Form 10-K for further discussion.
Regional Haze Rule
EPA’s 1999 Regional Haze Rule established timelines for states to improve visibility in national parks and wilderness areas throughout the United States by establishing reasonable progress goals toward meeting a national goal of natural visibility conditions in Class I areas by the year 2064 through submittal of a series of state implementation plans (SIPs). Indiana’s SIP for the first planning period (through 2018) did not require any additional controls to be installed or operated on AES Indiana generating facilities. For all future SIP planning periods, states must evaluate whether additional emissions reduction measures may be needed to continue making reasonable progress toward natural visibility conditions. On December 22, 2021, IDEM submitted Indiana's Regional Haze SIP for the Second Implementation Period to EPA for review and approval. The SIP does not include additional requirements for AES Indiana EGUs or for other EGUs in Indiana. However, we cannot predict the possible outcome or potential impacts of this matter at this time. We would seek recovery of capital expenditures; however, there is no guarantee we would be successful.
Climate Change Legislation and Regulation
One byproduct of burning coal and other fossil fuels is the emission of GHGs, including CO2. We face certain risks related to existing and potential international, federal, state, regional and local GHG legislation and regulations,
including risks related to increased capital expenditures or other compliance costs, as well as increased climate change disclosure obligations, which could have a material adverse effect on our results of operations, financial condition and cash flows.
The possible impact of any existing or future international, federal, regional or state GHG legislation, regulations or proposals will depend on various factors, including but not limited to:
▪The geographic scope of legislation and/or regulation (e.g., international, federal, regional, state), which entities are subject to the legislation and/or regulation (e.g., electricity generators, load-serving entities, electricity deliverers, etc.), the enactment date of the legislation and/or regulation and the compliance deadlines set forth therein;
▪The level of reductions of GHGs being sought by the regulation and/or legislation (e.g., 10%, 20%, 50%, etc.) and the year selected as a baseline for determining the amount or percentage of mandated GHG reduction (e.g., 10% reduction from 1990 emission levels, 20% reduction from 2000 emission levels, etc.);
▪The legislative and/or regulatory structure (e.g., a GHG cap-and-trade program, a carbon tax, GHG emission limits, etc.);
▪In any cap-and-trade program, the mechanism used to determine the price of emission allowances or offsets to be auctioned by designated governmental authorities or representatives;
▪If a cap-and-trade or similar market-based program is enacted, the price of offsets and emission allowances in the secondary market, including any price floors or price caps on the costs of offsets and emission allowances;
▪The operation of and emissions from regulated units;
▪The permissibility of using offsets to meet reduction requirements and the requirements of such offsets (e.g., type of offset projects allowed, the amount of offsets that can be used for compliance purposes, any geographic limitations regarding the origin or location of creditable offset projects), as well as the methods required to determine whether the offsets have resulted in reductions in GHG emissions and that those reductions are permanent (i.e., the verification method);
▪Whether the use of proceeds of any auction conducted by responsible governmental authorities is reinvested in developing new energy technologies, is used to offset any cost impact on certain energy consumers or is used to address issues unrelated to power;
▪How the price of electricity is determined, including whether the price includes any costs resulting from any new climate change legislation and the potential to transfer compliance costs pursuant to legislation, market or contract, to other parties;
▪Any impact on fuel demand and volatility that may affect the market clearing price for power;
▪The effects of any legislation or regulation on the operation of power generation facilities that may in turn affect reliability;
▪The availability and cost of carbon control technology;
▪The impact of any laws and regulations, supply or cost of fuels used by our generation facilities, including coal, natural gas or oil;
▪Whether any federal legislation regulating GHG emissions will preclude the EPA from regulating GHG emissions under the CAA or preempt private nuisance suits or other litigation by third parties;
▪Any opportunities to change the use of fuel at the generation facilities or opportunities to increase efficiency;
▪The outcome of legal challenges to the SEC's final 2024 climate change disclosure rule, as well as the impact of any potential reconsideration of this rule by the Trump Administration SEC; 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, state or regional initiatives may be pursued in the future.
On May 9, 2024, EPA published the final NSPS requiring carbon capture and sequestration for new and reconstructed baseload stationary combustion turbines, among other requirements. EPA did not finalize revisions to the NSPS for newly constructed or reconstructed coal-fired electric utility steam generating units as proposed in 2018.
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. On May 9, 2024, EPA published the final rule regulating GHGs from existing EGUs pursuant to Section 111(d) of the Clean Air Act and effective on July 8, 2024. Existing EGUs are those that were constructed prior to January 8, 2014. Depending on various EGU-specific factors, the bases of emissions guidelines for natural gas-fired units include the use of uniform fuels and routine methods of operation and maintenance and the bases of emissions guidelines for coal-fired units include 40% natural gas co-firing or carbon capture and sequestration with 90% capture of CO2 depending on the date that coal operations cease. Specific standards for performance for EGUs will be established through a State Plan (or a Federal Plan if the state of Indiana were to not submit an approvable plan). The May 2024 rule is subject to legal challenges. On October 16, 2024, the U.S. Supreme Court denied emergency stay applications.
It is too early to determine any potential impact. GHG regulations, current or future amendments to, resulting state or federal plans, or pending or future litigation associated with such regulations or plans 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. 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. On January 20, 2025, President Trump issued an Executive Order titled “Putting America First in International Environmental Agreements” directing the U.S. Ambassador to the United Nations to formally withdraw from the Paris Agreement. The international community has gathered and continues to gather annually for the Conference to the Parties on the UN Framework Convention on Climate.
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, or resulting state or federal plans, on our consolidated results of operations, cash flows, and financial condition, but it could be material.
New Source Performance Standards for Stationary Combustion Turbines
On November 22, 2024, EPA released a prepublication version of a proposed rule that would revise the NSPS regulating NOx and SO2 from certain new, modified, and reconstructed stationary combustion turbines. The proposal would establish more stringent NOx emissions standards and would retain the existing SO2 standards. The revised standards would apply to affected sources that begin construction, modification, or reconstruction after the date the proposed rule is published in the Federal Register. 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.
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. Additionally, AES Indiana plans to add up to 1,300 MW of wind, solar, and battery energy storage by 2027. In January 2025, AES Indiana initiated its 2025 IRP process with external stakeholders, with AES Indiana anticipating it will submit its final 2025 IRP, shaped by stakeholder feedback, to the IURC in November 2025. For further discussion, see Note 2, "Regulatory Matters - IRP Filings and Replacement Generation" to the Financial Statements of this Annual Report on Form 10-K.
NSR and Other CAA NOVs
See Note 11, “Commitments and Contingencies - Contingencies - Environmental Matters - NSR and other CAA NOVs” to the Financial Statements of this Annual Report on Form 10-K for additional details.
NAAQS
Under the CAA, the EPA sets NAAQS for six criteria pollutants considered harmful to public health and the environment, including particulate matter, NOx, ozone and SO2, which result from fossil-fuel combustion. Areas meeting the NAAQS are designated attainment areas while those that do not meet the NAAQS are considered nonattainment areas. Each state must develop a plan to bring nonattainment areas into compliance with the NAAQS, which may include imposing operating limits on individual plants. The EPA is required to review NAAQS at five-year intervals.
Ozone and NOx. 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 December 10, 2024, EPA issued a final 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 NOx emissions from dozens of upwind generating stations, including AES Indiana's Petersburg, Harding Street, and Eagle Valley stations on the basis that they are contributing significantly to New York’s ability to
meet the 2008 ozone NAAQS. On July 14, 2020, the D.C. Circuit Court vacated and remanded EPA’s denial of the petition. EPA must now issue a new decision based on the Court’s decision. If the Section 126 petition is ultimately granted, our units could be subject to additional requirements, which could be material. We would seek recovery of any resulting capital expenditures; however, there is no guarantee we would be successful.
Fine Particulate Matter. In 2013, the EPA published the 2012 annual PM2.5 standard of 12 micrograms per cubic meter of air and the 24-hour PM2.5 standard of 35 micrograms per cubic meter of air. In 2015, the EPA published its final attainment designations for the 2012 PM2.5 standard. In addition to the PM2.5 standard, there is also a 24-hour PM10 standard of 150 micrograms per cubic meter of air. No AES Indiana operations are currently located in nonattainment areas. On January 27, 2023, the EPA published a proposed rule to lower the primary annual PM2.5 NAAQS from 12 micrograms per cubic meter to a level between 9 and 10 micrograms per cubic meter and to maintain other PM NAAQS at current levels. On February 7, 2024, EPA released a final rule lowering the primary annual PM2.5 NAAQS from 12 micrograms per cubic meter to 9 micrograms per cubic meter. The PM2.5 NAAQS final rule is subject to legal challenges. On December 10, 2024, EPA issued a final 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 December 10, 2024, EPA issued a final 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.
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.
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 and includes enhancements in the revised Group 3 trading program. On June 27, 2024, the U.S. Supreme Court issued an order granting a stay of EPA’s 2023 FIP pending resolution of legal challenges to the FIP.
On November 6, 2024, EPA published in the Federal Register an Interim Final Rule in response to the U.S. Supreme Court’s stay of its FIP addressing interstate transport for the 2015 ozone national ambient air quality standards. The effective date is November 6, 2024. The Interim Final Rule stays the effectiveness of the Good Neighbor FIP and revises the CSAPR regulations to continue application of the states’ respective trading programs. The updated emissions budgets will apply for the entirety of the 2024 ozone season and EPA is expected to adjust quantities of updated allowances to reflect pre-stay transactions. 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 the final CWA Hazardous Substance Facility Response Plans rule which became 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.
CWA - Environmental Wastewater Requirements and Regulation of Water Discharge
In November 2015, the EPA published its final Steam Electric Power Generating Effluent Limitation Guidelines (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. On May 9, 2024, EPA published the final rule which became effective on July 8, 2024. The final rule establishes more stringent best available technology limits for flue gas desulfurization wastewater, bottom ash transport water and combustion residual leachate and established a new set of definitions and new limits for combustion residual leachate and legacy wastewater. The May 2024 rule is subject to legal challenges. On October 10, 2024, the Eighth Circuit Court denied stay applications. 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. The Decision provides a standard that substantially restricts the Agencies' ability to regulate certain types of wetlands and streams. Specifically, under the 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 final NPDES 316(b) permit decisions and any challenges associated with such final determinations. However, if additional capital expenditures are necessary, they could be material. We would seek recovery of these capital expenditures; however, there is no guarantee we would be successful.
CWA - NPDES Permits
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. On February 18, 2025, the Indiana Office of Administrative Law Proceedings (OALP) issued a final order which determined that the third-party appellant failed to prove it has associational standing to challenge the NPDES permit and that the third-party appellant failed to prove any of the alleged deficiencies in its petition for review as a matter of law. The third-party appellant may seek judicial review within 30 days of the service of notice of the final order. 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. Among other new requirements, the permit includes 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 initially granted on January 4, 2024, and is in effect until April 30, 2025 (as extended from January 28, 2025), which could be further extended. The renewal application for the Petersburg NPDES permit remains pending. IDEM published the draft Petersburg NPDES permit for public notice on September 19, 2024, with the comment period closing October 21, 2024. 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.
ENERGY SUPPLY
Total electricity sold to our retail customers in 2024 came from the following sources: 67.9% from AES Indiana-owned natural gas-fired units, 21.2% from AES Indiana-owned coal-fired steam generation, 9.9% from power purchased in the wholesale power market and under power purchase agreements (primarily wind and solar), and 1.0% from AES Indiana-owned wind generation.
Natural gas accounted for approximately 74% of the total kWh we generated in 2024, as compared to 64% in 2023 and 42% in 2022. 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. We have natural gas inventory related to a storage agreement with Citizens Energy Group which provides natural gas supply to Harding Street Station.
Coal and fuel oil provided approximately 23% of the total kWh we generated in 2024 compared to approximately 36% and 58% in 2023 and 2022, respectively. In early in 2022, coal was a higher percentage of kWh generated due to an extended outage at the Eagle Valley CCGT plant. AES Indiana has regulatory approval to convert the remaining two coal units at Petersburg to natural gas in 2026 (for further discussion, see Note 2, “Regulatory Matters - IRP Filings and Replacement Generation” to the Financial Statements of this Annual Report on Form 10-K). Our existing coal contracts and inventory provide for approximately 86% of our current projected requirements in 2025. We have long-term coal contracts with two suppliers for 2025. 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 in 2025 with lower levels in 2026 due to conversion to natural gas. Our present inventory is above our target range. Fuel oil accounted for less than 1% of the total kWh we generated in 2024, 2023, and 2022, 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 and Petersburg in 2016, 2021 and 2023, and the future repowering of the remaining coal-fired units at Petersburg to natural gas, we generally have experienced and expect to continue to experience an increase in the percentage of generation from natural gas and renewable projects. 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.
AES Indiana renewable projects provided the remaining 3% of kWh generation in 2024. See Note 2 “Regulatory Matters - IRP Filings and Replacement Generation” to the Financial Statements of this Annual Report on Form 10-K for further discussion of AES Indiana's Preferred Resource Portfolio for meeting generation capacity needs for serving AES Indiana's retail customers over the next several years.
Additionally, we meet the electricity demands of our retail customers with energy purchased under power purchase agreements and by power purchases in MISO. We are currently committed under a long-term power purchase agreement to purchase all wind-generated electricity through 2031 from a project in Minnesota, which has a maximum output capacity of 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, 2024 (see Note 2, "Regulatory Matters - "Wind and Solar Power Purchase Agreements" to the Financial Statements of this Annual Report on Form 10-K for further details).
AES Indiana retired Petersburg Unit 1 in May 2021 and Petersburg Unit 2 in June 2023. In addition, AES Indiana’s most recent 2022 IRP short-term action plan includes the conversion of Petersburg Units 3 and 4 from coal to gas as part of AES Indiana’s preferred portfolio. On November 6, 2024, AES Indiana received approval from the IURC to convert Petersburg Units 3 and 4 from coal to natural gas and to recover costs through future rates. The Company has engaged a vendor through an EPC Agreement for the turn-key engineering, procurement, and construction services of the project. This agreement has been approved by the IURC and preconstruction stage work is ongoing. The on-site construction work for the conversion of Unit 3 is expected to begin in February 2026 and be completed by June 2026, and for Unit 4 is expected to begin in June 2026 and be completed by December 2026.
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 and the Petersburg unit conversions, we expect our installed capacity to be approximately 73% from AES Indiana-owned natural gas-fired units, 20% from AES Indiana-owned renewable projects, and 7% from wind and solar power purchase agreements. See Note 2 “Regulatory Matters - IRP Filings and Replacement Generation” for further discussion of AES Indiana's Preferred Resource Portfolio for meeting generation capacity needs of serving AES Indiana's retail customers over the next several years.
STATISTICAL INFORMATION ON OPERATIONS
The following table of statistical information presents additional data on our operations:
Years Ended December 31,
2024 2023 2022 2021 2020
Revenue (In Thousands):
Residential $ 688,728 $ 668,209 $ 698,648 $ 607,260 $ 575,329
Small commercial and industrial 250,777 238,595 247,884 212,169 194,904
Large commercial and industrial 606,565 635,221 644,181 541,471 500,208
Public lighting 10,366 10,013 9,784 8,994 9,257
Other(1)
35,602 24,615 17,845 16,785 14,402
Retail electric revenue 1,592,038 1,576,653 1,618,342 1,386,679 1,294,100
Wholesale 37,519 56,557 148,517 25,059 46,482
Miscellaneous 14,236 16,707 24,852 14,394 12,403
Total revenue $ 1,643,793 $ 1,649,917 $ 1,791,711 $ 1,426,132 $ 1,352,985
kWh Sales (In Millions):
Residential 5,048 4,800 5,305 5,172 5,115
Small commercial and industrial 1,771 1,722 1,823 1,774 1,709
Large commercial and industrial 6,010 5,929 6,091 6,006 5,839
Public lighting 39 19 18 21 30
Sales - retail customers 12,868 12,470 13,237 12,973 12,693
Wholesale 854 1,657 2,148 908 1,866
Total kWh sold 13,722 14,127 15,385 13,881 14,559
Retail Customers at End of Year:
Residential 469,499 462,848 458,585 455,756 451,735
Small commercial and industrial 55,587 54,998 55,210 55,078 54,253
Large commercial and industrial 4,627 4,456 4,517 4,506 4,567
Public lighting 1,089 1,093 1,007 983 986
Total retail customers 530,802 523,395 519,319 516,323 511,541
(1) Other retail revenue includes miscellaneous charges to customers.
HOW TO CONTACT IPALCO AND SOURCES OF OTHER INFORMATION
Our principal executive offices are located at One Monument Circle, Indianapolis, Indiana 46204, and our telephone number is (317) 261-8261. Our website address is www.aesindiana.com. The information on our website is not incorporated by reference into this report. The SEC maintains an internet website that contains this report and other information that we file electronically with the SEC at www.sec.gov.

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ITEM 1A. RISK FACTORS
ITEM 1A. RISK FACTORS
Investors should consider carefully the following risk factors that could cause our business, operating results and financial condition to be materially adversely affected. We routinely encounter and address risks, some of which may cause our future results to be materially different than we presently anticipate. New risks may emerge at any time, and we cannot predict those risks or estimate the extent to which they may affect our business or financial performance. The categories of risk we have identified in "Item 1A. Risk Factors" include risks associated with our operations, governmental regulation and laws, our indebtedness and financial condition. These risk factors should be read in conjunction with the other detailed information concerning IPALCO and AES Indiana set forth in the Notes to the Financial Statements and in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report on Form 10-K herein. The risks and uncertainties described below are not the only ones we face.
RISKS ASSOCIATED WITH OUR OPERATIONS
Our electric generating facilities are subject to operational risks that at times result in unscheduled plant outages, unanticipated operation and/or maintenance expenses, increased fuel or power purchased costs and other liabilities, and these liabilities could become significant for which we may not have adequate insurance coverage.
We operate generating facilities, including those using coal, oil, natural gas, and renewable energy, which involve certain risks that can adversely affect energy costs, output and efficiency levels. These risks include:
•unit or facility shutdowns due to a breakdown or failure of equipment or processes;
•increased prices for fuel and fuel transportation as existing contracts expire or as such contracts are adjusted through price re-opener provisions or automatic adjustments;
•disruptions in the availability or delivery of fuel and lack of adequate inventories;
•shortages of or delays in obtaining equipment;
•loss of cost-effective disposal options for solid waste generated by the facilities;
•accidents and injuries;
•reliability of our suppliers;
•inability to comply with regulatory or permit requirements;
•operational restrictions resulting from environmental or permit limitations or governmental interventions;
•construction delays and cost overruns;
•disruptions in the delivery of electricity;
•labor disputes or work stoppages by employees;
•the availability of qualified personnel;
•events occurring on third party systems that interconnect to and affect our system;
•operator error; and
•catastrophic events.
We experience unscheduled plant outages, unanticipated operation and/or maintenance expenses, increased capital expenditures and/or increased fuel and power purchased 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 power purchased 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, power purchased 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 power purchased, in part, to meet our seasonal planning reserve margins. Any changes in fuel prices could affect the prices we charge, our operating costs and our competitive position with respect to our products and services. The cost of fuel and other commodities has been volatile in recent years and we expect that volatility to continue.
Our exposure to fluctuations in the price of fuel is limited because, pursuant to Indiana law, we apply to the IURC for a change in our FAC every three months to recover our estimated fuel costs, which may be above or below the levels included in our basic rates and charges. In addition, we apply to recover the energy portion of our power purchased costs in these quarterly FAC proceedings subject to a benchmark (please see Note 2, “Regulatory Matters - FAC and Authorized Annual Jurisdictional Net Operating Income” to the Financial Statements of this Annual Report on Form 10-K for additional details regarding the benchmark and the process to recover fuel costs). As part of this cost-recovery process, we must present evidence in each proceeding that we have made every reasonable effort to acquire fuel and generate or purchase power or both so as to provide electricity to our retail customers at the lowest fuel cost reasonably possible. If we are unable to timely or fully recover our fuel and power purchased costs, it could have a material adverse effect on our results of operations, financial condition and cash flows.
Approximately 23% of the energy we produced in 2024 was generated by coal as compared to approximately 36% and 58% in 2023 and 2022, respectively. While we have approximately 86% of our forecasted coal requirements for 2025 currently in inventory or secured under contract for delivery in 2025 as of the date of this report, the balance is yet to be purchased and will be purchased under a combination of short-term contracts and 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 affect mining costs and supply availability. Moreover, the variable demand of retail customer load and the performance of our generation fleet have an impact on our fuel procurement operations over the remaining period of coal generation in our portfolio.
As our coal usage is scheduled to end by June 2026 with the conversion of our last two coal fired units to natural gas, our exposure is shifting to natural gas to meet customer demand for electricity. Our business and operations could be materially adversely affected by unexpected price volatility in the gas market. Our dependence on natural gas also means that the output of our natural gas-fired generation units can be greatly affected by the costs of other facilities that compete with our natural-gas generation units, in particular renewable energy resources. The continued addition of renewable energy facilities to the MISO grid increases the uncertainty forecasting run hours for our existing and future natural gas fired facilities.
While coal supply is largely procured via long term contracts with a degree of price certainty, natural gas is procured on a shorter term basis and balanced with consumption on a daily basis. In order to bring additional price certainty and enhance reliability of delivery the Company procures quantities of firm transportation on relevant pipelines and has an IURC approved structured natural gas hedging plan to offset the impact of price fluctuations.
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 snowstorms, 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, as well as certain of our existing and proposed renewable energy projects, are located in the Wabash Valley seismic zone, adjacent to the New Madrid seismic zone, which are both areas of significant seismic activity in the central U.S.
Our business is sensitive to weather and seasonal variations.
Weather conditions significantly affect the demand for electric power, and accordingly, our business is affected by variations in general weather conditions and unusually severe weather. As a result of these factors, our operating revenue and associated operating expenses are not generated evenly by month during the year. We forecast electric sales on the basis of normal weather, which represents a long-term historical average. Significant variations from normal weather (such as warmer winters and cooler summers) could have a material impact on our revenue, operating income and net income and cash flows. In addition, severe or unusual weather, such as floods, tornadoes and ice or snowstorms, 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. See also “Item 1. Business - MISO Operations" and “Item 1. Business - Regulation - Retail Ratemaking.”
Our transmission and distribution system is subject to operational, reliability and capacity risks.
The ongoing reliable performance of our transmission and distribution system is subject to risks due to, among other things, weather damage, intentional or unintentional damage, equipment or process failure, catastrophic events, such as fires and/or explosions, facility outages, labor disputes, accidents or injuries, operator error, or inoperability of key infrastructure internal or external to us and events occurring on third party systems that interconnect to and affect our system. The failure of our transmission and distribution system to fully operate and deliver the energy demanded by customers could have a material adverse effect on our results of operations, financial condition and cash flows, and if such failures occur frequently and/or for extended periods of time, could result in adverse regulatory action. In addition, the advent and quick adaptation of new products and services that require increased levels of electrical energy cannot be predicted and could result in insufficient transmission and distribution system capacity timely enough to accommodate the potential increased demand. As with all utilities, potential concern with the adequacy of transmission capacity on AES Indiana’s system or the regional systems operated by MISO could result in MISO, the NERC, the FERC or the IURC requiring us to upgrade or expand our transmission system through additional capital expenditures or share in the costs of regional expansion. Also, as a result of the above risks and other potential risks and hazards associated with transmission and distribution operations, we may from time to time become exposed to significant liabilities for which we may not have adequate insurance coverage. Except for AES Indiana’s large substations, transmission and distribution assets are not covered by insurance and are considered to be outside the scope of property insurance. Otherwise, we maintain an amount of insurance protection that we believe is adequate, but there can be no assurance that our insurance will be sufficient or effective under all circumstances and against all hazards or liabilities to which we may be subject. Further, any increased costs or adverse changes in the insurance markets may cause delays or inability in maintaining insurance coverage on terms similar to those presently available to us or at all. A successful claim for which we are not fully insured could have an adverse impact on our results of operations, financial condition and cash flows.
Current and future conditions in the economy may adversely affect our customers, suppliers and other counterparties in a way which could materially and adversely affect our results of operations, financial condition and cash flows.
Our business, results of operations, financial condition and cash flows have been and will continue to be affected by general economic conditions. Slowing economic growth, credit market conditions, fluctuating consumer and business confidence, fluctuating commodity prices, and other challenges affecting the general economy, have caused and may continue to cause some of our customers to experience deterioration of their businesses, cash flow shortages, and difficulty obtaining financing. As a result, existing customers may reduce their electricity consumption and may not be able to fulfill their payment obligations to us in the normal, timely fashion. In addition, some existing commercial and industrial customers may discontinue their operations. Sustained downturns, recessions or a sluggish economy generally affect the markets in which we operate and negatively influence our energy operations. A contracting, slow or sluggish economy could reduce the demand for energy in areas in which we are doing business. For example, during economic downturns, our commercial and industrial customers may see a decrease in demand for their products, which in turn may lead to a decrease in the amount of energy they require. Furthermore, projects which may result in potential new customers may be delayed until economic 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 9, “Benefit Plans” to the Financial Statements of this Annual Report on Form 10-K for further discussion.
Counterparties providing materials or services may fail to perform their obligations, which could materially and adversely impact our results of operations, financial condition and cash flows.
We enter into transactions with and rely on many counterparties in connection with our business, including for the purchase and delivery of inventory, including fuel and equipment components, for our capital improvements and additions and to provide professional services, such as actuarial calculations, payroll processing and various consulting services. If any of these counterparties fails to perform its obligations to us or becomes unavailable, our business plans may be materially disrupted, we may be forced to discontinue or delay certain operations if a cost-effective alternative is not readily available or we may be forced to enter into alternative arrangements at then-current market prices that may exceed our contractual prices and cause delays. Although our agreements are designed to mitigate the consequences of a potential default by the counterparty, our actual exposure may be greater than the relief provided by these mitigation provisions. Any of the foregoing could result in regulatory actions, cost overruns, delays or other losses, any of which (or a combination of which) could have a material adverse effect on our results of operations, financial condition and cash flows.
Further, our construction program calls for extensive expenditures for capital improvements and additions, including the installation of environmental upgrades, additions and 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.
Highly infectious or contagious disease outbreaks could impact our business and operations.
Regional or global outbreaks of infectious or contagious diseases, such as 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:
•decline in customer demand as a result of general decline in business activity;
•destabilization of the markets and decline in business activity negatively impacting our customer growth or the number of customers in our service territory as well as our customers’ ability to pay for our services when due (or at all);
•delay or inability in obtaining regulatory actions and outcomes that could be material to our business, including for recovery of COVID-19 related expenses and losses, such as uncollectible customer amounts, and the review and approval of our applications, rates and charges by the IURC;
•difficulty accessing the capital and credit markets on favorable terms, or at all, a disruption and instability in the global financial markets, or deteriorations in credit and financing conditions which could affect our access to capital necessary to fund business operations or address maturing liabilities on a timely basis;
•negative impacts on the health of our essential personnel, especially if a significant number of them are affected, and on our operations as a result of implementing stay-at-home, quarantine and other social distancing measures;
•a deterioration in our ability to ensure business continuity during a disruption, including increased cybersecurity attacks related to a 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.
Any of the foregoing could have a material adverse effect on our business, financial condition, results of operations, reputation and prospects.
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.
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.
Cyber attacks and data security breaches could harm our business.
Our business relies on electronic systems and network technologies to operate our generation, transmission and distribution infrastructure. We also use various financial, accounting and other infrastructure systems. We also store and use customer, employee, and other personal information and other confidential and sensitive information. Our infrastructure may be targeted by nation states, hacktivists, criminals, insiders or terrorist groups. In particular, there has been an increased focus on the U.S. energy grid believed to be related to the Russia/Ukraine conflict. Such an attack, by hacking, malware or other means, may interrupt our operations, cause property damage, affect our ability to control our infrastructure assets, cause the release of sensitive customer information or limit communications with third parties. Any loss or corruption of confidential or proprietary data through a breach of our systems or certain of our third party vendor systems may:
•impact our operations, revenue, strategic objectives, customer and vendor relationships; expose us to negative publicity, legal claims, regulatory investigations and proceedings and associated penalties or liabilities;
•require extensive repair and restoration costs for additional security measures to avert future attacks;
•impair our reputation and limit our competitiveness for future opportunities; and
•impact our financial and accounting systems and, subsequently, our ability to correctly record, process and report financial information.
We have implemented measures to help prevent unauthorized access to our systems and facilities, including certain measures to comply with mandatory regulatory reliability standards.
To date, cyber breaches have not had a material impact on our operations or financial results. We continue to assess potential threats and vulnerabilities and make investments to address them, including global monitoring of networks and systems, identifying and implementing new technology, improving user awareness through employee security training, and updating our security policies as well as those for third-party providers.
We cannot guarantee the extent to which our security measures will prevent future cyber attacks and security breaches or that our insurance coverage will adequately cover any losses we may experience.
Please see "Item 1C. Cybersecurity" of this Annual Report on Form 10-K for further discussion.
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 manage the ongoing implementations associated with this initiative, including with respect to our systems for billing and collecting from our customers could continue to have adverse impacts on our business, operating results and financial condition.
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 power purchased costs to daily natural gas prices. Power purchased 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 power purchased costs on to our customers, and even if we are able to do so, there may be a significant delay between the time the costs are incurred and the time the costs are recovered. Since these situations most often occur during periods of peak demand, the market price for electric energy at the time we purchase it could be very high, and we may not be allowed to recover all of such costs through our FAC (please see Note 2, "Regulatory Matters - FAC and Authorized Annual Jurisdictional Net Operating Income" to the Financial Statements of this Annual Report on Form 10-K for additional details regarding the benchmark and the process to recover power purchased costs). Even if a supply shortage were brief, we could suffer substantial losses that could adversely affect our results of operations, financial condition and cash flows.
Changes in, or reinterpretations of, the laws, rules, policies and procedures that set electric rates, permitted rates of return, changes in AES Indiana’s rate structure, regulations regarding ownership of generation assets and electric
service, the supply or generation, reliability initiatives, fuel and power purchased (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 2024, 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. Following prior versions of CO2 emissions regulations promulgated by EPA, on May 9, 2024, EPA published the final NSPS requiring carbon capture and sequestration for new and reconstructed baseload stationary combustion turbines, among other requirements. Also on May 9, 2024, EPA published the final rule regulating GHGs from existing EGUs pursuant to Section 111(d) of the CAA.
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. The international community has gathered and continues to gather annually for Conference to the Parties of the United Nations Framework Convention on Climate Change. We anticipate that the Agreement will continue the trend toward efforts to de-carbonize the global economy. The U.S. withdrawal from the Paris Agreement became effective on November 4, 2020. 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. On January 20, 2025, President Trump issued an Executive Order titled “Putting America First in International Environmental Agreements” directing the U.S. Ambassador to the United Nations to formally withdraw from the Paris Agreement.
Any existing or future international, federal, state or regional legislation or regulation of GHG emissions could have a material adverse impact on our financial performance. The actual impact on our financial performance will depend on a number of factors, including among others, the degree and timing of GHG emissions reductions required under any such legislation or regulations, of offsets, the extent to which market-based compliance options are available, if such options were available, the extent to which we would be entitled to receive GHG emissions allowances without having to purchase them in an auction or on the open market as well as the cost or availability of such allowances and the impact of such legislation or regulation on our ability to recover costs incurred through rate increases or otherwise. Our cost of compliance could be substantial. Although we would seek recovery of costs associated with new climate change or GHG regulations, our inability to fully or timely recover such costs could have a material adverse effect on our results of operations, financial condition and cash flows. Additionally, concerns over GHG emissions and their effect on the environment have led, and could lead further, to reduced demand for coal-fired power, which could have a material adverse effect on our results of operations, financial condition and cash flows.
Furthermore, according to the Intergovernmental Panel on Climate Change, physical risks from climate change could include, but are not limited to, increased runoff and earlier spring peak discharge in many glacier and snow-fed rivers, warming of lakes and rivers, an increase in sea level, changes and variability in precipitation and in the intensity and frequency of extreme weather events. Physical impacts may have the potential to significantly affect our business and operations. For example, extreme weather events could result in increased downtime and operation and maintenance costs at our electric power generation facilities and our support facilities. Variations in weather conditions, primarily temperature and humidity, would also be expected to affect the energy needs of customers. A decrease in energy consumption could decrease our revenue. In addition, while revenue would be expected to increase if the energy consumption of customers increased, such increase could prompt the need for additional investment in generation capacity. Changes in the temperature of lakes and rivers and changes in precipitation that result in drought could adversely affect the operations of our fossil-fuel fired electric power generation facilities.
If any of the foregoing risks materialize, we expect our costs to increase or revenue to decrease and there could be a material adverse effect on our business and on our consolidated results of operations, financial condition, cash flows and reputation if such changes are significant. Please see “Item 1. Business - Environmental Matters” for additional information of environmental matters impacting us, including those relating to regulation of GHG emissions.
We are subject to numerous environmental laws, rules and regulations that require capital expenditures, increase our cost of operations, may expose us to environmental liabilities or make continued operation of certain generating units unprofitable.
