EDGAR 10-K Filing

Company CIK: 728391
Filing Year: 2024
Filename: 728391_10-K_2024_0000728391-24-000010.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 “all other.” All of our operations are conducted within the U.S. and principally within the state of Indiana. Please see Note 12, “Business Segments” to the Financial Statements of this Annual Report on Form 10-K.
AES INDIANA
IPALCO owns all of the outstanding common stock of AES Indiana. AES Indiana was incorporated under the laws of the state of Indiana in 1926. AES Indiana is engaged primarily in generating, transmitting, distributing and selling electric energy to approximately 523,000 retail customers in the city of Indianapolis and neighboring areas within the state of Indiana. AES Indiana has an exclusive right to provide electric service to those customers. AES Indiana's service area covers about 528 square miles with an estimated population of approximately 969,000. AES Indiana’s generation, transmission and distribution facilities, and changes to our sources of electric generation, are further described below under “Properties.” There have been no significant changes in the services rendered by AES Indiana during 2023.
AES Indiana is a transmission company member of RF. RF is one of eight Regional Reliability Councils under the NERC, which has been designated as the Electric Reliability Organization under the EPAct. RF seeks to preserve and enhance electric service reliability and security for the interconnected electric systems within the RF geographic area by setting and enforcing electric reliability standards. RF members cooperate under agreements to augment the reliability of its members’ electricity supply systems in the RF region through coordination of the planning and operation of the members’ generation and transmission facilities. Smaller electric utility systems, independent power producers and power marketers can participate as full members of RF.
HUMAN CAPITAL MANAGEMENT
AES Indiana's employees are essential to delivering and maintaining reliable service to our customers. As of December 31, 2023, AES Indiana had 1,138 employees, of whom 1,074 were full time. Of the total employees, 774 were represented by the IBEW in two bargaining units: a physical unit and a clerical-technical unit. In December 2021, the IBEW physical unit ratified a three-year agreement with AES Indiana that expires on December 4, 2024. In February 2023, the membership of the IBEW clerical-technical unit ratified a three-year labor agreement with AES Indiana that expires on February 12, 2026. Both collective bargaining agreements continue in full force and effect from year-to-year unless either party provides prior written notice at least sixty (60) days prior to the expiration, or anniversary thereof, of its desire to amend or terminate the agreement. As of December 31, 2023, neither IPALCO nor any of its majority-owned subsidiaries, other than AES Indiana, had any employees.
Safety
As part of AES, safety is one of our core values. Conducting safe operations at our facilities, so that each person can return home safely, is the cornerstone of our daily activities and decisions. Safety efforts are led globally by the AES Chief Operating Officer and supported by safety committees that operate at the local site level. Hazards in the workplace are actively identified, and management tracks incidents so remedial actions can be taken to improve workplace safety.
We work with the Safety Management System (“SMS”), a Global Safety Standard that applies to all AES employees and employees of AES subsidiaries, as well as contractors working in AES facilities and construction projects. The SMS requires continuous safety performance monitoring, risk assessment and performance of periodic integrated environmental, health, and safety audits. The SMS provides a consistent framework for all AES operational businesses and construction projects to set expectations for risk identification and reduction, measure performance, and drive continuous improvements. The SMS standard is consistent with the OHSAS 18001/ISO 45001 standard.
Our safety performance is also measured by both leading and lagging metrics. Our leading safety metrics track safety observations, safety meeting engagement and the reporting of lost time incident (“LTI”) rates for our employees and contractors based on OSHA standards. Our lagging safety metrics track lost workday cases, severity rate, and recordable incidents. We are committed to excellence in safety and have implemented various programs to increase safety awareness and improve work practices.
Talent
We believe our success depends on our ability to attract, develop and retain key personnel. The skills, experience and industry knowledge of key employees significantly benefit our operations and performance. We have a comprehensive approach to managing our talent and developing our leaders in order to ensure our people have the right skills for today and tomorrow, whether that requires us to build new business models or leverage leading technologies.
We emphasize employee development and training. To empower employees, we provide a range of development programs and opportunities, skills, and resources they need to be successful by focusing on experience and exposure, as well as formal programs including the AES' ACE Academy for Talent Development, and our Trainee Program.
We believe that our individual differences make us stronger. Our Global Diversity and Inclusion Program is led by the AES Diversity and Inclusion Officer. Governance and standards are guided by the AES Chief Human Resources Officer, with input from members of AES' Executive Leadership Team.
Compensation
Our compensation philosophy emphasizes pay-for-performance. Our incentive plans are designed to reward strong performance, with greater compensation paid when performance exceeds expectations and less compensation paid when performance falls below expectations. We invest significant time and resources to ensure our compensation programs are competitive and reward the performance of our people. Every year, our people who are not part of a collective bargaining agreement are eligible for an annual merit-based salary increase. In addition, individuals are eligible for a salary increase if they receive a significant promotion. For non-collectively bargained employees at certain levels in the organization, we offer annual incentives (bonus) and long-term compensation to reinforce the alignment between employees and AES.
SERVICE COMPANY
The Service Company provides services including operations, accounting, legal, human resources, information technology and other corporate services on behalf of certain AES U.S. companies, including among other companies, IPALCO and AES Indiana. The Service Company allocates the costs for these services based on cost drivers designed to result in fair and equitable allocations. This includes ensuring that the regulated utilities served, including AES Indiana, are not subsidizing costs incurred for the benefit of other businesses. Please see Note 11, “Related Party Transactions - Service Company” to the Financial Statements and “Item 13. Certain Relationships and Related Transactions, and Director Independence” of this Annual Report on Form 10-K for additional details.
PROPERTIES
Our executive offices are located at One Monument Circle, Indianapolis, Indiana. This facility and the remainder of our material properties in our business and operations are owned directly by AES Indiana. The following is a description of these material properties.
We own two distribution service centers in Indianapolis. We also own the building in Indianapolis that houses our customer service center.
We own and operate four generating stations, all within the state of Indiana. The first station, Petersburg, is coal-fired. AES Indiana retired 230 MW Petersburg Unit 1 in May 2021 and 415 MW Petersburg Unit 2 in June 2023, which resulted in 630 MW of total retired economic capacity at this station. AES Indiana plans to convert the remaining two coal units at Petersburg to natural gas (for further discussion, see Note 2, "Regulatory Matters - IRP Filings and Replacement Generation - 2022 IRP" to the Financial Statements of this Annual Report on Form 10-K). The second station, Harding Street, consists of three natural gas-fired boilers and steam turbines and uses natural gas and fuel oil to power five combustion turbines. In addition, AES Indiana operates a 20 MW battery energy storage unit at this location, which provides frequency response. The third station, Eagle Valley, is a CCGT natural gas plant. The fourth station, Georgetown, is a peaking station that uses natural gas to power combustion turbines. For electric generation, the net winter design capacity is 3,070 MW and net summer design capacity is 2,925 MW. Our highest summer peak level of 3,139 MW was recorded in August 2007 and the highest winter peak level of 2,971 MW was recorded in January 2009.
Our sources of electric generation are as follows:
Fuel Name Number of
Units Winter
Capacity
(MW) Summer
Capacity
(MW) Location
Gas Harding Street 6 1,026 963 Marion County, Indiana
Eagle Valley 1 719 689 Morgan County, Indiana
Georgetown 2 200 158 Marion County, Indiana
Total 9 1,945 1,810
Coal Petersburg(1)
2 1,064 1,064 Pike County, Indiana
Total 2 1,064 1,064
Oil Petersburg 3 8 8 Pike County, Indiana
Harding Street 3 53 43 Marion County, Indiana
Total 6 61 51
Grand Total 17 3,070 2,925
(1) AES Indiana retired 230 MW Petersburg Unit 1 in May 2021 and 415 MW Petersburg Unit 2 in June 2023, which resulted in 630 MW of total retired economic capacity at this station. AES Indiana plans to convert the remaining two coal units at Petersburg to natural gas (for further discussion, see Note 2, “Regulatory Matters - IRP Filings and Replacement Generation - 2022 IRP”).
Net electrical generation during 2023 at our Eagle Valley, Petersburg, Harding Street and Georgetown plants accounted for approximately 41.9%, 32.5%, 24.8% and 0.8%, respectively, of our total net generation. Even though the capacity of our Harding Street plant far exceeds that of the Eagle Valley CCGT plant, we expect the generation at Eagle Valley to continue to far exceed that of Harding Street due to the relatively lower cost to produce electricity at Eagle Valley.
The following table summarizes projects that have not yet been fully placed into service (see further discussion in Note 2, “Regulatory Matters - IRP Filings and Replacement Generation” to the Financial Statements of this Annual Report on Form 10-K):
Type Project Name Solar Capacity (MW) Storage Capacity (MWh) Date filed with IURC Date of IURC approval
Estimated Completion Location
Solar Hardy Hills Solar Project
195 - 2/12/2021 6/16/2021 2024(1)
Clinton County, Indiana
Solar & Storage Petersburg Energy Center Project 250 180 7/30/2021 11/24/2021 2025 Pike County, Indiana
Storage
Pike County BESS Project
- 800 7/19/2023
1/17/2024
2024 Pike County, Indiana
(1)In December 2023, the first stage of construction for the Hardy Hills Solar Project was completed and placed in service, with initial operations for over half of the project commencing on December 28, 2023. The final stage for construction of the project is expected to be completed during the first half of 2024.
Our electric system is directly interconnected with the electric systems of Indiana Michigan Power Company, CenterPoint Indiana (formerly Vectren Corporation), Hoosier Energy Rural Electric Cooperative, Inc., and the electric system jointly owned by Duke Energy Indiana, Indiana Municipal Power Agency and Wabash Valley Power Association, Inc. Our transmission system includes 458 circuit miles of 345,000 volt lines and 408 circuit miles of 138,000 volt lines. The distribution system consists of 5,314 circuit miles of underground primary and secondary cables and 6,081 circuit miles of overhead primary and secondary wire. Underground street lighting facilities include 790 circuit miles of underground cable. Also included in the system are 132 substations. Depending on the voltage levels at the substation, some substations may be considered both a bulk power substation and a distribution substation. There are 73 bulk power substations and 103 distribution substations; 52 substations are considered both bulk power and distribution substations.
All critical facilities we own are well maintained, in good condition and meet our present needs. Our plants generally have enough capacity to meet the daily needs of our retail customers when all of our units are available. During periods when our generating capacity is not sufficient to meet our retail demand, or when MISO provides a lower cost alternative to some of our available generation, we purchase power on the MISO wholesale market.
SEASONALITY
The electric utility business is affected by seasonal weather patterns throughout the year and, therefore, the operating revenue and associated operating expenses are not generated evenly by month during the year. AES Indiana’s business is not dependent on any single customer or group of customers. Additionally, retail kWh sales, after adjustments for weather variations, are impacted by changes in service territory economic activity and the number of retail customers we have, as well as DSM energy efficiency programs implemented by AES Indiana. For the ten years ending in 2023, AES Indiana’s retail kWh sales have decreased at a compound annual rate of 1.2%. Conversely, the number of our retail customers grew at a compound annual rate of 0.9% during that same period. Going forward, we expect modest retail kWh sales growth annually, which will continue to be offset by our DSM programs. Please see Note 2, “Regulatory Matters - DSM” to the Financial Statements of this Annual Report on Form 10-K for more details. AES Indiana’s electricity sales for 2019 through 2023 are set forth in the table of statistical information included at the end of this section.
Weather and Weather-Related Damage in our Service Area
Extreme high and low temperatures in our service area have a significant impact on revenue as many of our retail customers use electricity to power air conditioners, electric furnaces and heat pumps. The impact on customers is partially mitigated by our declining block rate structure, which generally provides for residential and commercial customers to be charged a lower per kWh rate at higher consumption levels. Therefore, as volumes increase, the weighted average price per kWh decreases. The effect is generally more significant with high temperatures than with low temperatures as many of our customers use gas heat. In addition, because extreme temperatures have the effect of increasing demand for electricity, the wholesale price for electricity generally increases during periods of extreme hot or cold weather, however 100% of annual wholesale margins AES Indiana earns above (or below) the benchmark of $16.3 million are passed back (or charged) to customer rates through a rider.
Storm activity can also have an adverse effect on our operating performance. Severe storms often damage transmission and distribution equipment, thereby causing power outages, which reduce revenue and increase repair costs. Partially mitigating this impact is AES Indiana’s ability to timely recover certain operation and maintenance repair costs related to severe storms. In our 2016 and 2018 Base Rate Orders, we received approval for a storm damage restoration reserve account that allows us to defer major storm costs over a benchmark that meet certain criteria considered to be severe, for recovery in a future basic rate proceeding. Because AES Indiana's basic rates and charges include an annual amount for recovery for such severe storm costs, if actual severe storm costs are below that level, AES Indiana will record a regulatory liability for the shortfall to be passed to customers in a future basic rate proceeding. Conversely, if AES Indiana's major storm costs are above the level in basic rates, AES Indiana will defer the excess for future recovery.
MISO OPERATIONS
AES Indiana is one of many transmission system owner members in MISO. MISO is a RTO which maintains functional control over the combined transmission systems of its members and manages one of the largest energy and ancillary services markets in the U.S. MISO policies are developed, in part, through a stakeholder process in which we are an active participant. We focus our participation in this process primarily on items that could impact our customers, shared cost of transmission expansion, resource adequacy, results of operations, financial condition and cash flows. Additionally, we participate in the process to impact MISO and FERC policy by filing comments with MISO, the FERC, or the IURC.
MISO has functional control of our transmission facilities and our transmission operations are integrated with those of MISO. Our participation and authority to sell wholesale power at market-based rates are subject to the FERC jurisdiction. Transmission service over our facilities is provided through MISO’s tariff.
As a member of MISO, we offer our available electricity production of each of our generation assets into the MISO day-ahead and real-time markets. MISO dispatches generation assets in economic order considering transmission constraints and other reliability issues to meet the total demand in the MISO region. MISO settles hourly offers and bids based on locational marginal prices, which is pricing for energy at a given location based on a market clearing price that takes into account physical limitations, generation and demand throughout the MISO region. MISO evaluates the market participants’ energy offers and demand bids optimizing for energy and ancillary services products to economically and reliably dispatch the entire MISO system. The IURC has authorized AES Indiana to
recover its ongoing costs from MISO and such costs are being recovered per specific rate orders. The unamortized balance of total MISO costs deferred as regulatory assets was $30.6 million and $44.6 million as of December 31, 2023 and 2022, respectively.
We have preserved our right to withdraw from MISO by tendering our Notice of Withdrawal (subject to the FERC and the IURC approval). We have made no decision to seek withdrawal from MISO at this time. We will continue to assess the relative costs and benefits of being a MISO member, as well as actively advocate for our positions through the existing MISO stakeholder process and in filings with the FERC or IURC.
See also Note 2, “Regulatory Matters” to the Financial Statements of this Annual Report on Form 10-K for additional details on the regulatory oversight of the FERC and the IURC.
REGULATION
General
AES Indiana is a regulated public utility principally engaged in providing electric service to the Indianapolis metropolitan area. An inherent business risk facing any regulated public utility is that of unexpected or adverse regulatory action. Regulatory discretion is reasonably broad in Indiana, as it is elsewhere. We attempt to work cooperatively with regulators and those who participate in the regulatory process, while remaining vigilant in protecting or asserting our legal rights in the regulatory process. We take an active role in addressing regulatory policy issues in the current regulatory environment. Additionally, there is increased activity by environmental regulators, in particular under a President Biden administration, which has had and will continue to have a significant impact on our operations and financial statements for the foreseeable future. We maintain our books and records consistent with GAAP reflecting the impact of regulation. See Note 1, “Overview and Summary of Significant Accounting Policies” to the Financial Statements of this Annual Report on Form 10-K.
Retail Ratemaking
AES Indiana’s tariff rates for electric service to retail customers consist of basic rates and charges which are set and approved by the IURC after public hearings. In addition, AES Indiana’s rates include various adjustment mechanisms including, but not limited to:
•a rider to reflect changes in fuel and purchased power costs to meet AES Indiana’s retail load requirements, referred to as the FAC;
•a rider for the timely recovery of costs (including a return) incurred to comply with environmental laws and regulations, referred to as the ECCRA;
•a rider to reflect changes in ongoing MISO costs, referred to as the RTO Adjustment;
•a rider to reflect changes in net capacity sales above and below an established annual benchmark of $11.3 million, referred to as the Capacity Adjustment;
•a rider for passing through to customers wholesale sales margins above and below an established annual benchmark of $16.3 million, referred to as the Off-System Sales Margin Adjustment;
•a rider for the timely recovery of costs (including a return) incurred on investments for eligible TDSIC improvements; and
•cost recovery, lost margin recoveries and performance incentives from our DSM programs.
Each of these tariff rate components may be set and approved by the IURC in separate proceedings at different points in time (currently the FAC proceedings occur on a quarterly basis and AES Indiana's other rider proceedings all occur on an annual basis). These components function somewhat independently of one another, but the overall structure of our rates and charges would be subject to review at the time of any review of our basic rates and charges.
For additional discussion of the regulatory environment related to our business, see the discussion in Note 2, “Regulatory Matters” to the Financial Statements of this Annual Report on Form 10-K, which is incorporated by reference herein.
ENVIRONMENTAL MATTERS
We are subject to various federal, state, regional and local environmental protection and health and safety laws and regulations governing, among other things, the generation, storage, handling, use, disposal and transportation of regulated materials, including ash; the use and discharge of water used in generation boilers and for cooling purposes; the emission and discharge of hazardous and other materials, including GHGs, into the environment; climate change; and the health and safety of our employees. These laws and regulations often require a lengthy and complex process of obtaining and renewing permits and other governmental authorizations from federal, state and local agencies. Violation of these laws, regulations or permits can result in substantial fines, other sanctions, suspension or revocation of permits and/or facility shutdowns. There can be no assurance that we have been or will be at all times in full compliance with such laws, regulations and permits.
Where no accrued liability has been recognized, it is reasonably possible that some matters could be decided unfavorably to us and could require us to pay damages or make expenditures in amounts that could be material but could not be estimated as of December 31, 2023.
From time to time, we are subject to enforcement actions for claims of noncompliance with environmental laws and regulations. AES Indiana cannot assure that it will be successful in defending against any claim of noncompliance. However, we do not believe any currently open environmental investigations will result in fines material to our results of operations, financial condition and cash flows.
Under certain environmental laws, we could be held responsible for costs relating to contamination at our past or present facilities and at third-party waste disposal sites. We could also be held liable for human exposure to hazardous substances or for other environmental damage. Our costs of complying with current and future environmental and health and safety laws, and our liabilities arising from past or future releases of, or exposure to, hazardous substances may adversely affect our business, results of operations, financial condition and cash flows. A discussion of the legislative and regulatory initiatives most likely to affect us follows.
MATS
In April 2012, the EPA’s rule to establish maximum achievable control technology standards for hazardous air pollutants regulated under the CAA emitted from coal and oil-fired electric utilities, known as “MATS”, became effective. AES Indiana management developed and implemented a plan, which was approved by the IURC, to comply with this rule and all Petersburg units subject to the rule have been and remain in material compliance with the MATS rule since applicable deadlines.
In June 2015, the U.S. Supreme Court remanded MATS to the D.C. Circuit due to the EPA’s failure to consider costs before deciding to regulate power plants under Section 112 of the CAA and subsequently remanded MATS to the EPA without vacatur. On March 6, 2023, the EPA published a final rule reaffirming its 2016 finding that it is appropriate and necessary to regulate emissions under MATS. On April 24, 2023, EPA published the proposed MATS Risk and Technology Review (RTR) Rule to lower certain emissions limits and revise certain other aspects of MATS. It is too early to predict the outcome of this proposed rule and any potential impact. However, the existing requirements of MATS and the proposed requirements of MATS RTR Rule would not apply to AES Indiana upon conversion of the remaining two coal-fired units at Petersburg to natural gas.
Further rulemakings and/or proceedings are possible; however, in the meantime, MATS remains in effect. We currently cannot predict the outcome of the regulatory or judicial process, or its impact, if any, on our MATS compliance planning or ultimate costs.
Waste Management and CCR
In the course of operations, our facilities generate solid and liquid waste materials requiring eventual disposal or
processing. Waste materials generated at our electric power and distribution facilities include asbestos, CCR, oil,
scrap metal, rubbish, small quantities of industrial hazardous wastes such as spent solvents, tree-and-land-clearing
wastes and polychlorinated biphenyl contaminated liquids and solids. We endeavor to ensure that all our solid and
liquid wastes are disposed of in accordance with applicable national, regional, state and local regulations. With the
exception of CCR, we have not usually physically disposed of waste materials on our property. Instead, they are usually shipped off-site for final disposal, treatment or recycling. Some of our CCRs have been and/or are currently beneficially used on-site and offsite, including as a raw material for production of wallboard, and concrete or cement, and some are disposed off-site in permitted disposal facilities. A small amount of CCR, which consists of bottom ash, fly ash and air pollution control wastes, is disposed of at our Petersburg coal-fired power generation plant in an engineered, permitted landfill.
The EPA's final CCR rule became effective in October 2015 (the "CCR Rule"). Generally, the rule regulates CCR as
nonhazardous solid waste and establishes national minimum criteria for existing and new CCR landfills and existing and new CCR ash ponds, including location restrictions, design and operating criteria, groundwater monitoring,
corrective action and closure requirements and post-closure care. The 2016 Water Infrastructure Improvements for
the Nation Act ("WIIN Act") includes provisions to implement the CCR rule through a state permitting program, or if the state chooses not to participate, a federal permit program. On February 20, 2020, the EPA published a proposed rule to establish a federal CCR permit program that would operate in states without approved CCR permit programs. If this rule is finalized before Indiana establishes a final state-level CCR permit program, AES Indiana
could eventually be required to apply for a federal CCR permit from the EPA. On December 21, 2022, IDEM
published in the Indiana Register a Second Notice of Comment Period for its proposed CCR rulemaking which would include regulation of CCR through a state permitting program. In 2023, the Indiana legislature passed a law prohibiting IDEM from promulgating a CCR state permitting program that was more stringent than the federal CCR rule or imposed requirements not imposed by the federal CCR rule.
The EPA has indicated that they will implement a phased approach to amending the CCR Rule, which is ongoing. On January 11, 2022, EPA released its first in a series of proposed and final determinations regarding CCR Part A Rule demonstrations and compliance-related letters notifying certain other facilities of their compliance obligations under the federal CCR regulations. On April 8, 2022, petitions for review were filed challenging these EPA actions. The petitions are consolidated in Electric Energy, Inc. v. EPA. While AES Indiana has not received a proposed determination nor a letter, the determinations and letters include interpretations regarding implementation of the CCR Rule. It is too early to determine the impact of these letters or any determinations that may be made.
On May 18, 2023, EPA published a proposed rule that would expand the scope of CCR units regulated by the CCR Rule to include inactive surface impoundments at inactive generating facilities as well as additional inactive and closed landfills and certain other accumulations of CCR. It is too early to predict the outcome of this proposed rule and any potential impact.
The CCR Rule, current or proposed amendments to, or EPA interpretations of, the CCR Rule, Indiana CCR regulations, the results of groundwater monitoring data or the outcome of CCR-related litigation could have a material impact on our business, financial condition and results of operations. We would seek recovery of any resulting expenditures; however, there is no guarantee we would be successful in this regard. See Note 3, "Property, Plant and Equipment - ARO" and Note 10, "Commitments and Contingencies - Contingencies - Legal Matters - Coal Ash Insurance Litigation" to the Financial Statements of this Annual Report on Form 10-K for further discussion.
Regional Haze Rule
EPA’s 1999 Regional Haze Rule established timelines for states to improve visibility in national parks and wilderness areas throughout the United States by establishing reasonable progress goals toward meeting a national goal of natural visibility conditions in Class I areas by the year 2064 through submittal of a series of state implementation plans (SIPs). Indiana’s SIP for the first planning period (through 2018) did not require any additional controls to be installed or operated on AES Indiana generating facilities. For all future SIP planning periods, states must evaluate whether additional emissions reduction measures may be needed to continue making reasonable progress toward natural visibility conditions. On December 22, 2021, IDEM submitted Indiana's Regional Haze SIP for the Second Implementation Period to EPA for review and approval. The SIP does not include additional requirements for AES Indiana EGUs or for other EGUs in Indiana. However, we cannot predict the possible outcome or potential impacts of this matter at this time. We would seek recovery of capital expenditures; however, there is no guarantee we would be successful.
Climate Change Legislation and Regulation
One byproduct of burning coal and other fossil fuels is the emission of GHGs, including CO2. We face certain risks related to existing and potential international, federal, state, regional and local GHG legislation and regulations,
including risks related to increased capital expenditures or other compliance costs, as well as increased climate change disclosure obligations, which could have a material adverse effect on our results of operations, financial condition and cash flows.
The possible impact of any existing or future international, federal, regional or state GHG legislation, regulations or proposals will depend on various factors, including but not limited to:
▪The geographic scope of legislation and/or regulation (e.g., international, federal, regional, state), which entities are subject to the legislation and/or regulation (e.g., electricity generators, load-serving entities, electricity deliverers, etc.), the enactment date of the legislation and/or regulation and the compliance deadlines set forth therein;
▪The level of reductions of GHGs being sought by the regulation and/or legislation (e.g., 10%, 20%, 50%, etc.) and the year selected as a baseline for determining the amount or percentage of mandated GHG reduction (e.g., 10% reduction from 1990 emission levels, 20% reduction from 2000 emission levels, etc.);
▪The legislative and/or regulatory structure (e.g., a GHG cap-and-trade program, a carbon tax, GHG emission limits, etc.);
▪In any cap-and-trade program, the mechanism used to determine the price of emission allowances or offsets to be auctioned by designated governmental authorities or representatives;
▪If a cap-and-trade or similar market-based program is enacted, the price of offsets and emission allowances in the secondary market, including any price floors or price caps on the costs of offsets and emission allowances;
▪The operation of and emissions from regulated units;
▪The permissibility of using offsets to meet reduction requirements and the requirements of such offsets (e.g., type of offset projects allowed, the amount of offsets that can be used for compliance purposes, any geographic limitations regarding the origin or location of creditable offset projects), as well as the methods required to determine whether the offsets have resulted in reductions in GHG emissions and that those reductions are permanent (i.e., the verification method);
▪Whether the use of proceeds of any auction conducted by responsible governmental authorities is reinvested in developing new energy technologies, is used to offset any cost impact on certain energy consumers or is used to address issues unrelated to power;
▪How the price of electricity is determined, including whether the price includes any costs resulting from any new climate change legislation and the potential to transfer compliance costs pursuant to legislation, market or contract, to other parties;
▪Any impact on fuel demand and volatility that may affect the market clearing price for power;
▪The effects of any legislation or regulation on the operation of power generation facilities that may in turn affect reliability;
▪The availability and cost of carbon control technology;
▪The impact of any laws and regulations, supply or cost of fuels used by our generation facilities, including coal, natural gas or oil;
▪Whether any federal legislation regulating GHG emissions will preclude the EPA from regulating GHG emissions under the CAA or preempt private nuisance suits or other litigation by third parties;
▪Any opportunities to change the use of fuel at the generation facilities or opportunities to increase efficiency;
▪The extent of any required GHG emissions disclosure requirements in the forthcoming final version of the SEC's proposed 2022 climate change disclosure rule, including potential disclosure of Scope 1-3 GHG emissions; and
▪Our ability to recover any resulting costs from our customers and the timing of such recovery.
Except as noted in the discussion below, at this time, we cannot estimate the costs of compliance with existing,
proposed or potential international, federal, state or regional GHG emissions reductions legislation or initiatives due
in part to the fact that many of these proposals are in earlier stages of development and any final laws or
regulations, if adopted, could vary drastically from current proposals. Any international, federal, state or regional
legislation adopted in the U.S. that would require the reduction of GHG emissions could have a material adverse effect on our business and/or results of operations, financial condition and cash flows.
In the past, the U.S. Congress has considered several different draft bills pertaining to GHG legislation, including comprehensive GHG legislation that would impact many industries and more limited legislation focusing only on the
utility and electric generation industry. Although no legislation pertaining to GHG emissions has been passed to date
by the U.S. Congress, similar legislation may be considered or passed by the U.S. Congress in the future. In
addition, in the past Midwestern state governors (including the Governor of Indiana) and the premier of Manitoba,
Canada committed to reduce GHG emissions through the implementation of a cap-and-trade program pursuant to
the Midwestern Greenhouse Gas Reduction Accord. Though the participating states and province are no longer
pursuing this commitment, similar applicable state or regional initiatives may be pursued in the future.
The final NSPS for CO2 emissions from new, modified and reconstructed fossil-fuel-fired power plants were published in the Federal Register on October 23, 2015. Several states and industry groups challenged the NSPS for CO2 in the D.C. Circuit Court. On December 20, 2018, the EPA published proposed revisions to the final NSPS for new, modified and reconstructed coal-fired electric utility steam generating units. The EPA proposed that the Best System of Emissions Reduction (BSER) for these units is highly efficient generation that would be equivalent to supercritical steam conditions for larger units and sub-critical steam conditions for smaller units, and not partial carbon capture and sequestration (CCS), which had been the BSER for these units in the 2015 final NSPS. The EPA did not include revisions for natural-gas combined cycle or simple cycle units in the December 20, 2018 proposal. Challenges to the GHG NSPS remain held in abeyance at this time. On May 23, 2023, EPA published a proposed rule that would establish CO2 emissions limits for certain new fossil-fuel fired stationary combustion turbines that commence construction or are modified after May 23, 2023.
On July 8, 2019, the EPA published the final ACE Rule which would have established CO2 emission rules for existing coal-fired power plants under CAA Section 111(d) and would have replaced the EPA's 2015 CPP, which among other things, had called on states to mandate that power companies shift electricity generation to lower or zero carbon fuel sources. However, on January 19, 2021, the D.C. Circuit vacated and remanded to EPA the ACE Rule. Subsequently, on June 30, 2022, the U.S. Supreme Court reversed the judgment of the D.C. Circuit Court and
remanded for further proceedings consistent with its opinion, holding that the “generation shifting” approach in the CPP exceeded the authority granted to EPA by Congress under Section 111(d) of the CAA. As a result of the June 30, 2022 U.S. Supreme Court decision, on October 27, 2022, the D.C. Circuit issued a partial mandate holding pending challenges to the ACE Rule in abeyance while EPA developed a replacement rule.
On May 23, 2023, EPA published a proposed rule that would vacate the ACE Rule, establish emissions guidelines in the form of CO2 emissions limitations for certain existing EGUs and would require states to develop State Plans that establish standards of performance for such EGUs that are at least as stringent as EPA’s emissions guidelines. Depending on various EGU-specific factors, the bases of proposed emissions guidelines range from routine methods of operations to carbon capture and sequestration or co-firing low-GHG hydrogen starting in the 2030s.
Due to the uncertainty of these regulations, and existing and potential associated litigation, it is too early to determine the potential impact, but any rule could have a material impact on our business, financial condition and results of operations. We would seek recovery of any resulting capital expenditures; however, there is no guarantee we would be successful in this regard.
On the international level, on December 12, 2015, 195 nations, including the U.S., finalized the text of an
international climate change accord in Paris, France (the “Paris Agreement”), which agreement was signed and
officially entered into on April 22, 2016. The Paris Agreement calls for countries to set their own GHG emissions targets, make these emissions targets more stringent over time and be transparent about the GHG emissions reporting and the measures each country will use to achieve its GHG emissions targets. A long-term goal of the
Paris Agreement is to limit global temperature increase to well below two degrees Celsius from temperatures in the
pre-industrial era. The U.S. withdrawal from the Paris Agreement became effective on November 4, 2020. However,
on January 20, 2021, President Biden signed and submitted an instrument for the U.S. to rejoin the Paris Agreement, which became effective on February 19, 2021. In November 2023, the international community
gathered for the 28th Conference to the Parties on the UN Framework Convention on Climate Change (“COP28”). The Parties agreed to non-binding language calling on countries to transition away from fossil fuels in energy systems to achieve net zero emissions by 2050.
Based on the above, there is some uncertainty with respect to the impact of GHG rules on AES Indiana. The EPA, states and other utilities are still evaluating potential impacts of the GHG regulations in our industry. In light of these uncertainties, we cannot predict the impact of the EPA’s current and future GHG regulations on our consolidated results of operations, cash flows, and financial condition, but it could be material.
Unit Retirements and Replacement Generation
In December 2019, AES Indiana filed its 2019 IRP, which included plans to retire approximately 630 MW of coal-fired generation at Petersburg Units 1 and 2 in 2021 and 2023, respectively. AES Indiana retired 230 MW Petersburg Unit 1 in May 2021 and 415 MW Petersburg Unit 2 in June 2023. AES Indiana filed its 2022 IRP with the IURC in December 2022. The 2022 IRP short-term action plan includes converting the two remaining coal units at Petersburg to natural gas. AES Indiana has not yet filed for the regulatory approvals from the IURC to convert Petersburg units 3 and 4; however, AES Indiana expects to do so in the first half of 2024. Additionally, AES Indiana plans to add up to 1,300 MW of wind, solar, and battery energy storage by 2027. In December 2023, the first stage of construction for the Hardy Hills Solar Project was completed and placed in service, with initial operations for over half of the project commencing on December 28, 2023. For further discussion, see Note 2, "Regulatory Matters - IRP Filings and Replacement Generation - 2022 IRP" to the Financial Statements of this Annual Report on Form 10-K.
NSR and Other CAA NOVs
See Note 10, “Commitments and Contingencies - Contingencies - Environmental Matters - NSR and other CAA NOVs” to the Financial Statements of this Annual Report on Form 10-K for additional details.
NAAQS
Under the CAA, the EPA sets NAAQS for six criteria pollutants considered harmful to public health and the environment, including particulate matter, NOx, ozone and SO2, which result from fossil-fuel combustion. Areas meeting the NAAQS are designated attainment areas while those that do not meet the NAAQS are considered nonattainment areas. Each state must develop a plan to bring nonattainment areas into compliance with the NAAQS, which may include imposing operating limits on individual plants. The EPA is required to review NAAQS at five-year intervals.
Ozone. In October 2015, the EPA published a final rule lowering the NAAQS for ozone to 70 parts per billion from 75 parts per billion. The EPA published its final designations for the areas in which our operations are located on November 16, 2017. None of our operations are located in areas designated as nonattainment.
In March 2018, the state of New York submitted a petition to the EPA pursuant to Section 126 of the CAA requesting new limitations on NOx emissions from dozens of upwind generating stations, including AES Indiana's Petersburg, Harding Street, and Eagle Valley stations on the basis that they are contributing significantly to New York’s ability to meet the 2008 ozone NAAQS. On July 14, 2020, the D.C. Circuit Court vacated and remanded EPA’s denial of the petition. EPA must now issue a new decision based on the Court’s decision. If the Section 126 petition is ultimately granted, our units could be subject to additional requirements, which could be material. We would seek recovery of any resulting capital expenditures; however, there is no guarantee we would be successful.
Fine Particulate Matter. In 2013, the EPA published the 2012 annual PM2.5 standard of 12 micrograms per cubic meter of air and the 24-hour PM2.5 standard of 35 micrograms per cubic meter of air. In 2015, the EPA published its final attainment designations for the 2012 PM2.5 standard. In addition to the PM2.5 standard, there is also a 24-hour PM10 standard of 150 micrograms per cubic meter of air. No AES Indiana operations are currently located in nonattainment areas. On January 27, 2023, the EPA published a proposed rule to lower the primary annual PM2.5 NAAQS from 12 micrograms per cubic meter to a level between 9 and 10 micrograms per cubic meter and to maintain other PM NAAQS at current levels. On February 7, 2024, EPA released a final rule lowering the primary annual PM2.5 NAAQS from 12 micrograms per cubic meter to 9 micrograms per cubic meter.
SO2. In 2010, a new one-hour SO2 primary NAAQS became effective. In 2015, IDEM published its final rule establishing reduced SO2 limits for AES Indiana facilities in accordance with the 2010 one-hour standard with compliance required by January 1, 2017. Improvements to the existing FGD systems at Petersburg station were required to meet the emission limits imposed by the rule. All areas in which AES Indiana operates have been subsequently redesignated and are no longer designated as nonattainment.
Based on these current and potential national ambient air quality standards, the state of Indiana is required to determine whether certain areas within the state meet the NAAQS. With respect to Marion, Morgan and Pike Counties, as well as any other areas determined to be in "nonattainment," the state of Indiana will be required to modify its SIP to detail how the state will regain its attainment status. As part of this process, it is possible that the
IDEM or the EPA may require reductions of emissions from our generating stations to reach attainment status for ozone, fine particulate matter or SO2. At this time, we cannot predict what the impact will be to AES Indiana with respect to new ambient standards, but it could be material.
CSAPR and 2015 Ozone NAAQS FIP
CSAPR, which became effective in January 2015, addresses the "good neighbor" provision of the CAA, which prohibits sources within each state from emitting any air pollutant in an amount which will contribute significantly to any other state’s nonattainment, or interference with maintenance of, any NAAQS. CSAPR is implemented, in part, through a market-based program under which compliance may be achievable through the acquisition and use of emissions allowances created by the EPA. In October 2016, the EPA published a final rule to update the CSAPR to address the 2008 ozone NAAQS (“CSAPR Update Rule”). Following legal challenges related to the CSAPR Update Rule, on April 30, 2021, EPA issued the Revised CSAPR Update Rule. The Revised CSAPR Update Rule required affected EGUs within certain states (including Indiana) to participate in a new trading program, the CSAPR NOx Ozone Season Group 3 trading program. These affected EGUs received fewer NOx Ozone Season allowances beginning in 2021.
On June 5, 2023, the EPA published a final Federal Implementation Plan ("FIP") to address air quality impacts with respect to the 2015 Ozone NAAQS. The rule established a revised CSAPR NOx Ozone Season Group 3 trading program for 22 states, including Indiana and became effective during 2023. The FIP also includes enhancements in the revised Group 3 trading program which include a dynamic budget setting process beginning in 2026, annual recalibration of the allowance bank to reflect changes to affected sources, a daily backstop emissions rate limit for certain coal-fired electric generating units beginning in 2024, and a secondary emissions limit prohibiting certain emissions associated with state assurance levels.
At this time we cannot predict the impact of these rule revisions or potential future legal outcomes, but any such impact could include the need to purchase additional allowances or make operational adjustments or could otherwise be material to our business, financial condition or results of operation.
CWA - Facility Response Plan
On March 28, 2022, the EPA published a proposed rule to establish Facility Response Plan (“FRP”) requirements for non-transportation onshore facilities that store CWA hazardous substances and meet certain criteria and thresholds. It is too early to determine whether this proposed rule may have a material impact on our business, financial condition or results of operation.
CWA - Environmental Wastewater Requirements and Regulation of Water Discharge
In November 2015, the EPA published its final Steam ELG rule to reduce toxic pollutants discharged into waterways by steam-electric power plants through technology applications. In 2020, EPA issued a final rule, known as the 2020 Reconsideration Rule, revising certain aspects of the 2015 ELG rule. Wastewater treatment technologies already installed and operated at Petersburg met the requirements of these rules. Following the 2019 U.S. Court of Appeals vacatur and remand of portions of the 2015 ELG rule related to leachate and legacy water, on March 29, 2023, EPA published a proposed rule revising the 2020 Reconsideration Rule. The proposed rule would establish new best available technology economically achievable effluent limits for flue gas desulfurization wastewater, bottom ash treatment water, and combustion residual leachate. It is too early to determine whether any outcome of this proposed rule, litigation or current or future revisions to the ELG rule might have a material impact on our business, financial condition and results of operations.
On April 23, 2020, the U.S. Supreme Court issued a decision in the Hawaii Wildlife Fund v. County of Maui case related to whether a CWA permit is required when pollutants originate from a point source but are conveyed to navigable waters through a nonpoint source such as groundwater. The Court held that discharges to groundwater require a permit if the addition of the pollutants through groundwater is the functional equivalent of a direct discharge from the point source into navigable waters. A number of legal cases relevant to determination of "functional equivalent" are ongoing in various jurisdictions. On November 27, 2023, EPA issued a draft guidance addressing how the Supreme Court decision would be applied to the NPDES permit program as it relates to functional equivalent discharge. It is too early to determine whether the U.S. Supreme Court decision,
implementation thereof, or the result of litigation related to "functional equivalent" determination may have a material impact on our business, financial condition or results of operations.
The concept of WOTUS defines the geographic reach and authority of the U.S. Army Corps of Engineers and EPA (together, the "Agencies") to regulate streams, wetlands, and other water bodies under the CWA. There have been multiple Supreme Court decisions and dueling regulatory definitions over the past several years concerning the appropriate standard for how to properly determine whether a wetland or stream that is not navigable is considered a WOTUS. On May 25, 2023, the U.S. Supreme Court rendered a decision (Decision) in the case of Sackett v. Environmental Protection Agency, addressing the definition of WOTUS with regards to the CWA. This decision provides a standard that substantially restricts the Agencies' ability to regulate certain types of wetlands and streams. Specifically, under this decision, wetlands that do not have a continuous surface connection with traditional interstate navigable water are not considered a WOTUS and therefore are not federally jurisdictional.
On September 8, 2023, the Agencies published final amendments to the “Revised Definition of ‘Waters of the United States’” rule. These final rule amendments conform the definition of WOTUS to the definition adopted in the Decision. The Agencies have amended key aspects of the regulatory text to conform the rule to the Decision.
It is too early to determine whether any outcome of litigation or current or future revisions to rules interpreting federal jurisdiction over WOTUS might have a material adverse effect on our results of operations, financial condition and cash flows.
CWA - Cooling Water Intake Regulations
We use water as a coolant at our generating stations. Under the CWA, cooling water intake structures are required to reflect the BTA for minimizing adverse environmental impact. In 2014, the EPA's final standards became effective to protect fish and other aquatic organisms drawn into cooling water systems at large power plants and other facilities. These standards, based on Section 316(b) of the CWA, require affected facilities to choose amongst seven BTA options to reduce fish impingement. In addition, certain facilities must conduct studies to assist permitting authorities to determine whether and what site-specific controls, if any, would be required to reduce entrainment of aquatic organisms. It is possible this process, which includes permitting and public input, could result in the need to install closed-cycle cooling systems (closed-cycle cooling towers) or other technology. Finally, the standards require that new units added to an existing facility must reduce both impingement and entrainment that achieves one of two alternatives under national BTA standards. AES Indiana’s NPDES permits as described below will be updated with the requirements of this rule, including any source-specific requirements arising from the evaluation process described above. At this time it is not yet possible to predict the total impacts of this final rule, including any challenges to such final rule and the outcome of any such challenges. However, if additional capital expenditures are necessary, they could be material. We would seek recovery of these capital expenditures; however, there is no guarantee we would be successful.
CWA - NPDES Permits
National Pollutant Discharge Elimination System (NPDES) permits regulate specific industrial wastewater and storm water discharges to the waters of Indiana under Section 402 of the Federal Water Pollution Control Act. A number of CWA regulations described above are implemented through NPDES permits.
In 2017, IDEM issued to Eagle Valley a NPDES permit regulating water discharges associated with operation of its CCGT. As part of the normal course of business, AES Indiana submitted a timely application for renewal for the Eagle Valley NPDES permit, and on March 31, 2023, IDEM issued the renewed NPDES permit. On April 17, 2023, a third party filed an appeal of Eagle Valley’s renewed NPDES permit. AES Indiana contends that the renewed permit was validly issued, and the permit remains in effect. AES Indiana is unable to predict the outcome of the appeal, but depending on the results, it could have an adverse effect on the Company.
In 2017, IDEM also issued to Harding Street and Petersburg NPDES permits regulating water discharges associated with operation of their power plant operations. As part of the normal course of business, AES Indiana submitted timely applications for renewal for both Harding Street and Petersburg NPDES permits in March 2022. On November 29, 2023, IDEM issued the final NPDES permit renewal for Harding Street with an effective date of January 1, 2024. The permit includes a 316(b) determination requiring the installation of modified traveling screens and fish handling return system and an entrainment study. The permit also includes other new requirements,
including new thermal limitations, that could result in the need for AES Indiana to take additional actions to ensure compliance with the final permit. On December 14, 2023, AES Indiana filed a petition for appeal of certain new requirements, including the new thermal limitations, in the final Harding Street NPDES permit. A stay of the appealed requirements was granted on January 4, 2024, and is in effect until April 15, 2024, which could be further extended. It is too early to determine the potential impact, but final or future permits could have a material impact on our business, financial condition and results of operations. We would seek recovery of any resulting capital expenditures; however, there is no guarantee we would be successful in this regard. The renewal application for the Petersburg NPDES permit remains pending.
ENERGY SUPPLY
Total electricity sold to our retail customers in 2023 came from the following sources: 58.3% from AES Indiana-owned natural gas-fired units, 30.6% from AES Indiana-owned coal-fired steam generation, and 11.1% from power purchased under power purchase agreements (primarily wind and solar) and from the wholesale power market.
Natural gas accounted for approximately 64% of the total kWh we generated in 2023, as compared to 42% in 2022 and 28% in 2021. Natural gas is used in our steam boiler units at Harding Street Station, our CCGT at Eagle Valley and combustion turbines at Georgetown. AES Indiana sources natural gas from the wholesale market delivered to our plants by interstate pipeline and local distribution companies. AES Indiana holds firm pipeline transportation commitments on Texas Gas Transmission, Rockies Express Pipeline, LLC, Trunkline Gas Company, LLC, Panhandle Eastern Pipeline Company, and has firm redelivery contracts with the local distribution companies that serve AES Indiana plants. AES Indiana has established physical natural gas hedges for firm supply over a two year period in accordance with a hedge program approved by the IURC. Hedge percentages vary by season with winter the highest percentage of coverage. Eagle Valley returned from an extended outage in March of 2022 and the hedge program was initiated after the return date. We have natural gas inventory related to a storage agreement with Citizens Energy Group which provides natural gas supply to Harding Street Station.
Coal and fuel oil provided the remaining kWh generation in 2023. Approximately 36% of the total kWh we generated in 2023 was from coal as compared to approximately 58% and 72% in 2022 and 2021, respectively. In 2021 and early in 2022, coal was a higher percentage of kWh generated due to an extended outage at the Eagle Valley CCGT plant, and we expect this percentage to be lower going forward. Additionally, AES Indiana plans to convert the remaining two coal units at Petersburg to natural gas (for further discussion, see Note 2, “Regulatory Matters - IRP Filings and Replacement Generation - 2022 IRP” to the Financial Statements of this Annual Report on Form 10-K). Our existing coal contracts provide for approximately 100% of our current projected requirements in 2024 and approximately 83% in total for the two-year period ending December 31, 2025. We have long-term coal contracts with one supplier. Pricing provisions in some of our long-term coal contracts allow for price changes under certain circumstances. Substantially all of our coal is currently mined in the state of Indiana, and all of our coal supply is mined by unaffiliated suppliers or third parties. Our goal is to carry a 25-50 day system supply of coal to offset unforeseen occurrences such as equipment breakdowns and transportation or mine delays. Our present inventory is above our target range. Fuel oil accounted for less than 1% of the total kWh we generated in 2023, 2022, and 2021, and is used for start-up and flame stabilization in coal-fired generating units, as primary fuel in two older combustion turbines, and as an alternate fuel in two other combustion turbines.
As a result of the completion of the CCGT at the Eagle Valley Station in 2018, the Harding Street Station refueling projects in 2015 and 2016, the retirement of coal-fired units at Eagle Valley in 2016, and the 2021, 2023 and future retirement of coal-fired units at Petersburg, we generally have experienced and expect to continue to experience an increase in the percentage of generation from natural gas and renewable projects. Due to outages at the Eagle Valley CCGT this was not the case in 2021 and early 2022, however we expect to continue experiencing an increase in the percentage of generation from natural gas and renewable projects going forward. The generation fuel mix from coal and natural gas will continue to change as the relative prices of the commodities change and as our generation portfolio changes.
See Note 2 “Regulatory Matters - IRP Filings and Replacement Generation” to the Financial Statements of this Annual Report on Form 10-K for further discussion of AES Indiana's Preferred Resource Portfolio for meeting generation capacity needs for serving AES Indiana's retail customers over the next several years, including the acquisition and development of the Hardy Hills Solar Project and Petersburg Energy Center Project, the development of the Pike County BESS Project, acquisition of the Hoosier Wind Project, and the conversion of the remaining two coal units at Petersburg to natural gas.
Additionally, we meet the electricity demands of our retail customers with energy purchased under power purchase agreements and by power purchases in MISO. We are currently committed under long-term power purchase agreements to purchase all energy from two wind projects that have a combined maximum output capacity of 300 MW, including the Hoosier Wind Project. AES Indiana received IURC approval for the acquisition of the Hoosier Wind Project in January 2024 (see Note 2, “Regulatory Matters - IRP Filings and Replacement Generation - Hoosier Wind Project” to the Financial Statements of this Annual Report on Form 10-K). We have 94.5 MW of solar-generated electricity in our service territory under long-term contracts, of which 94.0 MW was in operation as of December 31, 2023. We also purchase up to 8 MW of energy from a combined heat and power facility located in Indianapolis, Indiana.
AES Indiana retired Petersburg Unit 1 in May 2021 and Petersburg Unit 2 in June 2023. In addition, AES Indiana’s most recent 2022 IRP short-term action plan includes the conversion of Petersburg Units 3 and 4 from coal to gas as part of AES Indiana’s preferred portfolio. AES Indiana has not yet filed for the regulatory approvals from the IURC to convert Petersburg units 3 and 4; however, AES Indiana expects to do so in the first half of 2024.
After the conversion of Petersburg Units 3 and 4 from coal to natural gas, we will no longer have any coal fired generation in our generation portfolio. Upon the completion of our various renewable projects (e.g., Hardy Hills Solar Project, Petersburg Energy Center Project, Pike County BESS Project, Hoosier Wind Project, etc.) and the Petersburg unit conversions, we expect our installed capacity to be approximately 74% from AES Indiana-owned natural gas-fired units, 16% from AES Indiana-owned renewable projects, and 10% from wind and solar power purchase agreements.
STATISTICAL INFORMATION ON OPERATIONS
The following table of statistical information presents additional data on our operations:
Years Ended December 31,
2023 2022 2021 2020 2019
Revenue (In Thousands):
Residential $ 668,209 $ 698,648 $ 607,260 $ 575,329 $ 597,809
Small commercial and industrial 238,595 247,884 212,169 194,904 215,878
Large commercial and industrial 635,221 644,181 541,471 500,208 564,216
Public lighting 10,013 9,784 8,994 9,257 7,335
Other(1)
24,615 17,845 16,785 14,402 14,136
Retail electric revenue 1,576,653 1,618,342 1,386,679 1,294,100 1,399,374
Wholesale 56,557 148,517 25,059 46,482 68,474
Miscellaneous 16,707 24,852 14,394 12,403 13,795
Total revenue $ 1,649,917 $ 1,791,711 $ 1,426,132 $ 1,352,985 $ 1,481,643
kWh Sales (In Millions):
Residential 4,800 5,305 5,172 5,115 5,200
Small commercial and industrial 1,722 1,823 1,774 1,709 1,840
Large commercial and industrial 5,929 6,091 6,006 5,839 6,283
Public lighting 19 18 21 30 42
Sales - retail customers 12,470 13,237 12,973 12,693 13,365
Wholesale 1,657 2,148 908 1,866 2,718
Total kWh sold 14,127 15,385 13,881 14,559 16,083
Retail Customers at End of Year:
Residential 462,848 458,585 455,756 451,735 448,210
Small commercial and industrial 54,998 55,210 55,078 54,253 53,751
Large commercial and industrial 4,456 4,517 4,506 4,567 4,635
Public lighting 1,093 1,007 983 986 980
Total retail customers 523,395 519,319 516,323 511,541 507,576
(1) Other retail revenue includes miscellaneous charges to customers.
HOW TO CONTACT IPALCO AND SOURCES OF OTHER INFORMATION
Our principal executive offices are located at One Monument Circle, Indianapolis, Indiana 46204, and our telephone number is (317) 261-8261. Our website address is www.aesindiana.com. The information on our website is not
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 purchased power costs and other liabilities, and these liabilities could become significant for which we may not have adequate insurance coverage.
We operate generating facilities, including those using coal, oil, natural gas, and renewable energy, which involve certain risks that can adversely affect energy costs, output and efficiency levels. These risks include:
•unit or facility shutdowns due to a breakdown or failure of equipment or processes;
•increased prices for fuel and fuel transportation as existing contracts expire or as such contracts are adjusted through price re-opener provisions or automatic adjustments;
•disruptions in the availability or delivery of fuel and lack of adequate inventories;
•shortages of or delays in obtaining equipment;
•loss of cost-effective disposal options for solid waste generated by the facilities;
•accidents and injuries;
•reliability of our suppliers;
•inability to comply with regulatory or permit requirements;
•operational restrictions resulting from environmental or permit limitations or governmental interventions;
•construction delays and cost overruns;
•disruptions in the delivery of electricity;
•labor disputes or work stoppages by employees;
•the availability of qualified personnel;
•events occurring on third party systems that interconnect to and affect our system;
•operator error; and
•catastrophic events.
We experience unscheduled plant outages, unanticipated operation and/or maintenance expenses, increased capital expenditures and/or increased fuel and purchased power costs from time to time, any of which could have a material adverse effect on our results of operations, financial condition and cash flows. These risks are partially mitigated by our ability to generally pass fuel and purchased power costs through to customers through the FAC. If unexpected plant outages occur frequently and/or for extended periods of time, this could result in adverse regulatory action that may have a significant impact on our results of operations, financial condition and cash flows.
Additionally, as a result of the above risks and other potential hazards associated with the power generation industry, we may from time to time become exposed to significant liabilities for which we may not have adequate insurance coverage. Power generation involves hazardous activities, including acquiring, transporting and unloading fuel, operating large pieces of rotating equipment and delivering electricity to transmission and distribution systems. The control and management of these risks depend upon adequate development and training of personnel and on the existence of operational procedures, preventative maintenance plans and specific programs supported by quality control systems which reduce, but do not eliminate, the possibility of the occurrence and impact of these risks.
The hazardous activities described above can also cause personal injury or loss of life, damage to and destruction of property, plant and equipment, contamination of, or damage to, the environment and suspension of operations. The occurrence of any one of these events results in us from time to time being named as a defendant in lawsuits asserting claims for damages, environmental cleanup costs, personal injury and fines and/or penalties. We maintain an amount of insurance protection that we believe is adequate, but there can be no assurance that our insurance will be sufficient or effective under all circumstances and against all hazards or liabilities to which we may be subject. A successful claim that is significant for which we are not fully insured could adversely and materially affect our results of operations, financial condition and cash flows. In addition, except for our large substations, transmission and distribution assets are not covered by insurance and are considered to be outside the scope of property insurance. Further, due to rising insurance costs and changes in the insurance markets, we cannot provide assurance that insurance coverage will continue to be available on terms similar to those presently available to us or at all. Any such losses not covered by insurance could have a material adverse effect on our financial condition, results of operations and cash flows.
We may be negatively affected by a lack of growth or a decline in the number of customers or in customer usage.
Customer growth and customer usage are affected by a number of factors outside our control, such as energy efficiency and DSM measures, population changes, job and income growth, housing starts, new business formation and the overall level of economic activity. A significant lack of growth, or a decline, in the number of customers in our service territory or in customer demand for electricity could have a material adverse effect on our results of operations, financial condition and cash flows and may cause us to fail to fully realize anticipated benefits from investments and expenditures.
The cost of fuel and other commodities have experienced and could continue to experience volatility and we may not be able to hedge the entire exposure of our operations from availability and price volatility. In addition, until our coal units are converted or retired, a portion of our electricity is generated by coal.
Our business is sensitive to changes in the price of natural gas, coal, purchased power and emissions allowances. In addition, changes in the prices of steel, copper and other raw materials can have a significant impact on our costs. We also are dependent on purchased power, in part, to meet our seasonal planning reserve margins. Any changes in fuel prices could affect the prices we charge, our operating costs and our competitive position with respect to our products and services. The cost of fuel and other commodities has been volatile in recent years and we expect that volatility to continue.
Our exposure to fluctuations in the price of fuel is limited because, pursuant to Indiana law, we apply to the IURC for a change in our FAC every three months to recover our estimated fuel costs, which may be above or below the levels included in our basic rates and charges. In addition, we apply to recover the energy portion of our purchased power costs in these quarterly FAC proceedings subject to a benchmark (please see Note 2, “Regulatory Matters - FAC and Authorized Annual Jurisdictional Net Operating Income” to the Financial Statements of this Annual Report on Form 10-K for additional details regarding the benchmark and the process to recover fuel costs). As part of this cost-recovery process, we must present evidence in each proceeding that we have made every reasonable effort to acquire fuel and generate or purchase power or both so as to provide electricity to our retail customers at the lowest fuel cost reasonably possible. If we are unable to timely or fully recover our fuel and purchased power costs, it could have a material adverse effect on our results of operations, financial condition and cash flows.
Approximately 36% of the energy we produced in 2023 was generated by coal as compared to approximately 58% and 72% in 2022 and 2021, respectively. While we have approximately 83% in total of our current coal requirements for the two-year period ending December 31, 2025 under long-term contracts as of the date of this report, the balance is yet to be purchased and will be purchased under a combination of long-term contracts, short-term contracts and on the spot market. Prices can be highly volatile in both the short-term market and on the spot market. The coal market has experienced price volatility in the last several years. We are now in a global market for coal in which our domestic price is increasingly affected by international supply disruptions and demand balance. Coal exports from the U.S. have increased significantly at times in recent years. In addition, domestic developments such as government-imposed direct costs and permitting issues that affect mining costs and supply availability, and the variable demand of retail customer load and the performance of our generation fleet have an impact on our fuel procurement operations. In addition, pricing provisions in some of our coal contracts with terms of one year or more allow for price changes under certain circumstances.
Because of our dependence on coal to meet customer demand for electricity, our business and operations could be materially adversely affected by unexpected price volatility in the coal market, price increases pursuant to the provisions of certain of our long-term coal contracts, and the continued regulatory and political scrutiny of coal. As discussed below, regulators, politicians and non-governmental organizations have expressed concern about GHG emissions and are taking actions which, in addition to the potential physical risk associated with climate change, could have a material adverse impact on our results of operations, financial condition and cash flows. Our dependence on coal also means that the output of our coal-fired generation units can be greatly affected by the costs of other fuels combusted by generation facilities that compete with our coal-fired generation units. Until 2021, natural gas prices over the last several years have been relatively low and some gas-fired generators that previously were primarily used during periods of peak and intermediate electric demand have run even during periods of relatively low demand. This can cause many coal-fired generators, including ours, to run fewer hours during these periods of base-load demand. The cyclical nature of commodity markets makes this a possibility in the future, however, we would expect any retirement of our coal-fired generators to reduce the potential impact of these events due to lower volumes of coal in our generation fleet.
In addition, substantially all of our coal supply is currently mined in the state of Indiana, and all of our coal supply is currently mined by unaffiliated suppliers or third parties. Our current goal is to carry a 25-50 day system supply of coal to offset unforeseen occurrences such as equipment breakdowns and transportation or mine delays. AES Indiana typically has long-term contracts with a small number of suppliers of coal. In recent years, the coal industry has undergone significant restructuring as a result of debt restructurings, bankruptcy proceedings and other factors. Further restructuring may result in a failure of our suppliers to fulfill their contractual obligations or fewer suppliers and, consequently, increased dependency on any one supplier. Any significant disruption in the ability of our suppliers, particularly our most significant suppliers, to mine or deliver coal or other fuel, or any failure on the part of our suppliers to fulfill their contractual obligations could have a material adverse effect on our business. In the event of disruptions or failures, there can be no assurance that we would be able to find another supplier of fuel on similarly favorable terms, which could also limit our ability to recover fuel costs through the FAC proceedings.
Catastrophic events could adversely affect our facilities, systems and operations.