We are subject to various federal, state, regional and local environmental protection and health and safety laws, rules and regulations governing, among other things, the generation, storage, handling, use, disposal and transportation of regulated materials, including CCR; the use and discharge of water used in generation boilers and for cooling purposes; the emission and discharge of hazardous and other materials into the environment; and the health and safety of our employees. Such laws, rules and regulations can become stricter over time, and we could also become subject to additional environmental laws, rules and regulations and other requirements in the future. Environmental laws, rules and regulations also generally require us to comply with inspections and obtain and comply with a wide variety of environmental licenses, permits, and other governmental authorizations. These laws and regulations often require a lengthy and complex process of obtaining and renewing licenses, permits and other governmental authorizations from federal, state and local agencies. If we are not able to timely comply with inspections and obtain, maintain or comply with all environmental laws, rules and regulations, and all licenses, permits, and other government authorizations required to operate our business, then our operations could be prevented, delayed or subject to additional costs. A violation of environmental laws, rules, regulations, permits or other requirements can result in substantial fines, penalties, other sanctions, permit revocation, facility shutdowns, the imposition of stricter environmental standards and controls or other injunctive measures affecting operating assets. Compliance with these laws, regulations and other requirements requires us to expend significant funds and resources and could at some point become prohibitively expensive or result in our shutting down (temporarily or permanently) or altering the operation of our facilities. Under certain environmental laws, we could also be held responsible for costs relating to contamination at our past or present facilities and at third-party waste disposal sites. We could also be held strictly, jointly and severally liable for investigation or remediation of such contamination, human exposure to hazardous substances or for other environmental damage. From time to time, we are subject to enforcement and litigation actions for claims of noncompliance with environmental laws, rules and regulations or other environmental requirements. We cannot assure that we will be successful in defending against any claim of noncompliance. Any actual or alleged violation of environmental laws, rules, regulations and other requirements also may require us to expend significant resources to defend against any such alleged violations and expose us to unexpected costs. Our costs and liabilities relating to environmental matters could have a material adverse effect on our results of operations, financial condition and cash flows.
In addition, we are subject to potentially significant remediation expenses, enforcement initiatives, private party lawsuits and reputational risk associated with CCR, which consists of bottom ash, fly ash, and air pollution control wastes generated at our current and former coal-fired generation plant sites. We expect to incur substantial costs to comply with CCR rules and requirements and any changes to existing CCR rules or requirements or other new rules or requirements addressing CCR may require us to incur additional costs. Also, we may become subject to CCR-related lawsuits or involved in other CCR-related litigation from time to time that may require us to incur other costs or expose us to unexpected liabilities, which could be significant. In addition, CCR and its production at our facilities have been the subject of interest from environmental non-governmental organizations and the media. Any of the foregoing could have a material adverse effect on our results of operations, financial condition and cash flows. While we maintain insurance for certain of these costs and liabilities, there can be no assurance that our insurance will be available, sufficient or effective under all circumstances and against all of our claimed liabilities.
Please see “Item 1. Business - Environmental Matters” for additional information of environmental matters impacting us, including our current CCR-related insurance coverage litigation.
If we were found not to be in compliance with the mandatory reliability standards, we could be subject to sanctions, including substantial monetary penalties, which likely would not be recoverable from customers through regulated rates.
As an owner and operator of a bulk power transmission system, AES Indiana is subject to mandatory reliability standards promulgated by the NERC and enforced by the FERC. The standards are based on the functions that
need to be performed to ensure the bulk power system operates reliably and is guided by reliability and market interface principles. Compliance with reliability standards may subject us to higher operating costs or increased capital expenditures. Although we expect to recover costs and expenditures from customers through regulated rates, there can be no assurance that the IURC will approve full recovery in a timely manner. If we were found not to be in compliance with the mandatory reliability standards, we could be subject to sanctions, including substantial monetary penalties, which likely would not be recoverable from customers through regulated rates and could have a material adverse effect on our results of operations, financial condition and cash flows.
We are subject to extensive laws and local, state and federal regulation, as well as litigation and other proceedings that affect our operations and costs.
We are subject to extensive regulation at the federal, state and local levels. For example, at the federal level, AES Indiana, as an electric utility, is regulated by the FERC and the NERC and, at the state level, we are regulated by the IURC. The regulatory power of the IURC over AES Indiana is both comprehensive and typical of the traditional form of regulation generally imposed by state public utility commissions. We face the risk of unexpected or adverse regulatory action. Regulatory discretion is reasonably broad in Indiana. AES Indiana is subject to regulation by the IURC as to our services and facilities, the valuation of property, the construction, purchase, or lease of electric generating facilities, the classification of accounts, rates of depreciation, the increase or decrease in retail rates and charges, the issuance of securities and long-term debt, the acquisition and sale of some public utility properties or securities and certain other matters.
AES Indiana’s tariff rates for electric service to retail customers consist of basic rates and charges which are set and approved by the IURC after public hearings. In addition, AES Indiana’s rates typically include various adjustment mechanisms and we must seek approval from the IURC through such public proceedings of our rate adjustment mechanism factors to reflect changes in certain costs. There can be no assurance that we will be granted approval of rate adjustment mechanism factors that we request from the IURC. The failure to obtain IURC approval of requested relief, or any other adverse rate determination by the IURC could have a material adverse effect on our results of operations, financial condition and cash flows.
As a result of the EPAct and subsequent legislation affecting the electric utility industry, we have been required to comply with rules and regulations in areas including mandatory reliability standards, cybersecurity, transmission expansion and energy efficiency. We are currently unable to predict the long-term impact, if any, to our results of operations, financial condition and cash flows as a result of these rules and regulations. Complying with the regulatory environment to which we are subject requires us to expend a significant amount of funds and resources. The failure to comply with this regulatory environment could subject us to substantial financial costs and penalties and changes, either forced or voluntary, in the way we operate our business.
Independent of the IURC’s ability to review basic rates and charges, Indiana law requires electric utilities under the jurisdiction of the IURC to meet operating expense and income test requirements as a condition for approval of requested changes in the FAC. Additionally, the fuel charge applied for can be reduced if a utility’s rolling twelve-month operating income, determined at quarterly measurement dates, exceeds a utility’s authorized annual jurisdictional net operating income and there are not sufficient applicable cumulative net operating income deficiencies against which the excess rolling twelve-month jurisdictional net operating income can be offset.
Future events, including the advent of retail competition within AES Indiana’s service territory, could result in the deregulation of part of AES Indiana’s existing regulated business. In addition to effects on our business that could result from any deregulation, such as a loss of customers and increased costs to retain or attract customers upon deregulation, adjustments to AES Indiana’s accounting records may be required to eliminate the historical impact of regulatory accounting. Such adjustments, as required by FASB ASC 980 “Regulated Operations,” could eliminate the effects of any actions of regulators that have been recognized as assets and liabilities. Required adjustments could include the expensing of any unamortized net regulatory assets, the elimination of certain tax liabilities, and a write down of any impaired utility plant balances. We expect AES Indiana to meet the criteria for the application of ASC 980 for the foreseeable future.
We are subject to litigation, regulatory proceedings, administrative proceedings, audits, settlements, investigations and claims from time to time that require us to expend significant funds to address. There can be no assurance that the outcome of these matters will not have a material adverse effect on our business, results of operations, financial condition and cash flows. Asbestos and other regulated substances are, and may continue to be, present at our facilities, and we have been named as a defendant in asbestos litigation. The continued presence of asbestos and
other regulated substances at these facilities could result in additional litigation being brought against us, which could have a material adverse effect on our results of operations, financial condition and cash flows. Please see Note 2, “Regulatory Matters” and Note 11, “Commitments and Contingencies” to the Financial Statements of this Annual Report on Form 10-K for a summary of significant regulatory matters and legal proceedings involving us.
Tax legislation initiatives or challenges to our tax positions could adversely affect our results of operations and financial condition.
We are subject to the tax laws and regulations of the U.S. federal, state and local governments. From time to time, legislative measures may be enacted that could adversely affect our overall tax positions regarding income or other taxes. There can be no assurance that our effective tax rate or tax payments will not be adversely affected by these legislative measures. In addition, U.S. federal, state and local tax laws and regulations are extremely complex and subject to varying interpretations. There can be no assurance that our tax positions will be sustained if challenged by relevant tax authorities and if not sustained, there could be a material impact on our results of operations.
RISKS RELATED TO OUR INDEBTEDNESS AND FINANCIAL CONDITION
We rely on access to the financial markets. General economic conditions and disruptions in the financial markets could adversely affect our ability to raise capital on favorable terms or at all, and cause increases in our interest expense.
From time to time, we rely on access to the capital and credit markets as a source of liquidity for capital requirements not satisfied by operating cash flows. These capital and credit markets experience volatility and disruption from time to time and the ability of corporations to raise capital can be negatively impacted. Disruptions in the capital and credit markets make it harder and more expensive to raise capital. Our ability to raise capital on favorable terms or at all can be adversely affected by unfavorable market conditions or declines in our creditworthiness, and we may be unable to access adequate funding to refinance our debt as it becomes due or finance capital expenditures. The extent of any impact will depend on several factors, including our operating cash flows, financial condition and prospects, the overall supply and demand in the credit markets, our credit ratings, credit capacity, the cost of financing, the financial condition, performance and prospects of other companies in our industry or with similar financial circumstances and other general economic and business conditions. It may also depend on the performance of credit counterparties and financial institutions with which we do business. Access to funds under our existing financing arrangements is also dependent on the ability of our counterparties to meet their financing commitments and our satisfying conditions to borrowing. Our inability to obtain financing on reasonable terms, or at all, with creditworthy counterparties could adversely affect our results of operations, financial condition and cash flows. If our available funding is limited or we are forced to fund our operations at a higher cost, these conditions may require us to curtail our business activities and increase our cost of funding, both of which would adversely impact our profitability.
See Note 7, “Debt” to the Financial Statements of this Annual Report on Form 10-K for information regarding indebtedness. See also “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” for information related to market risks.
The level of our indebtedness, and the security provided for this indebtedness, could adversely affect our financial flexibility.
As of December 31, 2024, we had on a consolidated basis $4,182.4 million of indebtedness, including finance lease obligations, and total shareholders’ equity of $1,284.5 million. AES Indiana had $2,763.8 million of first mortgage bonds outstanding as of December 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, subject to the terms of our debt agreements and regulatory approvals for any AES Indiana debt. To the extent we become more leveraged, the risks described above would increase. Further, actual cash requirements in the future may be greater than expected. Accordingly, our cash flow from operations may not be sufficient to repay at maturity all of the outstanding debt as it becomes due and, in that event, we may not be able to borrow money, sell assets or otherwise raise funds on acceptable terms or at all to refinance our debt as it becomes due. For a further discussion of outstanding debt, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources” and Note 7, “Debt” to the Financial Statements of this Annual Report on Form 10-K.
We have variable rate debt that bears interest based on a prevailing rate that is reset based on a market index that can be affected by market demand, supply, market interest rates and other market conditions. We also maintain both cash on deposit and investments in cash equivalents from time to time that could be impacted by interest rate fluctuations. As such, any event which impacts market interest rates could have a material effect on our results of operations, financial condition and cash flows. In addition, ratings agencies issue credit ratings on us and our debt that affect our borrowing costs under our financial arrangements and affect our potential pool of investors and funding sources. Our credit ratings also govern the collateral provisions of certain of our contracts. If rating agencies downgrade our credit ratings, our borrowing costs would likely further increase, our potential pool of investors and funding resources could be reduced, and we could be required to post additional cash collateral under selected contracts. These events would likely reduce our liquidity and profitability and could have a material adverse effect on our results of operations, financial condition and cash flows.
IPALCO is a holding company and parent of AES Indiana and other subsidiaries. IPALCO’s cash flow is dependent on operating cash flows of AES Indiana and its ability to pay cash to IPALCO.
IPALCO is a holding company with no material assets other than the common stock of its subsidiaries, and accordingly all cash is generated by the operating activities of our subsidiaries, principally AES Indiana. As such, IPALCO’s cash flow is largely dependent on the operating cash flows of AES Indiana and its ability to pay cash to IPALCO. AES Indiana’s mortgage and deed of trust, its amended articles of incorporation, its Credit Agreement and its $400 million Term Loan Agreement contain restrictions on AES Indiana’s ability to issue certain securities or pay cash dividends to IPALCO. For example, there are restrictions that require maintenance of a leverage ratio which could limit the ability of AES Indiana to pay dividends. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity” for a discussion of these restrictions. See Note 7, “Debt” to the Financial Statements of this Annual Report on Form 10-K for information regarding indebtedness. In addition, AES Indiana is regulated by the IURC, which possesses broad oversight powers to ensure that the needs of utility customers are being met. The IURC could impose additional restrictions on the ability of AES Indiana to distribute, loan or advance cash to IPALCO pursuant to these broad powers. While we do not expect any of the foregoing restrictions to significantly affect AES Indiana’s ability to pay funds to IPALCO in the future, a significant limitation on AES Indiana’s ability to pay dividends or loan or advance funds to IPALCO would have a material adverse effect on IPALCO’s results of operations, financial condition and cash flows.
Our ownership by AES subjects us to potential risks that are beyond our control.
All of AES Indiana’s common stock is owned by IPALCO, all of whose common stock is owned by AES U.S. Investments (82.35%) and CDPQ (17.65%). Due to our relationship with AES, any adverse developments and announcements concerning AES may impair our ability to access the capital markets and to otherwise conduct business. In particular, downgrades in AES’s credit ratings could result in AES Indiana’s or IPALCO’s credit ratings being downgraded.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.

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ITEM 2. PROPERTIES
ITEM 2. PROPERTIES
Information relating to our properties is contained in “Item 1. Business - Properties” and Note 3, “Property, Plant and Equipment” to the Financial Statements of this Annual Report on Form 10-K.
AES Indiana’s mortgage and deed of trust secures first mortgage bonds issued by AES Indiana. Pursuant to the terms of the mortgage and deed of trust, substantially all property owned by AES Indiana is subject to a direct first mortgage lien securing indebtedness of $2,763.8 million at December 31, 2024. In addition, IPALCO has outstanding $875.0 million of debt obligations which are secured by its pledge of all of the outstanding common stock of AES Indiana.

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ITEM 3. LEGAL PROCEEDINGS
ITEM 3. LEGAL PROCEEDINGS
In the normal course of business, we are subject to various lawsuits, actions, claims, and other proceedings. We are also from time to time involved in other reviews, investigations and proceedings by governmental and regulatory agencies regarding our business, certain of which may result in adverse judgments, settlements, fines, penalties, injunctions or other relief. We have accrued in our Financial Statements of this Annual Report on Form 10-K for litigation and claims where it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. We believe the amounts provided in our Financial Statements of this Annual Report on Form 10-K, as prescribed by GAAP, for these matters are adequate in light of the probable and estimable contingencies. However, there can be no assurances that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims and other matters (including those matters noted below), and to comply with applicable laws and regulations will not exceed the amounts reflected in our Financial Statements of this Annual Report on Form 10-K. As such, costs, if any, that may be incurred in excess of those amounts provided for in our Financial Statements of this Annual Report on Form 10-K, cannot be reasonably determined, but could be material. Please see Note 2, “Regulatory Matters” and Note 11, “Commitments and Contingencies” to the Financial Statements of this Annual Report on Form 10-K for summaries of significant legal proceedings involving us, which are incorporated by reference herein.
The following additional information is incorporated by reference into this Item: information about the legal proceedings contained in "Regulation" and “Environmental Matters” in “Item 1. Business” of this Annual Report on Form 10-K.

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ITEM 4. MINE SAFETY DISCLOSURE
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
As of March 5, 2025, all of the outstanding common stock of IPALCO is owned by AES U.S. Investments (82.35%) and CDPQ (17.65%). As a result, our stock is not listed for trading on any stock exchange.
Dividends
During the years ended December 31, 2024, 2023 and 2022, IPALCO declared and paid distributions to our shareholders totaling $156.6 million, $104.3 million and $102.0 million, respectively. Future distributions to our
shareholders will be determined at the discretion of our Board of Directors and will depend primarily on dividends received from AES Indiana and such other factors as our Board of Directors deems relevant. Please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity” of this Form 10-K for a discussion of limitations on dividends from AES Indiana. In order for us to make any dividend payments to our shareholders, we must, at the time and as a result of such dividends, either maintain certain credit ratings on our senior long-term debt or be in compliance with leverage and interest coverage ratios contained in IPALCO’s Third Amended and Restated Articles of Incorporation. We do not believe this requirement will be a limiting factor in paying dividends in the ordinary course of prudent business operations.
Dividends and Capital Structure Restrictions
AES Indiana’s mortgage and deed of trust and its amended articles of incorporation contain restrictions on AES Indiana’s ability to issue certain securities or pay cash dividends. So long as any of the several series of bonds of AES Indiana issued under its mortgage remains outstanding, and subject to certain exceptions, AES Indiana is restricted in the declaration and payment of dividends, or other distribution on shares of its capital stock of any class, or in the purchase or redemption of such shares, to the aggregate of its net income, as defined in the mortgage, after December 31, 1939. In addition, pursuant to AES Indiana’s articles, no dividends may be paid or accrued, and no other distribution may be made on AES Indiana’s common stock unless dividends on all outstanding shares of AES Indiana preferred stock have been paid or declared and set apart for payment. On December 30, 2022 (the “Redemption Date”), AES Indiana redeemed all of its issued and outstanding preferred stock for $60.1 million (for further discussion, see Note 10, "Equity" to the Financial Statements of this Annual Report on Form 10-K). As of December 31, 2024, and as of the filing of this report, AES Indiana was in compliance with these restrictions.
AES Indiana is also restricted in its ability to pay dividends if it is in default under the terms of its Credit Agreement and $400 million Term Loan Agreement, which could happen if AES Indiana fails to comply with certain covenants. These covenants, among other things, require AES Indiana to maintain total debt to total capitalization not in excess of 0.67 to 1. As of December 31, 2024, 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, 2024, and as of the filing of this report, IPALCO was in compliance with all covenants and no event of default existed.

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ITEM 6. SELECTED FINANCIAL DATA
ITEM 6. [RESERVED]

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis should be read in conjunction with our Financial Statements of this Annual Report on Form 10-K and the notes thereto. The following discussion contains forward-looking statements. Our actual results may differ materially from the results suggested by these forward-looking statements. Please see “Forward-Looking Statements” and “Item 1A. Risk Factors.” For a list of certain terms, abbreviations or acronyms in this discussion, see “Glossary of Terms” at the beginning of this Form 10-K.
OVERVIEW OF 2024 RESULTS AND STRATEGIC PERFORMANCE
The most important matters on which we focus in evaluating our financial condition and operating performance and allocating our resources include: (i) recurring factors which have significant impacts on operating performance such as: regulatory action, environmental matters, weather and weather-related damage in our service area, customer growth and the local economy; (ii) our progress on performance improvement and growth strategies designed to maintain high standards in several operating areas (including safety, reliability, customer satisfaction, operations, financial and enterprise-wide performance, talent management/people, capital allocation/sustainability and corporate social responsibility) simultaneously; and (iii) our short-term and long-term financial and operating
strategies. For a discussion of how we are impacted by regulation and environmental matters, please see Note 2, “Regulatory Matters” to the Financial Statements and “Environmental Matters” in “Item 1. Business” of this Annual Report on Form 10-K.
Operational Excellence
Our objective is to optimize AES Indiana’s performance in the U.S. utility industry by focusing on the following areas: safety, operations (reliability and customer satisfaction), financial and enterprise-wide performance (efficiency and cost savings, talent management/people, capital allocation/sustainability and corporate social responsibility). We set and measure these objectives carefully, balancing them in a way and to a degree necessary to ensure a sustainable high level of performance in these areas simultaneously as compared to our peers. We monitor our performance in these areas, and where practical and meaningful, compare performance in some areas to peer utilities. Because some of our financial and enterprise-wide performance measures are company-specific performance goals, they are not benchmarked.
Our safety performance is measured by both leading and lagging metrics. Our leading safety metrics track safety observations, safety meeting engagement and the reporting of near miss events which provide learning opportunities to strengthen our safety practices and process. Our lagging safety metrics track lost workday cases and OSHA total 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 Experiencing Multiple Interruptions 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 perceptions of their overall experience using the Qualtrics XM platform. Areas measured include overall Customer Satisfaction as well as customer perceptions of affordability, reliability and customer service. We also subscribe to the J.D. Power Electric Utility Residential Customer Satisfaction Study.
EXECUTIVE SUMMARY
Compared with the prior year, the results for the year ended December 31, 2024 reflect an increase in income before income tax of $61.8 million, or 86%, as well as an increase in net income of $48.2 million, or 85%, primarily due to factors including, but not limited to:
$ in millions 2024 vs. 2023
Increase in retail margin due to higher prices (primarily driven by the 2024 Base Rate Order, including the impact of certain riders now included in base rates)
$ 74.0
Increase in retail margin due to higher volumes (primarily driven by weather and higher retail demand)
28.0
Increase in ECCRA rider revenue due to recovery of certain renewable project investments
26.4
Decrease due to higher depreciation expense from additional assets placed in service, higher amortization of regulatory assets and changes in depreciation rates as a result of the 2024 Base Rate Order
(41.6)
Decrease due to higher interest expense primarily from increased borrowings
(29.2)
Other 4.2
Net change in income before income tax
61.8
Net change in income tax expense
(13.6)
Net change in net income
$ 48.2
RESULTS OF OPERATIONS
The following review of results of operations and "Capital Resources and Liquidity" sections compare the results for the year ended December 31, 2024 to the results for the year ended December 31, 2023. For discussion comparing the results for the year ended December 31, 2023 to the results for the year ended December 31, 2022, see Item 7.-Management's Discussion and Analysis of Financial Condition and Results of Operations of our 2023 Annual Report on Form 10-K, filed with the SEC on February 27, 2024. In addition to the discussion on operations below, please see the “Statistical Information on Operations” table included in “Item 1. Business” of this report for additional data such as kWh sales and number of customers by customer class.
IPALCO’s results of operations include the results of its subsidiaries, including the consolidated results of its principal subsidiary AES Indiana. All material intercompany accounts and transactions have been eliminated in consolidation.
Statements of Operations Highlights
Years Ended December 31, Change 2024 vs. 2023 Change 2023 vs. 2022
(In Thousands) 2024 2023 2022 $ % $ %
REVENUE $ 1,643,793 $ 1,649,917 $ 1,791,711 $ (6,124) (0.4) % $ (141,794) (7.9) %
OPERATING COSTS AND EXPENSES:
Fuel 359,132 494,000 568,676 (134,868) (27.3) % (74,676) (13.1) %
Power purchased 148,412 159,908 199,860 (11,496) (7.2) % (39,952) (20.0) %
Operation and maintenance 476,494 477,880 493,674 (1,386) (0.3) % (15,794) (3.2) %
Depreciation and amortization 329,468 287,863 266,504 41,605 14.5 % 21,359 8.0 %
Taxes other than income taxes 27,478 24,864 33,048 2,614 10.5 % (8,184) (24.8) %
Other, net
(106) (361) (3,201) 255 (70.6) % 2,840 (88.7) %
Total operating costs and expenses 1,340,878 1,444,154 1,558,561 (103,276) (7.2) % (114,407) (7.3) %
OPERATING INCOME 302,915 205,763 233,150 97,152 47.2 % (27,387) (11.7) %
OTHER (EXPENSE) / INCOME, NET:
Allowance for equity funds used during construction 3,991 9,315 4,784 (5,324) (57.2) % 4,531 94.7 %
Interest expense (172,150) (142,926) (131,232) (29,224) 20.4 % (11,694) 8.9 %
Other (expense) / income, net (1,163) (410) 11,783 (753) 183.7 % (12,193) (103.5) %
Total other expense, net (169,322) (134,021) (114,665) (35,301) 26.3 % (19,356) 16.9 %
INCOME BEFORE INCOME TAX 133,593 71,742 118,485 61,851 86.2 % (46,743) (39.5) %
Income tax expense 28,364 14,715 21,859 13,649 92.8 % (7,144) (32.7) %
NET INCOME 105,229 57,027 96,626 48,202 84.5 % (39,599) (41.0) %
Dividends on and redemption of preferred stock - - 3,509 - - % (3,509) (100.0) %
Net loss attributable to noncontrolling interests (28,294) (26,093) - (2,201) 8.4 % (26,093) (100.0) %
NET INCOME ATTRIBUTABLE TO COMMON STOCK $ 133,523 $ 83,120 $ 93,117 $ 50,403 60.6 % $ (9,997) (10.7) %
Revenue
Revenue decreased in 2024 from the prior year by $6.1 million, which resulted from the following changes (dollars in thousands):
2024 2023 Change % Change
Revenue:
Retail Revenue $ 1,592,038 $ 1,576,653 $ 15,385 1.0 %
Wholesale Revenue 37,519 56,557 (19,038) (33.7) %
Miscellaneous Revenue 14,236 16,707 (2,471) (14.8) %
Total Revenue $ 1,643,793 $ 1,649,917 $ (6,124) (0.4) %
Heating Degree Days(1):
Actual 4,273 4,350 (77) (1.8) %
30-year Average 5,164 5,198
Cooling Degree Days(1):
Actual 1,337 1,139 198 17.4 %
30-year Average 1,186 1,177
(1) Heating and cooling degree-days are a measure of the relative heating or cooling required for a home or business. The heating degrees in a day are calculated as the degrees that the average actual daily temperature is below 65 degrees Fahrenheit. For example, if the average temperature on March 20th was 40 degrees Fahrenheit, the heating degree days for that day would be the 25-degree difference between 65 degrees and 40 degrees. Similarly, cooling degree days in a day are calculated as the degrees that the average actual daily temperature is above 65 degrees Fahrenheit.
The following table presents additional data on kWh sold:
2024 2023 kWh Change % Change
kWh Sales (In Millions):
Residential 5,048 4,800 248 5.2 %
Small commercial and industrial 1,771 1,722 49 2.8 %
Large commercial and industrial 6,010 5,929 81 1.4 %
Public lighting 39 19 20 105.3 %
Sales - retail customers 12,868 12,470 398 3.2 %
Wholesale 854 1,657 (803) (48.5) %
Total kWh sold 13,722 14,127 (405) (2.9) %
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, 2024 as compared to the prior year:
The decrease in revenue of $6.1 million was primarily due to the following:
$ in millions 2024 vs. 2023
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.
$ 67.8
Price:
Net decrease in the weighted average price of retail kWh sold mainly due to lower FAC revenue primarily in the first half of 2024, partially offset by the 2024 Base Rate Order.
(43.4)
Other:
Primarily due to decrease in alternative revenue programs and miscellaneous charges to customers (including reconnection and late fee charges).
(9.0)
Net change in retail revenue 15.4
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.
(27.4)
Price:
Net increase 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.
8.4
Net change in wholesale revenue (19.0)
Miscellaneous revenue:
Primarily due to decrease in capacity revenue due to recent MISO auction results, partially offset by increase in RTO revenue
(2.5)
Net change in revenue $ (6.1)
Operating Costs and Expenses
The following table illustrates changes in Operating costs and expenses from 2023 to 2024 (in thousands):
Years Ended
December 31,
2024 2023 $ Change % Change
Operating costs and expenses:
Fuel $ 359,132 $ 494,000 $ (134,868) (27.3) %
Power purchased 148,412 159,908 (11,496) (7.2) %
Operation and maintenance 476,494 477,880 (1,386) (0.3) %
Depreciation and amortization 329,468 287,863 41,605 14.5 %
Taxes other than income taxes 27,478 24,864 2,614 10.5 %
Other, net
(106) (361) 255 (70.6) %
Total operating costs and expenses $ 1,340,878 $ 1,444,154 $ (103,276) (7.2) %
Fuel
The decrease in fuel costs of $134.9 million was primarily due to the following:
$ in millions 2024 vs. 2023
Volume:
Coal $ (50.4)
Natural gas 40.6
Oil (0.2)
Net change in volume (10.0)
Price:
Coal 13.4
Natural gas (43.9)
Oil (0.7)
Deferred fuel (93.7)
Net change in price (124.9)
Net change in fuel expense $ (134.9)
The changes in the volume of coal and natural gas are mostly attributed to the retirement of Petersburg Unit 2 in June 2023. 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 power purchased 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 power purchased costs incurred for wholesale energy sales are considered in the Off System Sales Margin rider.
Power Purchased
The decrease in Power purchased costs of $11.5 million was primarily due to the following:
$ in millions 2024 vs. 2023
Volume:
Net increase in the volume of power purchased primarily due to AES Indiana's generation units running less frequently, partially offset by the impact of acquiring the Hoosier Wind Project in the first quarter of 2024.
$ 4.8
Price:
Market prices 0.9
Deferred power purchased
(16.8)
Net change in price (15.9)
Other, net (mostly due to changes in capacity purchases) (0.4)
Net change in power purchased costs $ (11.5)
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 power purchased 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. We are generally permitted to recover underestimated fuel and power purchased costs to serve our retail customers in future rates through quarterly FAC proceedings.
Operation and Maintenance
The decrease in Operation and maintenance expense of $1.4 million was primarily due to the following:
$ in millions 2024 vs. 2023
Decrease in contracted services expenses and lower materials and supplies inventory consumption, primarily due to lower generation maintenance and outage costs
$ (31.9)
Increase due to higher expected credit losses
19.9
Increase in employee compensation and benefit costs
8.5
Other, net 2.1
Net change in operation and maintenance costs $ (1.4)
Depreciation and Amortization
The increase in Depreciation and amortization expense of $41.6 million was mostly attributed to the impact of additional assets placed in service, higher amortization of regulatory assets and changes in depreciation rates as a result of the 2024 Base Rate Order.
Taxes Other Than Income Taxes
The increase in Taxes other than income taxes of $2.6 million was mostly attributed to an increase in property tax expense of $3.0 million primarily as a result of higher assessed values.
Other (Expense) / Income, Net
The following table illustrates changes in Other (expense) / income, net from 2023 to 2024 (in thousands):
Years Ended
December 31,
2024 2023 $ Change % Change
Other (expense) / income, net:
Allowance for equity funds used during construction $ 3,991 $ 9,315 $ (5,324) (57.2) %
Interest expense (172,150) (142,926) (29,224) 20.4 %
Other (expense) / income, net (1,163) (410) (753) 183.7 %
Total other expense, net $ (169,322) $ (134,021) $ (35,301) 26.3 %
Allowance for Equity Funds Used During Construction
The decrease in Allowance for equity funds used during construction of $5.3 million was primarily driven by AES Indiana's capital structure in the comparative periods.
Interest Expense
The increase in Interest expense of $29.2 million was primarily due to (i) higher interest expense on debt of $48.1 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 $18.5 million.
Income Tax Expense
The following table illustrates changes in income tax expense from 2023 to 2024 (in thousands):
Years Ended
December 31,
2024 2023 $ Change % Change
Income tax expense $ 28,364 $ 14,715 $ 13,649 92.8 %
The increase in income tax expense of $13.6 million was primarily driven by higher pre-tax income and a decrease in the net tax benefit related to the reversal of excess deferred taxes of AES Indiana resulting from the 2024 Base Rate Order; partially offset by the reversal of certain excess deferred taxes which are not probable to cause a reduction in future base customer rates.
Net Loss Attributable to Noncontrolling Interests
The following table illustrates changes in Net loss attributable to noncontrolling interests from 2023 to 2024 (in thousands):
Years Ended
December 31,
2024 2023 $ Change % Change
Net loss attributable to noncontrolling interests
$ (28,294) $ (26,093) $ (2,201) 8.4 %
The increase in Net loss attributable to noncontrolling interests of $2.2 million relates to the higher allocation of losses to the tax equity investor of the Hardy Hills Solar Project, which was partially placed in service in December 2023, with the remainder of the project placed in service in May 2024. See Note 2, "Regulatory Matters - IRP Filings and Replacement Generation - Hardy Hills Solar Project " to the Financial Statements of this Annual Report on Form 10-K for more information.
KEY TRENDS AND UNCERTAINTIES
During 2025 and beyond, we expect that our financial results will be driven primarily by retail demand, weather, and maintenance costs. In addition, our financial results will likely be driven by many other factors including, but not limited to:
▪regulatory outcomes and impacts;
▪the passage of new legislation, implementation of regulations or other changes in regulation; and
▪timely recovery of capital expenditures and operation and maintenance costs.
If favorable outcomes related to these factors do not occur, or if the challenges described below and elsewhere in this report impact us more significantly than we currently anticipate, then these factors, or other factors unknown to us, may impact our operating margin, net income and cash flows. We continue to monitor our operations and address challenges as they arise. For a discussion of the risks related to our business, see “Item 1. Business” and “Item 1A. Risk Factors” of this Annual Report on Form 10-K.
Operational
Trade Restrictions and Supply Chain
In recent years, the U.S. Department of Commerce (“Commerce”) has initiated investigations 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. One such investigation initiated in April of 2022 resulted in a final determination by Commerce that circumvention would be deemed to occur under certain circumstances, resulting in the imposition AD and CVD duties on the imported cells and panels. Such determination and related matters remain the subject of ongoing litigation. Separate AD/CVD investigations initiated by Commerce in May of 2024 resulted in preliminary determinations by Commerce that South East Asia countries were also dumping and receiving subsidies and therefore Commerce established CVD and AD rates on certain solar manufacturers. The U.S. International Trade Commission is also investigating this matter. If the Commerce and U.S. International Trade Commission investigations result in Commerce issuing AD/CVD orders, the orders are likely to be imposed in June 2025.
Separately, the U.S. maintains a global tariff (currently 14.25% ad valorem) on solar cells and modules pursuant to the Section 201 Safeguard Action on crystalline silicon photovoltaic products, which became effective in February 2018. On June 21, 2024, President Biden issued Proclamation 10779, revoking the exclusion of bifacial panels from safeguard relief previously proclaimed in Proclamation 10339, and reinstating the tariff on bifacial panels under the Section 201 Safeguard Action, subject to certain qualifications. These global tariffs are expected to expire in February 2026.