Catastrophic events such as fires, explosions, cyber-attacks, terrorist acts, acts of war, acts of sabotage or vandalism, pandemic events, or natural disasters such as floods, earthquakes, tornadoes, severe winds, ice or snow storms, droughts or other similar occurrences could adversely affect our generation facilities, transmission and distribution systems, results of operations, financial condition and cash flows. Our Petersburg Plant, which is our largest source of generating capacity, is located in the Wabash Valley seismic zone, adjacent to the New Madrid seismic zone, which are both areas of significant seismic activity in the central U.S.
Our business is sensitive to weather and seasonal variations.
Weather conditions significantly affect the demand for electric power, and accordingly, our business is affected by variations in general weather conditions and unusually severe weather. As a result of these factors, our operating revenue and associated operating expenses are not generated evenly by month during the year. We forecast electric sales on the basis of normal weather, which represents a long-term historical average. Significant variations from normal weather (such as warmer winters and cooler summers) could have a material impact on our revenue, operating income and net income and cash flows. In addition, severe or unusual weather, such as floods, tornadoes and ice or snow storms, may cause outages and property damage that may require us to incur additional costs that may not be insured or recoverable from customers. While we are permitted to seek recovery of certain severe storm damage costs, if we are unable to fully recover such costs in a timely manner, it could have a material adverse effect on our results of operations, financial condition and cash flows.
Our membership in a RTO presents risks that could have a material adverse effect on our results of operations, financial condition and cash flows.
We are a member of MISO, a FERC-regulated RTO. MISO serves the electrical transmission needs of a 15-state area including much of the Mid-U.S. and Canada and maintains functional operational control over our electric transmission facilities, as well as that of the other utility members of MISO. We retain control over our distribution facilities. As a result of membership in MISO and its operational control, our continued ability to import power, when necessary, and export power to the wholesale market has been, and may continue to be, impacted. We offer our generation and bid our load into this market on a day-ahead basis and settle differences in real time. Given the
nature of MISO’s policies regarding use of transmission facilities, and its administration of the energy and ancillary services markets, it is difficult to predict near-term operational impacts. We cannot assure MISO’s reliable operation of the regional transmission system, or the impact of its operation of the energy and ancillary services markets.
The rules governing the various regional power markets may also change from time to time which could affect our costs and revenue and have a material adverse effect on our results of operations, financial condition and cash flows. We may expand or otherwise change our transmission system according to decisions made by MISO in addition to our internal planning process. In addition, various proposals and proceedings before the FERC relating to MISO or otherwise may cause transmission rates to change from time to time. We also incur fees and costs to participate in MISO.
To the extent that we rely, at least in part, on the performance of MISO to maintain the reliability of our transmission system, it puts us at some risk for the performance of MISO. In addition, actions taken by MISO to secure the reliable operation of the entire transmission system operated by MISO could result in voltage reductions, rolling blackouts, or sustained system-wide blackouts on AES Indiana’s transmission and distribution system, any of which could have a material adverse effect on our results of operations, financial condition and cash flows. See also “Item 1. Business - MISO Operations" and “Item 1. Business - Regulation - Retail Ratemaking.”
Our transmission and distribution system is subject to operational, reliability and capacity risks.
The ongoing reliable performance of our transmission and distribution system is subject to risks due to, among other things, weather damage, intentional or unintentional damage, equipment or process failure, catastrophic events, such as fires and/or explosions, facility outages, labor disputes, accidents or injuries, operator error, or inoperability of key infrastructure internal or external to us and events occurring on third party systems that interconnect to and affect our system. The failure of our transmission and distribution system to fully operate and deliver the energy demanded by customers could have a material adverse effect on our results of operations, financial condition and cash flows, and if such failures occur frequently and/or for extended periods of time, could result in adverse regulatory action. In addition, the advent and quick adaptation of new products and services that require increased levels of electrical energy cannot be predicted and could result in insufficient transmission and distribution system capacity. As with all utilities, potential concern with the adequacy of transmission capacity on AES Indiana’s system or the regional systems operated by MISO could result in MISO, the NERC, the FERC or the IURC requiring us to upgrade or expand our transmission system through additional capital expenditures or share in the costs of regional expansion. Also, as a result of the above risks and other potential risks and hazards associated with transmission and distribution operations, we may from time to time become exposed to significant liabilities for which we may not have adequate insurance coverage. Except for AES Indiana’s large substations, transmission and distribution assets are not covered by insurance and are considered to be outside the scope of property insurance. Otherwise, we maintain an amount of insurance protection that we believe is adequate, but there can be no assurance that our insurance will be sufficient or effective under all circumstances and against all hazards or liabilities to which we may be subject. Further, any increased costs or adverse changes in the insurance markets may cause delays or inability in maintaining insurance coverage on terms similar to those presently available to us or at all. A successful claim for which we are not fully insured could have an adverse impact on our results of operations, financial condition and cash flows.
Current and future conditions in the economy may adversely affect our customers, suppliers and other counterparties in a way which could materially and adversely affect our results of operations, financial condition and cash flows.
Our business, results of operations, financial condition and cash flows have been and will continue to be affected by general economic conditions. Slowing economic growth, credit market conditions, fluctuating consumer and business confidence, fluctuating commodity prices, and other challenges affecting the general economy, have caused and may continue to cause some of our customers to experience deterioration of their businesses, cash flow shortages, and difficulty obtaining financing. As a result, existing customers may reduce their electricity consumption and may not be able to fulfill their payment obligations to us in the normal, timely fashion. In addition, some existing commercial and industrial customers may discontinue their operations. Sustained downturns, recessions or a sluggish economy generally affect the markets in which we operate and negatively influence our energy operations. A contracting, slow or sluggish economy could reduce the demand for energy in areas in which we are doing business. For example, during economic downturns, our commercial and industrial customers may see a decrease in demand for their products, which in turn may lead to a decrease in the amount of energy they require. Furthermore, projects which may result in potential new customers may be delayed until economic
conditions improve. Some of our suppliers, customers and other counterparties, and others with whom we transact business experience financial difficulties, which may impact their ability to fulfill their obligations to us. For example, our counterparties on forward purchase contracts and financial institutions involved in our credit facility may become unable to fulfill their contractual obligations to us or result in their declaring bankruptcy or similar insolvency-like proceedings. We may not be able to enter into replacement agreements on terms as favorable as our existing agreements. Reduced demand for our electric services, failure by our customers to timely remit full payment owed to us and supply delays or unavailability could have a material adverse effect on our results of operations, financial condition and cash flows. In particular, the projected economic growth and total employment in Indianapolis are important to the realization of our forecasts for annual energy sales.
Economic conditions relating to the asset performance and interest rates of the Pension Plans could materially and adversely impact our results of operations, financial condition and cash flows.
Pension costs are based upon a number of actuarial assumptions, including an expected long-term rate of return on pension plan assets, level of employer contributions, the expected life span of pension plan beneficiaries and the discount rate used to determine the present value of future pension obligations. Any of these assumptions could prove to be wrong, resulting in a shortfall of our Pension Plans’ assets compared to pension obligations under the Pension Plans. Further, the performance of the capital markets affects the values of the assets that are held in trust to satisfy future obligations under the Pension Plans. These assets are subject to market fluctuations and will yield uncertain returns, which may fall below our projected return rates. A decline in the market value of the Pension Plans’ assets will increase the funding requirements under the Pension Plans if the actual asset returns do not recover these declines in value in the foreseeable future. Future pension funding requirements, and the timing of funding payments, may also be subject to changes in legislation. We are responsible for funding any shortfall of our Pension Plans’ assets compared to obligations under the Pension Plans, and a significant increase in our pension liabilities could materially and adversely impact our results of operations, financial condition, and cash flows. We are subject to the Pension Protection Act of 2006, which requires underfunded pension plans to improve their funding ratios within prescribed intervals based on the level of their underfunding. As a result, our required contributions to these plans, at times, have increased and may increase in the future. In addition, our pension and postemployment benefit plan liabilities are sensitive to changes in interest rates. If interest rates decrease, the discounted liabilities increase benefit expense and funding requirements. Further, changes in demographics, including increased numbers of retirements or changes in life expectancy assumptions, may also increase the funding requirements for the obligations related to the pension and other postemployment benefit plans. Declines in market values and increased funding requirements could have a material adverse effect on our results of operations, financial condition and cash flows. Please see Note 8, “Benefit Plans” to the Financial Statements of this Annual Report on Form 10-K for further discussion.
Counterparties providing materials or services may fail to perform their obligations, which could materially and adversely impact our results of operations, financial condition and cash flows.
We enter into transactions with and rely on many counterparties in connection with our business, including for the purchase and delivery of inventory, including fuel and equipment components, for our capital improvements and additions and to provide professional services, such as actuarial calculations, payroll processing and various consulting services. If any of these counterparties fails to perform its obligations to us or becomes unavailable, our business plans may be materially disrupted, we may be forced to discontinue or delay certain operations if a cost-effective alternative is not readily available or we may be forced to enter into alternative arrangements at then-current market prices that may exceed our contractual prices and cause delays. Although our agreements are designed to mitigate the consequences of a potential default by the counterparty, our actual exposure may be greater than the relief provided by these mitigation provisions. Any of the foregoing could result in regulatory actions, cost overruns, delays or other losses, any of which (or a combination of which) could have a material adverse effect on our results of operations, financial condition and cash flows.
Further, our construction program calls for extensive expenditures for capital improvements and additions, including the installation of environmental upgrades, improvements to and replacements of generation, transmission and distribution facilities, as well as other initiatives. As a result, we have engaged, and will continue to engage, numerous contractors and have entered into a number of agreements to acquire the necessary materials and/or obtain the required construction related services. In addition, some contracts provide for us to assume the risk of price escalation and availability of certain metals and key components. This could force us to enter into alternative arrangements at then-current market prices that may exceed our contractual prices or cause construction delays in a significant manner. It could also subject us to enforcement action by regulatory authorities to the extent that such
a contractor failure resulted in a failure by AES Indiana to comply with requirements or expectations, particularly with regard to the cost of the project. As a result of these events, we might incur losses or delays in completing construction.
The COVID-19 pandemic, or the future outbreak of any other highly infectious or contagious diseases, could impact our business and operations.
The COVID-19 pandemic has impacted global economic activity, caused significant volatility and negative pressure in financial markets and reduced the demand for energy in our service territory in recent years. In addition to reduced revenue and lower margins resulting from decreased energy demand within our service territory, we also have incurred expenses relating to COVID-19, including expenses relating to events outside of our control. In addition to contributing to economic slowdown or a recession, COVID-19 or another pandemic could have material and adverse effects on our results of operations, financial condition and cash flows due to, among other factors:
•further decline in customer demand as a result of general decline in business activity;
•further destabilization of the markets and decline in business activity negatively impacting our customer growth or the number of customers in our service territory as well as our customers’ ability to pay for our services when due (or at all);
•delay or inability in obtaining regulatory actions and outcomes that could be material to our business, including for recovery of COVID-19 related expenses and losses, such as uncollectible customer amounts, and the review and approval of our applications, rates and charges by the IURC;
•difficulty accessing the capital and credit markets on favorable terms, or at all, a disruption and instability in the global financial markets, or deteriorations in credit and financing conditions which could affect our access to capital necessary to fund business operations or address maturing liabilities on a timely basis;
•negative impacts on the health of our essential personnel, especially if a significant number of them are affected, and on our operations as a result of implementing stay-at-home, quarantine and other social distancing measures;
•a deterioration in our ability to ensure business continuity during a disruption, including increased cybersecurity attacks related to the work-from-home environment;
•delays or inability to access, transport and deliver fuel or other materials to our facilities due to restrictions on business operations or other factors affecting us and our third-party suppliers;
•the inability to hedge sufficient exposure of our operations from availability and cost of fuel and other commodities that experience significant volatility;
•delays or inability to access equipment or the availability of personnel to perform planned and unplanned maintenance, which can, in turn, lead to disruption in operations;
•delays or inability in achieving our financial goals, growth strategy and digital transformation; and
•delays in the implementation of expected rules and regulations.
The impact of the COVID-19 pandemic also depends on factors, including the effectiveness and timing of updated vaccines to address new variants, the development of more virulent COVID-19 variants as well as third-party actions taken to contain its spread and mitigate its public health effects. A resurgence or material worsening of the COVID-19 pandemic could present material uncertainty which could materially and adversely affect our generation facilities, transmission and distribution systems, results of operations, financial condition and cash flows. To the extent COVID-19 adversely affects our business and financial results, it may also have the effect of heightening many of the other risks described in this “Risk Factors” section, such as those relating to our level of indebtedness, our need to generate sufficient cash flows to service our indebtedness and our ability to comply with the covenants contained in the agreements that govern our indebtedness.
Failure to maintain an effective system of internal controls over financial reporting could result in material misstatements in our financial statements, the disallowance of cost recovery, or incorrect payment processing.
Our internal controls, accounting policies and practices and internal information systems are designed to enable us to capture and process transactions and information in a timely and accurate manner in compliance with GAAP, laws and regulations, taxation requirements and federal securities laws and regulations in order to, among other things, disclose and report financial and other information in connection with the recovery of our costs and with our reporting requirements under federal securities, tax and other laws and regulations and to properly process payments. We have also implemented corporate governance, internal control and accounting policies and procedures in connection with the Sarbanes-Oxley Act of 2002. Our internal controls and policies have been and
continue to be closely monitored by management and our Board of Directors. While we believe these controls, policies, practices and systems are adequate to verify data integrity, the identification of significant deficiencies or material weaknesses in our internal controls that we cannot remediate in a timely manner could lead to undetected errors that could result in material misstatements in our financial statements, the disallowance of cost recovery, or incorrect payment processing. The consequences of these events could have a material adverse effect on our results of operations, financial condition and cash flows.
As more fully disclosed in "Item 9A. Controls and Procedures”, we have identified a material weakness in our internal control over financial reporting that resulted from the design and operation of information technology general controls. While we believe that this material weakness did not result in a material misstatement of our financial statements, this control deficiency was not remediated as of December 31, 2023. Since there is a reasonable possibility that the control deficiency could result in a material misstatement in our financial statements that would not be detected, we determined that this control deficiency constituted a material weakness. While we have taken steps to implement a remediation plan, the material weakness will not be considered remediated until the enhanced controls operate for a sufficient period of time and management has concluded, through testing, that the related controls are effective. Furthermore, we can give no assurance that the measures we take will remediate the material weakness. We can give no assurance that additional material weaknesses will not arise in the future. Any failure to remediate the material weakness, or the development of new material weaknesses in our internal control over financial reporting, could result in material misstatements in our financial statements and cause us to fail to meet our reporting and financial obligations.
If we are unable to maintain a qualified and properly motivated workforce, it could have a material adverse effect on our results of operations, financial condition and cash flows.
One of the challenges we face is to retain a skilled, efficient and cost-effective workforce while recruiting new talent to replace losses in knowledge and skills due to resignations, terminations or retirements. This undertaking could require us to make additional financial commitments and incur increased costs. If we are unable to successfully attract and retain an appropriately qualified workforce, it could have a material adverse effect on our results of operations, financial condition and cash flows. In addition, we have employee compensation plans that reward the performance of our employees. We seek to ensure that our compensation plans encourage acceptable levels for risk and high performance through pay mix, performance metrics and timing. We also have policies and procedures in place to mitigate potential excessive risk-taking by employees to achieve performance targets which could result in events that could have a material adverse effect on our results of operations, financial condition and cash flows.
We are subject to collective bargaining agreements that could adversely affect our business, results of operations, financial condition and cash flows.
We are subject to collective bargaining agreements with employees who are members of a union. Approximately 68% of our employees are represented by a union in two bargaining units: a physical unit and a clerical-technical unit. While we believe that we maintain a satisfactory relationship with our employees, it is possible that labor disruptions affecting some or all of our operations could occur during the period of the collective bargaining agreements or at the expiration of the collective bargaining agreements before new agreements are negotiated. We may not be able to successfully train new personnel as current workers with significant knowledge and expertise retire. We also may be unable to staff our business with qualified personnel in the event of significant absenteeism related to a pandemic illness. Work stoppages by, or poor relations or ineffective negotiations with, our employees or other workforce issues could have a material adverse effect on our results of operations, financial condition and cash flows.
The use of non-derivative and derivative instruments in the normal course of business could result in losses that could materially and adversely impact our results of operations, financial position and cash flows.
We sometimes use non-derivative and derivative instruments, such as swaps, options, futures and forwards, to manage commodity and financial risks. We may at times enter into forward contracts to hedge the risk of volatility in earnings from wholesale marketing activities. These trades are affected by a range of factors, including variations in power demand, fluctuations in market prices, market prices for alternative commodities and optimization opportunities. We have attempted to manage our commodities price risk exposure by establishing and enforcing risk limits and risk management policies. Despite our efforts, however, these risk limits and management policies may not work as planned and fluctuating prices and other events could adversely affect our results of operations,
financial condition and cash flows. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these instruments can involve management’s judgment or the use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of some of these contracts. We could also recognize financial losses as a result of volatility in the market values of these contracts, a counterparty failing to perform, or the underlying transactions which the instruments are intended to hedge failing to materialize, which could result in a material adverse effect on our results of operations, financial condition and cash flows.
Potential security breaches (including cybersecurity breaches) and terrorism risks could materially and adversely affect our businesses.
We operate in a highly regulated industry that requires the continued operation of sophisticated systems and network infrastructure at our generation stations, fuel storage facilities and transmission and distribution facilities. We also use various financial, accounting and other systems in our businesses. These systems and facilities are vulnerable to unauthorized access due to hacking, viruses, other cybersecurity attacks and other causes and also may be subject to acts of sabotage and vandalism. In particular, given the importance of energy and the electric grid, there is the possibility that our systems and facilities could be targets of terrorism or acts of war and there has been an increased focus on the U.S. energy grid that is believed to be related to the Russia/Ukraine conflict. We have implemented measures to help prevent unauthorized access to our systems and facilities, including network and system monitoring, identification and deployment of secure technologies, and certain other measures to comply with mandatory regulatory reliability standards. Pursuant to NERC requirements, we have a robust cybersecurity plan in place and are subject to regular audits by an independent auditor approved by NERC. We routinely test our systems and facilities against these regulatory requirements in order to measure compliance, assess potential security risks, and identify areas for improvement. In addition, we provide cybersecurity training for our employees and perform exercises designed to raise employee awareness of cyber risks on a regular basis. To date, cyber-attacks on our business and operations have not had a material impact on our operations or financial results. Despite our efforts, if our systems or facilities were to be breached or disabled, we may be unable to recover them in a timely manner to fulfill critical business functions, including the supply of electric services to our customers, and we could experience decreases in revenue and increases in costs that could materially and adversely affect our results of operations, cash flows and financial condition.
In the course of our business, we also store and use customer, employee, and other personal information and other confidential and sensitive information, including personally identifiable information and personal financial information. If our or our third-party vendors’ systems were to be breached or disabled, sensitive and confidential information and other data could be compromised, which could result in liability or penalties under privacy laws, negative publicity, remediation costs and potential litigation, damages, consent orders, injunctions, fines and other relief.
To help mitigate these risks, we maintain insurance coverage against some, but not all, potential losses, including coverage for illegal acts against us. However, insurance may not be adequate to protect us against all costs and liabilities associated with these risks.
Failure or disruption in our information systems or those of businesses we rely on, or implementation of new processes and information systems could, if significant, interrupt our operations and adversely affect our business, results of operations, financial condition and cash flows in a material manner.
Our business depends on numerous information systems to manage our operations and business processes, financial information, and customer billings. From time to time, we have experienced, and may in the future experience, damage or disruptions in our information technology and computer systems from various risks including, but not limited to, power outages, facility damage, computer and telecommunications failures, computer viruses, security breaches, vandalism, theft, natural disasters, catastrophic events, human error and potential cyber threats. Our disaster recovery planning cannot account for all eventualities.
In addition, we are currently making, and expect to continue to make, investments in our information technology systems and infrastructure, some of which are significant. In 2023, we implemented certain replacement information systems, including our customer information and billing system. Failure to successfully manage the post-implementation phase of this initiative, including with respect to our systems for billing and collecting from our customers, could, if significant, result in a material adverse effect on our business, operating results and financial
condition. In addition, the effectiveness of our information technology general controls and internal controls over financial reporting could continue to be negatively affected.
RISKS ASSOCIATED WITH GOVERNMENTAL REGULATION AND LAWS
We may not always be able to recover our costs to deliver electricity to our retail customers. The costs we can recover and the return on capital we are permitted to earn for certain aspects of our business are regulated and governed by the laws of Indiana and the rules, policies and procedures of the IURC.
We are currently obligated to supply electric energy to retail customers in our service territory. Even though rate regulation is premised on full recovery of prudently incurred costs and a reasonable rate of return on invested capital, there can be no assurance that the IURC will agree that all of our costs have been prudently incurred or are recoverable. There also is no assurance that the regulatory process in which rates are determined will always result in rates that will produce a full or timely recovery of our costs and authorized return. From time to time, the demand for electric energy required to meet our service obligations could exceed our available electric generating capacity. When our retail customer demand exceeds our generating capacity for units operating under MISO economic dispatch, recovery of our cost to purchase electric energy in the MISO market to meet that demand is subject to a stipulation and settlement agreement. The agreement includes a benchmark which compares hourly purchased power costs to daily natural gas prices. Purchased power costs above the benchmark must meet certain criteria in order for us to fully recover them from our retail customers, such as consideration of the capacity of units available but not selected by the MISO economic dispatch. We may not always have the ability to pass all of the purchased power costs on to our customers, and even if we are able to do so, there may be a significant delay between the time the costs are incurred and the time the costs are recovered. Since these situations most often occur during periods of peak demand, the market price for electric energy at the time we purchase it could be very high, and we may not be allowed to recover all of such costs through our FAC (please see Note 2, "Regulatory Matters - FAC and Authorized Annual Jurisdictional Net Operating Income" to the Financial Statements of this Annual Report on Form 10-K for additional details regarding the benchmark and the process to recover purchased power costs). Even if a supply shortage were brief, we could suffer substantial losses that could adversely affect our results of operations, financial condition and cash flows.
Changes in, or reinterpretations of, the laws, rules, policies and procedures that set electric rates, permitted rates of return, changes in AES Indiana’s rate structure, regulations regarding ownership of generation assets and electric service, the supply or generation, reliability initiatives, fuel and purchased power (which account for a substantial portion of our operating costs), capital expenditures and investments and the recovery of these and other costs on a full or timely basis through rates, power market prices and changes to the frequency and timing of rate increases could have a material adverse effect on our results of operations, financial condition and cash flows.
Concerns about GHG emissions and the potential risks associated with climate change have led to increased regulation and other actions that could impact our business.
One byproduct of burning coal and other fossil fuels is the emission of GHGs, including CO2. At the federal, state and regional levels, policies are under development or have been developed to regulate GHG emissions. In 2023, AES Indiana emitted approximately 9 million tons of CO2 from our power plants. AES Indiana uses CO2 emission estimation methodologies supported by “The Greenhouse Gas Protocol” reporting standard on GHG emissions. Our CO2 emissions are determined from emissions monitoring data and calculations using actual fuel heat inputs and fuel type CO2 emission factors.
There currently is no U.S. federal legislation imposing mandatory GHG emission reductions (including for CO2) that affects our electric power generation facilities. However, in 2015, the EPA promulgated a rule establishing NSPS for CO2 emissions for newly constructed and modified/reconstructed fossil-fueled EUSGUs larger than 25 MW, and the EPA proposed revisions to this rule in December 2018. On May 23, 2023, EPA published a proposed rule that would establish CO2 emissions limits for certain new fossil-fuel fired stationary combustion turbines that commence construction or are modified after May 23, 2023. Also on May 23, 2023, following prior rulemaking activity under CAA Section 111(d) and associated legal challenges, EPA published a proposed rule that would vacate its prior ACE Rule, establish emissions guidelines in the form of CO2 emissions limitations for certain existing electric generating units (EGUs) and would require states to develop State Plans that establish standards of performance for such EGUs that are that least as stringent as EPA's emissions guidelines. In addition, it is likely that there will be increased focus on climate change from a President Biden administration and any future Democrat-controlled U.S. Congress, both of which may result in additional legislation and regulations regarding GHG emissions. For example,
in March 2022, the SEC proposed a rule that would require extensive climate-related disclosures, including climate-related risks, GHG emissions and climate-related financial metrics; while this rule has not yet been finalized, once final it could require significant efforts and costs to comply.
In December 2015, the parties to the United Nations Framework Convention on Climate Change convened for the 21st Conference of the parties and the resulting Paris Agreement established a long-term goal of keeping the increase in global average temperature well below 2°C above pre-industrial levels. We anticipate that the Paris Agreement will continue the trend toward efforts to de-carbonize the global economy. Although the U.S. was officially able to withdraw from the Paris Agreement on November 4, 2020, on January 20, 2021, President Biden began the 30-day process of rejoining the Paris Agreement, which became effective for the U.S. on February 19, 2021. In November 2023, the international community gathered for COP28. The Parties agreed to non-binding language calling on countries to transition away from fossil fuels in energy systems to achieve net zero emissions by 2050.
Any existing or future international, federal, state or regional legislation or regulation of GHG emissions could have a material adverse impact on our financial performance. The actual impact on our financial performance will depend on a number of factors, including among others, the degree and timing of GHG emissions reductions required under any such legislation or regulations, of offsets, the extent to which market-based compliance options are available, if such options were available, the extent to which we would be entitled to receive GHG emissions allowances without having to purchase them in an auction or on the open market as well as the cost or availability of such allowances and the impact of such legislation or regulation on our ability to recover costs incurred through rate increases or otherwise. Our cost of compliance could be substantial. Although we would seek recovery of costs associated with new climate change or GHG regulations, our inability to fully or timely recover such costs could have a material adverse effect on our results of operations, financial condition and cash flows. Additionally, concerns over GHG emissions and their effect on the environment have led, and could lead further, to reduced demand for coal-fired power, which could have a material adverse effect on our results of operations, financial condition and cash flows.
Furthermore, according to the Intergovernmental Panel on Climate Change, physical risks from climate change could include, but are not limited to, increased runoff and earlier spring peak discharge in many glacier and snow-fed rivers, warming of lakes and rivers, an increase in sea level, changes and variability in precipitation and in the intensity and frequency of extreme weather events. Physical impacts may have the potential to significantly affect our business and operations. For example, extreme weather events could result in increased downtime and operation and maintenance costs at our electric power generation facilities and our support facilities. Variations in weather conditions, primarily temperature and humidity, would also be expected to affect the energy needs of customers. A decrease in energy consumption could decrease our revenue. In addition, while revenue would be expected to increase if the energy consumption of customers increased, such increase could prompt the need for additional investment in generation capacity. Changes in the temperature of lakes and rivers and changes in precipitation that result in drought could adversely affect the operations of our fossil-fuel fired electric power generation facilities.
If any of the foregoing risks materialize, we expect our costs to increase or revenue to decrease and there could be a material adverse effect on our business and on our consolidated results of operations, financial condition, cash flows and reputation if such changes are significant. Please see “Item 1. Business - Environmental Matters” for additional information of environmental matters impacting us, including those relating to regulation of GHG emissions.
We are subject to numerous environmental laws, rules and regulations that require capital expenditures, increase our cost of operations, may expose us to environmental liabilities or make continued operation of certain generating units unprofitable.
We are subject to various federal, state, regional and local environmental protection and health and safety laws, rules and regulations governing, among other things, the generation, storage, handling, use, disposal and transportation of regulated materials, including CCR; the use and discharge of water used in generation boilers and for cooling purposes; the emission and discharge of hazardous and other materials into the environment; and the health and safety of our employees. Such laws, rules and regulations can become stricter over time, and we could also become subject to additional environmental laws, rules and regulations and other requirements in the future. Environmental laws, rules and regulations also generally require us to comply with inspections and obtain and comply with a wide variety of environmental licenses, permits, and other governmental authorizations. These laws and regulations often require a lengthy and complex process of obtaining and renewing licenses, permits and other
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 10, “Commitments and Contingencies” to the Financial Statements of this Annual Report on Form 10-K for a summary of significant regulatory matters and legal proceedings involving us.
Tax legislation initiatives or challenges to our tax positions could adversely affect our results of operations and financial condition.
We are subject to the tax laws and regulations of the U.S. federal, state and local governments. From time to time, legislative measures may be enacted that could adversely affect our overall tax positions regarding income or other taxes. There can be no assurance that our effective tax rate or tax payments will not be adversely affected by these legislative measures. In addition, U.S. federal, state and local tax laws and regulations are extremely complex and subject to varying interpretations. There can be no assurance that our tax positions will be sustained if challenged by relevant tax authorities and if not sustained, there could be a material impact on our results of operations.
RISKS RELATED TO OUR INDEBTEDNESS AND FINANCIAL CONDITION
We rely on access to the financial markets. General economic conditions and disruptions in the financial markets could adversely affect our ability to raise capital on favorable terms or at all, and cause increases in our interest expense.
From time to time we rely on access to the capital and credit markets as a source of liquidity for capital requirements not satisfied by operating cash flows. These capital and credit markets experience volatility and disruption from time to time and the ability of corporations to raise capital can be negatively impacted. Disruptions in the capital and credit markets make it harder and more expensive to raise capital. Our ability to raise capital on favorable terms or at all can be adversely affected by unfavorable market conditions or declines in our creditworthiness, and we may be unable to access adequate funding to refinance our debt as it becomes due or finance capital expenditures. The extent of any impact will depend on several factors, including our operating cash flows, financial condition and prospects, the overall supply and demand in the credit markets, our credit ratings, credit capacity, the cost of financing, the financial condition, performance and prospects of other companies in our industry or with similar financial circumstances and other general economic and business conditions. It may also depend on the performance of credit counterparties and financial institutions with which we do business. Access to funds under our existing financing arrangements is also dependent on the ability of our counterparties to meet their financing commitments and our satisfying conditions to borrowing. Our inability to obtain financing on reasonable terms, or at all, with creditworthy counterparties could adversely affect our results of operations, financial condition and cash flows. If our available funding is limited or we are forced to fund our operations at a higher cost, these conditions may require us to curtail our business activities and increase our cost of funding, both of which would adversely impact our profitability.
See Note 6, “Debt” to the Financial Statements of this Annual Report on Form 10-K for information regarding indebtedness. See also “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” for information related to market risks.
The level of our indebtedness, and the security provided for this indebtedness, could adversely affect our financial flexibility.
As of December 31, 2023, we had on a consolidated basis $3,476.0 million of indebtedness, including finance lease obligations, and total shareholders’ equity of $1,076.5 million. AES Indiana had $2,153.8 million of first mortgage bonds outstanding as of December 31, 2023, which are secured by the pledge of substantially all of the assets of AES Indiana under the terms of AES Indiana’s mortgage and deed of trust. This level of indebtedness and related security has important consequences, including the following:
•increasing our vulnerability to general adverse economic and industry conditions;
•requiring us to dedicate a substantial portion of our cash flow from operations to make payments on our indebtedness, thereby reducing the availability of our cash flow to fund other corporate purposes;
•limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and
•limiting, along with the financial and other restrictive covenants in our indebtedness, our ability to borrow additional funds, as needed.
We expect to incur additional debt in the future, subject to the terms of our debt agreements and regulatory approvals for any AES Indiana debt. To the extent we become more leveraged, the risks described above would increase. Further, actual cash requirements in the future may be greater than expected. Accordingly, our cash flow from operations may not be sufficient to repay at maturity all of the outstanding debt as it becomes due and, in that event, we may not be able to borrow money, sell assets or otherwise raise funds on acceptable terms or at all to refinance our debt as it becomes due. For a further discussion of outstanding debt, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources” and Note 6, “Debt” to the Financial Statements of this Annual Report on Form 10-K.
We have variable rate debt that bears interest based on a prevailing rate that is reset based on a market index that can be affected by market demand, supply, market interest rates and other market conditions. We also maintain both cash on deposit and investments in cash equivalents from time to time that could be impacted by interest rate fluctuations. As such, any event which impacts market interest rates could have a material effect on our results of operations, financial condition and cash flows. In addition, ratings agencies issue credit ratings on us and our debt
that affect our borrowing costs under our financial arrangements and affect our potential pool of investors and funding sources. Our credit ratings also govern the collateral provisions of certain of our contracts. If rating agencies downgrade our credit ratings, our borrowing costs would likely further increase, our potential pool of investors and funding resources could be reduced, and we could be required to post additional cash collateral under selected contracts. These events would likely reduce our liquidity and profitability and could have a material adverse effect on our results of operations, financial condition and cash flows.
IPALCO is a holding company and parent of AES Indiana and other subsidiaries. IPALCO’s cash flow is dependent on operating cash flows of AES Indiana and its ability to pay cash to IPALCO.
IPALCO is a holding company with no material assets other than the common stock of its subsidiaries, and accordingly all cash is generated by the operating activities of our subsidiaries, principally AES Indiana. As such, IPALCO’s cash flow is largely dependent on the operating cash flows of AES Indiana and its ability to pay cash to IPALCO. AES Indiana’s mortgage and deed of trust, its amended articles of incorporation, its Credit Agreement and its $300 million Term Loan Agreement contain restrictions on AES Indiana’s ability to issue certain securities or pay cash dividends to IPALCO. For example, there are restrictions that require maintenance of a leverage ratio which could limit the ability of AES Indiana to pay dividends. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity” for a discussion of these restrictions. See Note 6, “Debt” to the Financial Statements of this Annual Report on Form 10-K for information regarding indebtedness. In addition, AES Indiana is regulated by the IURC, which possesses broad oversight powers to ensure that the needs of utility customers are being met. The IURC could impose additional restrictions on the ability of AES Indiana to distribute, loan or advance cash to IPALCO pursuant to these broad powers. While we do not expect any of the foregoing restrictions to significantly affect AES Indiana’s ability to pay funds to IPALCO in the future, a significant limitation on AES Indiana’s ability to pay dividends or loan or advance funds to IPALCO would have a material adverse effect on IPALCO’s results of operations, financial condition and cash flows.
Our ownership by AES subjects us to potential risks that are beyond our control.
All of AES Indiana’s common stock is owned by IPALCO, all of whose common stock is owned by AES U.S. Investments (82.35%) and CDPQ (17.65%). Due to our relationship with AES, any adverse developments and announcements concerning AES may impair our ability to access the capital markets and to otherwise conduct business. In particular, downgrades in AES’s credit ratings could result in AES Indiana’s or IPALCO’s credit ratings being downgraded.

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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 $2,153.8 million at December 31, 2023. In addition, IPALCO has outstanding $880.0 million of debt obligations which are secured by its pledge of all of the outstanding common stock of AES Indiana.

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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 10, “Commitments and Contingencies” to the Financial Statements of this Annual Report on Form 10-K for summaries of significant legal proceedings involving us, which are incorporated by reference herein.
The following additional information is incorporated by reference into this Item: information about the legal proceedings contained in "Regulation" and “Environmental Matters” in “Item 1. Business” of this Annual Report on Form 10-K.

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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 February 26, 2024, all of the outstanding common stock of IPALCO is owned by AES U.S. Investments (82.35%) and CDPQ (17.65%). As a result, our stock is not listed for trading on any stock exchange.
Dividends
During the years ended December 31, 2023, 2022 and 2021, IPALCO declared and paid distributions to our shareholders totaling $104.3 million, $102.0 million and $131.5 million, respectively. Future distributions to our shareholders will be determined at the discretion of our Board of Directors and will depend primarily on dividends received from AES Indiana and such other factors as our Board of Directors deems relevant. Please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity” of this Form 10-K for a discussion of limitations on dividends from AES Indiana. In order for us to make any dividend payments to our shareholders, we must, at the time and as a result of such dividends, either maintain certain credit ratings on our senior long-term debt or be in compliance with leverage and interest coverage ratios contained in IPALCO’s Third Amended and Restated Articles of Incorporation. We do not believe this requirement will be a limiting factor in paying dividends in the ordinary course of prudent business operations.
Dividends and Capital Structure Restrictions
AES Indiana’s mortgage and deed of trust and its amended articles of incorporation contain restrictions on AES Indiana’s ability to issue certain securities or pay cash dividends. So long as any of the several series of bonds of AES Indiana issued under its mortgage remains outstanding, and subject to certain exceptions, AES Indiana is restricted in the declaration and payment of dividends, or other distribution on shares of its capital stock of any class, or in the purchase or redemption of such shares, to the aggregate of its net income, as defined in the mortgage, after December 31, 1939. In addition, pursuant to AES Indiana’s articles, no dividends may be paid or accrued, and no other distribution may be made on AES Indiana’s common stock unless dividends on all outstanding shares of AES Indiana preferred stock have been paid or declared and set apart for payment. On December 30, 2022 (the “Redemption Date”), AES Indiana redeemed all of its issued and outstanding preferred stock for $60.1 million (for further discussion, see Note 9, "Equity and Cumulative Preferred Stock - Cumulative Preferred Stock" to the Financial Statements of this Annual Report on Form 10-K). As of December 31, 2023, and as of the filing of this report, AES Indiana was in compliance with these restrictions.
AES Indiana is also restricted in its ability to pay dividends if it is in default under the terms of its Credit Agreement and $300 million Term Loan Agreement, which could happen if AES Indiana fails to comply with certain covenants. These covenants, among other things, require AES Indiana to maintain total debt to total capitalization not in excess of 0.67 to 1. As of December 31, 2023, and as of the filing of this report, AES Indiana was in compliance with all covenants and no event of default existed.
IPALCO’s Third Amended and Restated Articles of Incorporation contain provisions which state that IPALCO may not make a distribution to its shareholders or make a loan to any of its affiliates (other than its subsidiaries), unless: (a) there exists no event of default (as defined in the articles) and no such event of default would result from the making of the distribution or loan; and either (b)(i) at the time of, and/or as a result of, the distribution or loan, IPALCO’s leverage ratio does not exceed 0.67 to 1 and IPALCO’s interest coverage ratio is not less than 2.50 to 1 or, (b)(ii) if such ratios are not within the parameters, IPALCO’s senior long-term debt rating from one of the three major credit rating agencies is at least investment grade. As of December 31, 2023, and as of the filing of this report, IPALCO was in compliance with all covenants and no event of default existed.

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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 2023 RESULTS AND STRATEGIC PERFORMANCE
The most important matters on which we focus in evaluating our financial condition and operating performance and allocating our resources include: (i) recurring factors which have significant impacts on operating performance such as: regulatory action, environmental matters, weather and weather-related damage in our service area, customer growth and the local economy; (ii) our progress on performance improvement and growth strategies designed to maintain high standards in several operating areas (including safety, reliability, customer satisfaction, operations, financial and enterprise-wide performance, talent management/people, capital allocation/sustainability and corporate social responsibility) simultaneously; and (iii) our short-term and long-term financial and operating strategies. For a discussion of how we are impacted by regulation and environmental matters, please see Note 2, “Regulatory Matters” to the Financial Statements and “Environmental Matters” in “Item 1. Business” of this Annual Report on Form 10-K.
Operational Excellence
Our objective is to optimize AES Indiana’s performance in the U.S. utility industry by focusing on the following areas: safety, operations (reliability and customer satisfaction), financial and enterprise-wide performance (efficiency and cost savings, talent management/people, capital allocation/sustainability and corporate social responsibility). We set
and measure these objectives carefully, balancing them in a way and to a degree necessary to ensure a sustainable high level of performance in these areas simultaneously as compared to our peers. We monitor our performance in these areas, and where practical and meaningful, compare performance in some areas to peer utilities. Because some of our financial and enterprise-wide performance measures are company-specific performance goals, they are not benchmarked.
Our safety performance is measured by both leading and lagging metrics. Our leading safety metrics track safety observations, safety meeting engagement and the reporting of lost time incident (“LTI”) rates for our employees and contractors based on OSHA standards. Our lagging safety metrics track lost workday cases, severity rate, and recordable incidents. We are committed to excellence in safety and have implemented various programs to increase safety awareness and improve work practices.
AES Indiana measures delivery reliability by Customer Average Interruption Duration Index ("CAIDI"), System Average Interruption Duration Index ("SAIDI") and System Average Interruption Frequency Index ("SAIFI") and benchmarks the reliability metrics against other utilities at both the state and national levels. AES Indiana also measures customer centricity on more of an individual basis by the industry metric of Customers that Experience Multiple Interruption of five or more times ("CEMI-5"). AES Indiana measures generation reliability by Commercial Availability (“CA”), Equivalent Forced Outage Factor (“EFOF”) and Equivalent Availability Factor (“EAF”) metrics and benchmarks both EFOF and EAF results nationally. We measure Customer Satisfaction using J.D. Power in their Electric Utility Residential Customer Satisfaction Study and Research America Market Research - Consumer Insight. Monitoring performance in the areas such as competitive rates, operational reliability and customer service supports our ongoing work to deliver reliable service to our customers.
EXECUTIVE SUMMARY
Compared with the prior year, the results for the year ended December 31, 2023 reflect lower income from operations before income tax of $46.7 million, or 39%, primarily due to factors including, but not limited to:
$ in millions
2023 vs. 2022
Decrease in retail margin due to lower volumes driven by weather and lower demand
$ (52.4)
Decrease due to higher depreciation expense from additional assets placed in service and higher amortization of regulatory assets (21.4)
Decrease due to higher defined benefit plan costs driven by increase in interest cost
(17.3)
Increase due to a charge to power purchased costs recorded in the prior period resulting from settlement of the FAC sub-docket on the Eagle Valley CCGT extended outage 27.8
Increase in TDSIC rider revenue
24.3
Other (7.7)
Net change in income from operations before income tax $ (46.7)
RESULTS OF OPERATIONS
The following review of results of operations and "Capital Resources and Liquidity" sections compare the results for the year ended December 31, 2023 to the results for the year ended December 31, 2022. For discussion comparing the results for the year ended December 31, 2022 to the results for the year ended December 31, 2021, see Item 7.-Management's Discussion and Analysis of Financial Condition and Results of Operations of our 2022 Annual Report on Form 10-K, filed with the SEC on March 1, 2023. In addition to the discussion on operations below, please see the “Statistical Information on Operations” table included in “Item 1. Business” of this report for additional data such as kWh sales and number of customers by customer class.
IPALCO’s results of operations include the results of its subsidiaries, including the consolidated results of its principal subsidiary AES Indiana. All material intercompany accounts and transactions have been eliminated in consolidation.
Statements of Operations Highlights
Years Ended December 31, Change 2023 vs. 2022 Change 2022 vs. 2021
(In Thousands) 2023 2022 2021 $ % $ %
REVENUE $ 1,649,917 $ 1,791,711 $ 1,426,132 $ (141,794) (7.9) % $ 365,579 25.6 %
OPERATING COSTS AND EXPENSES:
Fuel 494,000 568,676 255,817 (74,676) (13.1) % 312,859 122.3 %
Power purchased 159,908 199,860 175,025 (39,952) (20.0) % 24,835 14.2 %
Operation and maintenance 477,880 493,674 449,746 (15,794) (3.2) % 43,928 9.8 %
Depreciation and amortization 287,863 266,504 256,085 21,359 8.0 % 10,419 4.1 %
Taxes other than income taxes 24,864 33,048 44,419 (8,184) (24.8) % (11,371) (25.6) %
Other, net (361) (3,201) (5,630) 2,840 (88.7) % 2,429 (43.1) %
Total operating costs and expenses 1,444,154 1,558,561 1,175,462 (114,407) (7.3) % 383,099 32.6 %
OPERATING INCOME 205,763 233,150 250,670 (27,387) (11.7) % (17,520) (7.0) %
OTHER (EXPENSE) / INCOME, NET:
Allowance for equity funds used during construction 9,315 4,784 5,412 4,531 94.7 % (628) (11.6) %
Interest expense (142,926) (131,232) (125,626) (11,694) 8.9 % (5,606) 4.5 %
Other (expense) / income, net (410) 11,783 17,667 (12,193) (103.5) % (5,884) (33.3) %
Total other expense, net (134,021) (114,665) (102,547) (19,356) 16.9 % (12,118) 11.8 %
INCOME BEFORE INCOME TAX 71,742 118,485 148,123 (46,743) (39.5) % (29,638) (20.0) %
Income tax expense 14,715 21,859 28,941 (7,144) (32.7) % (7,082) (24.5) %
NET INCOME 57,027 96,626 119,182 (39,599) (41.0) % (22,556) (18.9) %
Dividends on and redemption of preferred stock - 3,509 3,213 (3,509) (100.0) % 296 9.2 %
Net loss attributable to noncontrolling interests (26,093) - - (26,093) (100.0) % - - %
NET INCOME ATTRIBUTABLE TO COMMON STOCK $ 83,120 $ 93,117 $ 115,969 $ (9,997) (10.7) % $ (22,852) (19.7) %
Revenue
Revenue decreased in 2023 from the prior year by $141.8 million, which resulted from the following changes (dollars in thousands):
2023 2022 Change % Change
Revenue:
Retail Revenue $ 1,576,653 $ 1,618,342 $ (41,689) (2.6) %
Wholesale Revenue 56,557 148,517 (91,960) (61.9) %
Miscellaneous Revenue 16,707 24,852 (8,145) (32.8) %
Total Revenue $ 1,649,917 $ 1,791,711 $ (141,794) (7.9) %
Heating Degree Days(1):
Actual 4,350 5,281 (931) (17.6) %
30-year Average 5,198 5,244
Cooling Degree Days(1):
Actual 1,139 1,295 (156) (12.0) %
30-year Average 1,177 1,171
(1) Heating and cooling degree-days are a measure of the relative heating or cooling required for a home or business. The heating degrees in a day are calculated as the degrees that the average actual daily temperature is below 65 degrees Fahrenheit. For example, if the average temperature on March 20th was 40 degrees Fahrenheit, the heating degree days for that day would be the 25-degree difference between 65 degrees and 40 degrees. Similarly, cooling degree days in a day are calculated as the degrees that the average actual daily temperature is above 65 degrees Fahrenheit.
The following table presents additional data on kWh sold:
2023 2022 kWh Change % Change
kWh Sales (In Millions):
Residential 4,800 5,305 (505) (9.5) %
Small commercial and industrial 1,722 1,823 (101) (5.5) %
Large commercial and industrial 5,929 6,091 (162) (2.7) %
Public lighting 19 18 1 5.6 %
Sales - retail customers 12,470 13,237 (767) (5.8) %
Wholesale 1,657 2,148 (491) (22.9) %
Total kWh sold 14,127 15,385 (1,258) (8.2) %
The following graph shows the percentage changes in weather-normalized and actual retail electric sales volumes by customer class for the year ended December 31, 2023 as compared to the prior year:
The decrease in revenue of $141.8 million was primarily due to the following:
$ in millions 2023 vs. 2022
Retail revenue:
Volume:
Net decrease in the volume of kWh sold primarily due to weather and demand in our service territory versus the comparable period.
$ (95.2)
Price:
Net increase in the weighted average price of retail kWh sold primarily due to higher fuel revenue, as well as higher TDSIC and Off System Sales Margin rider revenue.
55.9
Other: (2.4)
Net change in retail revenue (41.7)
Wholesale revenue:
Volume:
Net decrease in the volume of wholesale kWh sold. The amount of electricity available for wholesale sales is impacted by our retail load requirements, generation capacity and unit availability.
(34.0)
Price:
Net decrease in the weighted average price of wholesale kWh sold. Our ability to be dispatched in the MISO market is primarily driven by the locational marginal price of electricity and variable generation costs.
(58.0)
Net change in wholesale revenue (92.0)
Miscellaneous revenue:
Primarily due to decrease in capacity revenue due to recent MISO auction results (lower clearing prices in the 2023-2024 MISO auction).
(8.1)
Net change in revenue $ (141.8)
Operating Costs and Expenses
The following table illustrates changes in Operating costs and expenses from 2022 to 2023 (in thousands):
Years Ended
December 31,
2023 2022 $ Change % Change
Operating costs and expenses:
Fuel $ 494,000 $ 568,676 $ (74,676) (13.1) %
Power purchased 159,908 199,860 (39,952) (20.0) %
Operation and maintenance 477,880 493,674 (15,794) (3.2) %
Depreciation and amortization 287,863 266,504 21,359 8.0 %
Taxes other than income taxes 24,864 33,048 (8,184) (24.8) %
Other, net (361) (3,201) 2,840 (88.7) %
Total operating costs and expenses $ 1,444,154 $ 1,558,561 $ (114,407) (7.3) %
Fuel
The decrease in fuel costs of $74.7 million was primarily due to the following:
$ in millions 2023 vs. 2022
Volume:
Coal $ (92.1)
Natural gas 160.9
Oil (0.9)
Net change in volume 67.9
Price:
Coal 34.4
Natural gas (244.9)
Deferred fuel 67.9
Net change in price (142.6)
Net change in fuel expense $ (74.7)
The decrease in volume of coal is primarily attributable to the retirement of Petersburg Unit 2 in June 2023. As the company exits coal, we expect that overall volumes of coal decrease over time and volumes of other fuel sources to increase. The increase in natural gas is primarily attributable to the timing of outages versus the comparable period (including the extended outage at the Eagle Valley CCGT that began in April 2021 until March 2022). The changes in the price of fuel are reflective of market prices for coal and natural gas. We are generally permitted to recover underestimated fuel and purchased power costs to serve our retail customers in future rates through quarterly FAC proceedings. These variances are deferred when incurred and amortized into expense in the same period that our rates are adjusted to reflect these variances. Additionally, fuel and purchased power costs incurred for wholesale energy sales are considered in the Off System Sales Margin rider.
Power Purchased
The decrease in purchased power costs of $40.0 million was primarily due to the following:
$ in millions 2023 vs. 2022
Volume:
Net change in the volume of power purchased primarily due to AES Indiana's generation units running more frequently, as well as the timing and duration of outages, during these respective periods
$ (25.4)
Price:
Market prices (60.5)
Deferred purchased power 31.4
Net change in price (29.1)
Other, net (mostly due to changes in capacity purchases) 14.5
Net change in power purchased costs $ (40.0)
The volume of power purchased each period is primarily influenced by retail demand, generating unit capacity and outages, and the relative cost of producing power versus purchasing power in the market. The market price of purchased power is influenced primarily by changes in the market price of delivered fuel (primarily natural gas), the supply of and demand for electricity, and the time of day during which power is purchased.
The Eagle Valley CCGT was on unplanned outage from late April 2021 until mid-March 2022, impacting several FAC periods. The IURC initiated a sub-docket in FAC-133 (IURC Cause No. 38703-FAC-133 S1) to examine the impact of the Eagle Valley extended outage, which was settled in October 2022. A $27.8 million charge was recorded in the third quarter of 2022 resulting from the settlement of the FAC sub-docket of the Eagle Valley CCGT unplanned outage. For further discussion, please see Note 2, "Regulatory Matters - Regulatory Assets and Liabilities - Deferred Fuel" to the Financial Statements of this Annual Report on Form 10-K.
Operation and Maintenance
The decrease in Operation and maintenance expense of $15.8 million was primarily due to the following:
$ in millions 2023 vs. 2022
Decrease in compensation and benefits expense, primarily health and other insurance benefits and lower pension service costs
$ (11.4)
Decrease in DSM program costs (these program costs are recoverable through customer rates and are offset by a decrease in DSM revenue)
(8.2)
Decrease in contracted services expenses primarily due to lower generation maintenance and outage costs
(5.0)
Decrease in MISO non-purchased power costs (primarily transmission related expenses)
(3.2)
Increase in charges from the Service Company
13.3
Other, net (1.3)
Net change in operation and maintenance costs $ (15.8)
Depreciation and Amortization
The increase in Depreciation and amortization expense of $21.4 million was mostly attributed to the impact of additional assets placed in service and higher amortization of regulatory assets.
Taxes Other Than Income Taxes
The decrease in Taxes other than income taxes of $8.2 million was mostly attributed to (i) a decrease in taxes of $11.4 million related to the repeal of the URT in June 2022 (for further discussion, please see Note 2, "Regulatory Matters - House Bill 1002" to the Financial Statements of this Annual Report on Form 10-K), partially offset by (ii) an increase in property tax expense of $4.3 million primarily as a result of higher assessed values.
Other, Net
The change in Other, net of $2.8 million was primarily due to a gain on remeasurement of contingent consideration associated with the Hardy Hills Solar Project acquisition of $3.2 million resulting in higher one-time expenses in 2022. See Note 2, "Regulatory Matters - IRP Filings and Replacement Generation - Hardy Hills Solar Project " to the Financial Statements of this Annual Report on Form 10-K for more information.
Other (Expense) / Income, Net
The following table illustrates changes in Other (expense) / income, net from 2022 to 2023 (in thousands):
Years Ended
December 31,
2023 2022 $ Change % Change
Other (expense) / income, net:
Allowance for equity funds used during construction $ 9,315 $ 4,784 $ 4,531 94.7 %
Interest expense (142,926) (131,232) (11,694) 8.9 %
Other (expense) / income, net (410) 11,783 (12,193) (103.5) %
Total other expense, net $ (134,021) $ (114,665) $ (19,356) 16.9 %
Allowance for Equity Funds Used During Construction
The increase in Allowance for equity funds used during construction of $4.5 million was primarily due to increased construction activity.
Interest Expense
The increase in Interest expense of $11.7 million was primarily due to (i) higher interest expense on debt of $17.1 million mostly due to new debt issuances (including $350 million AES Indiana first mortgage bonds in November 2022 and $300 million Term Loan in November 2023) and higher line of credit balances, partially offset by (ii) an increase in the allowance for borrowed funds used during construction of $5.5 million.
Other (Expense) / Income, Net
The decrease in Other (expense) / income, net of $12.2 million was primarily due to (i) an increase in defined benefit plan costs of $17.3 million (mostly as a result of higher interest cost), partially offset by (ii) an increase in investment income of $5.1 million.
Income Tax Expense
The following table illustrates changes in income tax expense from 2022 to 2023 (in thousands):
Years Ended
December 31,
2023 2022 $ Change % Change
Income tax expense $ 14,715 $ 21,859 $ (7,144) (32.7) %
The decrease in income tax expense of $7.1 million was primarily driven by lower pretax income versus the comparable period, partially offset by tax effects associated with HLBV in the current period.
Dividends On and Redemption of Preferred Stock
The decrease in Dividends on and redemption of preferred stock was due to AES Indiana's redemption of its cumulative preferred stock on December 30, 2022. See Note 9, "Equity And Cumulative Preferred Stock - Cumulative Preferred Stock" to the Financial Statements of this Annual Report on Form 10-K for more information.
Net Loss Attributable to Noncontrolling Interests
The following table illustrates changes in Net loss attributable to noncontrolling interests from 2022 to 2023 (in thousands):
Years Ended
December 31,
2023 2022 $ Change % Change
Net loss attributable to noncontrolling interests
$ (26,093) $ - $ (26,093) (100.0) %
The Net loss attributable to noncontrolling interests of $26.1 million for the year ended December 31, 2023 was related to the initial allocation of earnings from tax attributes using the HLBV method upon the first stage of the Hardy Hills Solar Project being placed in service in December 2023. See Note 2, "Regulatory Matters - IRP Filings and Replacement Generation - Hardy Hills Solar Project " to the Financial Statements of this Annual Report on Form 10-K for more information.
KEY TRENDS AND UNCERTAINTIES
During 2024 and beyond, we expect that our financial results will be driven primarily by retail demand, weather, and maintenance costs. In addition, our financial results will likely be driven by many other factors including, but not limited to:
▪regulatory outcomes and impacts;
▪the passage of new legislation, implementation of regulations or other changes in regulation; and
▪timely recovery of capital expenditures and operation and maintenance costs.
If favorable outcomes related to these factors do not occur, or if the challenges described below and elsewhere in this report impact us more significantly than we currently anticipate, then these factors, or other factors unknown to us, may impact our operating margin, net income and cash flows. We continue to monitor our operations and address challenges as they arise. For a discussion of the risks related to our business, see “Item 1. Business” and “Item 1A. Risk Factors” of this Annual Report on Form 10-K.
Operational
Trade Restrictions and Supply Chain
On March 29, 2022, the U.S. Department of Commerce (“Commerce”) announced the initiation of an investigation into whether imports into the U.S. of solar cells and panels imported from Cambodia, Malaysia, Thailand and Vietnam ("Southeast Asia") are circumventing antidumping and countervailing duty ("AD/CVD") orders on solar cells and panels from China. This investigation resulted in disruptions to the import of solar panels from Southeast Asia. On June 6, 2022, President Biden issued a Proclamation waiving any circumvention duties on imported solar cells and panels from Southeast Asia that result from this investigation for a 24-month period ending June 6, 2024. Suppliers resumed importing cells and panels from Southeast Asia into the U.S. pursuant to a Commerce certification regime implementing the Proclamation.
On December 2, 2022, Commerce issued country-wide affirmative preliminary determinations that circumvention had occurred in each of the four Southeast Asian countries. Commerce also evaluated numerous individual companies and issued preliminary determinations that circumvention had occurred with respect to many but not all of these companies. Additionally, Commerce issued a preliminary determination that circumvention would not be deemed to occur for any solar cells and panels imported from the four countries if the wafers were manufactured outside of China or if no more than two out of six specifically identified components were produced in China. On August 18, 2023, Commerce issued its final determinations on the matter and affirmed its preliminary findings in
most respects. Additionally, Commerce found that three of the specific companies it investigated were not circumventing.
On December 29, 2023, Auxin Solar and Concept Clean Energy filed a lawsuit with the U.S. Court of International Trade, challenging certain aspects of the final rule promulgated by Commerce to implement the Proclamation. The lawsuit specifically challenges Commerce’s decisions not to suspend the final disposition of certain entries of imported solar cells and panels from Southeast Asia made prior to June 6, 2024, and not to collect AD/CVD deposits with respect to those entries. The Department of Justice has responded by filing a motion to dismiss the lawsuit.
While we have executed agreements for AES Indiana's existing solar projects, further disruptions may impact our suppliers’ ability or willingness to meet their contractual agreements with respect to these projects on terms that we deem satisfactory and these and future disruptions may impact the availability or costs of future projects. The impact of any adverse Commerce determination, the impact of the UFLPA, future disruptions to the solar panel supply chain and their effect on AES Indiana's solar project development and construction activities is uncertain. AES Indiana will continue to monitor developments and take prudent steps towards managing our renewables projects.
Capital Projects
Our construction projects have experienced some indications of delays and price increases due to supply chain disruptions; however, they are currently proceeding without material delays. For further discussion of our capital requirements, see "Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity" of this Annual Report on Form 10-K.
Macroeconomic and Political
IRA and U.S. Renewable Energy Tax Credits
The IRA was signed into law in the United States. The IRA includes provisions that are expected to benefit the Company's planned clean energy projects, including increases, extensions, and/or new tax credits for wind, solar, and storage. We expect that the extension of the current solar ITCs for projects that satisfy wage and apprenticeship requirements, as well as the "technology neutral" clean electricity PTC and ITC will provide incremental benefits for our current and future planned renewable projects. For further discussion of our renewable projects, see Note 2, "Regulatory Matters - IRP Filings and Replacement Generation" to the Financial Statements of this Annual Report on Form 10-K.
We account for renewable projects according to GAAP, which, when partnering with tax-equity investors to monetize tax benefits, utilizes the HLBV method. This method recognizes the tax-credit value that is transferred to tax equity investors at the time of its creation, which for projects utilizing the ITC, begins in the quarter the project is placed in service. For projects utilizing the PTC, this value is recognized over 10 years as the facility produces energy. In 2023, we recognized $26.1 million of earnings from tax attributes using the HLBV method upon the first stage of the Hardy Hills Solar Project being placed in service. As we progress in our plan of integrating additional renewable energy projects under our 2022 IRP, as discussed further below, we anticipate additional earnings associated with the tax attributes of these projects.
The implementation of the IRA requires substantial guidance from the U.S. Department of Treasury and other government agencies. While some of that guidance remains pending, there will be uncertainty with respect to the implementation of certain provisions of the IRA.