The U.S. also maintains a Section 301 tariff on certain Chinese made lithium-ion batteries and related components utilized for energy storage systems, with such tariff currently set at 7.5% and increasing to 25% effective January 1, 2026. There is also an ongoing AD/CVD investigation with respect to exports by China of natural and synthetic graphite used to make lithium-ion battery anode material. Any determinations or orders arising from such investigation could result in price increases.
Additionally, the Uyghur Forced Labor Prevention Act (“UFLPA”) seeks to block the import of products made with forced labor in certain areas of China, at any point in the supply chain, and may lead to certain suppliers being blocked from importing solar cells and panels to the U.S. While this has impacted the U.S. market, we have managed this issue without significant impact to our projects. Further disruptions may impact our suppliers’ ability or willingness to meet their contractual agreements or to continue to supply cells or panels into the U.S. market on terms that we deem satisfactory.
The Trump Administration has threatened or imposed tariffs on a wide range of countries and sectors. On February 10, 2025, President Trump signed Executive Orders modifying existing Section 232 tariffs on steel and aluminum imports to expand their scope of applicability and imposing 25% tariffs on both products. At this time we do not expect the modifications to tariffs on steel and aluminum to have a material impact on our business. On February 13, 2025, the Trump Administration announced a plan to counter non-reciprocal trading arrangements with all U.S. trading partners by determining the equivalent of a reciprocal tariff with respect to each foreign trade partner. On
February 1, 2025, President Trump issued an executive order declaring a national emergency under the International Emergency Economic Powers Act (IEEPA) and imposing a 10% additional tariff on imports from China. We expect that additional tariffs on imports from China will increase overall costs for materials and parts that are imported to build and maintain renewable energy plants for the U.S. industry. Any additional U.S. tariffs on imports from other countries or higher tariffs could negatively impact our business.
While we have executed agreements for AES Indiana’s existing solar and battery energy storage projects that mitigate these risks, potential future 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 tariffs, including reciprocal tariffs, Commerce investigations, the impact of any additional adverse Commerce determinations or other tariff disputes or litigation, the impact of the UFLPA, potential future disruptions to the renewable energy supply chain and their effect on AES Indiana’s solar and battery energy storage project development and construction activities remain uncertain. AES Indiana will continue to monitor developments and take prudent steps towards managing our renewable projects.
Customer Information and Billing System Implementation
In the fourth quarter of 2023, we implemented our new customer information and billing system, SAP IS-U, a software solution that SAP developed for businesses operating in the utility industries. In connection with this implementation, a temporary pause of customer disconnections and certain collection efforts and write-off processes was instituted. This has resulted in higher past due customer receivables and a higher allowance for credit losses as of December 31, 2024. We currently anticipate reinstituting the customer disconnections process and collection efforts and write-off processes in the first quarter of 2025.
Capital Projects
Our construction projects have experienced some indications of delays and price increases due to supply chain disruptions; however, they are currently proceeding without material delays. For further discussion of our capital requirements, see "Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity" of this Annual Report on Form 10-K.
Macroeconomic and Political
U.S. Utilities Load Growth and Large Load Customers
The expansion of data center needs related to the growing use of generative artificial intelligence has the potential to be a significant accelerant to the load growth of the U.S. utilities market. AES Indiana is working with several companies to provide solutions for the electric service needs of data centers and we see these relationships growing as utilization of generative artificial intelligence drives the expansion of data center use within our service territory. As part of this process, AES Indiana is evaluating cost effective options to reliably serve these large data center customers.
IRA and U.S. Renewable Energy Tax Credits
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. The IRA extends solar ITCs and provides higher credits for projects that satisfy wage and apprenticeship requirements, as well as the “technology neutral” clean electricity PTC and ITC will provide incremental benefits for our current and future planned renewable projects. For further discussion of our renewable projects, see Note 2, "Regulatory Matters - IRP Filings and Replacement Generation" to the Financial Statements of this Annual Report on Form 10-K.
We account for renewable projects according to GAAP, which, when partnering with tax-equity investors to monetize tax benefits, utilizes the HLBV method. This method recognizes the tax-credit value that is transferred to tax equity investors at the time of its creation, which for projects utilizing the ITC, begins in the quarter the project is placed in service. For projects utilizing the PTC, this value is recognized over 10 years as the facility produces energy. In 2023, we recognized $26.1 million of earnings from tax attributes using the HLBV method upon the first stage of the Hardy Hills Solar Project being placed in service. Upon the final stage of the project being placed in service in May 2024, the Company recognized $21.4 million of earnings from tax attributes using the HLBV method. 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 and interpretive rules from the U.S. Department of Treasury and other government agencies. Some of the guidance and rulemaking enacted under the Biden Administration could be changed or modified by the Trump Administration, creating uncertainty with respect to implementation of the IRA. Also, the Trump Administration has issued Executive Orders that pause certain funding allocated to projects under the Infrastructure Investment and Jobs Act (IIJA) and the IRA during a 90-day review process. As they currently stand, these Executive Orders do not impact the tax credits under 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. In the U.S., the IRA includes a 15% corporate alternative minimum tax (CAMT) based on adjusted financial statement income. In September 2024, the IRS released proposed regulations on the 15% CAMT. We are currently evaluating the potential impacts of these regulations.
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 2025. 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 power purchased 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 and $400 million Term Loan 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.
Trump Administration Actions
On January 25, 2025, President Trump issued an Executive Order titled "Declaring a National Energy Emergency" directing Agencies to, among other tasks, identify and exercise any lawful emergency authorities available to them to facilitate the identification, leasing, siting, production, transportation, refining, and generation of domestic energy resources.
Regulatory
Regulatory Rate Review
On April 17, 2024, the IURC issued an order (the “2024 Base 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. For further discussion, please see Note 2, "Regulatory Matters - Regulatory Rate Review and Base Rate Orders" to the Financial Statements of this Annual Report on Form 10-K.
2025 IRP
In January 2025, AES Indiana initiated its 2025 IRP process with external stakeholders. The first of five public advisory meetings took place on January 29, 2025 and will continue through most of 2025, with AES Indiana anticipating it will submit its final 2025 IRP, shaped by stakeholder feedback, to the IURC in November 2025. For
further discussion, please see Note 2, "Regulatory Matters - IRP Filings and Replacement Generation - 2025 IRP" to the Financial Statements of this Annual Report on Form 10-K.
2022 IRP
AES Indiana filed its 2022 IRP with the IURC in December 2022. The 2022 IRP short-term action plan includes converting the two remaining coal units at Petersburg to natural gas. Additionally, AES Indiana plans to add up to 1,300 MW of wind, solar, and battery energy storage by 2027. For further discussion, please see Note 2, "Regulatory Matters - IRP Filings and Replacement Generation - 2022 IRP" to the Financial Statements of this Annual Report on Form 10-K.
Please see “Item 1. Business - Regulation” and Note 2, “Regulatory Matters” to the Financial Statements of this Annual Report on Form 10-K for further discussion of these and other regulatory matters.
CAPITAL RESOURCES AND LIQUIDITY
Overview
As of December 31, 2024, we had unrestricted cash and cash equivalents of $26.6 million and available borrowing capacity of $250 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 29, 2026. 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 December 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 $0.0 million remains available under the order as of December 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 December 31, 2024. We also have restrictions on the amount of new debt that may be issued due to contractual obligations of AES and by financial covenant restrictions under our existing debt obligations. We do not believe such restrictions will be a limiting factor in our ability to issue debt in the ordinary course of prudent business operations.
We depend on timely and continued access to capital markets to manage our liquidity needs. The inability to raise capital on favorable terms, to refinance existing indebtedness or to fund operations and other commitments during times of political or economic uncertainty or otherwise could have material adverse effects on our financial condition and results of operations. In addition, changes in the timing of tariff increases or delays in the regulatory determinations as well as unfavorable regulatory outcomes could have a material adverse effect on our results of operations, financial condition and cash flows. See "Risks related to our indebtedness and financial condition" in "Item 1A. Risk Factors" and "Regulation" in "Item 1 - Business" of this Annual Report on Form 10-K for more information. From time to time, we may elect to repurchase our outstanding debt through cash purchases, privately negotiated transactions or otherwise when management believes such repurchases are favorable to make. The amounts involved in any such repurchases may be material.
Cash Flows
The following table summarizes the changes in operating, investing, and financing cash flows for the comparative periods:
Years ended December 31, $ Change
2024 2023 2022 2024 vs. 2023
(in thousands)
Net cash provided by operating activities $ 239,927 $ 391,933 $ 346,346 $ (152,006)
Net cash used in investing activities (1,026,057) (992,873) (525,087) (33,184)
Net cash provided by financing activities 784,198 427,971 373,377 356,227
Net change in cash, cash equivalents and restricted cash
(1,932) (172,969) 194,636 171,037
Cash, cash equivalents and restricted cash at beginning of year 28,584 201,553 6,917 (172,969)
Cash, cash equivalents and restricted cash at end of year
$ 26,652 $ 28,584 $ 201,553 $ (1,932)
The following cash flow discussion compares the cash flows for the year ended December 31, 2024 to the cash flows for the year ended December 31, 2023. For discussion comparing the cash flows for the year ended December 31, 2023 to the cash flows for the year ended December 31, 2022, see Item 7.-Management's Discussion and Analysis of Financial Condition and Results of Operations of our 2023 Annual Report on Form 10-K, filed with the SEC on February 27, 2024.
2024 versus 2023
Operating Activities
The following table summarizes the key components of our consolidated operating cash flows:
Years ended December 31, $ Change
2024 2023 2022 2024 vs. 2023
(in thousands)
Net income $ 105,229 $ 57,027 $ 96,626 $ 48,202
Depreciation and amortization 329,468 287,863 266,504 41,605
Amortization of deferred financing costs and debt discounts
3,567 3,880 3,914 (313)
Deferred income taxes and investment tax credit adjustments - net
835 32,653 (6,706) (31,818)
Allowance for equity funds used during construction (3,991) (9,315) (4,784) 5,324
Net income, adjusted for non-cash items 435,108 372,108 355,554 63,000
Net change in operating assets and liabilities (195,181) 19,825 (9,208) (215,006)
Net cash provided by operating activities $ 239,927 $ 391,933 $ 346,346 $ (152,006)
The net change in operating assets and liabilities for the year ended December 31, 2024 compared to the year ended December 31, 2023 was driven by the following (in thousands):
Decrease from current and non-current regulatory assets and liabilities primarily due to lower FAC collections in the current year, higher regulatory rider deferrals related to renewable projects and the settlement of a pre-existing power purchase agreement
$ (178,047)
Decrease in accounts payable primarily due to timing of invoices and payments
(99,944)
Decrease from higher net accounts receivable driven by the timing of collections, billing delays and a temporary pause of customer disconnections and certain collection efforts and write-off processes after the implementation of AES Indiana's customer billing system upgrade in the fourth quarter of 2023
(37,125)
Increase primarily due to lower purchases of fuel inventory in 2024
54,456
Increase from lower income tax receivables driven by higher income tax expense in 2024
52,441
Other (6,787)
Net change in operating assets and liabilities $ (215,006)
Investing Activities
Net cash used in investing activities increased $33.2 million for the year ended December 31, 2024 compared to the year ended December 31, 2023, which was primarily driven by (in thousands):
Payments for an acquisition made in the current year
$ (48,368)
Higher cash outflows for capital expenditures related with renewable energy projects and growth related capital expenditures primarily from TDSIC investments. This increase is partially offset by lower capex incurred in maintenance projects.
(28,617)
Purchase of intangibles in 2023
40,287
Other 3,514
Net change in investing activities $ (33,184)
Financing Activities
Net cash provided by financing activities increased $356.2 million for the year ended December 31, 2024 compared to the year ended December 31, 2023, which was primarily driven by (in thousands):
Increase due to net long-term debt issuances at IPALCO and AES Indiana
$ 605,000
Increase due to higher equity contributions from shareholders in the current year
225,000
Decrease due to net short-term debt repayments
(200,000)
Decrease due to net revolver repayments on AES Indiana's revolving credit facility
(210,000)
Decrease due to higher distributions to shareholders
(55,815)
Other (7,958)
Net change in financing activities $ 356,227
Capital Requirements
Capital Expenditures
Our capital expenditure program, including development and permitting costs, for the three-year period from 2025 through 2027 is currently estimated to cost approximately $2.8 billion (excluding environmental compliance), and includes estimates as follows (amounts in millions):
For the three-year period
2025 2026 2027 from 2025 through 2027
Power generation related projects $ 584.7 $ 577.6 $ 345.2 $ 1,507.5 (1)
Transmission and distribution related additions, improvements and extensions 231.7 198.6 347.2 777.5 (2)
TDSIC Plan investments 149.2 215.7 - 364.9 (3)
Other miscellaneous equipment 36.4 39.5 28.0 103.9
Total estimated costs of capital expenditure program $ 1,002.0 $ 1,031.4 $ 720.4 $ 2,753.8
(1) Includes spending for AES Indiana's power generation and renewable energy projects.
(2) Additions, improvements and extensions to AES Indiana's transmission and distribution lines, substations, power factor and voltage regulating equipment, distribution transformers and street lighting facilities.
(3) Includes spending under AES Indiana's TDSIC plan approved by the IURC on March 4, 2020 for eligible transmission, distribution and storage system improvements totaling $1.2 billion from 2020 through 2026. Total TDSIC costs expended from project inception through December 31, 2024 were $874.0 million.
The amounts described in the capital expenditure program above include estimated spending under AES Indiana's 2022 IRP filed with the IURC in December 2022. See Note 2, "Regulatory Matters - IRP Filings and Replacement Generation - 2022 IRP" to the Financial Statements of this Annual Report on Form 10-K for further discussion.
Capital Resources
As IPALCO is a holding company, substantially all of its cash is generated by the operating activities of its subsidiaries, principally AES Indiana. None of its subsidiaries, including AES Indiana, are obligated under or have guaranteed to make payments with respect to the 2030 IPALCO Notes or the 2034 IPALCO Notes; however, all of
AES Indiana’s common stock is pledged to secure these debt obligations. Accordingly, IPALCO’s ability to make payments on the 2030 IPALCO Notes and the 2034 IPALCO Notes depends on the ability of AES Indiana to generate cash and distribute it to IPALCO.
Liquidity
We expect our existing cash balances, cash generated from operating activities and borrowing capacity on our existing Credit Agreement will be adequate to meet our anticipated operating needs, including interest expense on our debt and dividends to our equity owners. Our business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and carrying costs, potential margin requirements related to interest rate and commodity hedges, taxes and dividend payments. For 2025 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
Significant Debt Transactions
For further discussion of our significant debt transactions, please see Note 7, “Debt” to the Financial Statements of this Annual Report on Form 10-K.
Line of Credit
AES Indiana entered into a second amendment and restatement of its $350 million revolving Credit Agreement on December 22, 2022 with a syndication of bank lenders, as discussed in Note 7, “Debt - Line of Credit” to the Financial Statements of this Annual Report on Form 10-K.
We had the following amounts available under the revolving Credit Agreement:
$ in millions Type Maturity Commitment Amounts available at December 31, 2024
AES Indiana Revolving December 2027 $ 350.0 $ 250.0
Credit Ratings
Our ability to borrow money or to refinance existing indebtedness and the interest rates at which we can borrow money or refinance existing indebtedness are affected by our credit ratings. In addition, the applicable interest rates on AES Indiana’s Credit Agreement (as well as the amount of certain other fees in the Credit Agreement) are dependent upon the credit ratings of AES Indiana. Downgrades in the credit ratings of AES could result in AES Indiana’s and/or IPALCO’s credit ratings being downgraded. Any reduction in our debt or credit ratings may adversely affect the trading price of our outstanding debt securities.
The following table presents the debt ratings and credit ratings (issuer/corporate rating) and outlook for IPALCO and AES Indiana.
Debt ratings IPALCO AES Indiana Outlook
Fitch Ratings BBB (a)
A (b)
Stable
Moody’s Investors Service Baa3 (a)
A2 (b)
Negative
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 Negative
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.
Contractual Obligations
Our non-contingent contractual obligations as of December 31, 2024 are set forth below:
Payments due in:
Total Less Than 1 Year 1 - 3
Years 3 - 5
Years More Than
5 Years
(In Millions)
Short-term and long-term debt $ 4,138.8 $ 540.0 $ 90.0 $ 55.0 $ 3,453.8
Interest obligations 2,944.5 199.7 360.1 359.6 2,025.1
Finance lease obligations 87.1 4.5 9.2 9.6 63.8
Purchase obligations:
Coal, gas, power purchased and
related transportation 643.8 176.8 201.2 171.7 94.1
Other 227.5 220.5 2.8 4.2 -
Total $ 8,041.7 $ 1,141.5 $ 663.3 $ 600.1 $ 5,636.8
Short-term and long-term debt:
Our short-term and long-term debt at December 31, 2024 consists of outstanding borrowings on the Credit Agreement, the $400 million Term Loan Agreement, AES Indiana first mortgage bonds and IPALCO long-term debt. The long-term debt amounts include current maturities but exclude unamortized debt discounts and deferred financing costs. See Note 7, "Debt" to the Financial Statements of this Annual Report on Form 10-K.
Interest payments:
Interest payments are associated with the short-term and long-term debt described above. The interest payments relating to variable-rate debt are projected using the interest rates in effect at December 31, 2024.
Finance lease obligations:
Finance lease obligations are primarily related to land. For additional information, see Note 15, "Leases - Lessee" to the Financial Statements of this Annual Report on Form 10-K.
Purchase obligations:
Purchase commitments for coal, gas, power purchased and related transportation:
AES Indiana enters into long-term contracts for the purchase of coal, gas, power purchased 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, 2024, 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 6, "Derivative Instruments and Hedging Activities"), (iii) taxes (see Note 8, "Income Taxes"), (iv) pension and other postretirement employee benefit liabilities (see Note 9, "Benefit Plans") and (v) contingencies (see Note 11, "Commitments and Contingencies"). See the indicated notes to the Financial Statements of this Annual Report on Form 10-K for additional information on the items excluded.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
We prepare our consolidated financial statements in accordance with GAAP. As such, we are required to make certain estimates, judgments and assumptions that we believe are reasonable based upon the information available. These estimates and assumptions affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the period presented. Therefore, the possibility exists for materially different reported amounts under different conditions or assumptions. Significant accounting policies used in the preparation of the consolidated financial statements are described in Note 1, “Overview and Summary of Significant Accounting Policies” to the Financial Statements of this Annual Report on Form 10-K. This section addresses only those accounting policies involving amounts material to our financial statements that require the most estimation, judgment or assumptions and should be read in conjunction with Note 1, “Overview and Summary of Significant Accounting Policies” to the Financial Statements of this Annual Report on Form 10-K.
Revenue Recognition
For information regarding the nature of our revenue streams and our critical accounting policies affecting revenue recognition, please see Note 1, “Overview and Summary of Significant Accounting Policies - Revenue Recognition” and Note 14, "Revenue" to the Financial Statements of this Annual Report on Form 10-K. The effect on 2024 revenue and ending unbilled revenue of a one percentage point change in unbilled MWhs for the month of December 2024 is immaterial.
Credit Losses
We use a forward-looking "expected loss" model to recognize allowances for credit losses on customer and other receivables. 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 the collectability, as applicable, of our receivables balance. Our determination of the allowance for credit losses requires us to make estimates and judgments regarding our customers' ability to pay amounts due, which have required a higher degree of estimation given the increases seen in past due customer receivables in 2024. We believe such estimates and judgments are reasonable and the related allowance for credit losses is adequate as of December 31, 2024; however, changes in such estimates and judgments could result in a different conclusion, which could be material. The effect of a one percentage point change in the assumptions used in the allowance for credit losses estimate as of December 31, 2024 is approximately $2.9 million. See Note 1, “Overview and Summary of Significant Accounting Policies - Accounts Receivable and Allowance for Credit Losses” to the Financial Statements of this Annual Report on Form 10-K for further information on AES Indiana’s receivable balances.
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, 2024, 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 8, "Income Taxes" to the Financial Statements of this Annual Report on Form 10-K for more information.
Regulatory Assets and Liabilities
As a regulated utility, we apply the provisions of ASC 980 “Regulated Operations,” which gives recognition to the ratemaking and accounting practices of the IURC and the FERC. Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in customer rates. Regulatory liabilities generally represent obligations to make refunds or future rate reductions to customers for previous overcollections or the deferral of revenue collected for costs that AES Indiana expects to incur in the future. Specific regulatory assets and liabilities are disclosed in Note 2, “Regulatory Matters - Regulatory Assets and Liabilities” to the Financial Statements of this Annual Report on Form 10-K.
The deferral of costs (as regulatory assets) is appropriate only when the future recovery of such costs is probable. In assessing probability, we consider such factors as specific orders from the IURC, regulatory precedent and the current regulatory environment. To the extent recovery of costs is no longer deemed probable, related regulatory assets would be required to be expensed in current period income. Our regulatory assets and liabilities have been created pursuant to specific orders of the IURC or established regulatory practices, such as other utilities under the jurisdiction of the IURC being granted recovery of similar costs. It is probable, but not certain, that these regulatory assets will be recoverable, subject to IURC approval.
AROs
In accordance with the provisions of GAAP relating to the accounting for AROs, legal obligations associated with the retirement of long-lived assets are required to be recognized at their fair value at the time those obligations are 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 4, "ARO" to the Financial Statements of this Annual Report on Form 10-K for more information.
Pension Plans
The valuation of our benefit obligation, fair value of plan assets, and net periodic benefit costs requires various estimates and assumptions, the most significant of which include the discount rate and expected return on plan assets. We review these and other assumptions, such as mortality, on an annual basis. Please see Note 1, “Overview and Summary of Significant Accounting Policies - Pension and Postretirement Benefits” and Note 9, "Benefit Plans" to the Financial Statements of this Annual Report on Form 10-K for more information.
Contingent and Other Obligations
During the conduct of our business, we are subject to a number of federal and state laws and regulations, as well as other factors and conditions that potentially subject us to environmental, litigation, insurance and other risks. We
periodically evaluate our exposure to such risks and record estimated liabilities for those matters where a loss is considered probable and reasonably estimable in accordance with GAAP. In recording such estimated liabilities, we may make assumptions, estimates and judgments that affect the reported amounts of assets, liabilities and expenses as they relate to contingent and other obligations. These assumptions and estimates are based on historical experience and assumptions and may be subject to change. We believe such estimates and assumptions are reasonable.
Please see Note 1, “Overview and Summary of Significant Accounting Policies - Contingencies” and Note 11, “Commitments and Contingencies” to the Financial Statements of this Annual Report on Form 10-K for information about significant contingencies involving us.
NEW ACCOUNTING STANDARDS
Please see Note 1, “Overview and Summary of Significant Accounting Policies” to the Financial Statements of this Annual Report on Form 10-K for a discussion of new accounting pronouncements and the potential impact to our results of operations, financial condition and cash flows.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Overview
The primary market risks to which we are exposed are those associated with environmental regulation, debt and equity investments, fluctuations in interest rates and certain raw materials. We sometimes use financial instruments and other contracts to hedge against such fluctuations, including, on a limited basis, financial and commodity derivatives. We generally do not enter into derivative instruments for trading or speculative purposes. Our U.S. Risk Management Committee (U.S. RMC), comprised of members of senior management, is responsible for establishing risk management policies and the monitoring and reporting of risk exposures related to our operations. The U.S. RMC meets on a regular basis with the objective of identifying, assessing and quantifying material risk issues and developing strategies to manage these risks.
The disclosures presented in this section are based upon a number of assumptions; actual effects may differ. The safe harbor provided in Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 shall apply to the disclosures contained in this section. For further information regarding market risk, see "Item 1A.-Risk Factors." Our businesses may incur substantial costs and liabilities and be exposed to price volatility as a result of risks associated with the electricity markets, which could have a material adverse effect on our financial performance; and we may not be adequately hedged against our exposure to changes in interest rates.
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 $43.93, $34.13 and $69.14 in 2024, 2023 and 2022, respectively. For the periods presented in the Financial Statements of this Annual Report on Form 10-K, a decline in wholesale prices could have had a negative impact on wholesale margins, because most of our non-fuel costs are fixed in the short term and lower wholesale prices can result in lower wholesale volumes sold. However, the impact is limited as the 2024 Base Rate Order provides that annual wholesale margins earned above (or below) a benchmark of $28.6 million shall be passed back (or charged) to customer rates through a rate adjustment mechanism. Our wholesale revenue represented 4.0% 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 have approximately 86% of our forecasted coal requirements for 2025 currently in inventory or secured under contract for delivery in 2025. 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 power purchased, 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. Power purchased costs can be highly volatile. We are currently committed under a long-term power purchase agreement to purchase all the wind-generated electricity through 2031 from a project in Minnesota, which has a maximum output capacity of 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, 2024. 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 power purchased costs incurred to meet jurisdictional retail load. In certain circumstances, we may not be allowed to recover a portion of power purchased costs incurred to meet our jurisdictional retail load. See Note 2, “Regulatory Matters - FAC and Authorized Annual Jurisdictional Net Operating Income” to the Financial Statements of this Annual Report on Form 10-K.
Equity Price Risk
Our Pension Plans are impacted significantly by the economy as a result of the Pension Plans being invested in common equity securities. The performance of the Pension Plans’ investments in such common equity securities and other instruments impacts our earnings as well as our funding liability. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $7.7 million reduction in fair value as of December 31, 2024 and approximately a $5.4 million increase to the 2025 pension expense. Please see Note 9, “Benefit Plans” to the Financial Statements of this Annual Report on Form 10-K for additional Pension Plan information.
Interest Rate Risk
We use long-term debt as a significant source of capital in our business, which exposes us to interest rate risk. We do not enter into market risk sensitive instruments for trading purposes. We manage our exposure to interest rate risk through the use of fixed-rate debt and by refinancing existing long-term debt at times when it is deemed economic and prudent. In addition, AES Indiana’s Credit Agreement and $400 million Term Loan Agreement bears interest at a variable rate based either on the Prime interest rate or on the SOFR. Fair values relating to financial instruments are dependent upon prevalent market rates of interest. At December 31, 2024, we had approximately $3,638.8 million principal amount of fixed rate debt and $500.0 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, 2024:
2025 2026 2027 2028 2029 Thereafter Total Fair Value
Fixed-rate $ 40.0 $ 90.0 $ - $ - $ 55.0 $ 3,453.8 $ 3,638.8 $ 3,404.5
Variable-rate 500.0 - - - - - 500.0 500.0
Total Indebtedness $ 540.0 $ 90.0 $ - $ - $ 55.0 $ 3,453.8 $ 4,138.8 $ 3,904.5
Weighted Average Interest Rates by Maturity 5.048% 0.883% N/A N/A 1.400% 5.189% 5.026%
For further discussion of our fair value of our indebtedness and book value of our indebtedness please see Note 5, “Fair Value” and Note 7, “Debt” to the Financial Statements of this Annual Report on Form 10-K.
Retail Energy Market
The legislatures of several states have enacted laws that allow various forms of competition or that experiment with allowing some form of customer choice of electricity suppliers for retail sales of electric energy. Indiana has not done so. In Indiana, competition among electric energy providers for sales has focused primarily on the sale of bulk power to other public and municipal utilities. Indiana law provides for electricity suppliers to have exclusive retail service areas. In order to increase sales, we work to attract new customers into our service territory. Although the retail sales of electric energy are regulated, we face competition from other energy sources. For example, customers have a choice of installing electric or natural gas home and hot water heating systems or installing qualified generation facilities on their premises.
Counterparty Credit Risk
At times, we may utilize forward purchase contracts to manage the risk associated with power purchases and could be exposed to counterparty credit risk in these contracts. We manage this exposure to counterparty credit risk by entering into contracts with companies that are expected to fully perform under the terms of the contract. Individual credit limits are generally implemented for each counterparty to further mitigate credit risk. We may also require a counterparty to provide collateral in the event certain financial benchmarks are not maintained, or certain credit ratings are not maintained.
We are also exposed to counterparty credit risk related to our ability to collect electricity sales from our customers, which may be impacted by volatility in the financial markets and the economy. Historically, our write-offs of customer accounts have been immaterial, which is common for the electric utility industry.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page No.
IPALCO Enterprises, Inc. and Subsidiaries - Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm - 2024, 2023 and 2022 (PCAOB ID: 42)
Consolidated Statements of Operations for the Years Ended December 31, 2024, 2023 and 2022 64
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2024, 2023 and 2022 65
Consolidated Balance Sheets as of December 31, 2024 and 2023 66
Consolidated Statements of Cash Flows for the Years Ended December 31, 2024, 2023 and 2022 67
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2024, 2023 and 2022 68
Notes to Consolidated Financial Statements 69
AES Indiana and Subsidiaries - Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm - 2024, 2023 and 2022 (PCAOB ID: 42)
Consolidated Statements of Operations for the Years Ended December 31, 2024, 2023 and 2022 119
Consolidated Balance Sheets as of December 31, 2024 and 2023 120
Consolidated Statements of Cash Flows for the Years Ended December 31, 2024, 2023 and 2022 121
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2024, 2023 and 2022 122
Notes to Consolidated Financial Statements 123
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, 2024 and 2023, 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, 2024, 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, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024 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. 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting in accordance with the standards of the PCAOB. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
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.
Regulatory Accounting
Description of the Matter As described in Note 1 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 the significant knowledge and experience required to assess the impact of regulatory orders on the consolidated financial statements including understanding the nature of the rate orders issued, or expected to be issued, and to assess the relevance and reliability of audit evidence to support the impacted account balances and disclosures.
How We Addressed the Matter in Our Audit Our audit procedures related to regulatory assets and liabilities included testing the effectiveness of management’s controls, such as the Company’s evaluation of regulatory orders and other developments that may affect the calculation of recorded amounts, the likelihood of recovering regulatory assets and the sufficiency of regulatory liabilities. Our procedures also included testing management’s calculations of recorded amounts, obtaining, reading, and evaluating relevant regulatory orders issued by the IURC to IPL, and considering regulatory precedents established by the IURC, to evaluate the likelihood of recovering regulatory assets, the sufficiency of regulatory liabilities and the accuracy and completeness of required disclosures related to the impacts of rate regulation and regulatory developments.
Asset Retirement Obligations
Description of the Matter At December 31, 2024, the Company’s asset retirement obligations (“ARO”) totaled $378.5 million. As described in Note 4 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 revisions to its existing ARO liabilities of $117.7 million during 2024 primarily to reflect revisions to cash flow estimates due to increases in closure costs and groundwater treatment measures for ash ponds and landfills.
Auditing the Company’s ARO liabilities revised in 2024 was complex and highly judgmental due to the significant estimation required by management to determine the 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 the scope and method of decommissioning utilized to determine the related cash flows.
How We Addressed the Matter in Our Audit To test the Company’s ARO liabilities revised in 2024, our audit procedures included evaluating the appropriateness of the Company’s methodology, interviewing members of the Company’s environmental staff and testing the scope and method of decommissioning. We involved our specialists in our assessment of the scope and method of decommissioning for the Company’s ARO liabilities revised in 2024, including reviewing the Company’s methodology, evaluating the reasonableness of the related cash flows, and assessing completeness of the estimates based upon regulatory requirements.
/s/ Ernst & Young LLP
We have served as the Company’s auditor since 2008.
Indianapolis, Indiana
March 5, 2025
IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Consolidated Statements of Operations
For the Years Ended December 31, 2024, 2023 and 2022
2024 2023 2022
(In Thousands)
REVENUE $ 1,643,793 $ 1,649,917 $ 1,791,711
OPERATING COSTS AND EXPENSES:
Fuel 359,132 494,000 568,676
Power purchased 148,412 159,908 199,860
Operation and maintenance 476,494 477,880 493,674
Depreciation and amortization 329,468 287,863 266,504
Taxes other than income taxes 27,478 24,864 33,048
Other, net
(106) (361) (3,201)
Total operating costs and expenses 1,340,878 1,444,154 1,558,561
OPERATING INCOME 302,915 205,763 233,150
OTHER (EXPENSE) / INCOME, NET:
Allowance for equity funds used during construction 3,991 9,315 4,784
Interest expense (172,150) (142,926) (131,232)
Other (expense) / income, net (1,163) (410) 11,783
Total other expense, net (169,322) (134,021) (114,665)
INCOME BEFORE INCOME TAX 133,593 71,742 118,485
Income tax expense 28,364 14,715 21,859
NET INCOME 105,229 57,027 96,626
Dividends on and redemption of preferred stock - - 3,509
Net loss attributable to noncontrolling interests (28,294) (26,093) -
NET INCOME ATTRIBUTABLE TO COMMON STOCK $ 133,523 $ 83,120 $ 93,117
See Notes to Consolidated Financial Statements.
IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Consolidated Statements of Comprehensive Income
For the Years Ended December 31, 2024, 2023 and 2022
2024 2023 2022
(In Thousands)
NET INCOME $ 105,229 $ 57,027 $ 96,626
Derivative activity:
Change in derivative fair value, net of income tax effect of $(2,193), $(528) and $(15,309), for each respective period
6,626 1,594 46,245
Reclassification to earnings, net of income tax effect of $179, $(1,798) and $(1,798), for each respective period
(542) 5,431 5,431
Net change in fair value of derivatives 6,084 7,025 51,676
Other comprehensive income 6,084 7,025 51,676
Comprehensive income 111,313 64,052 148,302
Less: dividends on and redemption of preferred stock of subsidiary
- - 3,509
Less: comprehensive loss attributable to noncontrolling interests
(28,294) (26,093) -
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON STOCK
$ 139,607 $ 90,145 $ 144,793
See Notes to Consolidated Financial Statements.
IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Consolidated Balance Sheets
December 31, 2024 and 2023
2024 2023
(In Thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 26,647 $ 28,579
Accounts receivable, net of allowance for credit losses of $29,798 and $2,283, respectively
313,078 233,921
Inventories 99,935 143,590
Regulatory assets, current 134,328 89,419
Taxes receivable 9,401 36,481
Derivative assets, current 1,526 15,682
Prepayments and other current assets 24,561 26,358
Total current assets 609,476 574,030
NON-CURRENT ASSETS:
Property, plant and equipment, net of accumulated depreciation of $3,071,167 and $2,954,555, respectively
5,461,243 4,486,902
Intangible assets, net 232,210 235,656
Regulatory assets, non-current 619,029 541,784
Pension plan assets 24,941 41,172
Other non-current assets 192,126 301,979
Total non-current assets 6,529,549 5,607,493
TOTAL ASSETS $ 7,139,025 $ 6,181,523
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Short-term debt and current portion of long-term debt (see Notes 7 and 15) $ 539,841 $ 899,159
Accounts payable 271,235 292,851
Accrued taxes 26,253 22,580
Accrued interest 43,388 33,639
Customer deposits 11,892 29,308
Regulatory liabilities, current 11,915 23,371
Asset retirement obligations, current 32,161 -
Accrued and other current liabilities 26,231 27,547
Total current liabilities 962,916 1,328,455
NON-CURRENT LIABILITIES:
Long-term debt (see Notes 7 and 15) 3,642,587 2,576,798
Deferred income tax liabilities 380,758 361,488
Regulatory liabilities, non-current 404,021 527,224
Accrued other postretirement benefits 2,834 2,776
Asset retirement obligations, non-current 346,299 249,930
Other non-current liabilities 8,499 5,130
Total non-current liabilities 4,784,998 3,723,346
Total liabilities 5,747,914 5,051,801
COMMITMENTS AND CONTINGENCIES (see Note 11)
REDEEMABLE STOCK OF SUBSIDIARIES 38,145 -
EQUITY:
Common shareholders' equity
Common stock (no par value, 290,000,000 shares authorized; 108,907,318 shares issued and outstanding at December 31, 2024 and 2023)
- -
Paid in capital 1,247,090 1,021,992
Accumulated other comprehensive income 35,378 29,294
Retained earnings 2,067 25,182
Total common shareholders' equity 1,284,535 1,076,468
Noncontrolling interests 68,431 53,254
Total equity 1,352,966 1,129,722
TOTAL LIABILITIES, REDEEMABLE STOCK OF SUBSIDIARIES AND EQUITY $ 7,139,025 $ 6,181,523
See Notes to Consolidated Financial Statements.
IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Consolidated Statements of Cash Flows
For the Years Ended December 31, 2024, 2023 and 2022
2024 2023 2022
CASH FLOWS FROM OPERATING ACTIVITIES: (In Thousands)
Net income $ 105,229 $ 57,027 $ 96,626
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization 329,468 287,863 266,504
Amortization of deferred financing costs and debt discounts 3,567 3,880 3,914
Deferred income taxes and investment tax credit adjustments - net 835 32,653 (6,706)
Allowance for equity funds used during construction (3,991) (9,315) (4,784)
Change in certain assets and liabilities:
Accounts receivable (54,523) (17,398) (37,387)
Inventories 24,285 (30,171) (47,489)
Prepayments and other current assets 2,269 (6,476) 19,056
Accounts payable (52,951) 46,993 32,038
Accrued and other current liabilities (21,640) 2,790 6,532
Accrued taxes payable/receivable 34,066 (18,375) (5,858)
Accrued interest 9,749 192 2,813
Pension and other postretirement benefit assets and liabilities 2,485 1,625 (8,727)
Current and non-current regulatory assets and liabilities
(123,689) 54,358 38,863
Other non-current liabilities
(18,083) (9,445) (14,384)
Other - net
2,851 (4,268) 5,335
Net cash provided by operating activities 239,927 391,933 346,346
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (931,322) (902,705) (496,510)
Project development costs (4,430) (4,462) (3,910)
Acquisitions
(48,368) - -
Cost of removal payments (39,133) (45,595) (23,948)
Insurance proceeds
- 4,900 -
Purchase of intangibles (4,363) (44,650) -
Other 1,559 (361) (719)
Net cash used in investing activities (1,026,057) (992,873) (525,087)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings from revolving credit facilities 750,000 435,000 300,000
Repayments from revolving credit facilities (805,000) (280,000) (360,000)
Short-term borrowings 400,000 300,000 200,000
Short-term borrowings from affiliate
92,000 - -
Repayments of short-term borrowings
(392,000) - (200,000)
Long-term borrowings 1,050,000 - 350,000
Retirement of long-term borrowings
(445,000) - -
Distributions to shareholders (156,638) (104,287) (101,986)
Equity contributions from shareholders 225,000 - 253,000
Distributions to noncontrolling interests
(3,464) - -
Sales to noncontrolling interests
84,142 77,921 -
Redemption of preferred stock - - (60,080)
Preferred dividends of subsidiary - - (3,213)
Payments of deferred financing costs and discounts (14,263) (350) (4,309)
Payments for financed capital expenditures (23,673) - -
Proceeds received from termination of interest rate swaps
23,114 - -
Other (20) (313) (35)
Net cash provided by financing activities 784,198 427,971 373,377
Net change in cash, cash equivalents and restricted cash (1,932) (172,969) 194,636
Cash, cash equivalents and restricted cash at beginning of year 28,584 201,553 6,917
Cash, cash equivalents and restricted cash at end of year $ 26,652 $ 28,584 $ 201,553
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the period for:
Interest (net of amount capitalized) $ 155,612 $ 129,113 $ 115,277
Income taxes $ - $ - $ 31,000
Non-cash investing activities:
Accruals for capital expenditures $ 162,450 $ 124,626 $ 66,949
Recognition of right-of-use assets - finance leases $ 72,462 $ 983 (3,402)
Non-cash financing activities:
Recognition of financing lease liabilities $ (69,318) $ (1,408) $ (3,402)
See Notes to Consolidated Financial Statements.
IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Consolidated Statements of Changes in Equity
For the Years Ended December 31, 2024, 2023 and 2022
Common Shareholders' Equity
Common Stock
(in Thousands)
Outstanding Shares
Amount
Paid in
Capital Accumulated Other Comprehensive Income (Loss) Retained Earnings (Accumulated
Deficit) Total Common Shareholders' Equity Cumulative Preferred Stock of Subsidiary Noncontrolling Interests Redeemable Stock Of Subsidiaries
Balance at January 1, 2022 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 -
Net income / (loss) - - - - 133,523 133,523 - (28,294) -
Other comprehensive income - - - 6,084 - 6,084 - - -
Distributions to shareholders
- - - - (156,638) (156,638) - - -
Sales to noncontrolling interests - - - - - - - 46,935 38,145
Distributions to noncontrolling interests - - - - - - - (3,464) -
Contributions from shareholders - - 225,000 - - 225,000 - - -
Other - - 98 - - 98 - - -
Balance at December 31, 2024 108,907 $ - $ 1,247,090 $ 35,378 $ 2,067 $ 1,284,535 $ - $ 68,431 $ 38,145
(1) IPALCO made return of capital payments of $46.5 million and $33.3 million in 2023 and 2022, 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.
IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Notes to Consolidated Financial Statements
For the Years Ended December 31, 2024, 2023 and 2022
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 531,000 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 December 31, 2024, AES Indiana’s net electric generation design capacity at these generating stations for winter is 3,070 MW and summer 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 placed in service during the fourth quarter of 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 placed in service during the first quarter of 2025.
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.
Principles of Consolidation
IPALCO’s consolidated financial statements are prepared in accordance with GAAP and in conjunction with the rules and regulations of the SEC. The consolidated financial statements include the accounts of IPALCO, its regulated utility subsidiary, AES Indiana, and its unregulated subsidiary, Mid-America. Furthermore, VIEs in which the Company has an ownership interest and is the primary beneficiary, thus controlling the VIE, as described below, have been consolidated. All intercompany items have been eliminated in consolidation. Certain costs for shared resources amongst AES Indiana and IPALCO, such as labor and benefits, are allocated to each entity based on allocation methodologies that management believes to be reasonable. We have evaluated subsequent events through the date this report is issued.
If IPALCO enters into transactions impacting equity interests in its affiliates, IPALCO must determine whether the transaction impacts the Company's consolidation conclusion by first determining whether the transaction should be evaluated under the variable interest model or the voting model. In determining which consolidation model applies to the transaction, IPALCO is required to make judgments about how the entity operates, the most significant of which are whether (i) the entity has sufficient equity to finance its activities, (ii) the equity holders, as a group, have the characteristics of a controlling financial interest, and (iii) whether the entity has non-substantive voting rights. If the entity is determined to be a VIE and IPALCO is determined to have power and benefits, the entity will be consolidated by IPALCO.
IPALCO consolidates the results of three AES Indiana subsidiaries that qualify as VIEs. These subsidiaries are Hardy Hills JV, Pike County Energy Storage JV and Petersburg Energy Center. AES Indiana is the primary beneficiary and controls the most significant activities of these VIEs. At December 31, 2024 and 2023, the assets of these VIEs were approximately $1,169.3 million and $613.2 million, primarily consisting of property, plant and equipment, construction work in progress and other non-current assets. At December 31, 2024 and 2023, the liabilities of these VIEs were approximately $180.5 million and $51.0 million, primarily consisting of finance leases and accounts payable.
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.
Noncontrolling interests with redemption features that are not solely within the control of the issuer are classified as temporary equity and are included in Redeemable stock of subsidiaries on the Consolidated Balance Sheets. Generally, initial measurement will be at fair value. The subsequent allocation of income and dividends is classified in temporary equity. Subsequent measurement and classification vary depending on whether the instrument is probable of becoming redeemable. For securities that are currently redeemable or where it is probable that the instrument will become redeemable, IPALCO recognizes any changes from the carrying value to redemption value at each reporting period against retained earnings or additional paid-in capital in the absence of retained earnings; such adjustments are classified in temporary equity. When the equity instrument is not probable of becoming redeemable, no adjustment to the carrying value is recognized.
Allocation of Earnings
Hardy Hills JV and Pike County Energy Storage JV are subject to profit-sharing arrangements where the allocation of earnings, cash distributions, and tax benefits are not based on fixed ownership percentages. These arrangements exist 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, see Note 10, "Equity - Equity Transactions with Noncontrolling Interests").
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.
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,
2024 2023
(In Thousands)
Cash, cash equivalents and restricted cash
Cash and cash equivalents $ 26,647 $ 28,579
Restricted cash (included in Prepayments and other current assets) 5 5
Total cash, cash equivalents and restricted cash $ 26,652 $ 28,584
Accounts Receivable and Allowance for Credit Losses
The following table summarizes our accounts receivable balances at December 31:
As of December 31,
2024 2023
(In Thousands)
Accounts receivable, net
Customer receivables $ 207,353 $ 125,715
Unbilled revenue 90,731 91,463
Amounts due from related parties 6,461 5,178
Other 38,331 13,848
Allowance for credit losses (29,798) (2,283)
Total accounts receivable, net $ 313,078 $ 233,921
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,
2024 2023
(In Thousands)
Allowance for credit losses:
Beginning balance $ 2,283 $ 1,117
Current period provision 26,662 7,413
Net write-offs charged against allowance
(902) (7,764)
Recoveries and account write-ons
1,755 1,517
Ending Balance $ 29,798 $ 2,283
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 the collectability, as applicable, of our receivables balance. Amounts are written off when reasonable collections efforts have been exhausted. During 2024, the current period provision and allowance for credit losses increased due to a temporary pause of customer disconnections and certain collection efforts and write-off processes after the implementation of AES Indiana's customer billing system upgrade in the fourth quarter of 2023. This has resulted in higher past due customer receivables as of December 31, 2024. AES Indiana currently anticipates reinstituting the customer disconnections process and collection efforts and write-off processes in the first quarter of 2025.
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,
2024 2023
(In Thousands)
Inventories
Fuel $ 50,842 $ 77,198
Materials and supplies, net 49,093 66,392
Total inventories $ 99,935 $ 143,590
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 3.8%, 3.7% and 3.8% during 2024, 2023 and 2022, respectively. Depreciation expense was $268.6 million, $244.8 million, and $247.5 million for the years ended December 31, 2024, 2023 and 2022, 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.
AES Indiana may receive contributions in aid of construction ("CIAC") from customers that are intended to defray all or a portion of the costs for certain capital projects, to the extent the project does not benefit regulated customers in general. AES Indiana accounts for CIAC as a reduction to property, plant and equipment.
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 6.6%, 7.1% and 5.4% during 2024, 2023 and 2022, respectively. AFUDC equity and AFUDC debt were as follows for the years ended December 31, 2024, 2023 and 2022:
2024 2023 2022
(In Thousands)
AFUDC equity $ 3,991 $ 9,315 $ 4,784
AFUDC debt $ 32,240 $ 13,739 $ 8,215
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 $5.5 billion and $4.5 billion as of December 31, 2024 and 2023, respectively. As of December 31, 2024 and 2023, AES Indiana had $230.4 million and $259.9 million, respectively, of long-term regulatory assets associated with retirement costs for Petersburg Units 1 and 2 and the conversion of Petersburg Units 3 and 4. We do not believe any of these assets are currently impaired. In making this assessment, we consider such factors as: the overall condition and generating and distribution capacity of the assets; the expected ability to recover additional expenditures in the assets; the anticipated demand and relative pricing of retail electricity in our service territory and wholesale electricity in the region; and the cost of fuel.
Intangible Assets
Finite-lived intangible assets primarily include capitalized software and project development intangible assets amortized on a straight-line basis over their useful lives. The following table presents information related to the Company's intangible assets, including the gross amount capitalized and related amortization:
December 31,
$ in thousands
Weighted average amortization periods (in years)
2024 2023
Capitalized software
8 $ 280,020 $ 261,872
Project development intangible assets
28 83,149 84,097
Other
Various
797 797
Less: Accumulated amortization
(131,756) (111,110)
Intangible assets - net
$ 232,210 $ 235,656
For the Years Ended December 31,
2024 2023 2022
Amortization expense
$ 26,193 $ 14,570 $ 10,122
Estimated future amortization
Years ending December 31,
2025 $ 26,372
2026 28,158
2027 28,158
2028 28,158
2029 28,158
Total
$ 139,004
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 $2.5 million and $7.1 million as of December 31, 2024 and 2023, respectively, which are recorded within "Prepayments and other current assets" and "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, 2024 and 2023. See Note 11, "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 5, 2027, and the contract
with the clerical-technical unit expires on February 12, 2026. Additionally, AES Indiana has long-term coal contracts with two suppliers, 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 6, “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.
ARO
The Company records the fair value of a liability for a legal obligation to retire an asset in the period in which the obligation is incurred. When a new liability is recognized, the Company capitalizes the costs of the liability by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the obligation, the Company eliminates the liability and, based on the actual cost to retire, may incur a gain or loss.
Accumulated Other Comprehensive Income / (Loss)
The amounts reclassified out of AOCI / (AOCL) by component during the years ended December 31, 2024, 2023 and 2022 are as follows (in thousands):
Details about AOCI / (AOCL) components
Affected line item in the Consolidated Statements of Operations For the Years Ended December 31,
2024 2023 2022
Net (gains) / losses on cash flow hedges (Note 6):
Interest expense $ (721) $ 7,229 $ 7,229
Income tax effect 179 (1,798) (1,798)
Total reclassifications for the period, net of income taxes $ (542) $ 5,431 $ 5,431
See Note 6, "Derivative Instruments and Hedging Activities - Cash Flow Hedges" for further information on the changes in the components of AOCI / (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 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 $27.4 million, $7.5 million and $5.9 million for the years ended December 31, 2024, 2023 and 2022, 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 May 2024. AES Indiana is permitted to recover actual costs of power purchased and fuel consumed, subject to certain restrictions. This is accomplished through quarterly FAC proceedings, in which AES Indiana estimates the amount of fuel and power purchased costs in future periods. Through these proceedings, AES Indiana is also permitted to recover, in future rates, underestimated fuel and power purchased 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 14, "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.
Pension and Postretirement Benefits
We recognize in our Consolidated Balance Sheets an asset or liability reflecting the funded status of pension and other postretirement plans with current-year changes in the funded status, that would otherwise be recognized in AOCI, recorded as a regulatory asset as this can be recovered through future rates. All plan assets are recorded at
fair value. We follow the measurement date provisions of the accounting guidance, which require a year-end measurement date of plan assets and obligations for all defined benefit plans.
We account for and disclose pension and postretirement benefits in accordance with the provisions of GAAP relating to the accounting for pension and other postretirement plans. These GAAP provisions require the use of assumptions, such as the discount rate for liabilities and long-term rate of return on assets, in determining the obligations, annual cost and funding requirements of the plans. Consistent with the requirements of ASC 715, we apply a disaggregated discount rate approach for determining service cost and interest cost for our defined benefit pension plans and postretirement plans.
See Note 9, "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 non-current 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 8, "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
The following table provides a brief description of recent accounting pronouncements that had an impact on the Company’s Financial Statements. Accounting pronouncements not listed below were assessed and determined to be either not applicable or did not have a 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.
December 31, 2024 The Company adopted this standard on a retrospective basis. Please refer to Note 13, "Business Segments" for impact.
New Accounting Pronouncements Issued But Not Yet Effective
The following table provides a brief description of recent accounting pronouncements that could have a material impact on the Company's Financial Statements once adopted. Accounting pronouncements not listed below were assessed and determined to be either not applicable or are expected to have no material impact on the Company's Financial Statements.
ASU Number and Name Description Date of Adoption Effect on the Financial Statements upon adoption
2023-06 Disclosure Improvements: Codification Amendments in Response to the SEC’s Disclosure Update and Simplification Initiative
In U.S. Securities and Exchange Commission (SEC) Release No. 33-10532, Disclosure Update and Simplification, issued August 17, 2018, the SEC referred certain of its disclosure requirements that overlap with, but require incremental information to, generally accepted accounting principles (GAAP) to the FASB for potential incorporation into the Codification. The amendments in this Update are the result of the Board’s decision to incorporate into the Codification 14 of the 27 disclosures referred by the SEC.
The amendments in this Update represent changes to clarify or improve disclosure and presentation requirements of a variety of Topics. Many of the amendments allow users to more easily compare entities subject to the SEC’s existing disclosures with those entities that were not previously subject to the SEC’s requirements. Also, the amendments align the requirements in the Codification with the SEC’s regulations.
The effective date for each amendment will be the date on which the SEC's removal of that related disclosure becomes effective, with early adoption prohibited. The amendments in this Update should be applied prospectively.
We will provide the required disclosures on a prospective basis on the date each amendment becomes effective. We do not expect ASU 2023-06 will have any impact to our consolidated financial statements.
2023-09 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.
2024-03: Income Statement-Reporting Comprehensive Income-Expense Disaggregation Disclosures (Subtopic 220-40) The amendments in this Update require disclosure, in the notes to financial statements, of specified information about certain costs and expenses. The amendments require that at each interim and annual reporting period an entity:
1. Disclose the amounts of (a) purchases of inventory, (b) employee compensation, (c) depreciation, (d) intangible asset amortization, and (e) depreciation, depletion, and amortization recognized as part of oil- and gas-producing activities (DD&A) (or other amounts of depletion expense) included in each relevant expense caption. A relevant expense caption is an expense caption presented on the face of the income statement within continuing operations that contains any of the expense categories listed in (a)-(e).
2. Include certain amounts that are already required to be disclosed under current generally accepted accounting principles (GAAP) in the same disclosure as the other disaggregation requirements.
3. Disclose a qualitative description of the amounts remaining in relevant expense captions that are not separately disaggregated quantitatively.
4. Disclose the total amount of selling expenses and, in annual reporting periods, an entity’s definition of selling expenses. The date for each amendment in this Update is effective for fiscal years beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. Early adoption is permitted 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.
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 OUCC, 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
On April 17, 2024, the IURC issued an order (the “2024 Base 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 Base 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 4.9% on a rate base of approximately $3.5 billion. Updated customer rates and charges became effective on May 9, 2024. The 2024 Base Rate Order provides that annual wholesale margins earned above (or below) the benchmark of $28.6 million shall be passed back (or charged) to customer rates through a rate adjustment mechanism. Similarly, the 2024 Base Rate Order provides that all capacity sales and expenses above (or below) an expense benchmark of $19.0 million shall be passed back (or charged) to customer rates through a rate adjustment mechanism.
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 power purchased 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 year 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 calendar years 2023 and 2024.
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, recover costs (including a return) on certain investments in renewable and battery energy storage projects, and recover the retail portion of costs for generation consumables and environmental allowances. The total amount of AES Indiana’s environmental equipment and renewable projects approved for ECCRA recovery as of December 31, 2024 was $437.5 million. The jurisdictional revenue requirement approved by the IURC to be included in AES Indiana’s rates for the twelve-month period ending February 2025 is a net cost to customers of $41.1 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 2024, 2023 and 2022, AES Indiana also had the ability to receive financial incentives, dependent upon the level of success of the programs. Financial incentives included in rates for the years ended December 31, 2024, 2023 and 2022 were $3.8 million, $2.7 million and $8.3 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 financial 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 financial 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 31, 2024 asking for approval of a two-year DSM plan for the 2025-2026 program years. On January 8, 2025, the IURC approved a two-year DSM plan for AES Indiana through 2026. The approval included cost recovery of programs as well as financial 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 were previously committed under a power purchase agreement to purchase all wind-generated electricity through 2029 from a wind project in Indiana (the "Hoosier Wind Project"), which had a maximum output capacity of approximately 100 MW. AES Indiana acquired the Hoosier Wind Project in February 2024, and the existing power purchase agreement was terminated upon closing (see "IRP Filings and Replacement Generation - Hoosier Wind Project" below for further information). We are currently committed under another agreement to purchase all wind-generated electricity through 2031 from a project in Minnesota, which 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, 2024. We have authority from the IURC to recover the costs for all of these agreements through an adjustment mechanism administered within the FAC. If and when AES Indiana sells the renewable energy attributes (in the form of renewable energy credits) generated from these facilities, the proceeds would pass back to benefit AES Indiana’s retail customers through the FAC.
TDSIC
In 2013, Senate Enrolled Act 560, the Transmission, Distribution, and Storage System Improvement Charge ("TDSIC") statute, was signed into law. The TDSIC statute was revised in 2019. Among other provisions, this legislation provides for cost recovery outside of a base rate proceeding for new or replacement electric and gas transmission, distribution, and storage projects that a public utility undertakes for the purposes of safety, reliability, system modernization, or economic development. Provisions of the TDSIC statute require that, among other things, requests for recovery include a plan of at least five years and not more than seven for eligible investments. The first eighty percent of eligible costs can be recovered using a periodic rate adjustment mechanism. The cost recovery mechanism is referred to as a TDSIC mechanism. Recoverable costs include a return on, and of, the investment, including AFUDC, post-in-service carrying charges, 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. In addition, there is a nine-month rate freeze after new basic rates are implemented. Because of this, there was no TDSIC rate adjustment filed in 2024 due to the 2024 Base Rate Order. However, a compliance filing was made after the 2024 Base Rate Order to update the TDSIC rates for projects that rolled into base rates. The total amount of AES Indiana’s equipment net of depreciation, including carrying costs, approved for TDSIC recovery as of December 31, 2024 was $138.4 million. There are also $340.7 million of TDSIC capital costs that were rolled into base rates per the 2024 base rate Order, which are no longer in the TDSIC rider. The jurisdictional revenue requirement approved by the IURC to be included in AES Indiana’s rates for the twelve-month period ending October 2025 is a net cost to customers of $17.7 million. These amounts are significantly lower than prior TDSIC periods as a result of having a majority of the TDSIC projects rolled into AES Indiana's basic rates and charges effective May 9, 2024 as a result of the 2024 Base Rate Order.
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.
2025 IRP
In January 2025, AES Indiana initiated its 2025 IRP process with external stakeholders. The first of five public advisory meetings took place on January 29, 2025 and will continue through most of 2025, with AES Indiana anticipating it will submit its final 2025 IRP, shaped by stakeholder feedback, to the IURC in November 2025.
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 (see "Petersburg Repowering" below for further information). Additionally, AES Indiana plans to add up to 1,300 MW of wind, solar, and battery energy storage by 2027.
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. AES Indiana retired 230 MW Petersburg Unit 1 in May 2021 and 415 MW Petersburg Unit 2 in June 2023. 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.
As a result of the plans to retire Petersburg Units 1 and 2, AES Indiana recorded $0.7 million and $2.1 million of obsolescence losses during the periods ended December 31, 2023 and 2022, 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.
AES Indiana had $129.4 million and $259.9 million of Petersburg Units 1 and 2 retirement costs, net of accumulated amortization, recorded as long-term regulatory assets as of December 31, 2024 and 2023, respectively.
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 (the "Petersburg Repowering Project") and to recover costs through future rates. On November 6, 2024, the IURC issued an order approving the CPCN which includes: (1) approval of the Petersburg Repowering Project and (2) approval of the accounting and ratemaking requests associated with the Petersburg Repowering Project including AES Indiana's creation of regulatory assets for the remaining net book value of the Petersburg Units 3 and 4 retired assets, and certain materials and supplies inventories that will no longer be used, and recovery of certain other costs.
The Company has engaged a vendor through an EPC Agreement for the turn-key engineering, procurement, and construction services of the project. This agreement has been approved by the IURC and preconstruction stage work is ongoing. The on-site construction work for the conversion of Unit 3 is expected to begin in February 2026 and be completed by June 2026, and for Unit 4 is expected to begin in June 2026 and be completed by December 2026.
As a result of the resolutions from this order, AES Indiana has $101.0 million of projected Petersburg Units 3 and 4 retirement costs (including MATS equipment which was approved for recovery in Cause No. 44242 - CPCN to construct, install and use clean coal technology), and $20.4 million of materials and supplies inventories that will no longer be used, upon retirement, recorded as long-term regulatory assets as of December 31, 2024.
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 VIE 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 associated with the transaction, primarily consisting of a development project intangible asset (see Note 1, "Overview and Summary of Significant Accounting Policies - Intangible Assets"). Total consideration included a future payment contingent on certain future costs incurred by the project and a $3.2 million contingent liability was recorded. During 2022, this liability was remeasured due to updated cost estimates and was reduced to $0.0 million.
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. 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. Construction was completed for the remaining MW and the project achieved full commercial operations in May 2024. Upon the final stage of the project being placed in service, the Company recognized $21.4 million of earnings from tax attributes using the HLBV method.
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 45 MW (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 VIE 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 placed in service during the first quarter of 2025.
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.
Crossvine Project
On August 1, 2024, AES Indiana executed an agreement for the acquisition of a development stage solar and BESS project to be developed in Dubois County, Indiana. AES Indiana plans to build 85 MW of solar and 85 MW (340 MWh) of energy storage which is expected to be completed in mid-2027. This transaction is subject to approval from the IURC. AES Indiana filed a petition and case-in-chief with the IURC in August 2024, seeking a CPCN for this project.
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, Pike County BESS Project, Petersburg Energy Center Project, Hardy Hills Solar Project and Petersburg Repowering 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 $4.6 million and $5.4 million as of December 31, 2024 and 2023, respectively, which is currently being recovered through base rates under the 2024 Base Rate Order.
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 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 Base 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 Base Rate Order, this Joint Petition was dismissed with prejudice.
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 and liabilities 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 35 years.
The following table presents AES Indiana's regulatory assets and liabilities:
December 31,
Type of Recovery Recovery Period 2024 2023
(In Thousands)
Regulatory assets, current:
Undercollections of rate riders B 2025 $ 115,911 $ 75,416
Unamortized reacquisition premium on debt B 2025 - 188
Costs being recovered through basic rates and charges A/B 2025 18,417 13,815
Total regulatory assets, current 134,328 89,419
Regulatory assets, non-current:
Unrecognized pension and other
postretirement benefit plan costs A/B Ongoing 124,176 115,847
Deferred MISO costs B 2026 7,699 21,091
Unamortized Petersburg Unit 4 carrying
charges and certain other costs A 2026 1,757 2,812
Unamortized reacquisition premium on debt B Ongoing 12,832 13,379
Environmental costs A/B 2044 65,186 66,837
COVID-19 costs B 2028 3,194 5,426
Major storm damage B Undetermined 8,883 1,493
TDSIC costs A 2060 52,469 35,979
Petersburg Unit 1 and 2 retirement costs A 2033 129,375 259,892
Petersburg Unit 3 and 4 retirement costs A Various 100,982 -
Petersburg Unit 3 and 4 materials and supplies B Undetermined 20,369 -
Hardy Hills Solar costs A/B 2059 15,255 6,774
Petersburg Energy Center costs A/B Undetermined 6,361 2,469
Pike County BESS costs A/B 2045 5,991 2,623
Hoosier Wind A 2039 53,394 -
ACE Costs A/B 2028 7,607 -
Fuel costs B Not applicable - 4,275
Other miscellaneous B Various 3,499 2,887
Total regulatory assets, non-current 619,029 541,784
Total regulatory assets $ 753,357 $ 631,203
Regulatory liabilities, current:
Overcollections and other credits being passed
to customers through rate riders B 2025 $ 8,959 $ 19,649
FTRs B 2025 2,956 3,722
Total regulatory liabilities, current 11,915 23,371
Regulatory liabilities, non-current:
ARO and accrued asset removal costs B Not applicable 344,506 451,886
Deferred income taxes payable to customers through rates B Ongoing 58,378 74,796
Hardy Hills sponsor investment tax credit B Undetermined 991 542
Environmental Compliance Rider B Undetermined 146 -
Total regulatory liabilities, non-current 404,021 527,224
Total regulatory liabilities $ 415,936 $ 550,595
A - Recovery of incurred costs plus rate of return.
B - Recovery of incurred costs without a rate of return.
C - Recovery not yet determined, but recovery is probable of occurring in future rate proceedings.
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, (v) overcollection of MISO rider costs, and (vi) 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) Green Power, (ii) deferred fuel costs, and (iii) FTRs.
Deferred Fuel
Deferred fuel costs are a component of current 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 power purchased costs in AES Indiana’s FAC and actual fuel and power purchased costs. AES Indiana is generally permitted to recover underestimated fuel and power purchased 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 2024 Base Rate Order. Amortization periods vary, ranging from 1 to 19 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 35 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 assets were reclassified from net property, plant and equipment to a long-term regulatory asset. See "IRP Filings and Replacement Generation" above for additional discussion.
Petersburg Unit 3 and 4 Retirement Costs and Materials and Supplies
On November 6, 2024, the IURC issued an order approving the CPCN to convert Petersburg Units 3 and 4 from coal to natural gas. As a result of this order and in accordance with ASC 980, it was determined that the conversion of Petersburg Units 3 and 4 from coal to natural gas became probable, and the projected remaining net book value of the Petersburg Units 3 and 4 retired assets of $101.0 million and materials and supplies inventories that will no longer be used of $20.4 million were reclassified from net property, plant and equipment and inventories, respectively, to long-term regulatory assets. 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 35 years. Amortization of the project development costs began in March 2024 along with ECR-37 rates.
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 begin in March 2025 along with ECR-38 rates.
Hoosier Wind
As discussed above in "IRP Filings and Replacement Generation", AES Indiana acquired the Hoosier Wind Project on February 29, 2025. The transaction was accounted for as an asset acquisition and a portion of the consideration transferred 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. This regulatory asset also includes deferred operation and maintenance and carrying costs on AES Indiana's investment in accordance with the approved CPCN.
ACE Costs
These consist of one-time implementation costs and Software as a Service costs related to the ACE Project. The IURC authorized recovery of one-time implementation costs over 4 years and Software as a Service costs over 10 years in the 2024 Base Rate Order.
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 5, "Fair Value - Fair Value Hierarchy and Valuation Techniques - Financial Assets - FTRs" for additional information.
ARO and Accrued Asset Removal Costs
In accordance with ASC 410 and ASC 980, AES Indiana recognizes the amount collected in customer rates for costs of removal not yet incurred that do not have an associated legal retirement obligation as a deferred regulatory liability. This amount is net of the portion of legal ARO costs that are deferred that is also being recovered in rates.
Deferred Income Taxes Recoverable/Payable Through Rates
A deferred income tax asset or liability is created from a difference in timing of income recognition between tax laws and accounting methods. As a regulated utility, AES Indiana includes in ratemaking the impacts of current income taxes and changes in deferred income tax liabilities or assets.
On December 22, 2017, the U.S. federal government enacted the TCJA, which, among other things, reduced the federal corporate income tax rate from 35% to 21%, beginning January 1, 2018. As required by GAAP, on December 31, 2017, AES Indiana and IPALCO remeasured their deferred income tax assets and liabilities using the new tax rate. The impact of the reduction of the income tax rate on deferred income taxes was utilized in the 2018 Base Rate Order to reduce jurisdictional retail rates. Accordingly, we have a net regulatory deferred income tax liability of $58.3 million and $74.8 million as of December 31, 2024 and 2023, respectively.
3. PROPERTY, PLANT AND EQUIPMENT
The original cost of property, plant and equipment segregated by functional classifications follows:
As of December 31,
2024 2023
(In Thousands)
Production $ 4,303,827 $ 3,942,052
Transmission 516,178 487,527
Distribution 2,562,827 2,304,526
General plant 251,715 348,338
Total property, plant and equipment 7,634,547 7,082,443
Less: Accumulated depreciation 3,071,167 2,954,555
4,563,380 4,127,888
Construction work in progress 897,863 359,014
Property, plant and equipment, net
$ 5,461,243 $ 4,486,902
Substantially all of AES Indiana’s property is subject to a $2,763.8 million direct first mortgage lien, as of December 31, 2024, securing AES Indiana’s first mortgage bonds.
4. 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 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 following is a roll forward of the ARO legal liabilities for the periods indicated:
2024 2023
(In Thousands)
Balance as of January 1 $ 249,930 $ 218,729
Liabilities incurred 9,060 17,080
Liabilities settled (14,539) (11,902)
Revisions to cash flow and timing estimates 117,743 12,921
Accretion expense 16,266 13,102
Balance as of December 31 $ 378,460 $ 249,930
Less: ARO liabilities, current 32,161 -
ARO liabilities, non-current $ 346,299 $ 249,930
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. AES Indiana recorded revisions to its ARO liabilities in 2024 primarily to reflect revisions to cash flow estimates due to increases in closure costs and groundwater treatment measures for ash ponds and landfills. As of December 31, 2024 and 2023, AES Indiana did not have any assets that are legally restricted for settling its ARO liabilities.
5. 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 and are recorded in "Other (expense) / income, net" on the accompanying Consolidated Statements of Operations. These changes to fair value were not material for the years ended December 31, 2024, 2023, or 2022.
FTRs
In connection with AES Indiana’s participation in MISO, in the second quarter of each year AES Indiana is granted financial instruments that can be converted into cash or FTRs based on AES Indiana’s forecasted peak load for the period. FTRs are used in the MISO market to hedge AES Indiana’s exposure to congestion charges, which result from constraints on the transmission system. AES Indiana’s FTRs are valued at the cleared auction prices for FTRs in MISO’s annual auction. Because of the infrequent nature of this valuation, the fair value assigned to the FTRs is considered a Level 3 input under the fair value hierarchy required by ASC 820. An offsetting regulatory liability has been recorded as these revenue or costs will be flowed through to customers through the FAC. As such, there is no impact on our Consolidated Statements of Operations.
Forward Power Contracts
As of December 31, 2024 and 2023, 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 6, "Derivative Instruments and Hedging Activities - Derivatives Not Designated as Hedge" for further information.
Interest Rate Hedges
In March 2024, IPALCO's interest rate hedges with a combined notional amount of $400.0 million were terminated in conjunction with the issuance of the 2034 IPALCO Notes. All changes in the market value of the interest rate hedges are recorded in AOCI. See also Note 6, "Derivative Instruments and Hedging Activities - Cash Flow Hedges" for further information.
Recurring Fair Value Measurements
The fair value of assets at December 31, 2024 and 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 December 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 3,947 - - 3,947 3,425 - - 3,425
Total VEBA investments 4,033 - - 4,033 3,552 - - 3,552
FTRs - - 1,526 1,526 - - 1,388 1,388
Interest rate hedges - - - - - 14,294 - 14,294
Total financial assets measured at fair value $ 4,033 $ - $ 1,526 $ 5,559 $ 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):
Reconciliation of Financial Instruments Classified as Level 3
(In Thousands)
Balance at January 1, 2023 $ 7,545
Issuances 3,624
Settlements (9,781)
Balance at December 31, 2023 1,388
Issuances 3,811
Settlements (3,673)
Balance at December 31, 2024 $ 1,526
Financial Instruments not Measured at Fair Value in the Consolidated Balance Sheets
Debt
The fair value of our outstanding fixed-rate debt has been determined on the basis of the quoted market prices of the specific securities issued and outstanding. In certain circumstances, the market for such securities was inactive and therefore the valuation was adjusted to consider changes in market spreads for similar securities. Accordingly, the purpose of this disclosure is not to approximate the value on the basis of how the debt might be refinanced.
The following table shows the face value and the fair value of fixed-rate and variable-rate indebtedness (Level 2) for the periods ending:
December 31, 2024 December 31, 2023
Face Value Fair Value Face Value Fair Value
(In Thousands)
Fixed-rate $ 3,638,800 $ 3,404,473 $ 3,033,800 $ 2,860,467
Variable-rate 500,000 500,000 455,000 455,000
Total indebtedness $ 4,138,800 $ 3,904,473 $ 3,488,800 $ 3,315,467
The difference between the face value and the carrying value of this indebtedness represents the following:
•unamortized deferred financing costs of $34.7 million and $24.8 million at December 31, 2024 and 2023, respectively; and
•unamortized discounts of $9.4 million and $6.8 million at December 31, 2024 and 2023, respectively.
6. 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 power purchased. 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, 2024, AES Indiana's outstanding derivative instruments were as follows:
Commodity Accounting Treatment (a)
Unit Notional
(in thousands) Sales
(in thousands) Net Notional
(in thousands)
FTRs Not Designated MWh 4,410 - 4,410
(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 are determined by current public market prices. The change in the fair value of a hedging instrument is recorded in AOCI and amounts deferred are reclassified to earnings in the same income statement line as the hedged item in the period in which it settles.
IPALCO’s three forward-starting interest rate swaps with a combined notional value of $400.0 million were terminated for total cash proceeds of $23.1 million in conjunction with the issuance of the 2034 IPALCO Notes in March 2024. AOCI of $95.4 million associated with the interest rate swaps through the date of the termination is currently being amortized out into interest expense over the 10-year life of the 2034 IPALCO Notes. IPALCO previously de-designated three forward-starting interest rate swaps used to hedge the interest risk associated with refinancing the IPALCO 2020 maturities. AOCL of $72.3 million was frozen at the date of de-designation, which is currently being amortized into interest expense over the remaining life of the 2030 IPALCO Notes.
The following tables provide information on gains or losses recognized in AOCI / (AOCL) for the cash flow hedges for the periods indicated:
Interest Rate Hedges for the Years Ended December 31,
$ in thousands (net of tax) 2024 2023 2022
Beginning accumulated derivative gain / (loss) in AOCI / (AOCL)
$ 29,294 $ 22,269 $ (29,407)
Net gains associated with current period hedging transactions 6,626 1,594 46,245
Net (gains) / losses reclassified to interest expense
(542) 5,431 5,431
Ending accumulated derivative gain / (loss) in AOCI / (AOCL)
$ 35,378 $ 29,294 $ 22,269
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 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 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, 2024 and 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):
December 31,
Commodity Hedging Designation Balance sheet classification 2024 2023
FTRs Not a Cash Flow Hedge Derivative assets, current
$ 1,526 $ 1,388
Interest rate hedges Cash Flow Hedge Derivative assets, current $ - $ 14,294
7. DEBT
The following table presents our long-term debt:
December 31,
Series Due 2024 2023
(In Thousands)
AES Indiana first mortgage bonds:
3.125% (1)
December 2024 $ - $ 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 (8,093) (6,449)
Deferred financing costs (25,469) (19,058)
Total AES Indiana first mortgage bonds 2,730,238 2,128,293
Total long-term debt - AES Indiana 2,730,238 2,128,293
Long-term debt - IPALCO:
3.70% Senior Secured Notes
September 2024 - 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 (1,331) (319)
Deferred financing costs (8,279) (4,554)
Total long-term debt - IPALCO 865,390 875,127
Total consolidated IPALCO long-term debt 3,595,628 3,003,420
Less: current portion of long-term debt 39,910 445,000
Net consolidated IPALCO long-term debt(3)
$ 3,555,718 $ 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.
(3)Excludes $0.2 million and $0.0 million (current) and $86.9 million and $17.8 million (non-current) finance lease liabilities included in the respective short and long-term debt line items on the Consolidated Balance Sheets as of December 31, 2024 and 2023, respectively. See Note 15, "Leases" for further information.
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, 2024 and 2023, AES Indiana had $100.0 million and $155.0 million in outstanding borrowings on the committed Credit Agreement, respectively.
Debt Maturities
Maturities on long-term indebtedness subsequent to December 31, 2024 are as follows:
Year Amount
(In Thousands)
2025 $ 40,000
2026 90,000
2027 -
2028 -
2029 55,000
Thereafter 3,453,800
3,638,800
Unamortized discounts (9,424)
Deferred financing costs, net (33,748)
Total long-term debt $ 3,595,628
Significant Transactions
AES Indiana Term Loans
In August 2024, AES Indiana entered into an unsecured $400 million 364-day term loan agreement ("$400 million Term Loan Agreement"), which can be drawn in two tranches. AES Indiana drew $300 million at closing and drew the remaining $100 million in October 2024, with the proceeds being used for general corporate purposes. This agreement matures on August 13, 2025, and bears interest at variable rates as described in the $400 million Term Loan Agreement. The $400 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 the $400 million Term Loan Agreement as short-term indebtedness as it matures August 2025. Management plans to repay the $400 million Term Loan Agreement through a combination of funds from debt financings and parent equity capital contributions.
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 (described below), outstanding borrowings on the Credit Agreement and for general corporate purposes.
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 was set to mature on November 19, 2024, but was fully repaid in March 2024.
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
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.
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.
Pursuant to a registration rights agreement dated March 14, 2024, IPALCO agreed to register the 2034 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 2034 IPALCO Notes with the SEC on May 28, 2024 in respect of its obligations under such registration rights agreement, and this registration statement was declared effective on June 6, 2024. The exchange offer closed on July 12, 2024.
Other
In February 2024, AES Indiana received a $92.0 million short-term loan from AES. This loan was fully repaid in March 2024.
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 29, 2026. In February 2024, AES Indiana received an order from the IURC granting AES Indiana 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 December 31, 2024. 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 $0.0 million remains available under the order as of December 31, 2024. 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, 2024. 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.
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 $2,763.8 million as of December 31, 2024. 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, 2024.
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.
8. 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 2020, but is open for all subsequent periods. IPALCO made tax sharing payments to AES of $0.0 million, $0.0 million and $31.0 million in 2024, 2023 and 2022, respectively.
Income Tax Provision
Federal and state income taxes charged to income are as follows:
2024 2023 2022
(In Thousands)
Components of income tax expense:
Current income taxes:
Federal $ 22,125 $ (14,222) $ 22,539
State 5,404 (3,716) 6,026
Total current income taxes 27,529 (17,938) 28,565
Deferred income taxes:
Federal 5,515 24,885 (6,920)
State (4,680) 7,768 214
Total deferred income taxes 835 32,653 (6,706)
Total income tax expense $ 28,364 $ 14,715 $ 21,859
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:
2024 2023 2022
Federal statutory tax rate 21.0 % 21.0 % 21.0 %
State income tax, net of federal tax benefit 3.9 % 3.9 % 3.9 %
Depreciation flow through and amortization (9.7) % (12.9) % (7.8) %
AFUDC - equity 0.5 % (0.3) % 0.9 %
Noncontrolling interests in subsidiaries 5.2 % 9.0 % - %
Other - net 0.3 % (0.2) % 0.4 %
Effective tax rate 21.2 % 20.5 % 18.4 %
Deferred Income Taxes
The significant items comprising IPALCO’s net accumulated deferred tax liability recognized on the Consolidated Balance Sheets as of December 31, 2024 and 2023 are as follows:
2024 2023
(In Thousands)
Deferred tax liabilities:
Relating to utility property, net $ 438,018 $ 409,675
Regulatory assets recoverable through future rates 112,389 108,823
Right of use asset 17,670 -
Other 19,005 17,694
Total deferred tax liabilities 587,082 536,192
Deferred tax assets:
Investment tax credit 4 5
Regulatory liabilities including ARO 170,236 168,619
Employee benefit plans 265 -
Investments in tax partnerships 6,670 2,501
Lease liability 18,169 -
Other 10,980 3,579
Total deferred tax assets 206,324 174,704
Deferred income tax liability - net $ 380,758 $ 361,488
Uncertain Tax Positions
Tax years subsequent to 2020 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, 2024, 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.
9. 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 $3.9 million, $3.7 million and $3.6 million for 2024, 2023 and 2022, 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 $2.7 million, $2.5 million and $2.1 million for 2024, 2023 and 2022, respectively.
Defined Benefit Plans
Approximately 64% of AES Indiana’s active employees are covered by the qualified Defined Benefit Pension Plan; while approximately 13% 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, 2024 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 120 active employees and 27 retirees (including spouses) were receiving such benefits or entitled to future benefits as of January 1, 2024. The plan is unfunded. These postretirement health care benefits and the related unfunded obligation of $3.0 million and $3.0 million at December 31, 2024 and 2023, 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,
2024 2023
(In Thousands)
Change in benefit obligation:
Projected benefit obligation at January 1 $ 549,546 $ 577,530
Service cost 5,011 5,189
Interest cost 26,958 29,818
Actuarial (gain) / loss (18,044) 9,681
Amendments (primarily increases in pension bands) 7,948 653
Benefits paid (37,166) (73,325)
Projected benefit obligation at December 31 534,253 549,546
Change in plan assets:
Fair value of plan assets at January 1 590,819 611,125
Actual return on plan assets 5,526 52,905
Employer contributions 15 114
Benefits paid (37,166) (73,325)
Fair value of plan assets at December 31 559,194 590,819
Funded status $ 24,941 $ 41,273
Amounts recognized in the statement of financial position:
Non-current assets $ 24,941 $ 41,273
Net amount recognized at end of year $ 24,941 $ 41,273
Sources of change in regulatory assets(1):
Prior service cost arising during period $ 7,948 $ 653
Net loss / (gain) arising during period 6,204 (10,117)
Amortization of prior service cost (1,900) (2,172)
Amortization of loss (4,828) (6,145)
Total recognized in regulatory assets $ 7,424 $ (17,781)
Amounts included in regulatory assets:
Net loss $ 116,674 $ 115,297
Prior service cost 16,183 10,136
Total amounts included in regulatory assets $ 132,857 $ 125,433
(1)Amounts that would otherwise be charged/credited to Accumulated Other Comprehensive Income or Loss upon application of ASC 715, “Compensation - Retirement Benefits,” are recorded as a regulatory asset or liability because AES Indiana has historically recovered and currently recovers pension and other postretirement benefit expenses in rates. These are unrecognized amounts not yet recognized as components of net periodic benefit costs.
Significant Loss / (Gain) Related to Changes in the Benefit Obligation for the Period
As shown in the table above, an actuarial gain of $18.0 million and an actuarial loss of $9.7 million for the year ended December 31, 2024 and December 31, 2023, 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 2024 net actuarial loss of $6.2 million recognized in regulatory assets is comprised of two parts: (1) a $18.0 million pension liability actuarial gain primarily due to an increase in the discount rate used to value pension liabilities; and (2) a $24.2 million pension asset actuarial loss primarily due to lower than expected return on assets. The unrecognized net loss of $116.7 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. 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 12.11 years based on estimated demographic data as of December 31, 2024. The projected benefit obligation of $534.3 million less the fair value of assets of $559.2 million results in an overfunded status of $24.9 million at December 31, 2024.
Pension benefits for
years ended December 31,
2024 2023 2022
(In Thousands)
Components of net periodic benefit cost / (credit):
Service cost $ 5,011 $ 5,189 $ 8,949
Interest cost 26,958 29,818 18,099
Expected return on plan assets (29,774) (33,107) (35,656)
Amortization of prior service cost 1,900 2,172 2,589
Amortization of actuarial loss 4,828 6,145 2,424
Amortization of settlement loss - - 199
Net periodic benefit cost / (credit) 8,923 10,217 (3,396)
Less: amounts capitalized 1,780 1,689 (316)
Amount charged to expense $ 7,143 $ 8,528 $ (3,080)
Rates relevant to each year’s expense calculations:
Discount rate - defined benefit pension plan 5.15 % 5.41 % 2.83 %
Discount rate - supplemental retirement plan 5.66 % 5.32 % 2.62 %
Expected return on defined benefit pension plan assets 5.20 % 5.60 % 4.45 %
Expected return on supplemental retirement plan assets 6.35 % 6.45 % 5.50 %
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 2024, pension expense / (income) was determined using an assumed long-term rate of return on plan assets of 5.20% for the Defined Benefit Pension Plan and 6.35% for the Supplemental Retirement Plan. As of the December 31, 2024 measurement date, AES Indiana increased the discount rate from 5.15% to 5.66% for the Defined Benefit Pension Plan and decreased the discount rate from 5.66% to 5.16% for the Supplemental Retirement Plan. The discount rate assumptions affect the pension expense / (income) determined for 2025. In addition, AES Indiana increased the expected long-term rate of return on plan assets from 5.20% to 5.75% for the Defined Benefit Pension Plan and decreased from 6.35% to 6.15% for the Supplemental Retirement Plan for 2025. The expected long-term rate of return assumptions affect the pension expense / (income) determined for 2025. The effect on 2025 total pension expense / (income) of a 25 basis point increase and decrease in the assumed discount rate is $(0.7) million and $0.7 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, 2024. 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, 2024. Pension costs are determined for the following year based on the market value of pension plan assets, expected employer contributions, a discount rate used to determine the projected benefit obligation and the expected long-term rate of return on plan assets.
Fair value is defined under ASC 820 as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (i.e., an exit price). The fair value hierarchy prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets and liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).
Purchases and sales of securities are recorded on a trade-date basis. Interest income is recorded as earned. Dividends are recorded on the ex-dividend date. Net appreciation includes the Pension Plans’ gains and losses on investments bought and sold, as well as held, during the year.
A description of the valuation methodologies used for each major class of assets and liabilities measured at fair value follows:
•The non-qualified Supplemental Retirement Plan investments have quoted market prices and are categorized as Level 1 in the fair value hierarchy.
•The qualified Defined Benefit Pension Plan investments in common collective trusts are valued based on the daily net asset value and are categorized as Level 2 in the fair value hierarchy, except for cash and cash equivalents which are categorized as level 1.
The primary objective of the Pension Plans’ is to provide a source of retirement income for its participants and beneficiaries, while the primary financial objective is to improve the funded status of the Pension Plans. A secondary financial objective is, where possible, to minimize pension expense volatility. The objective is based on a long-term investment horizon, so that interim fluctuations should be viewed with appropriate perspective. There can be no assurance that these objectives will be met.
In establishing our expected long-term rate of return assumption, we utilize a methodology developed by the plan’s investment consultant who maintains a capital market assumption model that takes into consideration risk, return and correlation assumptions across asset classes. A combination of quantitative analysis of historical data and qualitative judgment is used to capture trends, structural changes and potential scenarios not reflected in historical data.
The result of the analyses is a series of inputs that produce a picture of how the plan consultant believes portfolios are likely to behave through time. Capital market assumptions are intended to reflect the behavior of asset classes observed over several market cycles. Stress assumptions are also examined, since the characteristics of asset classes are constantly changing. A dynamic model is employed to manage the numerous assumptions required to estimate portfolio characteristics under different base currencies, time horizons and inflation expectations.
The Pension Plans’ consultant develops forward-looking, long-term capital market assumptions for risk, return and correlations for a variety of global asset classes, interest rates and inflation. These assumptions are created using a combination of historical analysis, current market environment assessment and by applying the consultant’s own judgment. The consultant then determines an equilibrium long-term rate of return. We then take into consideration the investment manager/consultant expenses, as well as any other expenses expected to be paid out of the Pension Plans’ trust. Finally, we have the Pension Plans’ actuary perform a tolerance test of the consultant’s equilibrium expected long-term rate of return. We use an expected long-term rate of return compatible with the actuary’s tolerance level.
The following table summarizes the Company’s target pension plan allocation for 2024:
Asset Category: Target Allocations
Equity Securities 13.5%
Debt Securities 86.5%
Fair Value Measurements at
December 31, 2024
(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)
$ 76,939 $ 2,325 $ 74,614 14 %
Debt securities (b)
364,121 1,135 362,986 65 %
Government debt securities (c)
115,228 373 114,855 21 %
Total common collective trusts 556,288 3,833 552,455 100 %
Cash and cash equivalents (d)
2,906 2,906 - - %
Total pension plan assets $ 559,194 $ 6,739 $ 552,455 100 %
(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, 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.
Pension Funding
We contributed $0.0 million, $0.1 million, and $0.4 million to the Pension Plans in 2024, 2023 and 2022, 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 89%. 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 $5.6 million in 2025 (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 2025. 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, 2024, 2023 and 2022 were $37.2 million, $73.3 million and $38.6 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)
2025 $ 39,526
2026 40,694
2027 41,020
2028 41,660
2029 41,681
2030 through 2034 205,297
10. EQUITY
Cumulative Preferred Stock
AES Indiana previously had five separate series of 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.
Paid In Capital
During 2024, AES U.S. Investments received equity capital contributions totaling $185.3 million, of which $157.5 million was contributed by AES U.S. Holdings, LLC and $27.8 million was contributed by CDPQ. IPALCO then received equity capital contributions totaling $225.0 million, of which $185.3 million was contributed by AES U.S. Investments and $39.7 million was contributed by CDPQ. IPALCO then made the same investments in AES Indiana. The proceeds from the equity capital contributions are intended primarily for funding needs related to AES Indiana’s capital expenditure program. The equity 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.
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. IPALCO then made the same investments in AES Indiana. The proceeds from the equity contribution are intended primarily for funding needs related to AES Indiana’s TDSIC and replacement generation projects.
These 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 during the three years ended December 31, 2024.
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, 2024, 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 $400 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, 2024, 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, 2024, 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, 2024, 2023 and 2022, IPALCO declared and paid distributions to its shareholders totaling $156.6 million, $104.3 million and $102.0 million, respectively.
Equity Transactions with Noncontrolling Interests
The Hardy Hills Solar Project and the Pike County BESS Project are 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, AES Indiana, through a wholly-owned subsidiary, sold a noncontrolling interest in the Hardy Hills Solar Project to a tax equity investor. Through December 31, 2024, the tax equity investor has made total contributions of $126.2 million under the agreement, including $46.9 million contributed in May 2024 upon final completion of the project, and noncontrolling interest was recorded by AES Indiana at the amount of cash contributed.
On December 6, 2024, AES Indiana, through a wholly-owned subsidiary, sold a noncontrolling interest in the Pike County BESS Project to a tax equity investor. Through December 31, 2024, the tax equity investor made contributions of $38.1 million, recorded as Redeemable stock of subsidiaries on the Consolidated Balance Sheets at the amount of cash contributed. The redemption feature of the tax equity partnership agreement is contingent upon the underlying assets being placed in service by a guaranteed date. The Company has concluded it is probable that the project will be placed in service by the guaranteed date; therefore, the noncontrolling ownership interest is not probable of becoming redeemable and subsequent adjustments to the carrying value were not required.
11. 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, 2024, 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, power purchased and
related transportation $ 643.8 $ 176.8 $ 201.2 $ 171.7 $ 94.1
Other $ 227.5 $ 220.5 $ 2.8 $ 4.2 $ -
Purchase obligations:
Purchase commitments for coal, gas, power purchased and related transportation:
AES Indiana enters into long-term contracts for the purchase of coal, gas, power purchased 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, 2024, 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 6, "Derivative Instruments and Hedging Activities"), (iii) taxes (see Note 8, "Income Taxes"), (iv) pension and other postretirement employee benefit liabilities (see Note 9, "Benefit Plans") and (v) contingencies (see Note 11, "Commitments and Contingencies"). See the indicated notes to the Financial Statements for additional information on the items excluded.
Contingencies
Subsidiary Guarantees
In connection with AES Indiana's renewable projects financed with a tax equity structure, AES Indiana has expressly undertaken limited obligations and commitments on behalf of certain of the Company's subsidiaries, which will only be effective or will be terminated upon the occurrence of future events. As of December 31, 2024, the maximum undiscounted potential exposure to tax equity financing related guarantees was $164.4 million.
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, 2024 and 2023.
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, 2024 and 2023.
NSR and other CAA NOVs
In October 2009, AES Indiana received a NOV and Finding of Violation from the EPA pursuant to the CAA Section 113(a). The NOV alleged violations of the CAA at AES Indiana’s three primarily coal-fired electric generating facilities at the time, dating back to 1986. The alleged violations primarily pertain to the PSD and non-attainment NSR requirements under the CAA. In addition, on October 1, 2015, AES Indiana received a NOV from the EPA pursuant to CAA Section 113(a) alleging violations of the CAA, the Indiana SIP, and the Title V operating permit related to alleged particulate matter and opacity violations at AES Indiana Petersburg Unit 3. Also, on February 5, 2016, the EPA issued a NOV pursuant to CAA Section 113(a) alleging violations of PSD, non-attainment NSR and other CAA regulations, the Indiana SIP, and the Title V operating permit at Petersburg Generating Station. On August 31, 2020, AES Indiana reached a settlement with the EPA, the DOJ and IDEM resolving the purported violations of the CAA with respect to the coal-fired generation units at AES Indiana's Petersburg location. The settlement agreement, in the form of a proposed judicial consent decree was approved and entered by the U.S. District Court for the Southern District of Indiana on March 23, 2021, and includes, among other items, the following requirements: annual caps on NOx and SO2 emissions and more stringent emissions limits than AES Indiana's prior Title V air permit; payment of civil penalties totaling $1.525 million (the payment of which was satisfied by AES Indiana in April 2021); a $5 million environmental mitigation project consisting of the construction and operation of a new, non-emitting source of generation at the site; expenditure of $0.325 million on a state-only environmentally beneficial project to preserve local, ecologically-significant lands; and retirement of Units 1 and 2 prior to July 1, 2023 (which has occurred). AES Indiana previously had a contingent liability recorded related to these NSR and other CAA NOV matters.
12. 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 $11.6 million, $11.7 million, and $9.5 million in 2024, 2023 and 2022, respectively, and is recorded in “Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations. As of December 31, 2024 and 2023, we had prepaid approximately $7.9 million and $7.5 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 $20.1 million, $19.0 million, and $25.2 million in 2024, 2023 and 2022, 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, 2024 and 2023, 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 $9.4 million and $36.5 million as of December 31, 2024 and 2023, respectively, which is recorded in “Taxes receivable” on the accompanying Consolidated Balance Sheets. See Note 8, "Income Taxes" for more information.
Long-term Compensation Plan
During 2024, 2023 and 2022, 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 2024, 2023 and 2022 was $0.5 million, $0.3 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 9, “Benefit Plans” for a description of benefits awarded to AES Indiana employees by AES under the RSP.
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.
The following table provides a summary of our related party transactions:
Years Ended December 31,
2024 2023 2022
(In Millions)
Transactions included in Operation and Maintenance on the Consolidated Statements of Operations:
Charges from the Service Company
$ 85.4 $ 73.8 $ 60.3
Charges to the Service Company
$ 15.4 $ 11.9 $ 10.0
Services provided by other related parties
$ 6.7 $ 7.4 $ 5.7
Transactions primarily included in Property, plant and equipment, net and Intangible assets, net on the Consolidated Balance Sheets:
Charges from the Service Company
$ 15.9 $ 47.1 $ 22.7
Balances with related parties (included in Prepayments and other current assets and Accounts Payable on the Consolidated Balance Sheets):
At December 31, 2024 At December 31, 2023
Prepayments and other current assets
$ 13.3 $ -
Accounts payable
$ - $ 25.6
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 $72.9 million and $223.3 million to this vendor during 2024 and 2023, respectively, which is recorded primarily in "Property, plant and equipment, net" on the accompanying Consolidated Balance Sheets.
13. BUSINESS SEGMENTS
IPALCO manages its business through one reportable operating segment, the Utility segment, led by our Chief Executive Officer and Chief Financial Officer, who, collectively, are the Chief Operating Decision Maker. The primary segment performance measures are income / (loss) before income tax and net income / (loss) as management has concluded that these measures best reflect the underlying business performance of IPALCO and are the most
relevant measures considered in IPALCO's internal evaluation of the financial performance of its segment. The Chief Operating Decision Maker uses income / (loss) before income tax and net income / (loss) in the annual budget and forecasting process, including making decisions on reinvesting profits to support Utility segment growth. On a monthly basis, the Chief Operating Decision Maker reviews variances in budget versus actual results and monitors changes in forecasted results to assess the underlying operating performance and analyze risks and opportunities for the Utility 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, 2030 IPALCO Notes, 2034 IPALCO Notes and related interest expense, balances associated with IPALCO's interest rate hedges, cash and other immaterial balances. See "Note 6 "Derivative Instruments and Hedging Activities" and Note 7 "Debt" for further information on the interest rate swaps related to the 2024 IPALCO Notes. The accounting policies of the identified segment are consistent with those policies and procedures described in the summary of significant accounting policies.
The following table provides information about IPALCO’s business segments (in thousands):
2024 2023 2022
Utility Other Total Utility Other Total Utility Other Total
Revenue $ 1,643,793 $ - $ 1,643,793 $ 1,649,917 $ - $ 1,649,917 $ 1,791,711 $ - $ 1,791,711
Fuel 359,132 - 359,132 494,000 - 494,000 568,676 - 568,676
Power purchased 148,412 - 148,412 159,908 - 159,908 199,860 - 199,860
Operation and maintenance 475,778 716 476,494 477,497 383 477,880 493,454 220 493,674
Depreciation and amortization 329,468 - 329,468 287,863 - 287,863 266,504 - 266,504
Taxes other than income taxes 27,478 - 27,478 24,865 (1) 24,864 33,048 - 33,048
Allowance for equity funds used during construction (3,991) - (3,991) (9,315) - (9,315) (4,784) - (4,784)
Interest expense 129,023 43,127 172,150 99,051 43,875 142,926 87,428 43,804 131,232
Other segment items (a)
3,102 (2,045) 1,057 285 (236) 49 (15,337) 353 (14,984)
Income/(loss) before income tax 175,391 (41,798) 133,593 115,763 (44,021) 71,742 162,862 (44,377) 118,485
Income tax expense / (benefit) 38,763 (10,399) 28,364 25,666 (10,951) 14,715 32,887 (11,028) 21,859
Net income / (loss) $ 136,628 $ (31,399) $ 105,229 $ 90,097 $ (33,070) $ 57,027 $ 129,975 $ (33,349) $ 96,626
Capital expenditures (b)
$ 954,995 $ - $ 954,995 $ 902,705 $ - $ 902,705 $ 496,510 $ - $ 496,510
As of December 31, 2024 As of December 31, 2023 As of December 31, 2022
Total assets $ 7,123,241 $ 15,784 $ 7,139,025 $ 6,129,581 $ 51,942 $ 6,181,523 $ 5,559,977 $ 29,237 $ 5,589,214
(a) Other segment items primarily includes other miscellaneous gains and losses in Other (expense) income, net.
(b) Capital expenditures includes $23,673 thousand, $0 thousand and $0 thousand of payments for financed capital expenditures in 2024, 2023 and 2022, respectively.
14. REVENUE
Revenue is primarily earned from retail and wholesale electricity sales and electricity transmission and distribution delivery services. Revenue is recognized upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Revenue is recorded net of any taxes assessed on and collected from customers, which are remitted to the governmental authorities.
Retail revenue - AES Indiana energy sales to utility customers are based on the reading of meters at the customer’s location that occurs on a systematic basis throughout the month. AES Indiana sells electricity directly to end-users, such as homes and businesses, and bills customers directly. Retail revenue have a single performance obligation, as the promise to transfer energy and other distribution and/or transmission services are not separately identifiable from other promises in the contracts and, therefore, are not distinct. Additionally, as the performance obligation is satisfied over time as energy is delivered, and the same method is used to measure progress, the performance obligation meets the criteria to be considered a series.
In exchange for the exclusive right to sell or distribute electricity in our service area, AES Indiana is subject to rate regulation by federal and state regulators. This regulation sets the framework for the prices (“tariffs”) that AES Indiana is allowed to charge customers for electric services. Since tariffs are approved by the regulator, the price that AES Indiana has the right to bill corresponds directly with the value to the customer of AES Indiana’s performance completed in each period. Therefore, revenue under these contracts is recognized using an output method measured by the MWhs delivered each month at the approved tariff. Customer payments are typically due on a monthly basis.
Wholesale revenue - Power produced at the generation stations in excess of our retail load is sold into the MISO market. Such sales are made at either the day-ahead or real-time hourly market price, and these sales are classified as wholesale revenue. We sell to and purchase power from MISO, and such sales and purchases are settled and accounted for on a net hourly basis.
In the MISO market, wholesale revenue is recorded at the spot price based on the quantities of MWh delivered in each hour during each month. As a member of MISO, we are obligated to declare the availability of our energy production into the wholesale energy market, but we are not obligated to commit our previously declared availability. As such, contract terms end as the energy for each day is delivered to the market in the case of the day-ahead market and for each hour in the case of the real-time market.
Miscellaneous revenue - Miscellaneous revenue is mainly comprised of MISO transmission revenue and capacity revenue. MISO transmission revenue is earned when AES Indiana’s power lines are used in transmission of energy by power producers other than AES Indiana. As AES Indiana owns and operates transmission lines in central and southern Indiana, demand charges collected from network customers by MISO are allocated to the appropriate transmission owners (including AES Indiana) and recognized as transmission revenue. Capacity revenue is also included in miscellaneous revenue, and represent compensation received from MISO for making installed generation capacity available to satisfy system integrity and reliability requirements through the annual MISO capacity auction. Capacity, which is a stand-ready obligation to deliver energy when called upon by the RTO, is measured using MWs.
Transmission and capacity revenue each have a single performance obligation, as they each represent a distinct service or good. Additionally, as these performance obligations are satisfied over time and the same method is used to measure progress, the performance obligations meet the criteria to be considered a series. For transmission revenue, the price that the transmission operator has the right to bill corresponds directly with the value to the customer of AES Indiana’s performance completed in each period as the price paid is the transmission operator's allocation of the tariff rate (as approved by the regulator) charged to network participants. For capacity revenue, the capacity price that clears at the auction is fixed and AES Indiana is compensated based on the cleared MWs and cleared price.