U.S. Income Tax
The macroeconomic and political environments in the U.S. have changed during 2022 and 2023. This could result in significant impacts to tax law.
Inflation
In the markets in which we operate, there have been higher rates of inflation recently. If inflation continues to increase in our markets, it may increase our expenses that we may not be able to pass through to customers. It may
also increase the costs of some of our construction projects. AES Indiana may have the ability to recover operations and maintenance costs through the regulatory process, however, timing impacts on recovery may vary. In addition, we expect the cost of fuel, specifically coal and natural gas, to continue to be volatile during 2024. Our exposure to fluctuations in the price of fuel is limited because of our FAC. If we are unable to timely or fully recover our fuel and purchased power costs, however, it could have a material adverse effect on our results of operations, financial condition and cash flows.
Interest Rates
In the U.S. there has been a rise in interest rates during 2021 through 2023. Looking ahead, we anticipate a landscape marked by volatility in interest rates in the near term. Although all of our existing IPALCO and AES Indiana long-term debt is at fixed rates, an increase in interest rates can have several impacts on our business. For our existing short-term debt under floating rate structures and any future debt refinancings or future new money financings, rising interest rates will increase future financing costs. Our floating rate debt is currently limited to short-term borrowings under our Credit Agreement and $300 million Term Loan Agreement. For future IPALCO debt financings, IPALCO manages a hedging program to reduce uncertainty and exposure to future interest rates.
Bipartisan Infrastructure Law (Infrastructure Investment and Jobs Act)
In November 2021, President Biden signed into law the Infrastructure Investment and Jobs Act, which provides for approximately $1.2 trillion of federal spending over the next five years across the United States. The BIL’s energy-related provisions include new federal funding for power grid infrastructure and resiliency investments, new and existing energy efficiency and weatherization programs, electric vehicle infrastructure for public chargers and additional Low Income Home Energy Assistance Program funding. AES Indiana is participating as a sub-recipient for a Department of Energy Office of Energy Efficiency and Renewable Energy Topic 2 award and has identified other potential opportunities associated with the BIL and is submitting concept papers and grants for those that align with its strategy going forward.
Regulatory
Regulatory Rate Review
On June 28, 2023, AES Indiana filed a petition with the IURC for authority to increase its basic rates and charges to cover the rising operational costs and needs associated with continuing to serve its customers safely and reliably. On November 22, 2023, AES Indiana entered into a unanimous stipulation and settlement agreement (the "settlement") with the OUCC and the intervening parties which, if approved by the IURC, would increase its annual revenue requirement by $73 million. AES Indiana expects to receive an order from the IURC and place new rates into effect by the end of the second quarter of 2024.
2022 IRP
AES Indiana filed its 2022 IRP with the IURC in December 2022. The 2022 IRP short-term action plan includes converting the two remaining coal units at Petersburg to natural gas. Additionally, AES Indiana plans to add up to 1,300 MW of wind, solar, and battery energy storage by 2027. For further discussion, see Note 2, "Regulatory Matters - IRP Filings and Replacement Generation - 2022 IRP" to the Financial Statements of this Annual Report on Form 10-K.
Please see “Item 1. Business - Regulation” and Note 2, “Regulatory Matters” to the Financial Statements of this Annual Report on Form 10-K for further discussion of these and other regulatory matters.
CAPITAL RESOURCES AND LIQUIDITY
Overview
As of December 31, 2023, we had unrestricted cash and cash equivalents of $28.6 million and available borrowing capacity of $195 million under our unsecured revolving Credit Agreement. All of AES Indiana’s long-term borrowings must first be approved by the IURC and the aggregate amount of AES Indiana’s short-term indebtedness must be approved by the FERC. AES Indiana has approval from the FERC to borrow up to $750 million of short-term indebtedness outstanding at any time through July 26, 2024. In November 2021, AES Indiana received an order
from the IURC granting authority through December 31, 2024 to, among other things, issue up to $740 million in aggregate principal amount of long-term debt, of which $390 million remains available under the order as of December 31, 2023. This order also grants authority to have up to $750 million of long-term credit agreements and liquidity facilities outstanding at any one time, of which $100 million remains available under the order as of December 31, 2023. As an alternative to the sale of all or a portion of $65 million in principal of the long-term debt, AES Indiana has authority to issue up to $65 million of new preferred stock, all of which authority remains available under the order as of December 31, 2023. We also have restrictions on the amount of new debt that may be issued due to contractual obligations of AES and by financial covenant restrictions under our existing debt obligations. We do not believe such restrictions will be a limiting factor in our ability to issue debt in the ordinary course of prudent business operations.
We depend on timely and continued access to capital markets to manage our liquidity needs. The inability to raise capital on favorable terms, to refinance existing indebtedness or to fund operations and other commitments during times of political or economic uncertainty or otherwise could have material adverse effects on our financial condition and results of operations. In addition, changes in the timing of tariff increases or delays in the regulatory determinations as well as unfavorable regulatory outcomes could have a material adverse effect on our results of operations, financial condition and cash flows. See "Risks related to our indebtedness and financial condition" in "Item 1A. Risk Factors" and "Regulation" in "Item 1 - Business" of this Annual Report on Form 10-K for more information. From time to time, we may elect to repurchase our outstanding debt through cash purchases, privately negotiated transactions or otherwise when management believes such repurchases are favorable to make. The amounts involved in any such repurchases may be material.
Cash Flows
The following table summarizes the changes in operating, investing, and financing cash flows for the comparative periods:
Years ended December 31, $ Change
2023 2022 2021 2023 vs. 2022
(in thousands)
Net cash provided by operating activities $ 391,933 $ 346,346 $ 225,217 $ 45,587
Net cash used in investing activities (992,873) (525,087) (368,715) (467,786)
Net cash provided by financing activities 427,971 373,377 123,793 54,594
Net change in cash, cash equivalents and restricted cash
(172,969) 194,636 (19,705) (367,605)
Cash, cash equivalents and restricted cash at beginning of year 201,553 6,917 26,622 194,636
Cash, cash equivalents and restricted cash at end of year
$ 28,584 $ 201,553 $ 6,917 $ (172,969)
The following cash flow discussion compares the cash flows for the year ended December 31, 2023 to the cash flows for the year ended December 31, 2022. For discussion comparing the cash flows for the year ended December 31, 2022 to the cash flows for the year ended December 31, 2021, see Item 7.-Management's Discussion and Analysis of Financial Condition and Results of Operations of our 2022 Annual Report on Form 10-K, filed with the SEC on March 1, 2023.
2023 versus 2022
Operating Activities
The following table summarizes the key components of our consolidated operating cash flows:
Years ended December 31, $ Change
2023 2022 2021 2023 vs. 2022
(in thousands)
Net income $ 57,027 $ 96,626 $ 119,182 $ (39,599)
Depreciation and amortization 287,863 266,504 256,085 21,359
Amortization of deferred financing costs and debt discounts
3,880 3,914 3,915 (34)
Deferred income taxes and investment tax credit adjustments - net
32,653 (6,706) (7,378) 39,359
Allowance for equity funds used during construction (9,315) (4,784) (5,412) (4,531)
Gain on acquisition - - (5,630) -
Net income, adjusted for non-cash items 372,108 355,554 360,762 16,554
Net change in operating assets and liabilities 19,825 (9,208) (135,545) 29,033
Net cash provided by operating activities $ 391,933 $ 346,346 $ 225,217 $ 45,587
The net change in operating assets and liabilities for the year ended December 31, 2023 compared to the year ended December 31, 2022 was driven by the following (in thousands):
Increase in accounts receivable driven primarily by the timing of collections
$ 19,989
Increase in accounts payable due to the timing of invoices and payments
14,955
Increase in inventories due to the timing of coal purchases and higher coal prices in the current year
17,318
Decrease from prepaids mainly due to higher advanced capacity purchases and collateral deposits in 2023
(25,532)
Other 2,303
Net change in operating assets and liabilities $ 29,033
Investing Activities
Net cash used in investing activities increased $467.8 million for the year ended December 31, 2023 compared to the year ended December 31, 2022, which was primarily driven by (in thousands):
Higher cash outflows for capital expenditures related with renewable energy projects, higher T&D maintenance related capital expenditures and growth related capital expenditures primarily from TDSIC Plan
$ (406,195)
Higher cash outflows from purchase of intangibles in 2023
(44,650)
Higher cash outflows on cost of removal due to the timing of payments
(21,647)
Other 4,706
Net change in investing activities $ (467,786)
Financing Activities
Net cash provided by financing activities increased $54.6 million for the year ended December 31, 2023 compared to the year ended December 31, 2022, which was primarily driven by (in thousands):
Increase due to higher net revolver draws on AES Indiana's revolving credit facility
$ 215,000
Increase due to sales to noncontrolling interests
77,921
Increase due to redemption of preferred stock in the prior year
60,080
Decrease due to lower equity contributions from shareholders
(253,000)
Decrease due to lower debt issuances
(50,000)
Other 4,593
Net change in financing activities $ 54,594
Capital Requirements
Capital Expenditures
Our capital expenditure program, including development and permitting costs, for the three-year period from 2024 through 2026 is currently estimated to cost approximately $3.2 billion (excluding environmental compliance), and includes estimates as follows (amounts in millions):
For the three-year period
2024 2025 2026 from 2024 through 2026
Power generation related projects $ 786.8 $ 654.9 $ 430.2 $ 1,871.9 (1)
Transmission and distribution related additions, improvements and extensions 202.8 298.8 210.2 711.8 (2)
TDSIC Plan investments 177.6 194.9 156.6 529.1 (3)
Other miscellaneous equipment 37.1 28.5 27.2 92.8
Total estimated costs of capital expenditure program $ 1,204.3 $ 1,177.1 $ 824.2 $ 3,205.6
(1) Includes spending for AES Indiana's power generation and renewable energy projects.
(2) Additions, improvements and extensions to AES Indiana's transmission and distribution lines, substations, power factor and voltage regulating equipment, distribution transformers and street lighting facilities.
(3) Includes spending under AES Indiana's TDSIC plan approved by the IURC on March 4, 2020 for eligible transmission, distribution and storage system improvements totaling $1.2 billion from 2020 through 2026. Total TDSIC costs expended from project inception through December 31, 2023 were $678.8 million.
The amounts described in the capital expenditure program above include estimated spending under AES Indiana's 2022 IRP filed with the IURC in December 2022. See Note 2, "Regulatory Matters - IRP Filings and Replacement Generation - 2022 IRP" to the Financial Statements of this Annual Report on Form 10-K for further discussion. Additionally, estimated capital expenditure spending on environmental compliance costs for the three-year period from 2024 through 2026 is approximately $90 million. Please see “Item 1. Business - Environmental Matters" for additional details.
Capital Resources
As IPALCO is a holding company, substantially all of its cash is generated by the operating activities of its subsidiaries, principally AES Indiana. None of its subsidiaries, including AES Indiana, are obligated under or have guaranteed to make payments with respect to the 2024 IPALCO Notes or the 2030 IPALCO Notes; however, all of AES Indiana’s common stock is pledged to secure these debt obligations. Accordingly, IPALCO’s ability to make payments on the 2024 IPALCO Notes and the 2030 IPALCO Notes depends on the ability of AES Indiana to generate cash and distribute it to IPALCO.
Liquidity
We expect our existing cash balances, cash generated from operating activities and borrowing capacity on our existing Credit Agreement will be adequate to meet our anticipated operating needs, including interest expense on our debt and dividends to our equity owners. Our business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and carrying costs, potential margin requirements related to interest rate and commodity hedges, taxes and dividend payments. For 2024 and subsequent years, we expect to satisfy these requirements with a combination of cash from operations, funds from debt financing, funds from tax equity contributions, and parent capital contributions as our internal liquidity needs and market conditions warrant. We also expect that the borrowing capacity under our existing Credit Agreement will continue to be available to manage working capital requirements during those periods. The absence of adequate liquidity could adversely affect our ability to operate our business and have a material adverse effect on our results of operations, financial condition and cash flows.
Indebtedness
Significant Debt Transactions
For further discussion of our significant debt transactions, please see Note 6, “Debt” to the Financial Statements of this Annual Report on Form 10-K.
Line of Credit
AES Indiana entered into a second amendment and restatement of its $350 million revolving Credit Agreement on December 22, 2022 with a syndication of bank lenders, as discussed in Note 6, “Debt - Line of Credit” to the Financial Statements of this Annual Report on Form 10-K.
We had the following amounts available under the revolving Credit Agreement:
$ in millions Type Maturity Commitment Amounts available at December 31, 2023
AES Indiana Revolving December 2027 $ 350.0 $ 195.0
Credit Ratings
Our ability to borrow money or to refinance existing indebtedness and the interest rates at which we can borrow money or refinance existing indebtedness are affected by our credit ratings. In addition, the applicable interest rates on AES Indiana’s Credit Agreement (as well as the amount of certain other fees in the Credit Agreement) are dependent upon the credit ratings of AES Indiana. Downgrades in the credit ratings of AES could result in AES Indiana’s and/or IPALCO’s credit ratings being downgraded. Any reduction in our debt or credit ratings may adversely affect the trading price of our outstanding debt securities.
The following table presents the debt ratings and credit ratings (issuer/corporate rating) and outlook for IPALCO and AES Indiana.
Debt ratings IPALCO AES Indiana Outlook
Fitch Ratings BBB (a)
A (b)
Stable
Moody’s Investors Service Baa3 (a)
A2 (b)
Stable
S&P Global Ratings BBB- (a)
A- (b)
Stable
Credit ratings IPALCO AES Indiana Outlook
Fitch Ratings BBB- BBB+ Stable
Moody’s Investors Service - Baa1 Stable
S&P Global Ratings BBB BBB Stable
(a) Ratings relate to IPALCO's Senior Secured Notes
(b) Ratings relate to AES Indiana's first mortgage bonds
We cannot predict whether our current debt and credit ratings or the debt and credit ratings of AES Indiana will remain in effect for any given period of time or that one or more of these ratings will not be lowered or withdrawn entirely by a rating agency. A security rating is not a recommendation to buy, sell or hold securities. Such ratings may be subject to revision or withdrawal at any time by the assigning rating organization, and each rating should be evaluated independently of any other rating.
Contractual Obligations
Our non-contingent contractual obligations as of December 31, 2023 are set forth below:
Payments due in:
Total Less Than 1 Year 1 - 3
Years 3 - 5
Years More Than
5 Years
(In Millions)
Short-term and long-term debt $ 3,488.8 $ 900.0 $ 130.0 $ - $ 2,458.8
Interest obligations 1,788.4 159.6 241.0 239.8 1,148.0
Finance lease obligations 44.6 0.9 1.8 1.9 40.0
Purchase obligations:
Coal, gas, purchased power and
related transportation 933.5 249.7 267.3 225.7 190.8
Other 409.1 355.0 32.8 20.2 1.1
Total $ 6,664.4 $ 1,665.2 $ 672.9 $ 487.6 $ 3,838.7
Short-term and long-term debt:
Our short-term and long-term debt at December 31, 2023 consists of outstanding borrowings on the Credit Agreement, $300 million Term Loan Agreement, AES Indiana first mortgage bonds and IPALCO long-term debt. These long-term debt amounts include current maturities but exclude unamortized debt discounts and deferred financing costs. See Note 6, "Debt" to the Financial Statements of this Annual Report on Form 10-K.
Interest payments:
Interest payments are associated with the short-term and long-term debt described above. The interest payments relating to variable-rate debt are projected using the interest rates in effect at December 31, 2023.
Finance lease obligations:
Finance lease obligations are primarily related to land. For additional information, see Note 14, "Leases - Lessee" to the Financial Statements of this Annual Report on Form 10-K.
Purchase obligations:
Purchase commitments for coal, gas, purchased power and related transportation:
AES Indiana enters into long-term contracts for the purchase of coal, gas, purchased power and related transportation. In general, these contracts are subject to variable quantities or prices and are terminable only in limited circumstances.
Purchase orders and other contractual obligations:
At December 31, 2023, we had various other contractual obligations including contracts to purchase goods and services with various terms and expiration dates, as well as obligations under long-term construction contracts. Due to uncertainty regarding the timing and payment of future obligations to the Service Company, and our ability to terminate such obligations upon 90 days' notice, we have excluded such amounts in the contractual obligations table above. This table also does not include (i) regulatory liabilities (see Note 2, "Regulatory Matters"), (ii) derivatives (see Note 5, "Derivative Instruments and Hedging Activities"), (iii) taxes (see Note 7, "Income Taxes"), (iv) pension and other postretirement employee benefit liabilities (see Note 8, "Benefit Plans") and (v) contingencies (see Note 10, "Commitments and Contingencies"). See the indicated notes to the Financial Statements of this Annual Report on Form 10-K for additional information on the items excluded.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
We prepare our consolidated financial statements in accordance with GAAP. As such, we are required to make certain estimates, judgments and assumptions that we believe are reasonable based upon the information available. These estimates and assumptions affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the period presented. Therefore, the possibility exists for materially different reported amounts under different conditions or assumptions. Significant accounting policies used in the preparation of the consolidated financial statements are described in Note 1, “Overview and Summary of Significant Accounting Policies” to the Financial Statements of this Annual Report on Form 10-K. This section addresses only those accounting policies involving amounts material to our financial statements that require the most estimation, judgment or assumptions and should be read in conjunction with Note 1, “Overview and Summary of Significant Accounting Policies” to the Financial Statements of this Annual Report on Form 10-K.
Revenue Recognition
For information regarding the nature of our revenue streams and our critical accounting policies affecting revenue recognition, please see Note 1, “Overview and Summary of Significant Accounting Policies - Revenue Recognition” and Note 13, "Revenue" to the Financial Statements of this Annual Report on Form 10-K.
Income Taxes
We are subject to federal and state income taxes. Our income tax provision requires significant judgment and is based on calculations and assumptions that are subject to examination by the U.S. Internal Revenue Service and other tax authorities. We regularly assess the potential outcome of tax examinations when determining the adequacy of our income tax provisions by considering the technical merits of the filing position, case law, and results of previous tax examinations. Accounting guidance for uncertainty in income taxes prescribes a more-likely-than-not recognition threshold and measurement requirements for financial statement reporting of our income tax positions. If tax positions do not meet the more-likely-than-not threshold, reserves will be established. These reserves are adjusted only when there is more information available or when an event occurs necessitating a change to the reserves. While we have reasonably determined that a tax reserve is not required as of December 31, 2023, it is possible that the ultimate outcome of future examinations may be materially different than our current assessment of uncertain tax positions. Please see Note 1, “Overview and Summary of Significant Accounting Policies - Income Taxes” and Note 7, "Income Taxes" to the Financial Statements of this Annual Report on Form 10-K for more information.
Regulatory Assets and Liabilities
As a regulated utility, we apply the provisions of ASC 980 “Regulated Operations,” which gives recognition to the ratemaking and accounting practices of the IURC and the FERC. Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in customer rates. Regulatory liabilities generally represent obligations to make refunds or future rate reductions to customers for previous overcollections or the deferral of revenue collected for costs that AES Indiana expects to incur in the future. Specific regulatory assets and liabilities are disclosed in Note 2, “Regulatory Matters - Regulatory Assets and Liabilities” to the Financial Statements of this Annual Report on Form 10-K.
The deferral of costs (as regulatory assets) is appropriate only when the future recovery of such costs is probable. In assessing probability, we consider such factors as specific orders from the IURC, regulatory precedent and the current regulatory environment. To the extent recovery of costs is no longer deemed probable, related regulatory assets would be required to be expensed in current period income. Our regulatory assets and liabilities have been created pursuant to specific orders of the IURC or established regulatory practices, such as other utilities under the jurisdiction of the IURC being granted recovery of similar costs. It is probable, but not certain, that these regulatory assets will be recoverable, subject to IURC approval.
AROs
In accordance with the provisions of GAAP relating to the accounting for AROs, legal obligations associated with the retirement of long-lived assets are required to be recognized at their fair value at the time those obligations are
incurred. Upon initial recognition of a legal liability, costs are capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. These GAAP provisions also require that components of previously recorded depreciation related to the cost of removal of assets upon future retirement, whether legal AROs or not, must be removed from a company’s accumulated depreciation reserve and be reclassified as a regulatory liability. We make assumptions, estimates and judgments that affect the reported amounts of assets, liabilities and expenses as they relate to AROs. These assumptions and estimates are based on historical experience and assumptions that we believe to be reasonable at the time. See Note 3, "Property, Plant and Equipment - ARO" to the Financial Statements of this Annual Report on Form 10-K for more information.
Pension Plans
The valuation of our benefit obligation, fair value of plan assets, and net periodic benefit costs requires various estimates and assumptions, the most significant of which include the discount rate and expected return on plan assets. We review these and other assumptions, such as mortality, on an annual basis. Please see Note 1, “Overview and Summary of Significant Accounting Policies - Pension and Postretirement Benefits” and Note 8, "Benefit Plans" to the Financial Statements of this Annual Report on Form 10-K for more information.
Contingent and Other Obligations
During the conduct of our business, we are subject to a number of federal and state laws and regulations, as well as other factors and conditions that potentially subject us to environmental, litigation, insurance and other risks. We periodically evaluate our exposure to such risks and record estimated liabilities for those matters where a loss is considered probable and reasonably estimable in accordance with GAAP. In recording such estimated liabilities, we may make assumptions, estimates and judgments that affect the reported amounts of assets, liabilities and expenses as they relate to contingent and other obligations. These assumptions and estimates are based on historical experience and assumptions and may be subject to change. We believe such estimates and assumptions are reasonable.
Please see Note 1, “Overview and Summary of Significant Accounting Policies - Contingencies” and Note 10, “Commitments and Contingencies” to the Financial Statements of this Annual Report on Form 10-K for information about significant contingencies involving us.
NEW ACCOUNTING STANDARDS
Please see Note 1, “Overview and Summary of Significant Accounting Policies” to the Financial Statements of this Annual Report on Form 10-K for a discussion of new accounting pronouncements and the potential impact to our results of operations, financial condition and cash flows.

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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 the prices of SO2 and NOx allowances and certain raw materials. We sometimes use financial instruments and other contracts to hedge against such fluctuations, including, on a limited basis, financial and commodity derivatives. We generally do not enter into derivative instruments for trading or speculative purposes. Our U.S. Risk Management Committee (U.S. RMC), comprised of members of senior management, is responsible for establishing risk management policies and the monitoring and reporting of risk exposures related to our operations. The U.S. RMC meets on a regular basis with the objective of identifying, assessing and quantifying material risk issues and developing strategies to manage these risks.
The disclosures presented in this section are based upon a number of assumptions; actual effects may differ. The safe harbor provided in Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 shall apply to the disclosures contained in this section. For further information regarding market risk, see "Item 1A.-Risk Factors." Our businesses may incur substantial costs and liabilities and be exposed to price volatility as a result of risks associated with the electricity markets, which could have a material adverse effect on our financial performance; and we may not be adequately hedged against our exposure to changes in interest rates.
Wholesale Sales
We engage in wholesale power marketing activities that primarily involve the offering of utility-owned or contracted generation into the MISO day-ahead and real-time markets. Our ability to compete effectively in the wholesale market is dependent on a variety of factors, including our generating availability, the supply of wholesale power, the demand by load-serving entities, and the formation of AES Indiana’s offers into the market. Our wholesale revenue is generated primarily from sales directly to the MISO energy market. The average price per MWh we sold in the wholesale market was $34.13, $69.14 and $27.60 in 2023, 2022 and 2021, respectively. For the periods presented in the Financial Statements of this Annual Report on Form 10-K, a decline in wholesale prices could have had a negative impact on wholesale margins, because most of our non-fuel costs are fixed in the short term and lower wholesale prices can result in lower wholesale volumes sold. However, the impact is limited as the 2018 Base Rate Order provides that annual wholesale margins earned above (or below) a benchmark of $16.3 million shall be passed back (or charged) to customer rates through a rate adjustment mechanism. Our wholesale revenue represented 4.5% of our total electric revenue over the past five years. As a result, we anticipate that a 10% change in the market price for wholesale electricity would not have a material impact on our results of operations.
Fuel
We have limited exposure to commodity price risk for the purchase of coal and natural gas, the primary fuels used by us for the production of electricity. We manage this risk for coal by providing for a significant portion of our current projected burn through 2024 and approximately 83% of our current projected burn for the two-year period ending December 31, 2025, under long-term contracts. In addition, AES Indiana has established physical natural gas hedges for firm supply over a two year period in accordance with a hedge program approved by the IURC. Pricing provisions in some of our long-term contracts allow for price changes under certain circumstances. Our exposure to fluctuations in the price of fuel is limited because pursuant to Indiana law, we apply to the IURC for a change in our fuel charge every three months to recover our estimated fuel costs, which may be above or below the levels included in our basic rates. We must present evidence in each FAC proceeding that we have made every reasonable effort to acquire fuel and generate or purchase power or both so as to provide electricity to our retail customers at the lowest fuel cost reasonably possible.
Power Purchased
We depend on purchased power, in part, to meet our retail load obligations. As a result, we also have limited exposure to commodity price risk for the purchase of electric energy for our retail customers. Purchased power costs can be highly volatile. We are committed under long-term power purchase agreements to purchase all the electricity generated from a project located in Indiana ("Hoosier Wind Project") and a second project located in Minnesota, that have a combined maximum output capacity of 300 MW and have 94.5 MW of solar-generated electricity in our service territory under long-term contracts. AES Indiana is currently in the process of acquiring the Hoosier Wind Project and the existing power purchase agreement will be terminated upon closing (see "IRP Filings and Replacement Generation - Hoosier Wind Project" below for further information). We also purchase up to 8 MW of energy from a combined heat and power facility. We are generally allowed to recover, through our FAC, the energy portion of purchased power costs incurred to meet jurisdictional retail load. In certain circumstances, we may not be allowed to recover a portion of purchased power costs incurred to meet our jurisdictional retail load. See Note 2, “Regulatory Matters - FAC and Authorized Annual Jurisdictional Net Operating Income” to the Financial Statements of this Annual Report on Form 10-K.
Equity Price Risk
Our Pension Plans are impacted significantly by the economy as a result of the Pension Plans being invested in common equity securities. The performance of the Pension Plans’ investments in such common equity securities and other instruments impacts our earnings as well as our funding liability. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $8.3 million reduction in fair value as of December 31, 2023 and approximately a $5.7 million increase to the 2024 pension expense. Please see Note 8, “Benefit Plans” to the Financial Statements of this Annual Report on Form 10-K for additional Pension Plan information.
Interest Rate Risk
We use long-term debt as a significant source of capital in our business, which exposes us to interest rate risk. We do not enter into market risk sensitive instruments for trading purposes. We manage our exposure to interest rate risk through the use of fixed-rate debt and by refinancing existing long-term debt at times when it is deemed economic and prudent. In addition, AES Indiana’s Credit Agreement and $300 million Term Loan Agreement bears interest at a variable rate based either on the Prime interest rate or on the SOFR. Fair values relating to financial instruments are dependent upon prevalent market rates of interest. At December 31, 2023, we had approximately $3,033.8 million principal amount of fixed rate debt and $455.0 million variable rate debt outstanding. In regard to our fixed rate debt, the interest rate risk with respect to long-term debt primarily relates to the potential impact a decrease in interest rates has on the fair value of our fixed-rate debt and not on our financial condition or results of operations. Our interest rate risk on our fixed-rate debt is associated with refinancing activity.
The following table shows our consolidated indebtedness (in millions) by maturity as of December 31, 2023:
2024 2025 2026 2027 2028 Thereafter Total Fair Value
Fixed-rate $ 445.0 $ 40.0 $ 90.0 $ - $ - $ 2,458.8 $ 3,033.8 $ 2,860.5
Variable-rate 455.0 - - - - - 455.0 455.0
Total Indebtedness $ 900.0 $ 40.0 $ 90.0 $ - $ - $ 2,458.8 $ 3,488.8 $ 3,315.5
Weighted Average Interest Rates by Maturity 5.087% 0.650% 0.883% N/A N/A 4.877% 4.780%
For further discussion of our fair value of our indebtedness and book value of our indebtedness please see Note 4, “Fair Value” and Note 6, “Debt” to the Financial Statements of this Annual Report on Form 10-K.
Retail Energy Market
The legislatures of several states have enacted laws that allow various forms of competition or that experiment with allowing some form of customer choice of electricity suppliers for retail sales of electric energy. Indiana has not done so. In Indiana, competition among electric energy providers for sales has focused primarily on the sale of bulk power to other public and municipal utilities. Indiana law provides for electricity suppliers to have exclusive retail service areas. In order to increase sales, we work to attract new customers into our service territory. Although the retail sales of electric energy are regulated, we face competition from other energy sources. For example, customers have a choice of installing electric or natural gas home and hot water heating systems or installing qualified generation facilities on their premises.
Counterparty Credit Risk
At times, we may utilize forward purchase contracts to manage the risk associated with power purchases and could be exposed to counterparty credit risk in these contracts. We manage this exposure to counterparty credit risk by entering into contracts with companies that are expected to fully perform under the terms of the contract. Individual credit limits are generally implemented for each counterparty to further mitigate credit risk. We may also require a counterparty to provide collateral in the event certain financial benchmarks are not maintained, or certain credit ratings are not maintained.
We are also exposed to counterparty credit risk related to our ability to collect electricity sales from our customers, which may be impacted by volatility in the financial markets and the economy. Historically, our write-offs of customer accounts have been immaterial, which is common for the electric utility industry.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page No.
IPALCO Enterprises, Inc. and Subsidiaries - Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm - 2023, 2022 and 2021 (PCAOB ID: 42)
Consolidated Statements of Operations for the Years Ended December 31, 2023, 2022 and 2021 63
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2023, 2022 and 2021 64
Consolidated Balance Sheets as of December 31, 2023 and 2022 65
Consolidated Statements of Cash Flows for the Years Ended December 31, 2023, 2022 and 2021 66
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2023, 2022 and 2021
Notes to Consolidated Financial Statements 68
AES Indiana and Subsidiaries - Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm - 2023, 2022 and 2021 (PCAOB ID: 42)
Consolidated Statements of Operations for the Years Ended December 31, 2023, 2022 and 2021 115
Consolidated Balance Sheets as of December 31, 2023 and 2022 116
Consolidated Statements of Cash Flows for the Years Ended December 31, 2023, 2022 and 2021 117
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2023, 2022 and 2021
Notes to Consolidated Financial Statements 119
Report of Independent Registered Public Accounting Firm
To the Shareholders and the Board of Directors of IPALCO Enterprises, Inc.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of IPALCO Enterprises, Inc. and subsidiaries (the Company) as of December 31, 2023 and 2022, the related consolidated statements of operations, comprehensive income, changes in equity and cash flows for each of the three years in the period ended December 31, 2023, and the related notes and financial statement schedules listed in the Index at Item 15 (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023 in conformity with U.S. generally accepted accounting principles.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the Board of Directors and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Regulatory Accounting
Regulatory Accounting
Description of the Matter As described in Note 2 to the consolidated financial statements, the Company applies the provisions of FASB Accounting Standards Codification 980 “Regulated Operations”, which gives recognition to the ratemaking and accounting practices of the Indiana Utility Regulatory Commission and the Federal Energy Regulatory Commission. Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in customer rates. Regulatory assets can also represent performance incentives permitted by the regulator. Regulatory liabilities generally represent obligations to provide refunds or future rate reductions to customers for previous overcollections or the deferral of revenues collected for costs that the Company expects to incur in the future. Accounting for the economics of rate regulation affects multiple consolidated financial statement line items, including property, plant, and equipment; regulatory assets and liabilities; revenues; and depreciation expense, and related disclosures in the Company’s consolidated financial statements
Auditing the Company’s regulatory accounting was complex due to significant judgments made by management to support its assertions about the impact of future regulatory orders on the consolidated financial statements. In particular, there is subjectivity involved in assessing the impact of current and future regulatory orders on events that have occurred through December 31, 2023, judgment required to evaluate the relevance and reliability of audit evidence to support impacted account balances and disclosures, and judgments involved in assessing the probability of recovery in future rates of incurred costs or refunds to customers. These assumptions have a significant effect on the consolidated financial statements and related disclosures.
How We Addressed the Matter in Our Audit To evaluate the Company’s significant judgments in accounting for regulatory assets and liabilities, our audit procedures included, among others, reviewing relevant regulatory orders, statutes and interpretations; filings made by intervening parties; and other publicly available information, to assess the likelihood of recovery of regulatory assets in future rates or of a refund or future reduction in rates for regulatory liabilities based on precedents for the treatment of similar costs under similar circumstances. We evaluated the Company’s assertions regarding the probability of recovery of regulatory assets or refund or future reduction in rates for regulatory liabilities, to assess the Company’s assertion that amounts are probable of recovery or of a refund or future reduction in rates.
Asset Retirement Obligations
Regulatory Accounting
Description of the Matter At December 31, 2023, the Company’s asset retirement obligations (“ARO”) totaled $249.9 million. As described in Note 3 to the consolidated financial statements, the Company’s ARO liabilities relate primarily to environmental issues involving asbestos-containing materials, ash ponds, landfills and miscellaneous contaminants associated with its generating plants, transmission system and distribution system. The Company recorded adjustments to its ARO liabilities of $30.0 million during 2023. ARO liabilities incurred in 2023 primarily related to FGD residual water disposal. ARO liabilities were revised in 2023 primarily to reflect revisions to cash flow estimates due to increases to estimated ash pond closure costs.
Auditing the Company’s ARO liabilities was complex and highly judgmental due to the significant estimation required by management to determine the estimated cost estimates of the legal obligations associated with the Company’s generating plants, transmission system and distribution system. In particular, the estimate was sensitive to significant assumptions including the scope and method of decommissioning and timing of related cash flows.
How We Addressed the Matter in Our Audit To test the Company’s ARO liability estimates, our audit procedures included evaluating the appropriateness of the Company’s methodology, interviewing members of the Company’s environmental staff and testing significant assumptions and inputs including the timing of activities, projected closure dates and the method of decommissioning. We involved our specialists in our assessment of the Company’s ARO liabilities including reviewing the Company’s methodology, evaluating the reasonableness of the cost estimates and assumptions, and assessing completeness of the estimates with respect to regulatory requirements.
/s/ Ernst & Young LLP
We have served as the Company’s auditor since 2008.
Indianapolis, Indiana
February 26, 2024
IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Consolidated Statements of Operations
For the Years Ended December 31, 2023, 2022 and 2021
2023 2022 2021
(In Thousands)
REVENUE $ 1,649,917 $ 1,791,711 $ 1,426,132
OPERATING COSTS AND EXPENSES:
Fuel 494,000 568,676 255,817
Power purchased 159,908 199,860 175,025
Operation and maintenance 477,880 493,674 449,746
Depreciation and amortization 287,863 266,504 256,085
Taxes other than income taxes 24,864 33,048 44,419
Other, net (361) (3,201) (5,630)
Total operating costs and expenses 1,444,154 1,558,561 1,175,462
OPERATING INCOME 205,763 233,150 250,670
OTHER (EXPENSE) / INCOME, NET:
Allowance for equity funds used during construction 9,315 4,784 5,412
Interest expense (142,926) (131,232) (125,626)
Other (expense) / income, net (410) 11,783 17,667
Total other expense, net (134,021) (114,665) (102,547)
INCOME BEFORE INCOME TAX 71,742 118,485 148,123
Income tax expense 14,715 21,859 28,941
NET INCOME 57,027 96,626 119,182
Dividends on and redemption of preferred stock - 3,509 3,213
Net loss attributable to noncontrolling interests (26,093) - -
NET INCOME ATTRIBUTABLE TO COMMON STOCK $ 83,120 $ 93,117 $ 115,969
See Notes to Consolidated Financial Statements.
IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Consolidated Statements of Comprehensive Income
For the Years Ended December 31, 2023, 2022 and 2021
2023 2022 2021
(In Thousands)
NET INCOME $ 57,027 $ 96,626 $ 119,182
Derivative activity:
Change in derivative fair value, net of income tax effect of $(528), $(15,309) and $(3,441), for each respective period
1,594 46,245 10,393
Reclassification to earnings, net of income tax effect of $(1,798), $(1,798) and $(1,199), for each respective period
5,431 5,431 3,620
Net change in fair value of derivatives 7,025 51,676 14,013
Other comprehensive income 7,025 51,676 14,013
Comprehensive income 64,052 148,302 133,195
Less: dividends on and redemption of preferred stock of subsidiary
- 3,509 3,213
Less: comprehensive loss attributable to noncontrolling interests
(26,093) - -
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON STOCK
$ 90,145 $ 144,793 $ 129,982
See Notes to Consolidated Financial Statements.
IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Consolidated Balance Sheets
December 31, 2023 December 31, 2022
(In Thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 28,579 $ 201,548
Accounts receivable, net of allowance for credit losses of $2,283 and $1,117, respectively
233,921 216,523
Inventories 143,590 123,608
Regulatory assets, current 89,419 119,723
Taxes receivable 36,481 18,000
Derivative assets, current 15,682 7,545
Prepayments and other current assets 26,358 19,882
Total current assets 574,030 706,829
NON-CURRENT ASSETS:
Property, plant and equipment 7,082,443 6,982,314
Less: Accumulated depreciation 2,954,555 3,243,968
4,127,888 3,738,346
Construction work in progress 359,014 294,985
Total net property, plant and equipment 4,486,902 4,033,331
OTHER NON-CURRENT ASSETS:
Intangible assets - net 235,656 138,978
Regulatory assets, non-current 541,784 593,939
Pension plan assets 41,172 33,611
Derivative assets, non-current - 12,172
Other non-current assets 301,979 70,354
Total other non-current assets 1,120,591 849,054
TOTAL ASSETS $ 6,181,523 $ 5,589,214
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Short-term debt and current portion of long-term debt (see Note 6) $ 899,159 $ -
Accounts payable 292,851 189,845
Accrued taxes 22,580 22,474
Accrued interest 33,639 33,447
Customer deposits 29,308 35,097
Regulatory liabilities, current 23,371 23,348
Accrued and other current liabilities 27,547 19,014
Total current liabilities 1,328,455 323,225
NON-CURRENT LIABILITIES:
Long-term debt (see Notes 6 and 14) 2,576,798 3,016,810
Deferred income tax liabilities 361,488 312,641
Regulatory liabilities, non-current 527,224 612,585
Accrued other postretirement benefits 2,776 3,085
Asset retirement obligations 249,930 218,729
Other non-current liabilities 5,130 11,621
Total non-current liabilities 3,723,346 4,175,471
Total liabilities 5,051,801 4,498,696
COMMITMENTS AND CONTINGENCIES (see Note 10)
EQUITY:
Common shareholders' equity
Common stock (no par value, 290,000,000 shares authorized; 108,907,318 shares issued and outstanding at December 31, 2023 and 2022)
- -
Paid in capital 1,021,992 1,068,357
Accumulated other comprehensive income 29,294 22,269
Retained earnings / (accumulated deficit) 25,182 (108)
Total common shareholders' equity 1,076,468 1,090,518
Noncontrolling interests 53,254 -
Total equity 1,129,722 1,090,518
TOTAL LIABILITIES AND EQUITY $ 6,181,523 $ 5,589,214
See Notes to Consolidated Financial Statements.
IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Consolidated Statements of Cash Flows
For the Years Ended December 31, 2023, 2022 and 2021
2023 2022 2021
CASH FLOWS FROM OPERATING ACTIVITIES: (In Thousands)
Net income $ 57,027 $ 96,626 $ 119,182
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization 287,863 266,504 256,085
Amortization of deferred financing costs and debt discounts 3,880 3,914 3,915
Deferred income taxes and investment tax credit adjustments - net 32,653 (6,706) (7,378)
Allowance for equity funds used during construction (9,315) (4,784) (5,412)
Gain on acquisition - - (5,630)
Change in certain assets and liabilities:
Accounts receivable (17,398) (37,387) (13,943)
Inventories (30,171) (47,489) (12,017)
Prepayments and other current assets (6,476) 19,056 (4,593)
Accounts payable 46,993 32,038 21,417
Accrued and other current liabilities 2,790 6,532 (13,017)
Accrued taxes payable/receivable (18,375) (5,858) 638
Accrued interest 192 2,813 (1,099)
Pension and other postretirement benefit assets and liabilities 1,625 (8,727) (16,592)
Current and non-current regulatory assets and liabilities
54,358 38,863 (104,759)
Other non-current liabilities
(9,445) (14,384) 10,446
Other - net
(4,268) 5,335 (2,026)
Net cash provided by operating activities 391,933 346,346 225,217
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (902,705) (496,510) (291,510)
Project development costs (4,462) (3,910) (1,304)
Cost of removal payments (45,595) (23,948) (35,260)
Insurance proceeds
4,900 - -
Purchase of intangibles (44,650) - (26,261)
Other (361) (719) (14,380)
Net cash used in investing activities (992,873) (525,087) (368,715)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings from revolving credit facilities 435,000 300,000 320,000
Repayments from revolving credit facilities (280,000) (360,000) (335,000)
Short-term borrowings 300,000 200,000 -
Repayments of short-term borrowings
- (200,000) -
Long-term borrowings - 350,000 95,000
Retirement of long-term borrowings, including early payment premium
- - (95,000)
Distributions to shareholders (104,287) (101,986) (131,476)
Equity contributions from shareholders - 253,000 275,000
Sales to noncontrolling interests
77,921 - -
Redemption of preferred stock - (60,080) -
Preferred dividends of subsidiary - (3,213) (3,213)
Payments of deferred financing costs and discounts (350) (4,309) (1,387)
Other (313) (35) (131)
Net cash provided by financing activities 427,971 373,377 123,793
Net change in cash, cash equivalents and restricted cash (172,969) 194,636 (19,705)
Cash, cash equivalents and restricted cash at beginning of year 201,553 6,917 26,622
Cash, cash equivalents and restricted cash at end of year $ 28,584 $ 201,553 $ 6,917
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the period for:
Interest (net of amount capitalized) $ 129,113 $ 115,277 $ 118,052
Income taxes $ - $ 31,000 $ 27,500
Non-cash investing activities:
Accruals for capital expenditures $ 124,626 $ 66,949 $ 81,325
Recognition and changes to right-of-use assets - finance leases $ 983 $ (3,402) 19,763
Non-cash financing activities:
Recognition and changes to financing lease liabilities $ (1,408) $ (3,402) $ 19,763
See Notes to Consolidated Financial Statements.
IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Consolidated Statements of Changes in Equity
For the Years Ended December 31, 2023, 2022 and 2021
Common Shareholders' Equity
Common Stock
(in Thousands)
Outstanding Shares
Amount
Paid in
Capital Accumulated Other Comprehensive Income (Loss) Retained Earnings (Accumulated
Deficit) Total Common Shareholders' Equity Cumulative Preferred Stock of Subsidiary Noncontrolling Interests
Balance at January 1, 2021 108,907 $ - $ 588,966 $ (43,420) $ (24,558) $ 520,988 $ 59,784 $ -
Net income - - 119,182 119,182 3,213 -
Other comprehensive income - 14,013 - 14,013
Preferred stock dividends - - (3,213) (3,213) (3,213) -
Distributions to shareholders(1)
(15,507) - (115,969) (131,476) - -
Contributions from shareholders 275,000 - - 275,000 - -
Other 106 - - 106 - -
Balance at December 31, 2021 108,907 - 848,565 (29,407) (24,558) 794,600 59,784 -
Net income - - 96,626 96,626 3,213 -
Other comprehensive income - 51,676 - 51,676
Preferred stock dividends - - (3,213) (3,213) (3,213) -
Redemption of preferred stock - - (296) (296) (59,784) -
Distributions to shareholders(1)
(33,319) - (68,667) (101,986) - -
Contributions from shareholders 253,000 - - 253,000 - -
Other 111 - - 111 - -
Balance at December 31, 2022 108,907 - 1,068,357 22,269 (108) 1,090,518 - -
Net income / (loss) - - 83,120 83,120 - (26,093)
Other comprehensive income - 7,025 - 7,025 - -
Distributions to shareholders(1)
(46,457) - (57,830) (104,287) - -
Sales to noncontrolling interests - - - - 79,347
Other 92 - - 92 - -
Balance at December 31, 2023 108,907 $ - $ 1,021,992 $ 29,294 $ 25,182 $ 1,076,468 $ - $ 53,254
(1) IPALCO made return of capital payments of $46.5 million, $33.3 million and $15.5 million in 2023, 2022 and 2021, respectively, for the portion of current year distributions to shareholders in excess of current year net income at the time of distribution.
See Notes to Consolidated Financial Statements.
IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Notes to Consolidated Financial Statements
For the Years Ended December 31, 2023, 2022 and 2021
1. OVERVIEW AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
IPALCO is a holding company incorporated under the laws of the state of Indiana. IPALCO, acquired by AES in March 2001, is owned by AES U.S. Investments (82.35%) and CDPQ (17.65%). AES U.S. Investments is owned by AES U.S. Holdings, LLC (85%) and CDPQ (15%). IPALCO owns all of the outstanding common stock of IPL, which does business as AES Indiana. Substantially all of IPALCO’s business consists of generating, transmitting, distributing and selling of electric energy conducted through its principal subsidiary, AES Indiana. AES Indiana was incorporated under the laws of the state of Indiana in 1926. AES Indiana has approximately 523,000 retail customers in the city of Indianapolis and neighboring cities, towns and communities, and adjacent rural areas all within the state of Indiana. AES Indiana has an exclusive right to provide electric service to those customers.
AES Indiana owns and operates four generating stations all within the state of Indiana. The first station, Petersburg, is coal-fired, and AES Indiana retired 230 MW Petersburg Unit 1 in May 2021 and 415 MW Petersburg Unit 2 in June 2023, which resulted in 630 MW of total retired economic capacity at this station. AES Indiana plans to convert the remaining two coal units at Petersburg to natural gas (for further discussion, see Note 2, "Regulatory Matters - IRP Filings and Replacement Generation - 2022 IRP"). The second station, Harding Street, consists of three natural gas-fired boilers and steam turbines and uses natural gas and fuel oil to power five combustion turbines. In addition, AES Indiana operates a 20 MW battery energy storage unit at this location, which provides frequency response. The third station, Eagle Valley, is a CCGT natural gas plant. The fourth station, Georgetown, is a peaking station that uses natural gas to power combustion turbines. As of December 31, 2023, AES Indiana’s net electric generation capacity for winter is 3,070 MW and net summer capacity is 2,925 MW.
In December 2021, AES Indiana, through a wholly-owned subsidiary, completed the acquisition of Hardy Hills Solar Energy LLC, including the development of a 195 MW solar project (the "Hardy Hills Solar Project"). In December 2023, the first stage of construction for the Hardy Hills Solar Project was completed and placed in service, with initial operations for over half of the project commencing on December 28, 2023. The final stage for construction of the project is expected to be completed during the first half of 2024.
In August 2023, AES Indiana, through a wholly-owned subsidiary, completed the acquisition of Petersburg Energy Center, LLC, including the development of a 250 MW solar and 45 MW (180 MWh) energy storage facility (the "Petersburg Energy Center Project"). The Petersburg Energy Center Project is expected to be completed in 2025.
In June 2023, AES Indiana, through a wholly-owned subsidiary, executed an agreement for the construction of the 200 MW (800 MWh) Pike County BESS Project to be developed at the AES Indiana Petersburg Plant site in Pike County, Indiana, subject to IURC approval, which was received in January 2024. The Pike County BESS Project is expected to be completed in 2024.
For further discussion about AES Indiana's plans for wind, solar, and battery energy storage projects, please see Note 2, "Regulatory Matters - IRP Filings and Replacement Generation."
IPALCO’s other direct subsidiary is Mid-America. Mid-America is the holding company for IPALCO’s unregulated activities, which have not been material to the financial statements in the periods covered by this report. IPALCO’s regulated business is conducted through AES Indiana. IPALCO has two business segments: utility and nonutility. The utility segment consists of the operations of AES Indiana and everything else is included in the nonutility segment.
Principles of Consolidation
IPALCO’s consolidated financial statements are prepared in accordance with GAAP and in conjunction with the rules and regulations of the SEC. The consolidated financial statements include the accounts of IPALCO, its regulated utility subsidiary, AES Indiana, and its unregulated subsidiary, Mid-America. Furthermore, VIEs in which the Company has an ownership interest and is the primary beneficiary, thus controlling the VIE, as described below, have been consolidated. All intercompany items have been eliminated in consolidation. Certain costs for shared resources amongst AES Indiana and IPALCO, such as labor and benefits, are allocated to each entity based on
allocation methodologies that management believes to be reasonable. We have evaluated subsequent events through the date this report is issued.
If IPALCO enters into transactions impacting equity interests in its affiliates, IPALCO must determine whether the transaction impacts the Company's consolidation conclusion by first determining whether the transaction should be evaluated under the variable interest model or the voting model. In determining which consolidation model applies to the transaction, IPALCO is required to make judgments about how the entity operates, the most significant of which are whether (i) the entity has sufficient equity to finance its activities, (ii) the equity holders, as a group, have the characteristics of a controlling financial interest, and (iii) whether the entity has non-substantive voting rights. If the entity is determined to be a variable interest entity and IPALCO is determined to have power and benefits, the entity will be consolidated by IPALCO.
Noncontrolling Interests
Noncontrolling interests are classified as a separate component of equity in the Consolidated Balance Sheets and Consolidated Statements of Changes in Equity. Additionally, net income attributable to noncontrolling interests is reflected separately from consolidated net income on the Consolidated Statements of Operations. Any change in ownership of a subsidiary while the controlling financial interest is retained is accounted for as an equity transaction between the controlling and noncontrolling interests. Losses continue to be attributed to the noncontrolling interests, even when the noncontrolling interests' basis has been reduced to zero.
Allocation of Earnings
Hardy Hills JV is subject to profit-sharing arrangements where the allocation of earnings, cash distributions, and tax benefits are not based on fixed ownership percentages. This arrangement exists to designate different allocations of value among the investors, where the allocations change in form or percentage over the life of the partnership. IPALCO uses the HLBV method when it is a reasonable approximation of the profit-sharing arrangement. The HLBV method calculates the proceeds that would be attributable to each partner based on the liquidation provisions of the respective operating partnership agreement if the partnership was to be liquidated at book value at the balance sheet date. Each partner’s share of income in the period is equal to the change in the amount of net equity they are legally able to claim based on a hypothetical liquidation of the entity at the end of a reporting period compared to the beginning of that period, adjusted for any capital transactions (for further discussion about the Equity Capital Contribution Agreement, see Note 2, "Regulatory Matters - IRP Filings and Replacement Generation").
The HLBV method is used to calculate the earnings attributable to noncontrolling interest when the business is consolidated by IPALCO. In the early months of operations of a renewable generation facility where HLBV results in a significant decrease in the hypothetical liquidation proceeds attributable to the tax equity investor due to the recognition of ITCs or other adjustments as required by the U.S. Internal Revenue Code, the Company records the impact (sometimes referred to as the ‘Day one gain’) to income in the same period.
Use of Management Estimates
The preparation of financial statements in conformity with GAAP requires that management make certain estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements. The reported amounts of revenue and expenses during the reporting period may also be affected by the estimates and assumptions management is required to make. Actual results may differ from those estimates. Significant items subject to such estimates and assumptions include: recognition of revenue including unbilled revenue; the carrying value of property, plant and equipment; the valuation of insurance and claims liabilities; the valuation of allowances for credit losses and deferred income taxes; regulatory assets and liabilities; liabilities recorded for income tax exposures; litigation; contingencies; and assets and liabilities related to AROs and employee benefits.
Reclassifications
Certain immaterial amounts from prior periods have been reclassified to conform to the current year presentation.
Cash and Cash Equivalents
Cash and cash equivalents are stated at cost, which approximates fair value. All highly liquid short-term investments with original maturities of three months or less are considered cash equivalents.
Restricted Cash
Restricted cash includes cash which is restricted as to withdrawal or usage. The nature of the restrictions includes restrictions imposed by agreements related to deposits held as collateral.
The following table provides a summary of cash, cash equivalents, and restricted cash amounts reported within the Consolidated Balance Sheets that reconcile to the total of such amounts as shown on the Consolidated Statements of Cash Flows:
As of December 31,
2023 2022
(In Thousands)
Cash, cash equivalents and restricted cash
Cash and cash equivalents $ 28,579 $ 201,548
Restricted cash (included in Prepayments and other current assets) 5 5
Total cash, cash equivalents and restricted cash $ 28,584 $ 201,553
Accounts Receivable and Allowance for Credit Losses
The following table summarizes our accounts receivable balances at December 31:
As of December 31,
2023 2022
(In Thousands)
Accounts receivable, net
Customer receivables $ 125,715 $ 125,540
Unbilled revenue 91,463 74,488
Amounts due from related parties 5,178 239
Other 13,848 17,373
Allowance for credit losses (2,283) (1,117)
Total accounts receivable, net $ 233,921 $ 216,523
The following table is a rollforward of our allowance for credit losses related to the accounts receivable balances for the periods indicated:
For the Years Ended December 31,
2023 2022
(In Thousands)
Allowance for credit losses:
Beginning balance $ 1,117 $ 647
Current period provision 7,413 5,851
Write-offs charged against allowance
(7,764) (7,008)
Recoveries collected 1,517 1,627
Ending Balance $ 2,283 $ 1,117
The allowance for credit losses primarily relates to utility customer receivables, including unbilled amounts. Expected credit loss estimates are developed by disaggregating customers into those with similar credit risk
characteristics and using historical credit loss experience. In addition, we also consider how current and future economic conditions are expected to impact collectability, as applicable, of our receivable balance. Amounts are written off when reasonable collections efforts have been exhausted.
Inventories
We maintain coal, fuel oil, natural gas, materials and supplies inventories for use in the production of electricity. These inventories are accounted for at the lower of cost or net realizable value, using the average cost. The following table summarizes our inventories balances at December 31:
As of December 31,
2023 2022
(In Thousands)
Inventories
Fuel $ 77,198 $ 60,497
Materials and supplies, net 66,392 63,111
Total inventories $ 143,590 $ 123,608
Regulatory Accounting
The retail utility operations of AES Indiana are subject to the jurisdiction of the IURC. AES Indiana’s wholesale power transactions are subject to the jurisdiction of the FERC. These agencies regulate AES Indiana’s utility business operations, tariffs, accounting, depreciation allowances, services, issuances of securities and the sale and acquisition of utility properties. The financial statements of AES Indiana are based on GAAP, including the provisions of FASB ASC 980 “Regulated Operations,” which gives recognition to the ratemaking and accounting practices of these agencies. See also Note 2, “Regulatory Matters - Regulatory Assets and Liabilities” for a discussion of specific regulatory assets and liabilities.
Property, Plant and Equipment
Property, plant and equipment is stated at original cost as defined for regulatory purposes. The cost of additions to property, plant and equipment and replacements of retirement units of property are charged to plant accounts. Units of property replaced or abandoned in the ordinary course of business are retired from the plant accounts at cost; such amounts, less salvage, are charged to accumulated depreciation. Depreciation is computed by the straight-line method based on functional rates approved by the IURC and averaged 3.7%, 3.8% and 3.7% during 2023, 2022 and 2021, respectively. Depreciation expense was $244.8 million, $247.5 million, and $239.1 million for the years ended December 31, 2023, 2022 and 2021, respectively. "Depreciation and amortization" expense on the accompanying Consolidated Statements of Operations is presented net of regulatory deferrals of depreciation expense and also includes amortization of intangible assets and amortization of previously deferred regulatory costs.
AFUDC
In accordance with the Uniform System of Accounts prescribed by FERC, AES Indiana capitalizes an allowance for the net cost of funds (interest on borrowed funds and a reasonable rate of return on equity funds) used for construction purposes during the period of construction with a corresponding credit to income. AES Indiana capitalized amounts using pretax composite rates of 7.1%, 5.4% and 5.7% during 2023, 2022 and 2021, respectively. AFUDC equity and AFUDC debt were as follows for the years ended December 31, 2023, 2022 and 2021:
2023 2022 2021
(In Thousands)
AFUDC equity $ 9,315 $ 4,784 $ 5,412
AFUDC debt $ 13,739 $ 8,215 $ 4,815
Impairment of Long-lived Assets
GAAP requires that we test long-lived assets for impairment when indicators of impairment exist. If an asset is deemed to be impaired, we are required to write down the asset to its fair value with a charge to current earnings. The net book value of our property, plant, and equipment was $4.5 billion and $4.0 billion as of December 31, 2023 and 2022, respectively. As of December 31, 2023 and 2022, AES Indiana had $259.9 million and $287.5 million, respectively, of long-term regulatory assets associated with Petersburg Unit 1 and 2 retirement costs (for further discussion, see Note 2, “Regulatory Matters - IRP Filings and Replacement Generation” and Note 3, "Property, Plant and Equipment"). We do not believe any of these assets are currently impaired. In making this assessment, we consider such factors as: the overall condition and generating and distribution capacity of the assets; the expected ability to recover additional expenditures in the assets; the anticipated demand and relative pricing of retail electricity in our service territory and wholesale electricity in the region; and the cost of fuel.
Intangible Assets
Finite-lived intangible assets primarily include capitalized software and project development intangible assets amortized on a straight-line basis over their useful lives. The following table presents information related to the Company's intangible assets, including the gross amount capitalized and related amortization:
December 31,
$ in thousands
Weighted average amortization periods (in years)
Capitalized software
8 $ 261,872 $ 205,910
Project development intangible assets
28 84,097 39,455
Other
Various
797 797
Less: Accumulated amortization
(111,110) (107,184)
Intangible assets - net
$ 235,656 $ 138,978
For the Years Ended December 31,
2023 2022 2021
Amortization expense
$ 14,570 $ 10,122 $ 11,241
Estimated future amortization
Years ending December 31,
2024 $ 20,764
2025 20,764
2026 22,550
2027 22,550
2028 22,550
Total
$ 109,178
Implementation Costs Related to Software as a Service
IPALCO has recorded prepayments for implementation costs related to software as a service in support of utility customer services of $7.1 million and $8.2 million as of December 31, 2023 and 2022, respectively, which are recorded within "Other non-current assets" on the accompanying Consolidated Balance Sheets.
Debt Issuance Costs
Costs incurred in connection with the issuance of long-term debt are deferred and presented as a direct reduction from the face amount of that debt and amortized over the related financing period using the effective interest method. Debt issuance costs related to a line-of-credit or revolving credit facility are deferred and presented as an asset and amortized over the related financing period. Make-whole payments in connection with early debt retirements are classified as cash flows from financing activities.
Contingencies
IPALCO accrues for loss contingencies when the amount of the loss is probable and estimable. We are subject to various environmental regulations and are involved in certain legal proceedings. If IPALCO’s actual environmental and/or legal obligations are different from our estimates, the recognition of the actual amounts may have a material impact on our results of operations, financial condition and cash flows; although that has not been the case during the periods covered by this report. Accruals for loss contingencies were not material as of December 31, 2023 and 2022. See Note 10, "Commitments and Contingencies - Contingencies" for additional information.
Concentrations of Risk
Substantially all of AES Indiana’s customers are located within the Indianapolis area. Approximately 68% of AES Indiana’s employees are covered by collective bargaining agreements in two bargaining units: a physical unit and a clerical-technical unit. AES Indiana’s contract with the physical unit expires on December 4, 2024, and the contract with the clerical-technical unit expires February 12, 2026. Additionally, AES Indiana has long-term coal contracts with one supplier, and substantially all of AES Indiana's coal is currently mined in the state of Indiana.
Financial Derivatives
All derivatives are recognized as either assets or liabilities in the balance sheets and are measured at fair value. Changes in the fair value are recorded in earnings unless the derivative is designated as a cash flow hedge of a forecasted transaction or it qualifies for the normal purchases and sales exception.