AES Indiana’s revenue from contracts with customers was as follows (in thousands):
For the Years Ended December 31,
2024 2023 2022
Revenue from contracts with customers $ 1,616,000 $ 1,616,462 $ 1,759,971
The following table presents our revenue from contracts with customers and other revenue (in thousands):
For the Years Ended December 31,
2024 2023 2022
Retail Revenue
Retail revenue from contracts with customers:
Residential $ 688,728 $ 660,559 $ 688,487
Small commercial and industrial 250,777 241,800 247,655
Large commercial and industrial 606,565 619,899 625,351
Public lighting 10,366 9,767 9,832
Other (1)
10,638 14,016 17,845
Total retail revenue from contracts with customers 1,567,074 1,546,041 1,589,170
Alternative revenue programs 24,964 30,414 29,171
Wholesale Revenue
Wholesale revenue from contracts with customers 37,519 56,557 148,517
Miscellaneous Revenue
Capacity revenue 305 8,210 11,750
Transmission and other revenue 11,102 5,654 10,534
Total miscellaneous revenue from contracts with customers 11,407 13,864 22,284
Other miscellaneous revenue (2)
2,829 3,041 2,569
Total Revenue $ 1,643,793 $ 1,649,917 $ 1,791,711
(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 as follows (in thousands):
As of December 31,
2024 2023
Receivables from contracts with customers
$ 298,984 $ 218,822
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 temporarily paused customer disconnections and certain collection efforts and write-off processes to support the implementation of AES Indiana's customer billing system upgrade in the fourth quarter of 2023. In the third quarter of 2024, AES Indiana began offering extended payment plans for customers who may need assistance in paying their past due bills. See Note 1, “Overview and Summary of Significant Accounting Policies - Accounts Receivable and Allowance for Credit Losses” for further information on AES Indiana’s receivable balances.
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.
15. 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, 2024 December 31, 2023
Assets
Right-of-use assets - finance leases Other non-current assets $ 86,707 $ 16,357
Liabilities
Finance lease liabilities (current) Short-term debt and current portion of long-term debt 217 -
Finance lease liabilities (non-current)
Long-term debt 86,869 17,769
Total finance lease liabilities $ 87,086 $ 17,769
The following table summarizes supplemental balance sheet information related to leases as of the periods indicated:
Lease Term and Discount Rate December 31, 2024 December 31, 2023
Weighted-average remaining lease term - finance leases 36 years
35 years
Weighted-average discount rate - finance leases 5.67 % 5.30 %
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, 2024, 2023 and 2022, respectively (in thousands):
For the Year Ended December 31,
Components of Lease Cost 2024 2023 2022
Finance lease cost:
Amortization of right-of-use assets $ 638 $ 445 $ 542
Interest on lease liabilities 1,585 933 782
Total lease cost $ 2,223 $ 1,378 $ 1,324
Operating cash outflows from finance leases were $3.9 million, $0.6 million and $0.3 million for the years ended December 31, 2024, 2023 and 2022, 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, 2024 for 2025 through 2029 and thereafter (in thousands):
Finance Leases
2025 $ 4,476
2026 4,565
2027 4,657
2028 4,750
2029 4,845
Thereafter 205,039
Total 228,332
Less: Imputed interest (141,246)
Present value of lease payments $ 87,086
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,
2024 2023 2022
Total lease revenue $ 1,452 $ 1,537 $ 1,134
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, 2024 December 31, 2023
Gross assets $ 4,387 $ 4,341
Less: Accumulated depreciation (1,426) (1,222)
Net assets $ 2,961 $ 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 minimum lease receipts through 2029 and thereafter (in thousands):
Operating Leases
2025 $ 553
2026 554
2027 554
2028 354
2029 314
Thereafter 577
Total $ 2,906
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, 2024 and 2023, the related consolidated statements of operations, changes in equity, and cash flows for each of the three years in the period ended December 31, 2024, 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, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting in accordance with the standards of the PCAOB. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
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 1 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 the significant knowledge and experience required to assess the impact of regulatory orders on the consolidated financial statements including understanding the nature of the rate orders issued, or expected to be issued, and to assess the relevance and reliability of audit evidence to support the impacted account balances and disclosures.
How We Addressed the Matter in Our Audit Our audit procedures related to regulatory assets and liabilities included testing the effectiveness of management’s controls, such as the Company’s evaluation of regulatory orders and other developments that may affect the calculation of recorded amounts, the likelihood of recovering regulatory assets and the sufficiency of regulatory liabilities. Our procedures also included testing management’s calculations of recorded amounts, obtaining, reading, and evaluating relevant regulatory orders issued by the IURC to IPL, and considering regulatory precedents established by the IURC, to evaluate the likelihood of recovering regulatory assets, the sufficiency of regulatory liabilities and the accuracy and completeness of required disclosures related to the impacts of rate regulation and regulatory developments.
Asset Retirement Obligations
Description of the Matter At December 31, 2024, the Company’s asset retirement obligations (“ARO”) totaled $378.5 million. As described in Note 4 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 revisions to its existing ARO liabilities of $117.7 million during 2024 primarily to reflect revisions to cash flow estimates due to increases in closure costs and groundwater treatment measures for ash ponds and landfills.
Auditing the Company’s ARO liabilities revised in 2024 was complex and highly judgmental due to the significant estimation required by management to determine the 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 the scope and method of decommissioning utilized to determine the related cash flows.
How We Addressed the Matter in Our Audit To test the Company’s ARO liabilities revised in 2024, our audit procedures included evaluating the appropriateness of the Company’s methodology, interviewing members of the Company’s environmental staff and testing the scope and method of decommissioning. We involved our specialists in our assessment of the scope and method of decommissioning for the Company’s ARO liabilities revised in 2024, including reviewing the Company’s methodology, evaluating the reasonableness of the related cash flows, and assessing completeness of the estimates based upon regulatory requirements.
/s/ Ernst & Young LLP
We have served as the Company’s auditor since 2008.
Indianapolis, Indiana
March 5, 2025
AES INDIANA and SUBSIDIARIES
Consolidated Statements of Operations
For the Years Ended December 31, 2024, 2023 and 2022
2024 2023 2022
(In Thousands)
REVENUE $ 1,643,793 $ 1,649,917 $ 1,791,711
OPERATING COSTS AND EXPENSES:
Fuel 359,132 494,000 568,676
Power purchased 148,412 159,908 199,860
Operation and maintenance 475,778 477,497 493,454
Depreciation and amortization 329,468 287,863 266,504
Taxes other than income taxes 27,478 24,865 33,048
Other, net (106) (361) (3,201)
Total operating costs and expenses 1,340,162 1,443,772 1,558,341
OPERATING INCOME 303,631 206,145 233,370
OTHER (EXPENSE) / INCOME, NET:
Allowance for equity funds used during construction 3,991 9,315 4,784
Interest expense (129,023) (99,051) (87,428)
Other (expense) / income, net (3,208) (646) 12,136
Total other expense, net (128,240) (90,382) (70,508)
INCOME BEFORE INCOME TAX 175,391 115,763 162,862
Income tax expense 38,763 25,666 32,887
NET INCOME 136,628 90,097 129,975
Dividends on and redemption of preferred stock - - 3,509
Net loss attributable to noncontrolling interests (28,294) (26,093) -
NET INCOME ATTRIBUTABLE TO COMMON STOCK $ 164,922 $ 116,190 $ 126,466
See Notes to Consolidated Financial Statements.
AES INDIANA and SUBSIDIARIES
Consolidated Balance Sheets
December 31, 2024 and 2023
2024 2023
(In Thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 24,259 $ 25,767
Accounts receivable, net of allowance for credit losses of $29,798 and $2,283, respectively
313,124 233,970
Inventories 99,935 143,590
Regulatory assets, current 134,328 89,419
Taxes receivable - 5,140
Prepayments and other current assets 26,074 27,741
Total current assets 597,720 525,627
NON-CURRENT ASSETS:
Property, plant and equipment, net of accumulated depreciation of $3,071,167 and $2,954,555, respectively
5,461,243 4,486,902
Intangible assets, net 232,210 235,656
Regulatory assets, non-current 619,029 541,784
Pension plan assets 24,941 41,172
Other non-current assets 188,098 298,439
Total non-current assets 6,525,521 5,603,953
TOTAL ASSETS $ 7,123,241 $ 6,129,580
LIABILITIES AND SHAREHOLDER'S EQUITY
CURRENT LIABILITIES:
Short-term debt and current portion of long-term debt (see Notes 7 and 15) $ 539,841 $ 494,685
Accounts payable 271,118 292,835
Accrued taxes 26,556 22,580
Accrued interest 34,239 25,245
Customer deposits 11,892 29,308
Regulatory liabilities, current 11,915 23,371
Asset retirement obligations, current 32,161 -
Accrued and other current liabilities 25,932 34,748
Total current liabilities 953,654 922,772
NON-CURRENT LIABILITIES:
Long-term debt (see Notes 7 and 15) 2,777,197 2,106,146
Deferred income tax liabilities 368,949 342,557
Taxes payable 3,785 -
Regulatory liabilities, non-current 404,021 527,224
Accrued other postretirement benefits 2,834 2,776
Asset retirement obligations, non-current 346,299 249,930
Other non-current liabilities 4,715 5,129
Total non-current liabilities 3,907,800 3,233,762
Total liabilities 4,861,454 4,156,534
COMMITMENTS AND CONTINGENCIES (see Note 11)
REDEEMABLE STOCK OF SUBSIDIARIES 38,145 -
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, 2024 and 2023)
324,537 324,537
Paid in capital 1,418,296 1,193,199
Retained earnings 412,378 402,056
Total common shareholder's equity 2,155,211 1,919,792
Noncontrolling interests 68,431 53,254
Total equity 2,223,642 1,973,046
TOTAL LIABILITIES, REDEEMABLE STOCK OF SUBSIDIARIES AND EQUITY $ 7,123,241 $ 6,129,580
See Notes to Consolidated Financial Statements.
AES INDIANA and SUBSIDIARIES
Consolidated Statements of Cash Flows
For the Years Ended December 31, 2024, 2023 and 2022
2024 2023 2022
(In Thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 136,628 $ 90,097 $ 129,975
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization 329,468 287,863 266,504
Amortization of deferred financing costs and debt discounts 2,488 2,406 2,511
Deferred income taxes and investment tax credit adjustments - net 9,971 23,582 (6,584)
Allowance for equity funds used during construction (3,991) (9,315) (4,784)
Gain on acquisition - - -
Change in certain assets and liabilities:
Accounts receivable (54,519) (17,398) (37,391)
Inventories 24,285 (30,171) (47,489)
Prepayments and other current assets 2,278 (6,476) 19,016
Accounts payable (53,052) 47,016 32,232
Accrued and other current liabilities (21,640) 2,790 6,532
Accrued taxes payable/receivable 12,429 1,647 (3,452)
Accrued interest 8,994 192 2,813
Pension and other postretirement benefit assets and liabilities 2,485 1,625 (8,727)
Current and non-current regulatory assets and liabilities (123,689) 54,358 38,863
Other non-current liabilities (20,102) (16,663) (21,717)
Other - net 3,008 (4,074) 4,967
Net cash provided by operating activities 255,041 427,479 373,269
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (931,322) (902,705) (496,510)
Project development costs (4,430) (4,462) (3,910)
Cost of removal payments (39,133) (45,595) (23,948)
Acquisitions (48,368) - -
Insurance proceeds - 4,900 -
Purchase of intangibles (4,363) (44,650) -
Other 1,559 (361) (719)
Net cash used in investing activities (1,026,057) (992,873) (525,087)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings from revolving credit facilities 750,000 435,000 300,000
Repayments from revolving credit facilities (805,000) (280,000) (360,000)
Short-term borrowings 400,000 300,000 200,000
Repayment of short-term borrowings (300,000) - (200,000)
Long-term borrowings 650,000 - 350,000
Retirement of long-term debt (40,000) - -
Dividends on common stock (162,100) (140,200) (127,200)
Dividends on preferred stock - - (3,213)
Payments of deferred financings costs and discounts (5,377) (350) (4,309)
Purchase of preferred stock - - (60,080)
Equity contributions from IPALCO 225,000 - 253,000
Distributions to noncontrolling interest (3,464) - -
Sales to noncontrolling interests 84,142 77,921 -
Payments for financed capital expenditures (23,673) - -
Other (20) (313) (33)
Net cash provided by financing activities 769,508 392,058 348,165
Net change in cash, cash equivalents and restricted cash (1,508) (173,336) 196,347
Cash, cash equivalents and restricted cash at beginning of year 25,772 199,108 2,761
Cash, cash equivalents and restricted cash at end of year $ 24,264 $ 25,772 $ 199,108
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the period for:
Interest (net of amount capitalized) $ 113,598 $ 93,544 $ 80,104
Income taxes $ 22,900 $ - $ 39,500
Non-cash investing activities:
Accruals for capital expenditures $ 162,450 $ 124,626 $ 66,949
Recognition of right-of-use assets - finance leases $ 72,462 $ 983 $ (3,402)
Non-cash financing activities:
Recognition of financing lease liabilities $ (69,318) $ (1,408) $ (3,402)
See Notes to Consolidated Financial Statements.
AES INDIANA and SUBSIDIARIES
Consolidated Statements of Changes in Equity
For the Years Ended December 31, 2024, 2023 and 2022
Common Shareholder's Equity
Common Stock
(in Thousands)
Outstanding Shares
Amount
Paid in Capital Retained Earnings Total Common Shareholder's Equity Cumulative Preferred Stock Noncontrolling Interests Redeemable Stock Of Subsidiaries
Balance at January 1, 2022 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 -
Net income / (loss) - - - 164,922 164,922 - (28,294) -
Cash dividends declared on common stock - - - (154,600) (154,600) - - -
Sales to noncontrolling interests - - - - - - 46,935 38.145
Distributions to noncontrolling interest - - - - - - (3,464) -
Contributions from IPALCO - - - - 225,000 - 225,000 - - -
Other - - 97 - 97 - - -
Balance at December 31, 2024 17,207 $ 324,537 $ 1,418,296 $ 412,378 $ 2,155,211 $ - $ 68,431 38.145
See Notes to Consolidated Financial Statements.
AES INDIANA and SUBSIDIARIES
Notes to Consolidated Financial Statements
For the Years Ended December 31, 2024, 2023 and 2022
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 531,000 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 December 31, 2024, AES Indiana’s net electric generation design capacity at these generating stations for winter is 3,070 MW and summer 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 placed in service during the fourth quarter of 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 placed in service during the first quarter of 2025.
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 VIE and AES Indiana is determined to have power and benefits, the entity will be consolidated by AES Indiana.
AES Indiana consolidates the results of three subsidiaries that qualify as VIEs. These subsidiaries are Hardy Hills JV, Pike County Energy Storage JV and Petersburg Energy Center. AES Indiana is the primary beneficiary and controls the most significant activities of these VIEs. At December 31, 2024 and 2023, the assets of these VIEs were approximately $1,169.3 million and $613.2 million, primarily consisting of property, plant and equipment, construction work in progress and other non-current assets. At December 31, 2024 and 2023, the liabilities of these VIEs were approximately $180.5 million and $51.0 million, primarily consisting of finance leases and accounts payable.
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.
Noncontrolling interests with redemption features that are not solely within the control of the issuer are classified as temporary equity and are included in Redeemable stock of subsidiaries on the Consolidated Balance Sheets. Generally, initial measurement will be at fair value. The subsequent allocation of income and dividends is classified in temporary equity. Subsequent measurement and classification vary depending on whether the instrument is probable of becoming redeemable. For securities that are currently redeemable or where it is probable that the instrument will become redeemable, AES Indiana recognizes any changes from the carrying value to redemption value at each reporting period against retained earnings or additional paid-in capital in the absence of retained earnings; such adjustments are classified in temporary equity. When the equity instrument is not probable of becoming redeemable, no adjustment to the carrying value is recognized.
Allocation of Earnings
Hardy Hills JV and Pike County Energy Storage JV are subject to profit-sharing arrangements where the allocation of earnings, cash distributions, and tax benefits are not based on fixed ownership percentages. These arrangements exist 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, see Note 10, "Equity - Equity Transactions with Noncontrolling Interests").
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 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.
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,
2024 2023
(In Thousands)
Cash, cash equivalents and restricted cash
Cash and cash equivalents $ 24,259 $ 25,767
Restricted cash (included in Prepayments and other current assets) 5 5
Total cash, cash equivalents and restricted cash $ 24,264 $ 25,772
Accounts Receivable and Allowance for Credit Losses
The following table summarizes our accounts receivable balances at December 31:
As of December 31,
2024 2023
(In Thousands)
Accounts receivable, net
Customer receivables $ 207,353 $ 125,715
Unbilled revenue 90,731 91,463
Amounts due from related parties 6,508 5,227
Other 38,330 13,848
Allowance for credit losses (29,798) (2,283)
Total accounts receivable, net $ 313,124 $ 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 Years Ended December 31,
2024 2023
(In Thousands)
Allowance for credit losses:
Beginning balance $ 2,283 $ 1,117
Current period provision 26,662 7,413
Net write-offs charged against allowance
(902) (7,764)
Recoveries and account write-ons
1,755 1,517
Ending Balance $ 29,798 $ 2,283
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 the collectability, as applicable, of our receivables balance. Amounts are written off when reasonable collections efforts have been exhausted. During 2024, the current period provision and allowance for credit losses increased due to a temporary pause of customer disconnections and certain collection efforts and write-off processes after the implementation of AES Indiana's customer billing system upgrade in the fourth quarter of 2023. This has resulted in higher past due customer receivables as of December 31, 2024. AES Indiana currently anticipates reinstituting the customer disconnections process and collection efforts and write-off processes in the first quarter of 2025.
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,
2024 2023
(In Thousands)
Inventories
Fuel $ 50,842 $ 77,198
Materials and supplies, net 49,093 66,392
Total inventories $ 99,935 $ 143,590
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 3.8%, 3.7% and 3.8% during 2024, 2023 and 2022, respectively. Depreciation expense was $268.6 million, $244.8 million, and $247.5 million for the years ended December 31, 2024, 2023 and 2022, 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.
AES Indiana may receive contributions in aid of construction ("CIAC") from customers that are intended to defray all or a portion of the costs for certain capital projects, to the extent the project does not benefit regulated customers in general. AES Indiana accounts for CIAC as a reduction to property, plant and equipment.
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 6.6%, 7.1% and 5.4% during 2024, 2023 and 2022, respectively. AFUDC equity and AFUDC debt were as follows for the years ended December 31, 2024, 2023 and 2022:
2024 2023 2022
(In Thousands)
AFUDC equity $ 3,991 $ 9,315 $ 4,784
AFUDC debt $ 32,240 $ 13,739 $ 8,215
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 $5.5 billion and $4.5 billion as of December 31, 2024 and 2023, respectively. As of December 31, 2024 and 2023, AES Indiana had $230.4 million and $259.9 million, respectively, of long-term regulatory assets associated with retirement costs for Petersburg Units 1 and 2 and the conversion of Petersburg Units 3 and 4. AES Indiana does not believe any of these assets are currently impaired. In making this assessment, AES Indiana considers such factors as: the overall condition and generating and distribution capacity of the assets; the expected ability to recover additional expenditures in the assets; the anticipated demand and relative pricing of retail electricity in its service territory and wholesale electricity in the region; and the cost of fuel.
Intangible Assets
Finite-lived intangible assets primarily include capitalized software and project development intangible assets amortized on a straight-line basis over their useful lives. The following table presents information related to the Company's intangible assets, including the gross amount capitalized and related amortization:
December 31,
$ in thousands
Weighted average amortization periods (in years)
2024 2023
Capitalized software
8 $ 280,020 $ 261,872
Project development intangible assets
28 83,149 84,097
Other
Various
797 797
Less: Accumulated amortization
(131,756) (111,110)
Intangible assets - net
$ 232,210 $ 235,656
For the Years Ended December 31,
2024 2023 2022
Amortization expense
$ 26,193 $ 14,570 $ 10,122
Estimated future amortization
Years ending December 31,
2025 $ 26,372
2026 28,158
2027 28,158
2028 28,158
2029 28,158
Total
$ 139,004
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 $2.5 million and $7.1 million as of December 31, 2024 and 2023, respectively, which are recorded within Prepayments and other current assets" and "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, 2024 and 2023. See Note 11, "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 5, 2027, and the contract
with the clerical-technical unit expires on February 12, 2026. Additionally, AES Indiana has long-term coal contracts with two suppliers, and substantially all of AES Indiana's coal is currently mined in the state of Indiana.
Financial Derivatives
All derivatives are recognized as either assets or liabilities in the balance sheets and are measured at fair value. Changes in the fair value are recorded in earnings unless the derivative is designated as a cash flow hedge of a forecasted transaction or it qualifies for the normal purchases and sales exception.
AES Indiana has contracts involving the physical delivery of energy and fuel. Because some of these contracts qualify for the normal purchases and normal sales scope exception in ASC 815, AES Indiana has elected to account for them as accrual contracts, which are not adjusted for changes in fair value. AES Indiana has or previously had FTRs and forward power contracts that do not qualify for hedge accounting or the normal purchases and sales exceptions under ASC 815. Accordingly, FTRs are recorded at fair value when acquired and subsequently amortized over the annual period as they are used. FTRs are initially recorded at fair value using the income approach. The forward power contracts are recorded at fair value with changes in the fair value charged or credited to the Consolidated Statements of Operations in the period in which the change occurred. Forward power contracts are fair valued using the market approach.
Leases
The Company has finance leases primarily for land in which the Company is the lessee. Operating leases with an initial term of 12 months or less are not recorded on the balance sheet, but are expensed on a straight-line basis over the lease term. The Company’s leases do not contain any material residual value guarantees, restrictive covenants or subleases.
Right-of-use assets represent our right to use an underlying asset for the lease term while lease liabilities represent our obligation to make lease payments arising from the lease. Right-of-use assets and lease liabilities are recognized on commencement of the lease based on the present value of lease payments over the lease term. Generally, the rate implicit in the lease is not readily determinable; as such, we use the incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The Company determines discount rates based on its existing credit rates of its borrowings, which are then adjusted for the appropriate lease term. The right-of-use asset also includes any lease payments made and excludes lease incentives that are paid or payable to the lessee at commencement. The lease term includes periods covered by the option to extend if it is reasonably certain that the option will be exercised and periods covered by an option to terminate if it is reasonably certain that the option will not be exercised.
ARO
AES Indiana records the fair value of a liability for a legal obligation to retire an asset in the period in which the obligation is incurred. When a new liability is recognized, AES Indiana capitalizes the costs of the liability by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the obligation, AES Indiana eliminates the liability and, based on the actual cost to retire, may incur a gain or loss.
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 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 $27.4 million, $7.5 million and $5.9 million for the years ended December 31, 2024, 2023 and 2022, 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 May 2024. AES Indiana is permitted to recover actual costs of power purchased and fuel consumed, subject to certain restrictions. This is accomplished through quarterly FAC proceedings, in which AES Indiana estimates the amount of fuel and power purchased costs in future periods. Through these proceedings, AES Indiana is also permitted to recover, in future rates, underestimated fuel and power purchased costs from prior periods, subject to certain restrictions, and therefore the over or underestimated costs are deferred or accrued and amortized into fuel expense in the same period that AES Indiana’s rates are adjusted. See also Note 2, “Regulatory Matters” for a discussion of other costs that AES Indiana is permitted to recover through periodic rate adjustment proceedings and the status of current rate adjustment proceedings.
In addition, AES Indiana is one of many transmission system owner members of MISO, a RTO which maintains functional control over the combined transmission systems of its members and manages one of the largest energy markets in the U.S. See Note 14, "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.
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 9, "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 non-current 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 8, "Income Taxes" for additional information.
Repair and Maintenance Costs
Repair and maintenance costs are expensed as incurred.
Per Share Data
IPALCO owns all of the outstanding common stock of AES Indiana. AES Indiana does not report earnings on a per-share basis.
New Accounting Pronouncements
The following table provides a brief description of recent accounting pronouncements that had an impact on the Company’s Financial Statements. Accounting pronouncements not listed below were assessed and determined to be either not applicable or did not have a 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.
December 31, 2024 AES Indiana adopted this standard on a retrospective basis. Please refer to Note 13, "Business Segments" for impact.
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.
2023-09 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.
2024-03: Income Statement-Reporting Comprehensive Income-Expense Disaggregation Disclosures (Subtopic 220-40) The amendments in this Update require disclosure, in the notes to financial statements, of specified information about certain costs and expenses. The amendments require that at each interim and annual reporting period an entity:
1. Disclose the amounts of (a) purchases of inventory, (b) employee compensation, (c) depreciation, (d) intangible asset amortization, and (e) depreciation, depletion, and amortization recognized as part of oil- and gas-producing activities (DD&A) (or other amounts of depletion expense) included in each relevant expense caption. A relevant expense caption is an expense caption presented on the face of the income statement within continuing operations that contains any of the expense categories listed in (a)-(e).
2. Include certain amounts that are already required to be disclosed under current generally accepted accounting principles (GAAP) in the same disclosure as the other disaggregation requirements.
3. Disclose a qualitative description of the amounts remaining in relevant expense captions that are not separately disaggregated quantitatively.
4. Disclose the total amount of selling expenses and, in annual reporting periods, an entity’s definition of selling expenses. The date for each amendment in this Update is effective for fiscal years beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. Early adoption is permitted 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 OUCC, and other interested stakeholders. Pursuant to statute, the IURC is to conduct a periodic review of the basic rates and charges of all Indiana utilities at least once every four years, but the IURC has the authority to review the rates of any Indiana utility at any time. Once set, the basic rates and charges authorized do not assure the realization of a fair return on the fair value of property.
AES Indiana’s declining block rate structure generally provides for residential and commercial customers to be charged a lower per kWh rate at higher consumption levels. Therefore, as volumes increase, the weighted average price per kWh decreases. Numerous factors including, but not limited to, weather, inflation, customer growth and usage, the level of actual operating and maintenance expenditures, fuel costs, generating unit availability, and capital expenditures including those required by environmental regulations can affect the return realized.
Regulatory Rate Review and Base Rate Orders
On April 17, 2024, the IURC issued an order (the “2024 Base 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 Base 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 4.9% on a rate base of approximately $3.5 billion. Updated customer rates and charges became effective on May 9, 2024. The 2024 Base Rate Order provides that annual wholesale margins earned above (or below) the benchmark of $28.6 million shall be passed back (or charged) to customer rates through a rate adjustment mechanism. Similarly, the 2024 Base Rate Order provides that all capacity sales and expenses above (or below) an expense benchmark of $19.0 million shall be passed back (or charged) to customer rates through a rate adjustment mechanism.
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 power purchased 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 year 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 calendar years 2023 and 2024.
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, recover costs (including a return) on certain investments in renewable and battery energy storage projects, and recover the retail portion of costs for generation consumables and environmental allowances. The total amount of AES Indiana’s environmental equipment and renewable projects approved for ECCRA recovery as of December 31, 2024 was $437.5 million. The jurisdictional revenue requirement approved by the IURC to be included in AES Indiana’s rates for the twelve-month period ending February 2025 is a net cost to customers of $41.1 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 2024, 2023 and 2022, AES Indiana also had the ability to receive financial incentives, dependent upon the level of success of the programs. Financial incentives included in rates for the years ended December 31, 2024, 2023 and 2022 were $3.8 million, $2.7 million and $8.3 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 financial 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 financial 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 31, 2024 asking for approval of a two-year DSM plan for the 2025-2026 program years. On January 8, 2025, the IURC approved a two-year DSM plan for AES Indiana through 2026. The approval included cost recovery of programs as well as financial 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 was previously committed under a power purchase agreement to purchase all wind-generated electricity through 2029 from a wind project in Indiana (the "Hoosier Wind Project"), which had a maximum output capacity of approximately 100 MW. AES Indiana acquired the Hoosier Wind Project in February 2024, and the existing power purchase agreement was terminated upon closing (see "IRP Filings and Replacement Generation - Hoosier Wind Project" below for further information). AES Indiana is currently committed under another agreement to purchase all wind-generated electricity through 2031 from a project in Minnesota, which 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, 2024. 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, 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. In addition, there is a nine-month rate freeze after new basic rates are implemented. Because of this, there was no TDSIC rate adjustment filed in 2024 due to the 2024 Base Rate Order. However, a compliance filing was made after the 2024 Base Rate Order to update the TDSIC rates for projects that rolled into base rates. The total amount of AES Indiana’s equipment net of depreciation, including carrying costs, approved for TDSIC recovery as of December 31, 2024 was $138.4 million. There are also $340.7 million of TDSIC capital costs that were rolled into base rates per the 2024 base rate Order, which are no longer in the TDSIC rider. The jurisdictional revenue requirement approved by the IURC to be included in AES Indiana’s rates for the twelve-month period ending October 2025 is a net cost to customers of $17.7 million. These amounts are significantly lower than prior TDSIC periods as a result of having a majority of the TDSIC projects rolled into AES Indiana's basic rates and charges effective May 9, 2024 as a result of the 2024 Base Rate Order.
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.
2025 IRP
In January 2025, AES Indiana initiated its 2025 IRP process with external stakeholders. The first of five public advisory meetings took place on January 29, 2025 and will continue through most of 2025, with AES Indiana anticipating it will submit its final 2025 IRP, shaped by stakeholder feedback, to the IURC in November 2025.
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 (see "Petersburg Repowering" below for further information). Additionally, AES Indiana plans to add up to 1,300 MW of wind, solar, and battery energy storage by 2027.
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. AES Indiana retired 230 MW Petersburg Unit 1 in May 2021 and 415 MW Petersburg Unit 2 in June 2023. 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.
As a result of the plans to retire Petersburg Units 1 and 2, AES Indiana recorded $0.7 million and $2.1 million of obsolescence losses during the periods ended December 31, 2023 and 2022, 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.
AES Indiana had $129.4 million and $259.9 million of Petersburg Units 1 and 2 retirement costs, net of accumulated amortization, recorded as long-term regulatory assets as of December 31, 2024 and 2023, respectively.
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 (the "Petersburg Repowering Project") and to recover costs through future rates. On November 6, 2024, the IURC issued an order approving the CPCN which includes: (1) approval of the Petersburg Repowering Project and (2) approval of the accounting and ratemaking requests associated with the Petersburg Repowering Project including AES Indiana's creation of regulatory assets for the remaining net book value of the Petersburg Units 3 and 4 retired assets, and certain materials and supplies inventories that will no longer be used, and recovery of certain other costs.
The Company has engaged a vendor through an EPC Agreement for the turn-key engineering, procurement, and construction services of the project. This agreement has been approved by the IURC and preconstruction stage work is ongoing. The on-site construction work for the conversion of Unit 3 is expected to begin in February 2026 and be completed by June 2026, and for Unit 4 is expected to begin in June 2026 and be completed by December 2026.
As a result of the resolutions from this order, AES Indiana has $101.0 million of projected Petersburg Units 3 and 4 retirement costs (including MATS equipment which was approved for recovery in Cause No. 44242 - CPCN to construct, install and use clean coal technology), and $20.4 million of materials and supplies inventories that will no longer be used, upon retirement, recorded as long-term regulatory assets as of December 31, 2024.
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 VIE 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 associated with the transaction, primarily consisting of a development project intangible asset (see Note 1, "Overview and Summary of Significant Accounting Policies - Intangible Assets"). Total consideration included a future payment contingent on certain future costs incurred by the project and a $3.2 million contingent liability was recorded. During 2022, this liability was remeasured due to updated cost estimates and was reduced to $0.0 million.
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. 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. Construction was completed for the remaining MW and the project achieved full commercial operations in May 2024. Upon the final stage of the project being placed in service, the Company recognized $21.4 million of earnings from tax attributes using the HLBV method.
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 45 MW (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 VIE 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 placed in service during the first quarter of 2025.
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.
Crossvine Project
On August 1, 2024, AES Indiana executed an agreement for the acquisition of a development stage solar and BESS project to be developed in Dubois County, Indiana. AES Indiana plans to build 85 MW of solar and 85 MW (340 MWh) of energy storage which is expected to be completed in mid-2027. This transaction is subject to approval from the IURC. AES Indiana filed a petition and case-in-chief with the IURC in August 2024, seeking a CPCN for this project.
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, Pike County BESS Project, Petersburg Energy Center Project, Hardy Hills Solar Project and Petersburg Repowering 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 $4.6 million and $5.4 million as of December 31, 2024 and 2023, respectively, which is currently being recovered through base rates under the 2024 Base Rate Order.
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 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 Base 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 Base Rate Order, this Joint Petition was dismissed with prejudice.
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 and liabilities 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 35 years.