AES Indiana has contracts involving the physical delivery of energy and fuel. Because some of these contracts qualify for the normal purchases and normal sales scope exception in ASC 815, AES Indiana has elected to account for them as accrual contracts, which are not adjusted for changes in fair value. AES Indiana has or previously had FTRs and forward power contracts that do not qualify for hedge accounting or the normal purchases and sales exceptions under ASC 815. Accordingly, FTRs are recorded at fair value when acquired and subsequently amortized over the annual period as they are used. FTRs are initially recorded at fair value using the income approach. The forward power contracts are recorded at fair value with changes in the fair value charged or credited to the Consolidated Statements of Operations in the period in which the change occurred. Forward power contracts are fair valued using the market approach.
Additionally, we use interest rate hedges to manage the interest rate risk associated with refinancing our long-term debt. We use cash flow hedge accounting when the hedge or a portion of the hedge is deemed to be highly effective, which results in changes in the fair value being recorded within accumulated other comprehensive income, a component of shareholders' equity. We have elected not to offset net derivative positions in the Financial Statements. Accordingly, we do not offset such derivative positions against the fair value of amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral under master netting agreements. See Note 5, “Derivative Instruments and Hedging Activities” for additional information.
Leases
The Company has finance leases primarily for land in which the Company is the lessee. Operating leases with an initial term of 12 months or less are not recorded on the balance sheet, but are expensed on a straight-line basis over the lease term. The Company’s leases do not contain any material residual value guarantees, restrictive covenants or subleases.
Right-of-use assets represent our right to use an underlying asset for the lease term while lease liabilities represent our obligation to make lease payments arising from the lease. Right-of-use assets and lease liabilities are recognized on commencement of the lease based on the present value of lease payments over the lease term. Generally, the rate implicit in the lease is not readily determinable; as such, we use the incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The Company determines discount rates based on its existing credit rates of its borrowings, which are then adjusted for the appropriate lease term. The right-of-use asset also includes any lease payments made and excludes lease incentives that are paid or payable to the lessee at commencement. The lease term includes periods covered by the option to extend if it is reasonably certain that the option will be exercised and periods covered by an option to terminate if it is reasonably certain that the option will not be exercised.
Accumulated Other Comprehensive Income / (Loss)
The amounts reclassified out of AOCI / (AOCL) by component during the years ended December 31, 2023, 2022 and 2021 are as follows (in thousands):
Details about AOCI / (AOCL) components Affected line item in the Consolidated Statements of Operations For the Years Ended December 31,
2023 2022 2021
Net losses on cash flow hedges (Note 5): Interest expense $ 7,229 $ 7,229 $ 4,819
Income tax effect (1,798) (1,798) (1,199)
Total reclassifications for the period, net of income taxes $ 5,431 $ 5,431 $ 3,620
See Note 5, "Derivative Instruments and Hedging Activities - Cash Flow Hedges" for further information on the changes in the components of AOCL.
Revenue Recognition
Revenue related to the sale of energy is generally recognized when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to certain customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is accrued. In making its estimates of unbilled revenue, AES Indiana uses models that consider various factors including daily generation volumes; known amounts of energy usage by nearly all residential, commercial and industrial customers; and estimated customer rates based on prior period billings. Given the use of these models, and that customers are billed on a monthly cycle, we believe it is unlikely that materially different results will occur in future periods when revenue is billed. An allowance for potential credit losses is maintained and amounts are written off when normal collection efforts have been exhausted. Our provision for expected credit losses included in “Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations was $7.5 million, $5.9 million and $3.0 million for the years ended December 31, 2023, 2022 and 2021, respectively.
AES Indiana’s basic rates include a provision for fuel costs as established in AES Indiana’s most recent rate proceeding, which last adjusted AES Indiana’s rates in December 2018. AES Indiana is permitted to recover actual costs of purchased power and fuel consumed, subject to certain restrictions. This is accomplished through quarterly FAC proceedings, in which AES Indiana estimates the amount of fuel and purchased power costs in future periods. Through these proceedings, AES Indiana is also permitted to recover, in future rates, underestimated fuel and purchased power costs from prior periods, subject to certain restrictions, and therefore the over or underestimated costs are deferred or accrued and amortized into fuel expense in the same period that AES Indiana’s rates are adjusted. See also Note 2, “Regulatory Matters” for a discussion of other costs that AES Indiana is permitted to recover through periodic rate adjustment proceedings and the status of current rate adjustment proceedings.
In addition, we are one of many transmission system owner members of MISO, a RTO which maintains functional control over the combined transmission systems of its members and manages one of the largest energy markets in the U.S. See Note 13, "Revenue" for additional information of MISO sales and other revenue streams.
Operating Expenses - Other, Net
Operating expenses - Other, net generally includes gains or losses on asset sales, dispositions or acquisitions, gains or losses on the sale or acquisition of businesses, and other expense or income from miscellaneous operating transactions. For the year ended December 31, 2022, the $3.2 million is primarily due to a gain on remeasurement of contingent consideration associated with the Hardy Hills Solar Project acquisition. For the year ended December 31, 2021, the $5.6 million represents a gain on acquisition.
Pension and Postretirement Benefits
We recognize in our Consolidated Balance Sheets an asset or liability reflecting the funded status of pension and other postretirement plans with current-year changes in the funded status, that would otherwise be recognized in AOCI, recorded as a regulatory asset as this can be recovered through future rates. All plan assets are recorded at
fair value. We follow the measurement date provisions of the accounting guidance, which require a year-end measurement date of plan assets and obligations for all defined benefit plans.
We account for and disclose pension and postretirement benefits in accordance with the provisions of GAAP relating to the accounting for pension and other postretirement plans. These GAAP provisions require the use of assumptions, such as the discount rate for liabilities and long-term rate of return on assets, in determining the obligations, annual cost and funding requirements of the plans. Consistent with the requirements of ASC 715, we apply a disaggregated discount rate approach for determining service cost and interest cost for our defined benefit pension plans and postretirement plans.
See Note 8, "Benefit Plans" for more information.
Income Taxes
Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of the existing assets and liabilities, and their respective income tax bases. The Company establishes a valuation allowance when it is more likely than not that all or a portion of a deferred tax asset will not be realized. The Company’s tax positions are evaluated under a more likely than not recognition threshold and measurement analysis before they are recognized for financial statement reporting.
Uncertain tax positions are classified as noncurrent income tax liabilities unless expected to be paid within one year. The Company’s policy for interest and penalties is to recognize interest and penalties as a component of the provision for income taxes in the Consolidated Statements of Operations.
Income tax assets or liabilities, which are included in allowable costs for ratemaking purposes in future years, are recorded as regulatory assets or liabilities with a corresponding deferred tax liability or asset. Investment tax credits that reduced federal income taxes in the years they arose have been deferred and are being amortized to income over the useful lives of the properties in accordance with regulatory treatment. See Note 2, "Regulatory Matters" for additional information.
IPALCO and its subsidiaries file U.S. federal income tax returns as part of the consolidated U.S. income tax return filed by AES. The consolidated tax liability is allocated to each subsidiary based on the separate return method which is specified in our tax allocation agreement and which provides a consistent, systematic and rational approach. See Note 7, "Income Taxes" for additional information.
Repair and Maintenance Costs
Repair and maintenance costs are expensed as incurred.
Per Share Data
IPALCO is owned by AES U.S. Investments and CDPQ. IPALCO does not report earnings on a per-share basis.
New Accounting Pronouncements
We have assessed and determined that the new accounting pronouncements adopted did not have a material impact on the Company's Financial Statements.
New Accounting Pronouncements Issued But Not Yet Effective
The following table provides a brief description of recent accounting pronouncements that could have a material impact on the Company's Financial Statements once adopted. Accounting pronouncements not listed below were assessed and determined to be either not applicable or are expected to have no material impact on the Company's Financial Statements.
ASU Number and Name Description Date of Adoption Effect on the Financial Statements upon adoption
2023-06 Disclosure Improvements: Codification Amendments in Response to the SEC’s Disclosure Update and Simplification Initiative
In U.S. Securities and Exchange Commission (SEC) Release No. 33-10532, Disclosure Update and Simplification, issued August 17, 2018, the SEC referred certain of its disclosure requirements that overlap with, but require incremental information to, generally accepted accounting principles (GAAP) to the FASB for potential incorporation into the Codification. The amendments in this Update are the result of the Board’s decision to incorporate into the Codification 14 of the 27 disclosures referred by the SEC.
The amendments in this Update represent changes to clarify or improve disclosure and presentation requirements of a variety of Topics. Many of the amendments allow users to more easily compare entities subject to the SEC’s existing disclosures with those entities that were not previously subject to the SEC’s requirements. Also, the amendments align the requirements in the Codification with the SEC’s regulations.
The effective date for each amendment will be the date on which the SEC's removal of that related disclosure becomes effective, with early adoption prohibited. The amendments in this Update should be applied prospectively.
We will provide the required disclosures on a prospective basis on the date each amendment becomes effective. We do not expect ASU 2023-06 will have any impact to our consolidated financial statements.
2023-07 Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures
The amendments in this section are designed to improve the disclosures related to Segment reporting on an interim and annual basis. Public companies must disclose significant segment expenses and an amount for other segment items. This will also require that a company disclose its annual disclosures under Topic 280 in each interim period. Furthermore, companies will need to disclose the Chief Operating Decision Maker (CODM) and how the CODM assesses the performance of a segment. Lastly, public companies that have a single reportable segment must report the required disclosures under topic 280.
The amendments in this Update are effective for fiscal years beginning after
December 15, 2023, and interim periods within fiscal years beginning after
December 15, 2024. Early adoption is permitted.
We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
2023-09 Income Taxes (Topic 740): Improvements to Income Tax Disclosures
The amendments in this Update require that public business entities on an annual basis (1) disclose specific categories in the rate reconciliation and (2) provide additional information for reconciling items that meet a quantitative threshold. Furthermore, companies are required to disclose a disaggregated amount of income taxes paid at a federal, state, and foreign level as well as a break down of income taxes paid in a jurisdiction that comprises 5% of a company's total income taxes paid. Lastly, this ASU requires that companies disclose income (loss) from continuing operations before income tax at a domestic and foreign level and that companies disclose income tax expense from continuing operations on a federal, state, and foreign level.
The amendments in this Update are effective for fiscal years beginning after December 15, 2024.
We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
2. REGULATORY MATTERS
General
AES Indiana is subject to regulation by the IURC as to its services and facilities, the valuation of property, the construction, purchase, or lease of electric generating facilities, the classification of accounts, rates of depreciation, retail rates and charges, the issuance of securities (other than evidences of indebtedness payable less than twelve months after the date of issue), the acquisition and sale of some public utility properties or securities and certain other matters.
In addition, AES Indiana is subject to the jurisdiction of the FERC with respect to, among other things, short-term borrowings not regulated by the IURC, the sale of electricity at wholesale, the transmission of electric energy in interstate commerce, the classification of accounts, reliability standards, and the acquisition and sale of utility property in certain circumstances as provided by the Federal Power Act. As a regulated entity, AES Indiana is required to use certain accounting methods prescribed by regulatory bodies which may differ from those accounting methods required to be used by unregulated entities.
AES Indiana is also affected by the regulatory jurisdiction of the EPA at the federal level, and the IDEM at the state level. Other significant regulatory agencies affecting AES Indiana include, but are not limited to, the NERC, the U.S. Department of Labor and the IOSHA.
Basic Rates and Charges
Our basic rates and charges represent the largest component of our annual revenue. Our basic rates and charges are determined after giving consideration, on a pro-forma basis, to all allowable costs for ratemaking purposes including a fair return on the fair value of the utility property used and useful in providing service to customers. These basic rates and charges are set and approved by the IURC after public hearings. Such proceedings, which have occurred at irregular intervals, involve AES Indiana, the IURC, the Indiana Office of Utility Consumer Counselor, and other interested stakeholders. Pursuant to statute, the IURC is to conduct a periodic review of the basic rates and charges of all Indiana utilities at least once every four years, but the IURC has the authority to review the rates of any Indiana utility at any time. Once set, the basic rates and charges authorized do not assure the realization of a fair return on the fair value of property.
Our declining block rate structure generally provides for residential and commercial customers to be charged a lower per kWh rate at higher consumption levels. Therefore, as volumes increase, the weighted average price per kWh decreases. Numerous factors including, but not limited to, weather, inflation, customer growth and usage, the level of actual operating and maintenance expenditures, fuel costs, generating unit availability, and capital expenditures including those required by environmental regulations can affect the return realized.
Regulatory Rate Review and Base Rate Orders
AES Indiana filed a petition with the IURC on June 28, 2023, for authority to increase its basic rates and charges to cover the rising operational costs and needs associated with continuing to serve its customers safely and reliably. The factors leading to AES Indiana's first base rate increase request in five years include inflationary impacts on operations and maintenance expenses, investments in the transmission and distribution systems, and modernization of its customer systems. AES Indiana is also seeking recovery of increased costs to support its vegetation management plan, which covers the removal of overhang and tree trimming in its service territory. AES Indiana also seeks to better align depreciation expense with the period in which the generation plants provide service to customers and remove operational costs of the retired Petersburg units from rates. On November 22, 2023, AES Indiana entered into a unanimous stipulation and settlement agreement (the "settlement") with the OUCC and the intervening parties which, if approved by the IURC, would increase its annual revenue requirement by $73 million. AES Indiana expects to receive an order from the IURC and place new rates into effect by the end of the second quarter of 2024.
On October 31, 2018, the IURC issued an order approving an uncontested settlement agreement previously filed with the IURC by AES Indiana for a $43.9 million, or 3.2%, increase to annual revenue (the "2018 Base Rate Order"). The 2018 Base Rate Order includes recovery through rates of the CCGT at Eagle Valley completed in the first half of 2018, as well as other construction projects and changes to operating income since the 2016 Base Rate Order. New basic rates and charges became effective on December 5, 2018. The 2018 Base Rate Order provides that annual wholesale margins earned above (or below) the benchmark of $16.3 million shall be passed back (or charged) to customer rates through a rate adjustment mechanism. Similarly, the 2018 Base Rate Order provides that all capacity sales above (or below) a benchmark of $11.3 million shall be passed back (or charged) to customer rates through a rate adjustment mechanism.
FAC and Authorized Annual Jurisdictional Net Operating Income
AES Indiana may apply to the IURC for a change in AES Indiana’s fuel charge every three months to recover AES Indiana’s estimated fuel costs, including the energy portion of purchased power costs, which may be above or below the levels included in AES Indiana’s basic rates and charges. AES Indiana must present evidence in each
FAC proceeding that it has made every reasonable effort to acquire fuel and generate or purchase power or both so as to provide electricity to its retail customers at the lowest fuel cost reasonably possible.
Independent of the IURC’s ability to review basic rates and charges, Indiana law requires electric utilities under the jurisdiction of the IURC to meet operating expense and income test requirements as a condition for approval of requested changes in the FAC. A utility may be unable to recover all of its fuel costs if its rolling twelve-month operating income, determined at quarterly measurement dates, exceeds its authorized annual jurisdictional net operating income and there are not sufficient applicable cumulative net operating income deficiencies (“Cumulative Deficiencies”) to offset it. The Cumulative Deficiencies calculation provides that only five years’ worth of historical earnings deficiencies or surpluses are included, unless it has been greater than five years since the most recent rate case.
In calendar years 2021 and 2022, AES Indiana reported earnings in excess of the authorized level for certain quarterly reporting periods in those years. AES Indiana has not reported earnings in excess of the authorized level for any FAC periods in the calendar year 2023. Prior to 2020, AES Indiana was not required to reduce its fuel cost recovery because of its Cumulative Deficiencies. During 2020, AES Indiana's Cumulative Deficiencies dropped to zero. AES Indiana recorded a reduction to revenue of $0.0 million, $0.3 million and $5.5 million in 2023, 2022 and 2021, respectively. As of the FAC period ending with the twelve months of October 31, 2023, AES Indiana has Cumulative Deficiencies; therefore, AES will not be required to reduce its fuel cost recovery for future earnings in excess of the authorized level until there are no longer Cumulative Deficiencies.
ECCRA
AES Indiana may apply to the IURC for approval of a rate adjustment known as the ECCRA periodically to recover costs (including a return) to comply with certain environmental regulations applicable to AES Indiana’s generating stations and to recover certain investments in renewable and battery storage projects. The total amount of AES Indiana’s environmental equipment and renewable projects approved for ECCRA recovery as of December 31, 2023 was $129.7 million. The jurisdictional revenue requirement approved by the IURC to be included in AES Indiana’s rates for the twelve-month period ending February 2024 is a net cost to customers of $8.9 million.
DSM
Through various rate orders from the IURC, AES Indiana has been able to recover its costs of implementing various DSM programs throughout the periods covered by this report. In 2023, 2022 and 2021, AES Indiana also had the ability to receive performance incentives, dependent upon the level of success of the programs. Performance incentives included in rates for the years ended December 31, 2023, 2022 and 2021 were $2.7 million, $8.3 million and $7.2 million, respectively.
On December 29, 2020, the IURC approved a settlement agreement establishing a new three year DSM plan for AES Indiana through 2023. The approval included cost recovery of programs as well as performance incentives, depending on the level of success of the programs. The order also approved recovery of lost revenue, consistent with the provisions of the settlement agreement.
AES Indiana filed a petition with the IURC on May 26, 2023 asking for approval of a one year DSM interim plan. On December 27, 2023, the IURC approved a one-year DSM plan for AES Indiana through 2024. The approval included cost recovery of programs as well as performance incentives, depending on the level of success of the programs. The order also approved recovery of lost revenue, consistent with the provisions of the settlement agreement.
Wind and Solar Power Purchase Agreements
We are currently committed under a power purchase agreement to purchase all wind-generated electricity through 2029 from a wind project in Indiana ("Hoosier Wind Project"). On July 28, 2023, AES Indiana executed the Purchase Agreement and is currently in the process of acquiring this project. The existing power purchase agreement will be terminated upon closing (see "IRP Filings and Replacement Generation - Hoosier Wind Project" below for further information). We are also committed under another agreement to purchase all wind-generated electricity through 2031 from a project in Minnesota. The Indiana project has a maximum output capacity of approximately 100 MW and the Minnesota project has a maximum output capacity of approximately 200 MW. In addition, we have 94.5 MW of solar-generated electricity in our service territory under long-term contracts (these long-term contracts have
expiration dates ranging from 2026 to 2033), of which 94.0 MW was in operation as of December 31, 2023. We have authority from the IURC to recover the costs for all of these agreements through an adjustment mechanism administered within the FAC. If and when AES Indiana sells the renewable energy attributes (in the form of renewable energy credits) generated from these facilities, the proceeds would pass back to benefit AES Indiana’s retail customers through the FAC.
TDSIC
In 2013, Senate Enrolled Act 560, the Transmission, Distribution, and Storage System Improvement Charge ("TDSIC") statute, was signed into law. The TDSIC statute was revised in 2019. Among other provisions, this legislation provides for cost recovery outside of a base rate proceeding for new or replacement electric and gas transmission, distribution, and storage projects that a public utility undertakes for the purposes of safety, reliability, system modernization, or economic development. Provisions of the TDSIC statute require that, among other things, requests for recovery include a plan of at least five years and not more than seven for eligible investments. The first eighty percent of eligible costs can be recovered using a periodic rate adjustment mechanism. The cost recovery mechanism is referred to as a TDSIC mechanism. Recoverable costs include a return on, and of, the investment, including AFUDC, post-in-service carrying charges, operation and maintenance expenses, depreciation and property taxes. The remaining twenty percent of recoverable costs are to be deferred for future recovery in the public utility’s next base rate case. The periodic rate adjustment mechanism is capped at an annual increase of no more than two percent of total retail revenue.
On March 4, 2020, the IURC issued an order approving the projects in a seven-year TDSIC Plan for eligible transmission, distribution and storage system improvements totaling $1.2 billion from 2020 through 2026. Beginning in June 2020, AES Indiana files an annual TDSIC rate adjustment for a return on and of investments through March 31 with rates requested to be effective each November. Annual TDSIC plan update filings are required to be staggered by six months as ordered by the IURC and are filed each December. The total amount of AES Indiana’s equipment net of depreciation, including carrying costs, approved for TDSIC recovery as of December 31, 2023 was $399.6 million. The jurisdictional revenue requirement approved by the IURC to be included in AES Indiana’s rates for the twelve-month period ending October 2024 is a net cost to customers of $56.5 million.
IRP Filings and Replacement Generation
Electric utilities in Indiana are required to submit Integrated Resource Plans (IRPs) every three years. The IRPs are subject to a rigorous stakeholder process. IRPs describe how the utility plans to deliver safe, reliable, and efficient electricity at just and reasonable rates.
2022 IRP
AES Indiana held public advisory meetings for the 2022 IRP in January, April, June, September and October of 2022. Changes to our generation portfolio are evaluated and decided through the IRP. AES Indiana issued an all-source Request for Proposal on April 14, 2022, in order to competitively procure energy and capacity in the near term; such need was evaluated in AES Indiana's 2022 IRP.
In December 2022, AES Indiana filed its 2022 IRP with the IURC, which describes AES Indiana's Preferred Resource Portfolio for meeting generation capacity needs for serving AES Indiana's retail customers over the next several years. The Preferred Resource Portfolio is AES Indiana's reasonable least cost option and provides a cleaner and more diverse generation mix for customers. The 2022 IRP short-term action plan includes converting the two remaining coal units at Petersburg to natural gas. AES Indiana has not yet filed for the regulatory approvals from the IURC to convert Petersburg units 3 and 4; however, AES Indiana expects to do so in the first half of 2024. Construction is expected to begin in 2025 and be completed by the end of 2026. Additionally, AES Indiana plans to add up to 1,300 MW of wind, solar, and battery energy storage by 2027. As new technologies, such as green hydrogen, small modular reactors and carbon capture are developed and cost effective, AES Indiana will evaluate them in the future planning processes. As a result of the plan to convert Petersburg units 3 and 4 to natural gas, AES Indiana recorded a $1.5 million write off of capital projects during the period ended December 31, 2022 to "Operating expenses - Operation and maintenance" on the accompanying Consolidated Statements of Operations.
2019 IRP
In December 2019, AES Indiana filed its 2019 IRP, which included the retirement of approximately 630 MW of coal-fired generation at Petersburg Units 1 and 2 in 2021 and 2023, respectively. Based on extensive modeling, AES Indiana determined that the cost of operating Petersburg Units 1 and 2 exceeded the value customers received compared to alternative resources. Retirement of these units allowed the company to cost-effectively diversify the portfolio and transition to lower cost and cleaner resources while maintaining a reliable system.
AES Indiana issued an all-source Request for Proposal on December 20, 2019, in order to competitively procure replacement capacity by June 1, 2023, which was the first year AES Indiana was expected to have a capacity shortfall. Our modeling indicated that a combination of wind, solar, storage, and energy efficiency would be the lowest reasonable cost option for the replacement capacity. As a result of the plans to retire Petersburg Units 1 and 2, AES Indiana recorded $0.7 million, $2.1 million, and $0.8 million of obsolescence losses, during the periods ended December 31, 2023, 2022, and 2021, respectively, for materials and supplies inventory AES Indiana did not believe will be utilized by the planned retirement dates, which is recorded in "Operating expenses - Operation and maintenance" on the accompanying Consolidated Statements of Operations.
As a result of the plans to retire Petersburg Units 1 and 2, AES Indiana filed a petition with the IURC on February 26, 2021 for approvals and cost recovery associated with these retirements. On August 6, 2021, AES Indiana filed an uncontested Stipulation and Settlement Agreement with the other parties in the case which includes: (1) AES Indiana's creation of regulatory assets for the net book value of Petersburg units 1 and 2 upon retirement; (2) a method for amortization of the regulatory assets; and (3) recovery of the regulatory assets through ongoing amortization in AES Indiana’s future rate cases. The Settlement Agreement also reserves all rights of all the parties with respect to the ratemaking treatment related to the regulatory assets, including the proper rate of return and mechanisms for recovery. On November 17, 2021, the IURC approved the Settlement Agreement without modification. AES Indiana retired 230 MW Petersburg Unit 1 in May 2021 and 415 MW Petersburg Unit 2 in June 2023.
AES Indiana had $35.7 million and $224.2 million of Petersburg Units 1 and 2 retirement costs, respectively, net of accumulated amortization, recorded as long-term regulatory assets as of December 31, 2023. AES Indiana had $47.6 million and $239.9 million of Petersburg Units 1 and 2 retirement costs, respectively, net of accumulated amortization, recorded as long-term regulatory assets as of December 31, 2022.
Hardy Hills Solar Project
In January 2021, AES Indiana, through a wholly-owned subsidiary, executed an agreement for the acquisition and construction of the 195 MW Hardy Hills Solar Project to be developed in Clinton County, Indiana. In December 2022, the agreement was amended to revise the project schedule, including shifting the completion date to 2024, and adjusting for increased project costs. On January 13, 2023, AES Indiana filed a petition with the IURC for approval of these revisions, which was approved in August 2023.
On June 16, 2021, AES Indiana received an order from the IURC approving a petition and case-in-chief seeking a CPCN for this solar project, including a joint venture structure between an AES Indiana subsidiary and one or more tax equity partners upon completion and approval for recovery of project development costs and carrying costs on AES Indiana's investment in the project. The transaction closed in December 2021 and was accounted for as an asset acquisition of a variable interest entity that did not meet the definition of a business; therefore, the individual assets and liabilities were recorded at their fair values. Total net assets of $51.6 million were recorded in the accompanying Consolidated Balance Sheets associated with the transaction, primarily consisting of a development project intangible asset (see Note 1, "Overview and Summary of Significant Accounting Policies - Intangible Assets"). A gain for the difference between the consideration transferred and the assets and liabilities recognized was recorded in “Operating costs and expenses - Other, net” on the accompanying Consolidated Statements of Operations. Total consideration included a future payment contingent on certain future costs incurred by the project. As such, a $3.2 million contingent liability was recorded in "Other Non-Current Liabilities" on the accompanying Consolidated Balance Sheets as of December 31, 2021. During 2022, this liability was remeasured due to updated cost estimates and was reduced to $0.0 million.
On December 1, 2023, AES Indiana, through a wholly-owned subsidiary (the "Class B Member"), and a third-party investor (the "Class A Member"), entered into an Equity Capital Contribution Agreement, pursuant to which each member made certain capital contributions to Hardy Hills JV. The Class A member made total contributions of
$79.3 million through December 31, 2023. Hardy Hills JV is consolidated by the Class B Member under the Variable Interest Model, and noncontrolling interest (“NCI”) was recorded by AES Indiana at the amount of cash contributed by the Class A Member. In December 2023, the first stage of the construction for the Hardy Hills Solar Project was completed and placed in service, with initial operations for over half of the project commencing on December 28, 2023. Upon the first stage of the project being placed in service, the Company recognized $26.1 million of earnings from tax attributes using the HLBV method. The final stage for construction of the project is expected to be completed during the first half of 2024.
Petersburg Energy Center Project
In July 2021, AES Indiana, through a wholly-owned subsidiary, executed an agreement for the acquisition and construction of a 250 MW solar and 45MW (180 MWh) energy storage facility to be developed in Pike County, Indiana. In October 2022, the agreement was amended to revise the project schedule, including shifting the completion date to 2025, and adjusting for increased project costs. On December 22, 2022, AES Indiana filed a petition with the IURC for approval of these revisions, which was approved in May 2023. On August 31, 2023, AES Indiana closed on the agreement for the acquisition and construction of the Petersburg Energy Center Project. This transaction was accounted for as an asset acquisition of a variable interest entity that did not meet the definition of a business; therefore, the individual assets were recorded at their fair values. Total net assets of $48.7 million were recorded in the accompanying Consolidated Balance Sheets associated with the transaction, primarily consisting of project development intangible assets (see Note 1, "Overview and Summary of Significant Accounting Policies - Intangible Assets" for further information).
Pike County BESS Project
In June 2023, AES Indiana, through a wholly-owned subsidiary, executed an agreement for the construction of the 200 MW (800 MWh) Pike County BESS Project to be developed at the AES Indiana Petersburg Plant site in Pike County, Indiana. On July 19, 2023, AES Indiana filed a petition and case-in-chief with the IURC seeking approval for a Clean Energy Project and associated timely cost recovery under Indiana Code for this project. A hearing for this case was held in October 2023, and IURC approval was received on January 17, 2024. The Pike County BESS Project is expected to be completed in 2024.
Hoosier Wind Project
On July 5, 2023, AES Indiana filed a Notice of Intent with the IURC to request approval of a Clean Energy Project and for issuance of a CPCN for the Hoosier Wind Project acquisition. The proposed Project is the acquisition of the Hoosier Wind Project, which is an existing 106 MW wind facility located in Benton County, Indiana. The Company executed the Purchase Agreement on July 28, 2023. A CPCN for this case was filed in early August 2023, and IURC approval was received on January 24, 2024. The acquisition of the Hoosier Wind Project is expected to be completed in the first quarter of 2024.
Incentives for Clean Energy Projects
Indiana Code 8-1-8 (the "clean energy statute") offers certain incentives for clean energy projects. Primarily, it allows for the timely recovery of costs and expenses incurred during construction and operation of eligible projects outside of a base rate proceeding. Clean energy projects eligible for incentives under this statute include renewable energy resources such as wind, photovoltaic cells and panels, solar energy, and energy storage systems or technologies, among others. AES Indiana filed for and received IURC approval of the Hoosier Wind Project and Pike County BESS Project under this statute. AES Indiana continues to evaluate projects which may also be filed under this statute.
IURC COVID-19 Orders
Due to the COVID-19 pandemic, there was a disconnection moratorium in 2020 for IURC-jurisdictional utilities, as well as suspension of certain utility fees (late fees, convenience fees, deposits, and disconnection/reconnection fees) from residential customers. The IURC authorized Indiana utilities to use regulatory accounting for any impacts associated with the moratorium and suspension. The IURC also authorized regulatory accounting treatment for COVID-19 related uncollectible and incremental bad debt expense. As a result of the IURC's COVID-19 related orders issued in 2020, AES Indiana has recorded a regulatory asset of $5.4 million as of December 31, 2023 and
2022, which will be recovered through base rates under the stipulation and settlement agreement entered into on November 22, 2023, if approved by the IURC.