The following table presents AES Indiana's regulatory assets and liabilities:
December 31,
Type of Recovery Recovery Period 2024 2023
(In Thousands)
Regulatory assets, current:
Undercollections of rate riders B 2025 $ 115,911 $ 75,416
Unamortized reacquisition premium on debt B 2025 - 188
Costs being recovered through basic rates and charges A/B 2025 18,417 13,815
Total regulatory assets, current 134,328 89,419
Regulatory assets, non-current:
Unrecognized pension and other
postretirement benefit plan costs A/B Ongoing 124,176 115,847
Deferred MISO costs B 2026 7,699 21,091
Unamortized Petersburg Unit 4 carrying
charges and certain other costs A 2026 1,757 2,812
Unamortized reacquisition premium on debt B Ongoing 12,832 13,379
Environmental costs A/B 2044 65,186 66,837
COVID-19 costs B 2028 3,194 5,426
Major storm damage B Undetermined 8,883 1,493
TDSIC costs A 2060 52,469 35,979
Petersburg Unit 1 and 2 retirement costs A 2033 129,375 259,892
Petersburg Unit 3 and 4 retirement costs A Various 100,982 -
Petersburg Unit 3 and 4 materials and supplies B Undetermined 20,369 -
Hardy Hills Solar costs A/B 2059 15,255 6,774
Petersburg Energy Center costs A/B Undetermined 6,361 2,469
Pike County BESS costs A/B 2045 5,991 2,623
Hoosier Wind B 2039 53,394 -
ACE Costs A/B 2028 7,607 -
Fuel costs B Not applicable - 4,275
Other miscellaneous B Various 3,499 2,887
Total regulatory assets, non-current 619,029 541,784
Total regulatory assets $ 753,357 $ 631,203
Regulatory liabilities, current:
Overcollections and other credits being passed
to customers through rate riders B 2025 $ 8,959 $ 19,649
FTRs B 2025 2,956 3,722
Total regulatory liabilities, current 11,915 23,371
Regulatory liabilities, non-current:
ARO and accrued asset removal costs B Not applicable 344,506 451,886
Deferred income taxes payable to customers through rates B Ongoing 58,378 74,796
Hardy Hills sponsor investment tax credit B Undetermined 991 542
Environmental Compliance Rider B Undetermined 146 -
Total regulatory liabilities, non-current 404,021 527,224
Total regulatory liabilities $ 415,936 $ 550,595
A - Recovery of incurred costs plus rate of return.
B - Recovery of incurred costs without a rate of return.
C - Recovery not yet determined, but recovery is probable of occurring in future rate proceedings.
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, (v) overcollection of MISO rider costs, and (vi) 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) Green Power, (ii) deferred fuel costs, and (iii) FTRs.
Deferred Fuel
Deferred fuel costs are a component of current 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 power purchased costs in AES Indiana’s FAC and actual fuel and power purchased costs. AES Indiana is generally permitted to recover underestimated fuel and power purchased 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 2024 Base Rate Order. Amortization periods vary, ranging from 1 to 19 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 35 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 assets were reclassified from net property, plant and equipment to a long-term regulatory asset. See "IRP Filings and Replacement Generation" above for additional discussion.
Petersburg Unit 3 and 4 Retirement Costs and Materials and Supplies
On November 6, 2024, the IURC issued an order approving the CPCN to convert Petersburg Units 3 and 4 from coal to natural gas. As a result of this order and in accordance with ASC 980, it was determined that the conversion of Petersburg Units 3 and 4 from coal to natural gas became probable, and the projected remaining net book value of the Petersburg Units 3 and 4 retired assets of $101.0 million and materials and supplies inventories that will no longer be used of $20.4 million were reclassified from net property, plant and equipment and inventories, respectively, to long-term regulatory assets. 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 35 years. Amortization of the project development costs began in March 2024 along with ECR-37 rates.
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 begin in March 2025 along with ECR-38 rates.
Hoosier Wind
As discussed above in "IRP Filings and Replacement Generation", AES Indiana acquired the Hoosier Wind Project on February 29, 2025. The transaction was accounted for as an asset acquisition and a portion of the consideration transferred 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. This regulatory asset also includes deferred operation and maintenance and carrying costs on AES Indiana's investment in accordance with the approved CPCN.
ACE Costs
These consist of one-time implementation costs and Software as a Service costs related to the ACE Project. The IURC authorized recovery of one-time implementation costs over 4 years and Software as a Service costs over 10 years in the 2024 Base Rate Order.
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 5, "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 $58.3 million and $74.8 million as of December 31, 2024 and 2023, respectively.
3. PROPERTY, PLANT AND EQUIPMENT
The original cost of property, plant and equipment segregated by functional classifications follows:
As of December 31,
2024 2023
(In Thousands)
Production $ 4,303,827 $ 3,942,052
Transmission 516,178 487,527
Distribution 2,562,827 2,304,526
General plant 251,715 348,338
Total property, plant and equipment 7,634,547 7,082,443
Less: Accumulated depreciation 3,071,167 2,954,555
4,563,380 4,127,888
Construction work in progress 897,863 359,014
Property, plant and equipment, net
$ 5,461,243 $ 4,486,902
Substantially all of AES Indiana’s property is subject to a $2,763.8 million direct first mortgage lien, as of December 31, 2024, securing AES Indiana’s first mortgage bonds.
4. 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 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 following is a roll forward of the ARO legal liabilities for the periods indicated:
2024 2023
(In Thousands)
Balance as of January 1 $ 249,930 $ 218,729
Liabilities incurred 9,060 17,080
Liabilities settled (14,539) (11,902)
Revisions to cash flow and timing estimates 117,743 12,921
Accretion expense 16,266 13,102
Balance as of December 31 $ 378,460 $ 249,930
Less: ARO liabilities, current 32,161 -
ARO liabilities, non-current $ 346,299 $ 249,930
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. AES Indiana recorded revisions to its ARO liabilities in 2024 primarily to reflect revisions to cash flow estimates due to increases in closure costs and groundwater treatment measures for ash ponds and landfills. As of December 31, 2024 and 2023, AES Indiana did not have any assets that are legally restricted for settling its ARO liabilities.
5. FAIR VALUE
The fair value of current financial assets and liabilities approximate their reported carrying amounts. The estimated fair values of AES Indiana’s assets and liabilities have been determined using available market information.
Because these amounts are estimates and based on hypothetical transactions to sell assets or transfer liabilities, the use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.
Fair Value Hierarchy and Valuation Techniques
ASC 820 defines and establishes a framework for measuring fair value and expands disclosures about fair value measurements for financial assets and liabilities that are adjusted to fair value on a recurring basis and/or financial assets and liabilities that are measured at fair value on a nonrecurring basis, which have been adjusted to fair value during the period. In accordance with ASC 820, AES Indiana has categorized its financial assets and liabilities that are adjusted to fair value, based on the priority of the inputs to the valuation technique, following the three-level fair value hierarchy prescribed by ASC 820 as follows:
Level 1 - unadjusted quoted prices for identical assets or liabilities in an active market;
Level 2 - inputs from quoted prices in markets where trading occurs infrequently or quoted prices of instruments with similar attributes in active markets; and
Level 3 - unobservable inputs reflecting management’s own assumptions about the inputs used in pricing the asset or liability.
Whenever possible, quoted prices in active markets are used to determine the fair value of AES Indiana’s financial instruments. AES Indiana’s financial instruments are not held for trading or other speculative purposes. The estimated fair value of financial instruments has been determined by using available market information and appropriate valuation methodologies. However, considerable judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that AES Indiana could realize in a current market exchange. The use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.
Financial Assets
FTRs
In connection with AES Indiana’s participation in MISO, in the second quarter of each year AES Indiana is granted financial instruments that can be converted into cash or FTRs based on AES Indiana’s forecasted peak load for the period. FTRs are used in the MISO market to hedge AES Indiana’s exposure to congestion charges, which result from constraints on the transmission system. AES Indiana’s FTRs are valued at the cleared auction prices for FTRs in MISO’s annual auction. Because of the infrequent nature of this valuation, the fair value assigned to the FTRs is considered a Level 3 input under the fair value hierarchy required by ASC 820. An offsetting regulatory liability has been recorded as these revenue or costs will be flowed through to customers through the FAC. As such, there is no impact on AES Indiana’s Consolidated Statements of Operations.
Forward Power Contracts
As of December 31, 2024 and 2023, 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 6, "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, 2024 and 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 December 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 $ - $ - $ 1,526 $ 1,526 $ - $ - $ 1,388 $ 1,388
Total financial assets measured at fair value $ - $ - $ 1,526 $ 1,526 $ - $ - $ 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):
Reconciliation of Financial Instruments Classified as Level 3
(In Thousands)
Balance at January 1, 2023 $ 7,545
Issuances 3,624
Settlements (9,781)
Balance at December 31, 2023 1,388
Issuances 3,811
Settlements (3,673)
Balance at December 31, 2024 $ 1,526
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, 2024 December 31, 2023
Face Value Fair Value Face Value Fair Value
(In Thousands)
Fixed-rate $ 2,763,800 $ 2,555,449 $ 2,153,800 $ 2,020,997
Variable-rate 500,000 500,000 455,000 455,000
Total indebtedness $ 3,263,800 $ 3,055,449 $ 2,608,800 $ 2,475,997
The difference between the face value and the carrying value of this indebtedness represents the following:
•unamortized deferred financing costs of $26.4 million and $20.2 million at December 31, 2024 and 2023, respectively; and
•unamortized discounts of $8.1 million and $6.4 million at December 31, 2024 and 2023, respectively.
6. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
AES Indiana uses derivatives principally to manage the risk of price changes for power purchased. 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, 2024, AES Indiana's outstanding derivative instruments were as follows:
Commodity Accounting Treatment (a)
Unit Notional
(in thousands) Sales
(in thousands) Net Notional
(in thousands)
FTRs Not Designated MWh 4,410 - 4,410
(a) Refers to whether the derivative instruments have been designated as a cash flow hedge.
Derivatives Not Designated as Hedge
AES Indiana's FTRs and forward power contracts do not qualify for hedge accounting or the normal purchases and sales exceptions under ASC 815. Accordingly, FTRs are recorded at fair value using the income approach when acquired and subsequently amortized over the annual period as they are used. The forward power contracts are recorded at fair value using the market approach with changes in the fair value charged or credited to the Consolidated Statements of Operations in the period in which the change occurred. This is commonly referred to as "MTM accounting." Realized gains and losses on the forward power contracts are included in future FAC filings, therefore any realized and unrealized gains and losses are deferred as regulatory liabilities or regulatory assets.
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, 2024 and 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):
December 31,
Commodity Hedging Designation Balance sheet classification 2024 2023
FTRs Not a Cash Flow Hedge Prepayments and other current assets $ 1,526 $ 1,388
7. DEBT
The following table presents AES Indiana’s long-term debt:
December 31,
Series Due 2024 2023
(In Thousands)
AES Indiana first mortgage bonds:
3.125% (1)
December 2024 $ - $ 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 (8,093) (6,449)
Deferred financing costs (25,469) (19,058)
Total AES Indiana first mortgage bonds 2,730,238 2,128,293
Total consolidated AES Indiana long-term debt 2,730,238 2,128,293
Less: current portion of long-term debt 39,910 40,000
Net consolidated AES Indiana long-term debt(3)
$ 2,690,328 $ 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.
(3)Excludes $0.2 million and $0.0 million (current) and $86.9 million and $17.8 million (non-current) finance lease liabilities included in the respective short and long-term debt line items on the Consolidated Balance Sheets as of December 31, 2024 and 2023, respectively. See Note 15, "Leases" for further information.
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, 2024 and 2023, AES Indiana had $100.0 million and $155.0 million in outstanding borrowings on the committed Credit Agreement, respectively.
Debt Maturities
Maturities on long-term indebtedness subsequent to December 31, 2024 are as follows:
Year Amount
(In Thousands)
2025 $ 40,000
2026 90,000
2027 -
2028 -
2029 55,000
Thereafter 2,578,800
2,763,800
Unamortized discounts (8,093)
Deferred financing costs, net (25,469)
Total long-term debt $ 2,730,238
Significant Transactions
AES Indiana Term Loans
In August 2024, AES Indiana entered into an unsecured $400 million 364-day term loan agreement ("$400 million Term Loan Agreement"), which can be drawn in two tranches. AES Indiana drew $300 million at closing and drew the remaining $100 million in October 2024, with the proceeds being used for general corporate purposes. This agreement matures on August 13, 2025, and bears interest at variable rates as described in the $400 million Term Loan Agreement. The $400 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 the $400 million Term Loan Agreement as short-term indebtedness as it matures August 2025. Management plans to repay the $400 million Term Loan Agreement through a combination of funds from debt financings and parent equity capital contributions.
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 (described below), outstanding borrowings on the Credit Agreement and for general corporate purposes.
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 was set to mature on November 19, 2024, but was fully repaid in March 2024.
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
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.
Other
In February 2024, AES Indiana received a $92.0 million short-term loan from AES. This loan was fully repaid in March 2024.
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 29, 2026. In February 2024, AES Indiana received an order from the IURC granting AES Indiana 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 December 31, 2024. 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 $0.0 million remains available under the order as of December 31, 2024. 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, 2024. 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.
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 $2,763.8 million as of December 31, 2024. 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, 2024.
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.
8. 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 2020, but is open for all subsequent periods. AES Indiana made tax sharing payments to IPALCO of $22.9 million, $0.0 million and $39.5 million in 2024, 2023 and 2022, respectively.
Income Tax Provision
Federal and state income taxes charged to income are as follows:
2024 2023 2022
(In Thousands)
Components of income tax expense:
Current income taxes:
Federal $ 23,166 $ 1,816 $ 31,286
State 5,626 268 8,185
Total current income taxes 28,792 2,084 39,471
Deferred income taxes:
Federal 12,821 17,631 (6,822)
State (2,850) 5,951 238
Total deferred income taxes 9,971 23,582 (6,584)
Total income tax expense $ 38,763 $ 25,666 $ 32,887
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:
2024 2023 2022
Federal statutory tax rate 21.0 % 21.0 % 21.0 %
State income tax, net of federal tax benefit 3.9 % 3.9 % 3.9 %
Depreciation flow through and amortization (7.4) % (8.0) % (5.7) %
AFUDC - equity 0.4 % (0.2) % 0.7 %
Noncontrolling interests in subsidiaries 4.0 % 5.6 % - %
Other - net 0.2 % (0.1) % 0.3 %
Effective tax rate 22.1 % 22.2 % 20.2 %
Deferred Income Taxes
The significant items comprising AES Indiana’s net accumulated deferred tax liability recognized on the Consolidated Balance Sheets as of December 31, 2024 and 2023 are as follows:
2024 2023
(In Thousands)
Deferred tax liabilities:
Relating to utility property, net $ 438,018 $ 409,675
Regulatory assets recoverable through future rates 112,389 108,823
Right of use asset 17,670 -
Other 7,175 7,975
Total deferred tax liabilities 575,252 526,473
Deferred tax assets:
Investment tax credit 4 5
Regulatory liabilities including ARO 170,236 168,619
Employee benefit plans 265 -
Investments in tax partnerships 6,649 2,483
Operating loss carryforwards - 9,230
Lease liability 18,169 -
Other 10,980 3,579
Total deferred tax assets 206,303 183,916
Deferred income tax liability - net $ 368,949 $ 342,557
Uncertain Tax Positions
Tax years subsequent to 2020 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, 2024, 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.
9. 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 $3.9 million, $3.7 million and $3.6 million for 2024, 2023 and 2022, 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 $2.7 million, $2.5 million and $2.1 million for 2024, 2023 and 2022, respectively.
Defined Benefit Plans
Approximately 64% of AES Indiana’s active employees are covered by the qualified Defined Benefit Pension Plan; while approximately 13% 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, 2024 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 120 active employees and 27 retirees (including spouses) were receiving such benefits or entitled to future benefits as of January 1, 2024. The plan is unfunded. These postretirement health care benefits and the related unfunded obligation of $3.0 million and $3.0 million at December 31, 2024 and 2023, 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,
2024 2023
(In Thousands)
Change in benefit obligation:
Projected benefit obligation at January 1 $ 549,546 $ 577,530
Service cost 5,011 5,189
Interest cost 26,958 29,818
Actuarial (gain) / loss (18,044) 9,681
Amendments (primarily increases in pension bands) 7,948 653
Benefits paid (37,166) (73,325)
Projected benefit obligation at December 31 534,253 549,546
Change in plan assets:
Fair value of plan assets at January 1 590,819 611,125
Actual return on plan assets 5,526 52,905
Employer contributions 15 114
Benefits paid (37,166) (73,325)
Fair value of plan assets at December 31 559,194 590,819
Funded status $ 24,941 $ 41,273
Amounts recognized in the statement of financial position:
Non-current assets $ 24,941 $ 41,273
Net amount recognized at end of year $ 24,941 $ 41,273
Sources of change in regulatory assets(1):
Prior service cost arising during period $ 7,948 $ 653
Net loss / (gain) arising during period 6,204 (10,117)
Amortization of prior service cost (1,900) (2,172)
Amortization of loss (4,828) (6,145)
Total recognized in regulatory assets $ 7,424 $ (17,781)
Amounts included in regulatory assets:
Net loss $ 116,674 $ 115,297
Prior service cost 16,183 10,136
Total amounts included in regulatory assets $ 132,857 $ 125,433
(1)Amounts that would otherwise be charged/credited to Accumulated Other Comprehensive Income or Loss upon application of ASC 715, “Compensation - Retirement Benefits,” are recorded as a regulatory asset or liability because AES Indiana has historically recovered and currently recovers pension and other postretirement benefit expenses in rates. These are unrecognized amounts not yet recognized as components of net periodic benefit costs.
Significant Loss / (Gain) Related to Changes in the Benefit Obligation for the Period
As shown in the table above, an actuarial gain of $18.0 million and an actuarial loss of $9.7 million for the year ended December 31, 2024 and December 31, 2023, 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 2024 net actuarial loss of $6.2 million recognized in regulatory assets is comprised of two parts: (1) a $18.0 million pension liability actuarial gain primarily due to an increase in the discount rate used to value pension liabilities; and (2) a $24.2 million pension asset actuarial loss primarily due to lower than expected return on assets. The unrecognized net loss of $116.7 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. 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 12.11 years based on estimated demographic data as of December 31, 2024. The projected benefit obligation of $534.3 million less the fair value of assets of $559.2 million results in an overfunded status of $24.9 million at December 31, 2024.
Pension benefits for
years ended December 31,
2024 2023 2022
(In Thousands)
Components of net periodic benefit cost / (credit):
Service cost $ 5,011 $ 5,189 $ 8,949
Interest cost 26,958 29,818 18,099
Expected return on plan assets (29,774) (33,107) (35,656)
Amortization of prior service cost 1,900 2,172 2,589
Amortization of actuarial loss 4,828 6,145 2,424
Amortization of settlement loss - - 199
Net periodic benefit cost / (credit) 8,923 10,217 (3,396)
Less: amounts capitalized 1,780 1,689 (316)
Amount charged to expense $ 7,143 $ 8,528 $ (3,080)
Rates relevant to each year’s expense calculations:
Discount rate - defined benefit pension plan 5.15 % 5.41 % 2.83 %
Discount rate - supplemental retirement plan 5.66 % 5.32 % 2.62 %
Expected return on defined benefit pension plan assets 5.20 % 5.60 % 4.45 %
Expected return on supplemental retirement plan assets 6.35 % 6.45 % 5.50 %
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 2024, pension expense / (income) was determined using an assumed long-term rate of return on plan assets of 5.20% for the Defined Benefit Pension Plan and 6.35% for the Supplemental Retirement Plan. As of the December 31, 2024 measurement date, AES Indiana increased the discount rate from 5.15% to 5.66% for the Defined Benefit Pension Plan and decreased the discount rate from 5.66% to 5.16% for the Supplemental Retirement Plan. The discount rate assumptions affect the pension expense / (income) determined for 2025. In addition, AES Indiana increased the expected long-term rate of return on plan assets from 5.20% to 5.75% for the Defined Benefit Pension Plan and decreased from 6.35% to 6.15% for the Supplemental Retirement Plan for 2025. The expected long-term rate of return assumptions affect the pension expense / (income) determined for 2025. The effect on 2025 total pension expense / (income) of a 25 basis point increase and decrease in the assumed discount rate is $(0.7) million and $0.7 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, 2024. 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, 2024. Pension costs are determined for the following year based on the market value of pension plan assets, expected employer contributions, a discount rate used to determine the projected benefit obligation and the expected long-term rate of return on plan assets.
Fair value is defined under ASC 820 as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (i.e., an exit price). The fair value hierarchy prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets and liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).
Purchases and sales of securities are recorded on a trade-date basis. Interest income is recorded as earned. Dividends are recorded on the ex-dividend date. Net appreciation includes the Pension Plans’ gains and losses on investments bought and sold, as well as held, during the year.
A description of the valuation methodologies used for each major class of assets and liabilities measured at fair value follows:
•The non-qualified Supplemental Retirement Plan investments have quoted market prices and are categorized as Level 1 in the fair value hierarchy.
•The qualified Defined Benefit Pension Plan investments in common collective trusts are valued based on the daily net asset value and are categorized as Level 2 in the fair value hierarchy, except for cash and cash equivalents which are categorized as level 1.
The primary objective of the Pension Plans’ is to provide a source of retirement income for its participants and beneficiaries, while the primary financial objective is to improve the funded status of the Pension Plans. A secondary financial objective is, where possible, to minimize pension expense volatility. The objective is based on a long-term investment horizon, so that interim fluctuations should be viewed with appropriate perspective. There can be no assurance that these objectives will be met.
In establishing AES Indiana’s expected long-term rate of return assumption, we utilize a methodology developed by the plan’s investment consultant who maintains a capital market assumption model that takes into consideration risk, return and correlation assumptions across asset classes. A combination of quantitative analysis of historical data and qualitative judgment is used to capture trends, structural changes and potential scenarios not reflected in historical data.
The result of the analyses is a series of inputs that produce a picture of how the plan consultant believes portfolios are likely to behave through time. Capital market assumptions are intended to reflect the behavior of asset classes observed over several market cycles. Stress assumptions are also examined, since the characteristics of asset classes are constantly changing. A dynamic model is employed to manage the numerous assumptions required to estimate portfolio characteristics under different base currencies, time horizons and inflation expectations.
The Pension Plans’ consultant develops forward-looking, long-term capital market assumptions for risk, return and correlations for a variety of global asset classes, interest rates and inflation. These assumptions are created using a combination of historical analysis, current market environment assessment and by applying the consultant’s own judgment. The consultant then determines an equilibrium long-term rate of return. AES Indiana then takes into consideration the investment manager/consultant expenses, as well as any other expenses expected to be paid out of the Pension Plans’ trust. Finally, AES Indiana has the Pension Plans’ actuary perform a tolerance test of the consultant’s equilibrium expected long-term rate of return. AES Indiana uses an expected long-term rate of return compatible with the actuary’s tolerance level.
The following table summarizes AES Indiana’s target pension plan allocation for 2024:
Asset Category: Target Allocations
Equity Securities 13.5%
Debt Securities 86.5%
Fair Value Measurements at
December 31, 2024
(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)
$ 76,939 $ 2,325 $ 74,614 14 %
Debt securities (b)
364,121 1,135 362,986 65 %
Government debt securities (c)
115,228 373 114,855 21 %
Total common collective trusts 556,288 3,833 552,455 100 %
Cash and cash equivalents (d)
2,906 2,906 - - %
Total pension plan assets $ 559,194 $ 6,739 $ 552,455 100 %
(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, 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.
Pension Funding
AES Indiana contributed $0.0 million, $0.1 million, and $0.4 million to the Pension Plans in 2024, 2023 and 2022, 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 89%. 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 $5.6 million in 2025 (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 2025. 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, 2024, 2023 and 2022 were $37.2 million, $73.3 million and $38.6 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)
2025 $ 39,526
2026 40,694
2027 41,020
2028 41,660
2029 41,681
2030 through 2034 205,297
10. EQUITY
Cumulative Preferred Stock
AES Indiana previously had five separate series of 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.
Paid in Capital and Capital Stock
During 2024 and 2022, AES Indiana received equity capital contributions of $225.0 million and $253.0 million, respectively, from IPALCO. The proceeds are intended primarily for funding needs related to AES Indiana’s capital expenditure program.
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, 2024.
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, 2024, 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 $400 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, 2024, 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, 2024, 2023 and 2022, AES Indiana declared dividends to its shareholder totaling $154.6 million, $140.2 million, and $127.2 million, respectively.
Equity Transactions with Noncontrolling Interests
The Hardy Hills Solar Project and the Pike County BESS Project are 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, AES Indiana, through a wholly-owned subsidiary, sold a noncontrolling interest in the Hardy Hills Solar Project to a tax equity investor. Through December 31, 2024, the tax equity investor has made total contributions of $126.2 million under the agreement, including $46.9 million contributed in May 2024 upon final completion of the project, and noncontrolling interest was recorded by AES Indiana at the amount of cash contributed.
On December 6, 2024, AES Indiana, through a wholly-owned subsidiary, sold a noncontrolling interest in the Pike County BESS Project to a tax equity investor. Through December 31, 2024, the tax equity investor made contributions of $38.1 million, recorded as Redeemable stock of subsidiaries on the Consolidated Balance Sheets at the amount of cash contributed. The redemption feature of the tax equity partnership agreement is contingent upon the underlying assets being placed in service by a guaranteed date. The Company has concluded it is probable that the project will be placed in service by the guaranteed date; therefore, the noncontrolling ownership interest is not probable of becoming redeemable and subsequent adjustments to the carrying value were not required.
11. 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, 2024, 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, power purchased and
related transportation $ 643.8 $ 176.8 $ 201.2 $ 171.7 $ 94.1
Other $ 227.5 $ 220.5 $ 2.8 $ 4.2 $ -
Purchase obligations:
Purchase commitments for coal, gas, power purchased and related transportation:
AES Indiana enters into long-term contracts for the purchase of coal, gas, power purchased 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, 2024, 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 6, "Derivative Instruments and Hedging Activities"), (iii) taxes (see Note 8, "Income Taxes"), (iv) pension and other postretirement employee benefit liabilities (see Note 9, "Benefit Plans") and (v) contingencies
(see Note 11, "Commitments and Contingencies"). See the indicated notes to the Financial Statements for additional information on the items excluded.
Contingencies
Subsidiary Guarantees
In connection with AES Indiana's renewable projects financed with a tax equity structure, AES Indiana has expressly undertaken limited obligations and commitments on behalf of certain of the Company's subsidiaries, which will only be effective or will be terminated upon the occurrence of future events. As of December 31, 2024, the maximum undiscounted potential exposure to tax equity financing related guarantees was $164.4 million.
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, 2024 and 2023.
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, 2024 and 2023.
NSR and other CAA NOVs
In October 2009, AES Indiana received a NOV and Finding of Violation from the EPA pursuant to the CAA Section 113(a). The NOV alleged violations of the CAA at AES Indiana’s three primarily coal-fired electric generating facilities at the time, dating back to 1986. The alleged violations primarily pertain to the PSD and non-attainment NSR requirements under the CAA. In addition, on October 1, 2015, AES Indiana received a NOV from the EPA pursuant to CAA Section 113(a) alleging violations of the CAA, the Indiana SIP, and the Title V operating permit related to alleged particulate matter and opacity violations at AES Indiana Petersburg Unit 3. Also, on February 5, 2016, the EPA issued a NOV pursuant to CAA Section 113(a) alleging violations of PSD, non-attainment NSR and other CAA regulations, the Indiana SIP, and the Title V operating permit at Petersburg Generating Station. On August 31, 2020, AES Indiana reached a settlement with the EPA, the DOJ and IDEM resolving the purported violations of the CAA with respect to the coal-fired generation units at AES Indiana's Petersburg location. The settlement agreement, in the form of a proposed judicial consent decree was approved and entered by the U.S. District Court for the Southern District of Indiana on March 23, 2021, and includes, among other items, the following requirements: annual caps on NOx and SO2 emissions and more stringent emissions limits than AES Indiana's prior Title V air permit; payment of civil penalties totaling $1.525 million (the payment of which was satisfied by AES Indiana in April 2021); a $5 million environmental mitigation project consisting of the construction and operation of a new, non-emitting source of generation at the site; expenditure of $0.325 million on a state-only environmentally
beneficial project to preserve local, ecologically-significant lands; and retirement of Units 1 and 2 prior to July 1, 2023 (which has occurred). AES Indiana previously had a contingent liability recorded related to these NSR and other CAA NOV matters.
12. 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 $11.6 million, $11.7 million, and $9.5 million in 2024, 2023 and 2022, respectively, and is recorded in “Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations. As of December 31, 2024 and 2023, AES Indiana had prepaid approximately $7.9 million and $7.5 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 $20.1 million, $19.0 million, and $25.2 million in 2024, 2023 and 2022, 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, 2024 and 2023, 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 $0.0 million and $5.1 million as of December 31, 2024 and 2023, respectively, which is recorded in “Taxes receivable” on the accompanying Consolidated Balance Sheets. See Note 8, "Income Taxes" for more information.
Long-term Compensation Plan
During 2024, 2023 and 2022, 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 2024, 2023 and 2022 was $0.5 million, $0.3 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 9, “Benefit Plans” for a description of benefits awarded to AES Indiana employees by AES under the RSP.
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, 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.
The following table provides a summary of our related party transactions:
Years Ended December 31,
2024 2023 2022
(In Millions)
Transactions included in Operation and Maintenance on the Consolidated Statements of Operations:
Charges from the Service Company
$ 85.2 $ 73.6 $ 60.1
Charges to the Service Company
$ 15.4 $ 11.9 $ 10.0
Services provided by other related parties
$ 6.7 $ 7.4 $ 5.7
Transactions primarily included in Property, plant and equipment, net and Intangible assets, net on the Consolidated Balance Sheets:
Charges from the Service Company
$ 15.9 $ 47.1 $ 22.7
Balances with related parties (included in Prepayments and other current assets and Accounts Payable on the Consolidated Balance Sheets):
At December 31, 2024 At December 31, 2023
Prepayments and other current assets
$ 13.3 $ -
Accounts payable
$ - $ 25.6
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 $72.9 million and $223.3 million to this vendor during 2024 and 2023, respectively, which is recorded primarily in "Property, plant and equipment, net" on the accompanying Consolidated Balance Sheets.
13. BUSINESS SEGMENTS
All of AES Indiana’s current business consists of the generation, transmission, distribution and sale of electric energy, and therefore AES Indiana has only one reportable segment, led by our Chief Executive Officer and Chief Financial Officer, who, collectively, are the Chief Operating Decision Maker. The primary segment performance measures are income / (loss) before income tax and net income / (loss) as management has concluded that these measures best reflect the underlying business performance of AES Indiana and are the most relevant measures considered in AES Indiana's internal evaluation of the financial performance of its segment. The Chief Operating Decision Maker uses income / (loss) before income tax and net income / (loss) in the annual budget and forecasting process, including making decisions on reinvesting profits to support AES Indiana’s growth. On a monthly basis, the Chief Operating Decision Maker reviews variances in budget versus actual results and monitors changes in forecasted results to assess the underlying operating performance and analyze risks and opportunities for AES Indiana. See Note 1, "Overview and Summary of Significant Accounting Policies" for further information on AES Indiana.
The following table provides information about AES Indiana’s business segment (in thousands):
2024 2023 2022
Revenue $ 1,643,793 $ 1,649,917 $ 1,791,711
Fuel 359,132 494,000 568,676
Power purchased 148,412 159,908 199,860
Operation and maintenance 475,778 477,497 493,454
Depreciation and amortization 329,468 287,863 266,504
Taxes other than income taxes 27,478 24,865 33,048
Allowance for equity funds used during construction (3,991) (9,315) (4,784)
Interest expense 129,023 99,051 87,428
Other segment items (a)
3,102 285 (15,337)
Income/(loss) before income tax 175,391 115,763 162,862
Income tax expense / (benefit) 38,763 25,666 32,887
Net income / (loss) $ 136,628 $ 90,097 $ 129,975
Capital expenditures (b)
$ 954,995 $ 902,705 $ 496,510
As of December 31,
Total assets $ 7,123,241 $ 6,129,581 $ 5,559,977
(a) Other segment items primarily includes other miscellaneous gains and losses in Other (expense) income, net.
(b) Capital expenditures includes $23,673 thousand, $0 thousand and $0 thousand of payments for financed capital expenditures in 2024, 2023 and 2022, respectively.
14. REVENUE
Revenue is primarily earned from retail and wholesale electricity sales and electricity transmission and distribution delivery services. Revenue is recognized upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Revenue is recorded net of any taxes assessed on and collected from customers, which are remitted to the governmental authorities.
Retail revenue - AES Indiana energy sales to utility customers are based on the reading of meters at the customer’s location that occurs on a systematic basis throughout the month. AES Indiana sells electricity directly to end-users, such as homes and businesses, and bills customers directly. Retail revenue have a single performance obligation, as the promise to transfer energy and other distribution and/or transmission services are not separately identifiable from other promises in the contracts and, therefore, are not distinct. Additionally, as the performance obligation is satisfied over time as energy is delivered, and the same method is used to measure progress, the performance obligation meets the criteria to be considered a series.
In exchange for the exclusive right to sell or distribute electricity in our service area, AES Indiana is subject to rate regulation by federal and state regulators. This regulation sets the framework for the prices (“tariffs”) that AES Indiana is allowed to charge customers for electric services. Since tariffs are approved by the regulator, the price that AES Indiana has the right to bill corresponds directly with the value to the customer of AES Indiana’s performance completed in each period. Therefore, revenue under these contracts is recognized using an output method measured by the MWhs delivered each month at the approved tariff. Customer payments are typically due on a monthly basis.
Wholesale revenue - Power produced at the generation stations in excess of our retail load is sold into the MISO market. Such sales are made at either the day-ahead or real-time hourly market price, and these sales are classified as wholesale revenue. We sell to and purchase power from MISO, and such sales and purchases are settled and accounted for on a net hourly basis.
In the MISO market, wholesale revenue is recorded at the spot price based on the quantities of MWh delivered in each hour during each month. As a member of MISO, we are obligated to declare the availability of our energy production into the wholesale energy market, but we are not obligated to commit our previously declared availability.
As such, contract terms end as the energy for each day is delivered to the market in the case of the day-ahead market and for each hour in the case of the real-time market.
Miscellaneous revenue - Miscellaneous revenue is mainly comprised of MISO transmission revenue and capacity revenue. MISO transmission revenue is earned when AES Indiana’s power lines are used in transmission of energy by power producers other than AES Indiana. As AES Indiana owns and operates transmission lines in central and southern Indiana, demand charges collected from network customers by MISO are allocated to the appropriate transmission owners (including AES Indiana) and recognized as transmission revenue. Capacity revenue is also included in miscellaneous revenue, and represent compensation received from MISO for making installed generation capacity available to satisfy system integrity and reliability requirements through the annual MISO capacity auction. Capacity, which is a stand-ready obligation to deliver energy when called upon by the RTO, is measured using MWs.
Transmission and capacity revenue each have a single performance obligation, as they each represent a distinct service or good. Additionally, as these performance obligations are satisfied over time and the same method is used to measure progress, the performance obligations meet the criteria to be considered a series. For transmission revenue, the price that the transmission operator has the right to bill corresponds directly with the value to the customer of AES Indiana’s performance completed in each period as the price paid is the transmission operator's allocation of the tariff rate (as approved by the regulator) charged to network participants. For capacity revenue, the capacity price that clears at the auction is fixed and AES Indiana is compensated based on the cleared MWs and cleared price.
AES Indiana’s revenue from contracts with customers was as follows (in thousands):
For the Years Ended December 31,
2024 2023 2022
Revenue from contracts with customers $ 1,616,000 $ 1,616,462 $ 1,759,971
The following table presents AES Indiana's revenue from contracts with customers and other revenue (in thousands):
For the Years Ended December 31,
2024 2023 2022
Retail Revenue
Retail revenue from contracts with customers:
Residential $ 688,728 $ 660,559 $ 688,487
Small commercial and industrial 250,777 241,800 247,655
Large commercial and industrial 606,565 619,899 625,351
Public lighting 10,366 9,767 9,832
Other (1)
10,638 14,016 17,845
Total retail revenue from contracts with customers 1,567,074 1,546,041 1,589,170
Alternative revenue programs 24,964 30,414 29,171
Wholesale Revenue
Wholesale revenue from contracts with customers 37,519 56,557 148,517
Miscellaneous Revenue
Capacity revenue 305 8,210 11,750
Transmission and other revenue 11,102 5,654 10,534
Total miscellaneous revenue from contracts with customers 11,407 13,864 22,284
Other miscellaneous revenue (2)
2,829 3,041 2,569
Total Revenue $ 1,643,793 $ 1,649,917 $ 1,791,711
(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 as follows (in thousands):
As of December 31,
2024 2023
Receivables from contracts with customers
$ 298,984 $ 218,822
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 temporarily paused customer disconnections and certain collection efforts and write-off processes to support the implementation of AES Indiana's customer billing system upgrade in the fourth quarter of 2023. In the third quarter of 2024, AES Indiana began offering extended payment plans for customers who may need assistance in paying their past due bills. See Note 1, “Overview and Summary of Significant Accounting Policies - Accounts Receivable and Allowance for Credit Losses” for further information on AES Indiana’s receivable balances.
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.
15. 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, 2024 December 31, 2023
Assets
Right-of-use assets - finance leases Other non-current assets $ 86,707 $ 16,357
Liabilities
Finance lease liabilities (current) Short-term debt and current portion of long-term debt 217 -
Finance lease liabilities (non-current)
Long-term debt 86,869 17,769
Total finance lease liabilities $ 87,086 $ 17,769
The following table summarizes supplemental balance sheet information related to leases as of the periods indicated:
Lease Term and Discount Rate December 31, 2024 December 31, 2023
Weighted-average remaining lease term - finance leases 36 years
35 years
Weighted-average discount rate - finance leases 5.67% 5.30%
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, 2024, 2023 and 2022, respectively (in thousands):
For the Year Ended December 31,
Components of Lease Cost 2024 2023 2022
Finance lease cost:
Amortization of right- of-use assets $ 638 $ 445 $ 542
Interest on lease liabilities 1,585 933 782
Total lease cost $ 2,223 $ 1,378 $ 1,324
Operating cash outflows from finance leases were $3.9 million, $0.6 million and $0.3 million for the years ended December 31, 2024, 2023 and 2022, 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, 2024 for 2025 through 2029 and thereafter (in thousands):
Finance Leases
2025 $ 4,476
2026 4,565
2027 4,657
2028 4,750
2029 4,845
Thereafter 205,039
Total 228,332
Less: Imputed interest (141,246)
Present value of lease payments $ 87,086
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,
2024 2023 2022
Total lease revenue $ 1,452 $ 1,537 $ 1,134
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, 2024 December 31, 2023
Gross assets $ 4,387 $ 4,341
Less: Accumulated depreciation (1,426) (1,222)
Net assets $ 2,961 $ 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 minimum lease receipts through 2029 and thereafter (in thousands):
Operating Leases
2025 $ 553
2026 554
2027 554
2028 354
2029 314
Thereafter 577
Total $ 2,906

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.

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ITEM 9A. CONTROLS AND PROCEDURES
ITEM 9A. CONTROLS AND PROCEDURES
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
The Company maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed in the reports that the Company files or submits under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to the CEO and CFO, as appropriate, to allow timely decisions regarding required disclosures.
The Company carried out the evaluation required by Rules 13a-15(b) and 15d-15(b), under the supervision and with the participation of our management, including the CEO and CFO, of the effectiveness of our “disclosure controls and procedures” (as defined in the Exchange Act Rules 13a-15(e) and 15d-15(e)). Based upon this evaluation, the CEO and CFO concluded that as of December 31, 2024, our disclosure controls and procedures were effective.
Management’s Report on Internal Control over Financial Reporting
Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rule 13a-15(f) under the Exchange Act. The Company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP and includes those policies and procedures that:
•pertain to the maintenance of records that in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;
•provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and
•provide reasonable assurance that unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements are prevented or detected timely.
Management, including our CEO and CFO, does not expect that our internal controls will prevent or detect all misstatements and all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. In addition, any evaluation of the effectiveness of controls is subject to risks that those internal controls may become inadequate in future periods because of changes in business conditions, or that the degree of compliance with the policies or procedures deteriorates.
Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2024. In making this assessment, management used the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in 2013. As disclosed in our Form 10-K for the fiscal year ended December 31, 2023, management determined that material weaknesses in the internal control over financial reporting existed as of December 31, 2023, related to the fourth quarter 2023 implementation of SAP IS-U, a software solution that SAP developed for businesses operating in the utility industries. Management identified control deficiencies that aggregated to material weaknesses in the design and operation of information technology general controls (“ITGCs”) which supported the Company’s internal control processes for revenue recognition and related accounts and disclosures impacted by revenue recognition. The design deficiencies related to user access and program change-management controls. Business process controls (automated and manual) and management review controls reliant on SAP IS-U were deemed ineffective as they were adversely impacted by the ineffective ITGCs.
During the year ended December 31, 2024, management implemented measures designed to ensure that control deficiencies contributing to the material weaknesses are remediated. The remediation actions included: (i) changes to our ITGC attributes in the areas of user access and program change-management for systems supporting the Company’s revenue internal control processes to ensure that internal controls are designed and operating effectively; (ii) implementation of improvements to streamline control execution by adjusting system configurations, automating tasks, and allocating additional resources to enhance user access and change management activities; and (iii) training and educating the control owners on ITGC policies concerning the requirements of each control, with a focus on those related to user access and program change-management over IT systems impacting the Company's revenue process. Management has completed the documentation and testing of these corrective actions, and as of December 31, 2024, management concluded that the material weaknesses have been remediated. Based on this assessment, management believes that the Company maintained effective internal control over financial reporting as of December 31, 2024.
Changes in Internal Control Over Financial Reporting
Except for the remediation of the material weaknesses related to the implementation of the SAP IS-U system discussed above, there has been no change in the Company’s internal control over financial reporting during the quarter ended December 31, 2024, that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

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ITEM 9B. OTHER INFORMATION
ITEM 9B. OTHER INFORMATION
None.

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information required to be furnished pursuant to this item with respect to Directors and Executive Officers of IPALCO will be set forth under the captions “Directors” and “Executive Officers” in IPALCO’s Proxy Statement to be furnished to shareholders in connection with the solicitation of proxies by our Board of Directors, which information is incorporated herein by reference.
The information required to be furnished pursuant to this item for IPALCO with respect to the identification of the Audit Committee, the Audit Committee financial expert and the registrant’s code of ethics will be set forth under the caption “Corporate Governance” in the Proxy Statement, which information is incorporated herein by reference.

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ITEM 11. EXECUTIVE COMPENSATION
ITEM 11. EXECUTIVE COMPENSATION
The information required to be furnished pursuant to this item for IPALCO will be set forth under the caption “Executive Compensation” in the Proxy Statement, which information is incorporated herein by reference.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information required to be furnished pursuant to this item for IPALCO will be set forth under the caption “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” in the Proxy Statement, which information is incorporated herein by reference.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required to be furnished pursuant to this item for IPALCO will be set forth under the caption “Certain Relationships and Related Transactions, and Director Independence” in the Proxy Statement, which information is incorporated herein by reference.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The Financial Audit Committee of AES pre-approves the audit and non-audit services provided by the independent auditors for itself and its subsidiaries, including IPALCO and its subsidiaries. The AES Financial Audit Committee maintained its policy established in 2002 within which to judge if the independent auditor may be eligible to provide certain services outside of its main role as outside auditor. Services within the established framework include audit and related services and certain tax services. Services outside of the framework require AES Financial Audit Committee approval prior to the performance of the service. The Sarbanes-Oxley Act of 2002 addresses auditor independence and this framework is consistent with the provisions of the Act. No services performed by the independent auditor with respect to IPALCO and its subsidiaries were approved after the fact by the AES Financial Audit Committee other than those that were considered to be de minimis and approved in accordance with Regulation 2-01(c)(7)(i)(C) to Regulation S-X of the Exchange Act.
In addition to the pre-approval policies of the AES Financial Audit Committee, the IPALCO Board of Directors has established a pre-approval policy for audit, audit related, and certain tax and other non-audit services. The Board of Directors will specifically approve the annual audit services engagement letter, including terms and fees, with the independent auditor. Other audit, audit related and tax consultation services are specifically identified in the pre-approval policy and the policy is subject to review at least annually. This pre-approval allows management to request the specified services on an as-needed basis during the year. Any such services are reviewed with the Board of Directors on a timely basis. Any audit or non-audit services that involve a service not listed on the pre-approval list must be specifically approved by the Board of Directors prior to commencement of such work. No services were approved after the fact by the IPALCO Board of Directors other than those that were considered to be de minimis and approved in accordance with Regulation 2-01 (c)(7)(i)(c) to Regulation S-X of the Exchange Act.
Audit fees are fees billed or expected to be billed by our principal accountant for professional services for the audit of the Financial Statements, included in this Annual Report on Form 10-K and review of financial statements included in IPALCO’s quarterly reports on Form 10-Q, services that are normally provided by our principal accountants in connection with statutory, regulatory or other filings or engagements or any other service performed to comply with generally accepted auditing standards and include comfort and consent letters in connection with SEC filings and financing transactions.
The following table lists fees billed to IPALCO for products and services provided by our principal accountants:
Years Ended December 31,
2024 2023
Audit Fees $ 1,647,294 $ 1,442,837
Audit Related Fees:
Fees for the audit of AES Indiana’s employee benefit plans 71,400 70,000
Assurance services for debt offering documents 150,000 -
Other 10,200 10,000
Total Principal Accountant Fees and Services $ 1,878,894 $ 1,522,837
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
ITEM 15. EXHIBITS, FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
(a) Index to the financial statements, supplementary data and financial statement schedules
IPALCO Enterprises, Inc. and Subsidiaries - Consolidated Financial Statements Page
Report of Independent Registered Public Accounting Firm - 2024, 2023 and 2022 (PCAOB ID: 42)
Consolidated Statements of Operations for the Years Ended December 31, 2024, 2023 and 2022 64
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2024, 2023, and 2022 65
Consolidated Balance Sheets as of December 31, 2024 and 2023 66
Consolidated Statements of Cash Flows for the Years Ended December 31, 2024, 2023 and 2022 67
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2024, 2023 and 2022 68
Notes to Consolidated Financial Statements 69
Schedule I - Condensed Financial Information of Registrant 175
Schedule II - Valuation and Qualifying Accounts and Reserves 184
AES Indiana and Subsidiaries - Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm - 2024, 2023 and 2022 (PCAOB ID: 42)
Consolidated Statements of Operations for the Years Ended December 31, 2024, 2023 and 2022 119
Consolidated Balance Sheets as of December 31, 2024 and 2023 120
Consolidated Statements of Cash Flows for the Years Ended December 31, 2024, 2023 and 2022 121
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2024, 2023 and 2022 122
Notes to Consolidated Financial Statements 123
Schedule II - Valuation and Qualifying Accounts and Reserves 184
(b) Exhibits
Exhibit No. Document
3.1 Third Amended and Restated Articles of Incorporation of IPALCO Enterprises, Inc. (Incorporated by reference to Exhibit No. 3.1 to IPALCO’s Form 8-K dated as of February 18, 2015)
3.2 Amended and Restated By-Laws of IPALCO Enterprises, Inc. (Incorporated by reference to Exhibit No. 3.2 to IPALCO’s Form 8-K dated as of February 18, 2015)
4.1 Pledge Agreement between IPALCO Enterprises, Inc. and The Bank of New York Mellon Trust Company, N.A. dated as of November 14, 2001 (Incorporated by reference to Exhibit No 4.1 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
4.2 Mortgage and Deed of Trust, dated as of May 1, 1940, between IPL and the Bank of New York Mellon Trust Company, NA, as successor in interest to American National Bank & Trust Company of Chicago, Trustee (Incorporated by reference to Exhibit No. 4.2 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
4.3 The following supplemental indentures to the Mortgage and Deed of Trust referenced in 4.2 above:
Third Supplemental Indenture, dated as of April 1, 1949 (Incorporated by reference to Exhibit No. 4.3 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
Tenth Supplemental Indenture, dated as of October 1, 1960 (Incorporated by reference to Exhibit No. 4.3 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
Eighteenth Supplemental Indenture, dated as of February 15, 1974 (Incorporated by reference to Exhibit No. 4.3 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
Forty-Eighth Supplemental Indenture, dated as of January 1, 2004 (Incorporated by reference to Exhibit No. 4.3 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
Fifty-Third Supplemental Indenture, dated as of October 1, 2006 (Incorporated by reference to Exhibit No. 4.3 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
Fifty-Fourth Supplemental Indenture, dated as of June 1, 2007 (Incorporated by reference to Exhibit No. 4.3 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
Sixtieth Supplemental Indenture, dated as of November 1, 2011 (Incorporated by reference to Exhibit No. 4.3 to IPALCO’s December 31, 2011 Form 10-K)
Sixty-First Supplemental Indenture, dated as of June 1, 2013 (Incorporated by reference to Exhibit No. 4.1 to IPALCO’s June 30, 2013 Form 10-Q)
Sixty-Second Supplemental Indenture, dated as of June 1, 2014 (Incorporated by reference to Exhibit No. 4.1 to IPALCO’s June 30, 2014 Form 10-Q)
Sixty-Third Supplemental Indenture, dated as of September 1, 2015 (Incorporated by reference to Exhibit No. 4.3 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on September 28, 2015)
Sixty-Fourth Supplemental Indenture, dated as of May 1, 2016 (Incorporated by reference to Exhibit No. 4.1 to IPALCO’s June 30, 2016 Form 10-Q)
Sixty-Fifth Supplemental Indenture, dated as of December 1, 2016 (Incorporated by reference to Exhibit No. 4.3 to IPALCO’s December 31, 2016 Form 10-K)
Sixty-Sixth Supplemental Indenture, dated as of November 1, 2018 (Incorporated by reference to Exhibit No. 4.3 to IPALCO's December 31, 2018 Form 10-K)
Sixty-Seventh Supplemental Indenture, dated as of December 1, 2020 (Incorporated by reference to Exhibit No. 4.3A to IPALCO's December 31, 2020 Form 10-K)
Sixty-Eighth Supplemental Indenture, dated as of December 1, 2020 (Incorporated by reference to Exhibit No. 4.3B to IPALCO's December 31, 2020 Form 10-K)
Sixty-Ninth Supplemental Indenture, dated as of July 1, 2021 (Incorporated by reference to Exhibit No. 4.1 to IPALCO's June 30, 2021 Form 10-Q)
Seventieth Supplemental Indenture, dated as of July 1, 2021 (Incorporated by reference to Exhibit No. 4.2 to IPALCO's June 30, 2021 Form 10-Q)
Seventy-First Supplemental Indenture, dated as of November 15, 2022 (Incorporated by reference to Exhibit No. 4.3 to IPALCO's December 31, 2022 Form 10-K)
Seventy-Second Supplemental Indenture, dated as of March 1, 2024 (Incorporated by reference to Exhibit No. 4.4 to IPALCO's March 18, 2024 Form 8-K)
4.4
Indenture between IPALCO Enterprises, Inc. and U.S. Bank National Association, as Trustee, dated April 14, 2020 for the 4.250% Senior Secured Notes due 2030 (Incorporated by reference to Exhibit No. 4.1 to IPALCO's April 14, 2020 Form 8-K)
4.5
Pledge Agreement Supplement between IPALCO Enterprises, Inc. and The Bank of New York Mellon Trust Company, N.A., as Collateral Agent, dated April 14, 2020 to the Pledge Agreement between IPALCO Enterprises, Inc. and The Bank of New York Mellon Trust Company dated November 14, 2001, as amended and supplemented (Incorporated by reference to Exhibit No. 4.2 to IPALCO's April 14, 2020 Form 8-K)
4.6
Indenture between IPALCO Enterprises, Inc. and U.S. Bank Trust Company, National Association, as Trustee, dated March 14, 2024 for the 5.750% Senior Secured Notes due 2034 (Incorporated by reference to Exhibit No. 4.1 to IPALCO's March 18, 2024 Form 8-K)
4.7
Pledge Agreement Supplement between IPALCO Enterprises, Inc. and The Bank of New York Mellon Trust Company, N.A., as Collateral Agent, dated March 14, 2024 to the Pledge Agreement between IPALCO Enterprises, Inc. and The Bank of New York Mellon Trust Company dated November 14, 2001, as amended and supplemented (Incorporated by reference to Exhibit No. 4.2 to IPALCO's March 18, 2024 Form 8-K)
10.1 Interconnection Agreement, dated April 1, 2008, between American Electric Power Service Corporation, as agent for Indiana Michigan Power Company, and IPL (Incorporated by reference to Exhibit No. 10.1 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
10.2 Interconnection Agreement, dated December 2, 1968, between IPL and Southern Indiana Gas and Electric Company as modified through Modification Number 11 (Incorporated by reference to Exhibit No. 10.2 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
10.3 Interconnection Agreement dated December 1, 1981, between IPL and Hoosier Energy Rural Electric Cooperative, Inc., as modified through Modification 6 (Incorporated by reference to Exhibit No. 10.3 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
10.4 Tenth Supplemental Agreement to the Interconnection Agreement between IPL and PSI Energy, Inc., dated as of June 26, 2002, amending and completely restating prior agreements (Incorporated by reference to Exhibit No. 10.4 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
10.5 $350,000,000 Revolving Credit Facility Amended and Restated Credit Agreement, dated December 22, 2022, among Indianapolis Power & Light Company, each lender from time to time party thereto, PNC Bank, National Association, as Administrative Agent, PNC Capital Markets LLC, as Joint Bookrunner and Joint Lead Arranger, U.S. Bank, National Association, as Syndication Agent, Joint Bookrunner and Joint Lead Arranger and The Huntington National Bank, as Documentation Agent (Incorporated by reference to Exhibit 10.1 to IPALCO's Current Report on Form 8-K filed on December 23, 2022)
10.6
$400,000,000 Term Loan Agreement, dated August 14, 2024, among Indianapolis Power & Light Company, each lender from time to time party thereto, PNC Bank, National Association, as Administrative Agent, PNC Capital Markets LLC, as Bookrunner and Joint Lead Arranger, and U.S. Bank National Association, as Syndication Agent and Joint Lead Arranger (Incorporated by reference to Exhibit No. 10.1 of IPALCO's Form 8-K filed on August 14, 2024)
10.7
Subscription Agreement by and between IPALCO and CDP Infrastructures Fund G.P., a wholly owned subsidiary of La Caisse de dépȏt et placement du Québec dated December 14, 2014 (Incorporated by reference to Exhibit 10.10 to IPALCO’s December 31, 2014 10-K/A)
10.8
IPALCO’s Shareholders’ Agreement by and among AES U.S. Investments, Inc., IPALCO Enterprises, Inc. and CDP Infrastructures Fund G.P. dated as of February 11, 2015 (Incorporated by reference to Exhibit No. 10.1 to IPALCO’s March 31, 2015 10-Q)
10.9
The AES Corporation 2023 Long Term Compensation Plan, as amended and restated, dated October 11, 2023 (Incorporated by reference to Exhibit 10.5 of The AES Corporation’s Form 10-K for the year ended December 31, 2023)
10.10
Form of AES Performance Stock Unit Award Agreement under The AES Corporation 2003 Long Term Compensation Plan (Incorporated by reference to Exhibit 10.7 of The AES Corporation’s Form 10-K for the year ended December 31, 2023)
10.11
Form of AES Restricted Stock Unit Award Agreement under The AES Corporation 2003 Long Term Compensation Plan (Incorporated by reference to Exhibit 10.8 of The AES Corporation’s Form 10-K for the year ended December 31, 2023)
10.12
Form of AES Performance Cash Unit Award Agreement under The AES Corporation 2003 Long Term Compensation Plan (Incorporated by reference to Exhibit 10.9 of The AES Corporation’s Form 10-K for the year ended December 31, 2023)
10.13
Form of AES Nonqualified Stock Option Award Agreement under The AES Corporation 2003 Long Term Compensation Plan (Incorporated by reference to Exhibit 10.4 of The AES Corporation’s Form 10-Q for the quarter ended June 30, 2015)
10.14
Form of AES Performance Cash Unit Award Agreement under The AES Corporation 2003 Long Term Compensation Plan (Incorporated by reference to Exhibit 10.11 of The AES Corporation’s Form 10-K for the year ended December 31, 2023)
10.15
The AES Corporation Restoration Supplemental Retirement Plan, as amended and restated, effective October 10, 2023 (Incorporated by reference to Exhibit 10.12 of The AES Corporation’s Form 10-K for the year ended December 31, 2023)
10.16
The AES Corporation Amended and Restated Executive Severance Plan and Summary Plan Description (Incorporated by reference to Exhibit 10.14 of The AES Corporation’s Form 10-K for the year ended December 31, 2023)
10.17
The AES Corporation Performance Incentive Plan, as amended and restated on October 10, 2023 (Incorporated by reference to Exhibit 10.15 of The AES Corporation’s Form 10-K for the year ended December 31, 2023)
21 Subsidiaries of IPALCO Enterprises, Inc.
31.1 Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2 Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1 Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2 Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS XBRL Instance Document (furnished herewith as provided in Rule 406T of Regulation S-T)
101.SCH XBRL Taxonomy Extension Schema Document (furnished herewith as provided in Rule 406T of Regulation S-T)
101.CAL XBRL Taxonomy Extension Calculation Linkbase Document (furnished herewith as provided in Rule 406T of Regulation S-T)
101.DEF XBRL Taxonomy Extension Definition Linkbase Document (furnished herewith as provided in Rule 406T of Regulation S-T)
101.LAB XBRL Taxonomy Extension Label Linkbase Document (furnished herewith as provided in Rule 406T of Regulation S-T)
101.PRE XBRL Taxonomy Extension Presentation Linkbase Document (furnished herewith as provided in Rule 406T of Regulation S-T)
(c) Financial Statement Schedules
Schedules other than those listed below are omitted as the information is either not applicable, not required, or has been furnished in the financial statements or notes thereto included in Item 8 hereof.
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT
IPALCO ENTERPRISES, INC.
Schedule I - Condensed Financial Information of Registrant
Unconsolidated Statements of Operations
2024 2023 2022
(In Thousands)
OTHER INCOME / (EXPENSE), NET:
Equity in income of subsidiaries $ 164,922 $ 116,190 $ 126,466
Interest expense (43,127) (43,877) (43,805)
Loss on early extinguishment of debt (329) - -
Other income / (expense), net 1,658 (121) (571)
Total other income, net 123,124 72,192 82,090
INCOME FROM OPERATIONS BEFORE INCOME TAX 123,124 72,192 82,090
Income tax benefit (10,399) (10,928) (11,027)
NET INCOME $ 133,523 $ 83,120 $ 93,117
See Notes to Schedule I.
IPALCO ENTERPRISES, INC.
Schedule I - Condensed Financial Information of Registrant
Unconsolidated Statements of Comprehensive Income
2024 2023 2022
(In Thousands)
NET INCOME $ 133,523 $ 83,120 $ 93,117
Derivative activity:
Change in derivative fair value, net of income tax effect of $(2,193), $(528) and $(15,309), for each respective period
6,626 1,594 46,245
Reclassification to earnings, net of income tax effect of $179, $(1,798) and $(1,798), for each respective period
(542) 5,431 5,431
Net change in fair value of derivatives 6,084 7,025 51,676
Other comprehensive income 6,084 7,025 51,676
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON STOCK
$ 139,607 $ 90,145 $ 144,793
See Notes to Schedule I.
IPALCO ENTERPRISES, INC.
Schedule I - Condensed Financial Information of Registrant
Unconsolidated Balance Sheets
December 31, 2024 and 2023
2024 2023
(In Thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 299 $ 537
Taxes receivable 9,401 31,341
Derivative assets, current - 14,294
Prepayments and other current assets 317 7,626
Total current assets 10,017 53,798
OTHER NON-CURRENT ASSETS:
Investment in subsidiaries 2,156,967 1,921,548
Other non-current assets 4,027 3,540
Total other non-current assets 2,160,994 1,925,088
TOTAL ASSETS
$ 2,171,011 $ 1,978,886
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Short-term and current portion of long-term debt $ - $ 404,474
Accounts payable 162 -
Accrued interest 9,115 8,360
Total current liabilities 9,277 412,834
NON-CURRENT LIABILITIES:
Long-term debt 865,390 470,653
Deferred tax liability - long-term 11,809 18,931
Total non-current liabilities 877,199 489,584
Total liabilities 886,476 902,418
SHAREHOLDERS' EQUITY
Paid in capital 1,247,090 1,021,992
Accumulated other comprehensive income 35,378 29,294
Retained earnings 2,067 25,182
Total shareholders' equity 1,284,535 1,076,468
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 2,171,011 $ 1,978,886
See Notes to Schedule I.
IPALCO ENTERPRISES, INC.
Schedule I - Condensed Financial Information of Registrant
Unconsolidated Statements of Cash Flows
2024 2023 2022
(In Thousands)
CASH FLOWS FROM OPERATIONS:
Net income $ 133,523 $ 83,120 $ 93,117
Adjustments to reconcile net income to net cash
provided by operating activities:
Equity in earnings of subsidiaries (164,922) (116,190) (126,466)
Cash dividends received from subsidiary companies 162,100 140,200 127,200
Amortization of deferred financing costs and debt premium 1,079 1,474 1,403
Deferred income taxes - net (9,136) 9,276 (121)
Change in certain assets and liabilities:
Accounts payable 101 (23) (194)
Accrued taxes payable/receivable 21,637 (20,022) (2,406)
Accrued interest 755 - -
Other - net 2,035 6,798 7,744
Net cash provided by operating activities 147,172 104,633 100,277
CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in subsidiaries (225,000) - (253,000)
Net cash used in investing activities (225,000) - (253,000)
CASH FLOWS FROM FINANCING ACTIVITIES:
Long-term borrowings 400,000 - -
Retirement of long-term borrowings (405,000) - -
Distributions to shareholders (156,638) (104,287) (101,986)
Equity contributions from shareholders 225,000 - 253,000
Proceeds received from termination of interest rate swaps 23,114 - -
Deferred financing costs paid and other (8,886) - (2)
Net cash (used in) provided by financing activities 77,590 (104,287) 151,012
Net change in cash, cash equivalents and restricted cash (238) 346 (1,711)
Cash, cash equivalents and restricted cash at beginning of period 537 191 1,902
Cash, cash equivalents and restricted cash at end of period $ 299 $ 537 $ 191
Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest (net of amount capitalized) $ 42,014 $ 35,569 $ 35,173
Income taxes - - 31,000
See Notes to Schedule I.
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, 2022 $ 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
Net comprehensive income - 6,084 133,523 139,607
Distributions to shareholders(1)
- - (156,638) (156,638)
Contributions from shareholders 225,000 - - 225,000
Other 98 - - 98
Balance at December 31, 2024 $ 1,247,090 $ 35,378 $ 2,067 $ 1,284,535
1) IPALCO made return of capital payments of $46.5 million and $33.3 million in 2023 and 2022, 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.
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, 2024, 2023, or 2022. Any unrealized gains or losses are recorded in "Other income / (expense), net" on the accompanying Unconsolidated Statements of Operations.
Financial Assets
Interest Rate Hedges
In March 2024, IPALCO's interest rate hedges with a combined notional amount of $400.0 million were terminated in conjunction with the issuance of the 2034 IPALCO Notes. All changes in the market value of the interest rate hedges are recorded in AOCI. See also Note 3, "Derivative Instruments and Hedging Activities - Cash Flow Hedges" for further information.
Summary
The fair value of assets at December 31, 2024 and 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 December 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 3,947 - - 3,947 3,425 - - 3,425
Total VEBA investments 4,033 - - 4,033 3,552 - - 3,552
Interest rate hedges - - - - - 14,294 - 14,294
Total financial assets measured at fair value $ 4,033 $ - $ - $ 4,033 $ 3,552 $ 14,294 $ - $ 17,846
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, 2024 December 31, 2023
Face Value Fair Value Face Value Fair Value
(In Thousands)
Fixed-rate $ 875,000 $ 849,024 $ 880,000 $ 839,471
Total indebtedness $ 875,000 $ 849,024 $ 880,000 $ 839,471
The difference between the face value and the carrying value of this indebtedness represents the following:
•unamortized deferred financing costs of $8.3 million and $4.6 million at December 31, 2024 and 2023, respectively; and
•unamortized discounts of $1.3 million and $0.3 million at December 31, 2024 and 2023, respectively.
3. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
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. The change in the fair value of a hedging instrument is recorded in AOCI and amounts deferred are reclassified to earnings in the same income statement line as the hedged item in the period in which it settles.
IPALCO’s three forward-starting interest rate swaps with a combined notional value of $400.0 million were terminated for total cash proceeds of $23.1 million in conjunction with the issuance of the 2034 IPALCO Notes in March 2024. AOCI of $95.4 million 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. IPALCO previously de-designated three forward-starting interest rate swaps used to hedge the interest risk associated with refinancing the IPALCO 2020 maturities. AOCL of $72.3 million was frozen at the date of de-designation, which is currently being amortized into interest expense over the remaining life of the 2030 IPALCO Notes.
The following tables provide information on gains or losses recognized in AOCI / (AOCL) for the cash flow hedges for the period indicated:
Interest Rate Hedges for the Year Ended December 31,
$ in thousands (net of tax) 2024 2023 2022
Beginning accumulated derivative gain / (loss) in AOCI / (AOCL)
$ 29,294 $ 22,269 $ (29,407)
Net gains associated with current period hedging transactions
6,626 1,594 46,245
Net losses reclassified to interest expense
(542) 5,431 5,431
Ending accumulated derivative gain / (loss) in AOCI / AOCL)
$ 35,378 $ 29,294 $ 22,269
Net gain expected to be reclassified to earnings in the next twelve months
$ 1,737
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, 2024 and 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:
December 31,
Commodity Hedging Designation Balance sheet classification 2024 2023
Interest rate hedges Cash Flow Hedge Derivative assets, current
$ - $ 14,294
4. DEBT
The following table presents IPALCO’s long-term indebtedness:
December 31,
Series Due 2024 2023
(In Thousands)
Long-Term Debt
3.70% Senior Secured Notes
September 2024 $ - $ 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 (1,331) (319)
Deferred financing costs - net (8,279) (4,554)
Total long-term debt 865,390 875,127
Less: current portion of long-term debt - 405,000
Net long-term debt $ 865,390 $ 470,127
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.
Pursuant to a registration rights agreement dated March 14, 2024, IPALCO agreed to register the 2034 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 2034 IPALCO Notes with the SEC on May 28, 2024 in respect of its obligations under such registration rights agreement, and this registration statement was declared effective on June 6, 2024. The exchange offer closed on July 12, 2024.
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, 2024, 2023 and 2022
(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, 2024
Accumulated Provisions Deducted from
Assets - Doubtful Accounts $ 2,283 $ 28,417 $ - $ 902 $ 29,798
Deducted from Inventories
Valuation Allowance for Materials and Supplies $ 3,440 $ - $ 20,480 $ 3,440 $ 20,480
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
AES INDIANA and SUBSIDIARIES
Valuation and Qualifying Accounts and Reserves
For the Years Ended December 31, 2024, 2023 and 2022
(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, 2024
Accumulated Provisions Deducted from
Assets - Doubtful Accounts $ 2,283 $ 28,417 $ - $ 902 $ 29,798
Deducted from Inventories
Valuation Allowance for Materials and Supplies $ 3,440 $ - $ 20,480 $ 3,440 $ 20,480
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