EDG Rates
On March 1, 2021, AES Indiana filed a petition with the IURC for approval of its proposed rate for the procurement of EDG and related consumer EDG credit issues. The EDG rate replaced the net metering program beginning in July 2022, when net metering was no longer available to new customers. The IURC approved the EDG rate by order dated January 26, 2022, On March 16, 2022, the IURC denied the petition for reconsideration filed by the other parties on February 15, 2022. The matter was subject to an appeal filed by the other parties on February 22, 2022, which was held in abeyance by the Indiana Court of Appeals pending resolution of a petition to transfer to the Indiana Supreme Court filed in a similar case involving a different and unaffiliated utility. The stay was extended by the Indiana Court of Appeals on July 11, 2022. On January 4, 2023, the Indiana Supreme Court issued a final decision in favor of the utility in the similar case that served as the basis of the stay in the AES Indiana case. On February 3, 2023, the OUCC moved to dismiss the appeal, which motion was granted on February 13, 2023.
EV Portfolio Program
On January 27, 2023, AES Indiana filed with the IURC a request to approve its EV Portfolio and associated accounting and ratemaking treatment. The EV Portfolio includes two separate parts: (1) a set of EV specific rates, tariffs, and alternative pricing structures, and (2) a set of Public Use EV Pilot Programs. The EV portfolio is designed to produce net benefits for all customers through new retail margins and grid optimization. The projected costs to successfully implement the services proposed in the EV Portfolio are estimated at $16.2 million over the three-year period. AES Indiana requested approval to defer as a regulatory asset and recover in future base rates the cost necessary to implement the EV Portfolio, including carrying charges. A hearing on this request was held in July 2023. On November 22, 2023, the IURC issued an order approving AES Indiana's EV Portfolio filing with approval to defer as a regulatory asset and to seek recovery in future base rates the cost necessary to implement the EV Portfolio, including carrying charges with no other significant modifications.
Storm Outage Restoration Inquiry
On July 11, 2023, the OUCC and the Citizens Action Coalition (“CAC”) filed a Joint Petition through which they requested the IURC open an investigation into AES Indiana’s practices and procedures regarding storm outage restoration. A technical conference was held on October 2, 2023, to discuss AES Indiana’s response to outages and storm restoration; particularly the storms that occurred between June 29, 2023 and July 2, 2023.
House Bill 1002
In the first quarter of 2022, the 2022 Indiana General Assembly passed House Enrolled Act 1002, which includes language regarding the repeal of the URT. AES Indiana filed a rate adjustment with the IURC on April 29, 2022, which was approved by the IURC on June 28, 2022. AES Indiana began charging the new rates excluding URT in July 2022. Prior to the repeal, the URT was recoverable through a current charge to customer rates. After the repeal, the new rates approved by the IURC adjusted both revenue and tax expense. As a result, the repeal of the URT had no impact on the Company's net income.
Regulatory Assets and Liabilities
Regulatory assets represent deferred costs or credits that have been included as allowable costs or credits for ratemaking purposes. AES Indiana has recorded regulatory assets or liabilities relating to certain costs or credits as authorized by the IURC or established regulatory practices in accordance with ASC 980. AES Indiana is amortizing non tax-related regulatory assets to expense over periods ranging from 1 to 43 years. Tax-related regulatory assets represent the net income tax costs to be considered in future regulatory proceedings generally as the tax-related amounts are paid.
The amounts of regulatory assets and regulatory liabilities at December 31 are as follows:
2023 2022 Recovery Period
(In Thousands)
Regulatory assets, current:
Undercollections of rate riders $ 75,416 $ 26,047 Approximately 1 year(1)
Fuel costs - 79,861 Approximately 1 year(1)
Unamortized reacquisition premium on debt 188 - Approximately 1 year
Costs being recovered through basic rates and charges 13,815 13,815 Approximately 1 year(1)
Total regulatory assets, current 89,419 119,723
Regulatory assets, non-current:
Unrecognized pension and other
postretirement benefit plan costs 115,847 131,907 Various(2)
Deferred MISO costs 21,091 34,483 Through 2026(1)
Unamortized Petersburg Unit 4 carrying
charges and certain other costs 2,812 3,866 Through 2026(1)(3)
Unamortized reacquisition premium on debt 13,379 14,429 Over remaining life of debt
Environmental costs 66,837 68,947 Through 2046(1)(3)
COVID-19 costs 5,426 5,426 4 years(4)
Major storm damage 1,493 - To be determined
TDSIC costs 35,979 18,547 36.3 years(1)(3)
Petersburg Unit 1 and 2 retirement costs 259,892 287,463 Through 2034(1)(3)
Hardy Hills Solar Project development costs 6,774 5,744 30 years(3)
Petersburg Energy Center Project development costs 2,469 1,582 30 years(3)
Pike County BESS Project development costs 2,623 - 20 years(3)
Fuel costs 4,275 20,518 Through 2025(1)
Other miscellaneous 2,887 1,027 Various(5)
Total regulatory assets, non-current 541,784 593,939
Total regulatory assets $ 631,203 $ 713,662
Regulatory liabilities, current:
Overcollections and other credits being passed
to customers through rate riders $ 19,649 $ 15,803 Approximately 1 year(1)
FTRs 3,722 7,545 Approximately 1 year(1)
Total regulatory liabilities, current 23,371 23,348
Regulatory liabilities, non-current:
ARO and accrued asset removal costs 451,886 518,797 Not applicable
Deferred income taxes payable to customers through rates 74,796 88,662 Various
Hardy Hills sponsor investment tax credit 542 - To be determined(6)
Major storm damage - 5,126 To be determined
Total regulatory liabilities, non-current 527,224 612,585
Total regulatory liabilities $ 550,595 $ 635,933
(1)Recovered (credited) per specific rate orders
(2)AES Indiana receives a return on its discretionary funding
(3)Recovered with a current return
(4)Per the signed stipulation in the 2023 distribution rate case, Cause No. 45911
(5)Some of these costs are being recovered in basic rates and charges through 2026. For the remainder, recovery over four years was agreed to in the signed stipulation in the 2023 distribution rate case, Cause No. 45911. AES Indiana will include this credit in a future ECR filing.
(6)Will be included in a future ECR filing
Current Regulatory Assets and Liabilities
Current regulatory assets and liabilities primarily represent costs that are being recovered per specific rate orders; recovery for the remaining costs is probable, but not certain. As current assets, this includes undercollection of adjustment mechanisms for: (i) DSM, (ii) ECCRA costs, (iii) Off System Sales Margin Sharing, (iv) Capacity rider costs and (v) TDSIC. It also includes the current portion of deferred MISO costs and environmental costs collected through base rates which are described in greater detail below. With the exception of environmental costs, these costs do not earn a return on investment. As current liabilities, this includes (i) overcollection of MISO rider costs, (ii) Green Power, and (iii) deferred fuel costs.
Deferred Fuel
Deferred fuel costs are a component of current and long-term regulatory assets or liabilities (which is a result of AES Indiana charging either more or less for fuel than our actual costs to our jurisdictional customers) and are expected to be recovered through future FAC proceedings. AES Indiana records deferred fuel in accordance with standards prescribed by the FERC. The deferred fuel adjustment is the result of variances between estimated fuel and purchased power costs in AES Indiana’s FAC and actual fuel and purchased power costs. AES Indiana is generally permitted to recover underestimated fuel and purchased power costs in future rates through the FAC proceedings and therefore the costs are deferred when incurred and amortized into fuel expense in the same period that AES Indiana’s rates are adjusted to reflect these costs.
The Eagle Valley CCGT was on unplanned outage from late April 2021 until mid-March 2022, impacting several FAC periods. In November 2021, a sub-docket was created with the IURC to examine the unplanned outage. On October 25, 2022, AES Indiana and various intervening parties reached a unanimous settlement regarding the Eagle Valley CCGT unplanned outage, resolving all issues related to the FAC sub-docket and all outage related costs including energy purchases, Off-System Sales margins, Capacity trackers and base rate proceedings. As part of this comprehensive settlement, AES Indiana agreed not to recover $21.0 million of previously deferred costs and to credit an additional $6.8 million to customers in future rates. As such, AES Indiana recorded a $27.8 million charge to "Power purchased" in the Consolidated Statements of Operations during the third quarter of 2022. On January 18, 2023, AES Indiana received an order from the IURC approving the settlement.
Unrecognized Pension and Postretirement Benefit Plan Costs
In accordance with ASC 715 “Compensation - Retirement Benefits” and ASC 980, we recognize a regulatory asset equal to the unrecognized actuarial gains and losses and prior service costs. Pension expenses or income are recorded based on the benefit plan’s actuarially determined pension liability or asset and associated level of annual expenses or income to be recognized. The other postretirement benefit plan’s deferred benefit cost is the excess of the other postretirement benefit liability over the amount previously recognized.
Deferred MISO Costs
These consist of administrative costs for transmission services, transmission expansion cost sharing, and certain other operational and administrative costs from the MISO market. These costs are being recovered per specific rate order.
Unamortized Petersburg Unit 4 Carrying Charges and Certain Other Costs
These consist of deferred debt carrying costs, depreciation, and post-in-service AFUDC on Petersburg Unit 4. These costs are being recovered per specific rate order.
Unamortized Reacquisition Premium on Debt
This regulatory asset represents losses on long-term debt reacquired or redeemed in prior periods that have been deferred. These deferred losses are being amortized over the lives of the original issues in accordance with the rules of the FERC and the IURC.
Environmental Costs
These consist of various costs incurred to comply with environmental regulations. These costs were approved for recovery either through AES Indiana's ECCRA proceedings or in the 2018 Base Rate Order. Amortization periods vary, ranging from 3 to 43 years.
COVID-19 Costs
These consist of deferred fees (foregone late fees, reconnection fees and disconnection fees), as well as deferred convenience payments and incremental bad debt expense as the result of COVID-19. See "IURC COVID-19 Orders" above for additional discussion.
TDSIC Costs
These consist of various costs incurred for AES Indiana's approved TDSIC Plan. These costs were approved for recovery through AES Indiana's TDSIC proceedings and amortization periods range from 1 to 36 years. See "TDSIC" above for additional discussion.
Petersburg Unit 1 and 2 Retirement Costs
These consist of the remaining unamortized net book value of Petersburg Unit 1 and 2. In accordance with ASC 980, it was determined that the Petersburg Unit 1 retirement became probable, in the fourth quarter of 2020, and the Petersburg Unit 2 retirement became probable in the fourth quarter of 2021. As the entire carrying value of these assets will be recoverable through future rates, no loss on abandonment was recorded and the asset was reclassified from net property, plant and equipment to a long-term regulatory asset. See "IRP Filings and Replacement Generation" above for additional discussion.
Hardy Hills Solar Project Development Costs
These consist of project development costs, mainly legal and consulting fees, incurred for the Hardy Hills Solar Project as well as carrying costs on AES Indiana's investment in the project. The investment costs were approved for recovery via the ECCRA rider through AES Indiana’s Hardy Hills Solar Project regulatory proceedings with an amortization period of 30 years. Amortization of the project development costs will be determined in a future rate case filing.
Petersburg Energy Center Project Development Costs
These consist of project development costs, mainly legal and consulting fees, incurred for the Petersburg Energy Center Project as well as carrying costs on AES Indiana's investment in the project. The investment costs were approved for recovery via the ECCRA rider through AES Indiana’s Petersburg Energy Center Project regulatory proceedings with an amortization period of 30 years. Amortization of the project development costs will be determined in a future rate case filing.
Pike County BESS Project Development Costs
These consist of project development costs, mainly legal and consulting fees, incurred for the Pike County BESS Project as well as carrying costs on AES Indiana's investment in the project. The investment costs were approved for recovery via the ECCRA rider through AES Indiana’s Pike County BESS Project regulatory proceedings with an amortization period of 20 years. Amortization of the project development costs will be determined in a future rate case filing.
FTRs
In connection with AES Indiana’s participation in MISO, in the second quarter of each year AES Indiana is granted financial instruments that can be converted into cash or FTRs based on AES Indiana’s forecasted peak load for the period. See Note 4, "Fair Value - Fair Value Hierarchy and Valuation Techniques - Financial Assets - FTRs" for additional information.
ARO and Accrued Asset Removal Costs
In accordance with ASC 410 and ASC 980, AES Indiana recognizes the amount collected in customer rates for costs of removal not yet incurred that do not have an associated legal retirement obligation as a deferred regulatory liability. This amount is net of the portion of legal ARO costs that are deferred that is also being recovered in rates.
Deferred Income Taxes Recoverable/Payable Through Rates
A deferred income tax asset or liability is created from a difference in timing of income recognition between tax laws and accounting methods. As a regulated utility, AES Indiana includes in ratemaking the impacts of current income taxes and changes in deferred income tax liabilities or assets.
On December 22, 2017, the U.S. federal government enacted the TCJA, which, among other things, reduced the federal corporate income tax rate from 35% to 21%, beginning January 1, 2018. As required by GAAP, on December 31, 2017, AES Indiana and IPALCO remeasured their deferred income tax assets and liabilities using the new tax rate. The impact of the reduction of the income tax rate on deferred income taxes was utilized in the 2018 Base Rate Order to reduce jurisdictional retail rates. Accordingly, we have a net regulatory deferred income tax liability of $74.8 million and $88.7 million as of December 31, 2023 and 2022, respectively.
3. PROPERTY, PLANT AND EQUIPMENT
The original cost of property, plant and equipment segregated by functional classifications follows:
As of December 31,
2023 2022
(In Thousands)
Production $ 3,942,052 $ 4,164,416
Transmission 487,527 461,245
Distribution 2,304,526 2,045,579
General plant 348,338 311,074
Total property, plant and equipment $ 7,082,443 $ 6,982,314
As of December 31, 2023 and 2022, AES Indiana had $259.9 million and $287.5 million, respectively, of net property, plant and equipment associated with the Petersburg Unit 1 and Unit 2 retirements recorded as long-term regulatory assets (for further discussion, see Note 2, “Regulatory Matters - IRP Filings and Replacement Generation”).
Substantially all of AES Indiana’s property is subject to a $2,153.8 million direct first mortgage lien, as of December 31, 2023, securing AES Indiana’s first mortgage bonds. Total non-contractually or legally required accrued removal costs of utility plant in service at December 31, 2023 and 2022 were $680.9 million and $694.0 million, respectively; and total contractually or legally required removal costs of property, plant and equipment at December 31, 2023 and 2022 were $249.9 million and $218.7 million, respectively. Please see “ARO” below for further information.
ARO
ASC 410 “Asset Retirement and Environmental Obligations” addresses financial accounting and reporting for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal operation. A legal obligation for purposes of ASC 410 is an obligation that a party is required to settle as a result of an existing law, statute, ordinance, written or oral contract or the doctrine of promissory estoppel.
AES Indiana’s ARO relates primarily to environmental issues involving asbestos-containing materials, ash ponds, landfills and miscellaneous contaminants associated with its generating plants, transmission system and distribution system. The following is a roll forward of the ARO legal liability year end balances:
2023 2022
(In Thousands)
Balance as of January 1 $ 218,729 $ 189,509
Liabilities incurred 17,080 1,159
Liabilities settled (11,902) (24,699)
Revisions to cash flow and timing estimates 12,921 44,679
Accretion expense 13,102 8,081
Balance as of December 31 $ 249,930 $ 218,729
ARO liabilities incurred in 2023 and 2022 primarily relate to FGD residual water disposal and AES Indiana's solar projects. AES Indiana recorded revisions to its ARO liabilities in 2023 and 2022 primarily to reflect revisions to cash flow estimates and timing due to increases to estimated ash pond closure costs and changes to expected landfill closure dates. As of December 31, 2023 and 2022, AES Indiana did not have any assets that are legally restricted for settling its ARO liability.
4. FAIR VALUE
The fair value of current financial assets and liabilities approximate their reported carrying amounts. The estimated fair values of the Company’s assets and liabilities have been determined using available market information. Because these amounts are estimates and based on hypothetical transactions to sell assets or transfer liabilities, the use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.
Fair Value Hierarchy and Valuation Techniques
ASC 820 defines and establishes a framework for measuring fair value and expands disclosures about fair value measurements for financial assets and liabilities that are adjusted to fair value on a recurring basis and/or financial assets and liabilities that are measured at fair value on a nonrecurring basis, which have been adjusted to fair value during the period. In accordance with ASC 820, we have categorized our financial assets and liabilities that are adjusted to fair value, based on the priority of the inputs to the valuation technique, following the three-level fair value hierarchy prescribed by ASC 820 as follows:
Level 1 - unadjusted quoted prices for identical assets or liabilities in an active market;
Level 2 - inputs from quoted prices in markets where trading occurs infrequently or quoted prices of instruments with similar attributes in active markets; and
Level 3 - unobservable inputs reflecting management’s own assumptions about the inputs used in pricing the asset or liability.
Whenever possible, quoted prices in active markets are used to determine the fair value of our financial instruments. Our financial instruments are not held for trading or other speculative purposes. The estimated fair value of financial instruments has been determined by using available market information and appropriate valuation methodologies. However, considerable judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we could realize in a current market exchange. The use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.
Financial Assets
VEBA Assets
IPALCO has VEBA investments that are to be used to fund certain employee postretirement health care benefit plans. These assets are primarily comprised of open-ended mutual funds, which are valued using the net assets value per unit. These investments are recorded at fair value within "Other non-current assets" on the accompanying Consolidated Balance Sheets and classified as equity securities. All changes to fair value on the VEBA investments are included in income in the period that the changes occur. These changes to fair value were not material for the years ended December 31, 2023, 2022, or 2021. Any unrealized gains or losses are recorded in "Other (expense) / income, net" on the accompanying Consolidated Statements of Operations and were not material to the consolidated financial statements in the periods covered by this report.
FTRs
In connection with AES Indiana’s participation in MISO, in the second quarter of each year AES Indiana is granted financial instruments that can be converted into cash or FTRs based on AES Indiana’s forecasted peak load for the period. FTRs are used in the MISO market to hedge AES Indiana’s exposure to congestion charges, which result from constraints on the transmission system. AES Indiana’s FTRs are valued at the cleared auction prices for FTRs in MISO’s annual auction. Because of the infrequent nature of this valuation, the fair value assigned to the FTRs is considered a Level 3 input under the fair value hierarchy required by ASC 820. An offsetting regulatory liability has been recorded as these revenue or costs will be flowed through to customers through the FAC. As such, there is no impact on our Consolidated Statements of Operations.
Forward Power Contracts
As of December 31, 2023 and 2022, all outstanding forward power contracts had settled and there was no notional amount outstanding. All changes in the market value of the forward power contracts were recorded in the Consolidated Statements of Operations in the period in which the change occurred. See also Note 5, "Derivative Instruments and Hedging Activities - Derivatives Not Designated as Hedge" for further information.
Interest Rate Hedges
IPALCO's interest rate hedges have a combined notional amount of $400.0 million. All changes in the market value of the interest rate hedges are recorded in AOCI. See also Note 5, "Derivative Instruments and Hedging Activities - Cash Flow Hedges" for further information.
Recurring Fair Value Measurements
The fair value of assets at December 31, 2023 and 2022 measured on a recurring basis and the respective category within the fair value hierarchy for IPALCO was determined as follows:
Fair Value as of December 31, 2023 Fair Value as of December 31, 2022
Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
(In Thousands)
Financial assets:
VEBA investments:
Money market funds $ 127 $ - $ - $ 127 $ 5 $ - $ - $ 5
Mutual funds 3,425 - - 3,425 3,223 - - 3,223
Total VEBA investments 3,552 - - 3,552 3,228 - - 3,228
FTRs - - 1,388 1,388 - - 7,545 7,545
Interest rate hedges - 14,294 - 14,294 - 12,172 - 12,172
Total financial assets measured at fair value $ 3,552 $ 14,294 $ 1,388 $ 19,234 $ 3,228 $ 12,172 $ 7,545 $ 22,945
The following table sets forth a roll forward of financial instruments, measured at fair value on a recurring basis, classified as Level 3 in the fair value hierarchy (note, amounts in this table indicate carrying values, which approximate fair values):
Reconciliation of Financial Instruments Classified as Level 3
(In Thousands)
Balance at January 1, 2022 $ 1,235
Issuances 15,338
Settlements (9,028)
Balance at December 31, 2022 7,545
Issuances 3,624
Settlements (9,781)
Balance at December 31, 2023 $ 1,388
Financial Instruments not Measured at Fair Value in the Consolidated Balance Sheets
Debt
The fair value of our outstanding fixed-rate debt has been determined on the basis of the quoted market prices of the specific securities issued and outstanding. In certain circumstances, the market for such securities was inactive and therefore the valuation was adjusted to consider changes in market spreads for similar securities. Accordingly, the purpose of this disclosure is not to approximate the value on the basis of how the debt might be refinanced.
The following table shows the face value and the fair value of fixed-rate and variable-rate indebtedness (Level 2) for the periods ending:
December 31, 2023 December 31, 2022
Face Value Fair Value Face Value Fair Value
(In Thousands)
Fixed-rate $ 3,033,800 $ 2,860,467 $ 3,033,800 $ 2,775,644
Variable-rate 455,000 455,000 - -
Total indebtedness $ 3,488,800 $ 3,315,467 $ 3,033,800 $ 2,775,644
The difference between the face value and the carrying value of this indebtedness represents the following:
•unamortized deferred financing costs of $24.8 million and $26.3 million at December 31, 2023 and 2022, respectively; and
•unamortized discounts of $6.8 million and $7.1 million at December 31, 2023 and 2022, respectively.
5. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
We use derivatives principally to manage the interest rate risk associated with refinancing our long-term debt and the risk of price changes for purchased power. The derivatives that we use to economically hedge these risks are governed by our risk management policies for forward and futures contracts. Our net positions are continually assessed within our structured hedging programs to determine whether new or offsetting transactions are required. We monitor and value derivative positions monthly as part of our risk management processes. We use published sources for pricing, when possible, to mark positions to market. All of our derivative instruments are used for risk management purposes and are designated as cash flow hedges if they qualify under ASC 815 for accounting purposes.
At December 31, 2023, AES Indiana's outstanding derivative instruments were as follows:
Commodity Accounting Treatment (a)
Unit Notional
(in thousands) Sales
(in thousands) Net Notional
(in thousands)
Interest rate hedges Designated USD $ 400,000 $ - $ 400,000
FTRs Not Designated MWh 3,919 - 3,919
(a) Refers to whether the derivative instruments have been designated as a cash flow hedge.
Cash Flow Hedges
As part of our risk management processes, we identify the relationships between hedging instruments and hedged items, as well as the risk management objective and strategy for undertaking various hedge transactions. The fair values of cash flow hedges determined by current public market prices will continue to fluctuate with changes in market prices up to contract expiration. The change in the fair value of a hedging instrument is recorded in other comprehensive income and amounts deferred are reclassified to earnings in the same income statement line as the hedged item in the period in which it settles.
In March 2019, we entered into three forward interest rate swaps to hedge the interest risk associated with refinancing the IPALCO 2020 maturities. The three interest rate swaps had a combined notional amount of $400.0 million. In April 2020, we de-designated the swaps as cash flow hedges and froze the AOCL of $72.3 million at the date of de-designation. The interest rate swaps were then amended and re-designated as cash flow hedges to hedge the interest rate risk associated with refinancing the 2024 IPALCO Notes. The amended interest rate swaps have a combined notional amount of $400.0 million and will be settled when the 2024 IPALCO Notes are refinanced. The $72.3 million of AOCL associated with the interest rate swaps through the date of the amendment is being amortized out of AOCL into interest expense over the remaining life of the 2030 IPALCO Notes, while any changes in fair value associated with the amended interest rate swaps will be recognized in AOCL going forward.
The following tables provide information on gains or losses recognized in AOCI / (AOCL) for the cash flow hedges for the periods indicated:
Interest Rate Hedges for the Years Ended December 31,
$ in thousands (net of tax) 2023 2022 2021
Beginning accumulated derivative gain / (loss) in AOCI / (AOCL)
$ 22,269 $ (29,407) $ (43,420)
Net gains associated with current period hedging transactions 1,594 46,245 10,393
Net losses reclassified to interest expense 5,431 5,431 3,620
Ending accumulated derivative gain / (loss) in AOCI / (AOCL)
$ 29,294 $ 22,269 $ (29,407)
Loss expected to be reclassified to earnings in the next twelve months
$ (5,375)
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months) 9
Derivatives Not Designated as Hedge
AES Indiana's FTRs and forward power contracts do not qualify for hedge accounting or the normal purchases and sales exceptions under ASC 815. Accordingly, FTRs are recorded at fair value using the income approach when
acquired and subsequently amortized over the annual period as they are used. The forward power contracts are recorded at fair value using the market approach with changes in the fair value charged or credited to the Consolidated Statements of Operations in the period in which the change occurred. This is commonly referred to as "MTM accounting." Realized gains and losses on the forward power contracts are included in future FAC filings, therefore any realized and unrealized gains and losses are deferred as regulatory liabilities or regulatory assets. There were net realized gains of $0.0 million and $1.3 million related to forward power contracts during the years ended December 31, 2023 and 2022, respectively, related to the forward power contracts that were deferred and included with deferred fuel costs in "Regulatory assets, current" on the accompanying Consolidated Balance Sheets.
Certain qualifying derivative instruments have been designated as normal purchases or normal sales contracts, as provided under GAAP. Derivative contracts that have been designated as normal purchases or normal sales under GAAP are not subject to hedge or MTM accounting and are recognized in the Consolidated Statements of Operations on an accrual basis.
When applicable, IPALCO has elected not to offset derivative assets and liabilities and not to offset net derivative positions against the right to reclaim cash collateral pledged (an asset) or the obligation to return cash collateral received (a liability) under derivative agreements. As of December 31, 2023 and 2022, IPALCO did not have any offsetting positions.
The following table summarizes the fair value, balance sheet classification and hedging designation of IPALCO's derivative instruments (in thousands):
December 31,
Commodity Hedging Designation Balance sheet classification 2023 2022
FTRs Not a Cash Flow Hedge Derivative assets, current
$ 1,388 $ 7,545
Interest rate hedges Cash Flow Hedge Derivative assets, current $ 14,294 $ -
Interest rate hedges Cash Flow Hedge Derivative assets, non-current $ - $ 12,172
6. DEBT
The following table presents our long-term debt:
December 31,
Series Due 2023 2022
(In Thousands)
AES Indiana first mortgage bonds:
3.125% (1)
December 2024 $ 40,000 $ 40,000
0.65% (1)
August 2025 40,000 40,000
0.75% (2)
April 2026 30,000 30,000
0.95% (2)
April 2026 60,000 60,000
1.40% (1)
August 2029 55,000 55,000
5.65% December 2032 350,000 350,000
6.60% January 2034 100,000 100,000
6.05% October 2036 158,800 158,800
6.60% June 2037 165,000 165,000
4.875% November 2041 140,000 140,000
4.65% June 2043 170,000 170,000
4.50% June 2044 130,000 130,000
4.70% September 2045 260,000 260,000
4.05% May 2046 350,000 350,000
4.875% November 2048 105,000 105,000
Unamortized discount - net (6,449) (6,651)
Deferred financing costs (19,058) (20,362)
Total AES Indiana first mortgage bonds 2,128,293 2,126,787
Total long-term debt - AES Indiana 2,128,293 2,126,787
Long-term debt - IPALCO:
3.70% Senior Secured Notes
September 2024 405,000 405,000
4.25% Senior Secured Notes
May 2030 475,000 475,000
Unamortized discount - net (319) (425)
Deferred financing costs (4,554) (5,912)
Total long-term debt - IPALCO 875,127 873,663
Total consolidated IPALCO long-term debt 3,003,420 3,000,450
Less: current portion of long-term debt 445,000 -
Net consolidated IPALCO long-term debt $ 2,558,420 $ 3,000,450
(1)First mortgage bonds issued to the Indiana Finance Authority, to secure the loan of proceeds from tax-exempt bonds issued by the Indiana Finance Authority.
(2)First mortgage bonds issued to the Indiana Finance Authority, to secure the loan of proceeds from tax-exempt bonds issued by the Indiana Finance Authority. The notes have a final maturity date of December 31, 2038, but are subject to a mandatory put in April 2026.
Line of Credit
AES Indiana entered into a second amendment and restatement of its $350 million revolving Credit Agreement on December 22, 2022 with a syndication of bank lenders. This Credit Agreement is an unsecured committed line of credit to be used: (i) to finance capital expenditures; (ii) to refinance certain existing indebtedness, (iii) to support working capital; and (iv) for general corporate purposes. This agreement matures on December 22, 2027, and bears interest at variable rates as described in the Credit Agreement. It includes an uncommitted $150 million accordion feature to provide AES Indiana with an option to request an increase in the size of the facility at any time prior to December 22, 2026, subject to approval by the lenders. The Credit Agreement also includes two one-year extension options, allowing AES Indiana to extend the maturity date subject to approval by the lenders. As of December 31,
2023 and 2022, AES Indiana had $155.0 million and $0.0 million in outstanding borrowings on the committed Credit Agreement, respectively.
Debt Maturities
Maturities on long-term indebtedness subsequent to December 31, 2023 are as follows:
Year Amount
(In Thousands)
2024 $ 445,000
2025 40,000
2026 90,000
2027 -
2028 -
Thereafter 2,458,800
3,033,800
Unamortized discounts (6,768)
Deferred financing costs, net (23,612)
Total long-term debt $ 3,003,420
Significant Transactions
AES Indiana Term Loans
In November 2023, AES Indiana entered into an unsecured $300 million 364-day term loan agreement ("$300 million Term Loan Agreement"). The $300 million Term Loan Agreement was fully drawn at closing with the proceeds being used for general corporate purposes. This agreement matures on November 19, 2024, and bears interest at variable rates as described in the $300 million Term Loan Agreement. The $300 million Term Loan Agreement contains customary representations, warranties and covenants, including a leverage covenant consistent with the leverage covenant contained in AES Indiana's Credit Agreement. AES Indiana has classified this $300 million Term Loan Agreement as short-term indebtedness as it matures November 2024. Although current liquid funds are not sufficient to repay the amount due at maturity, management plans to refinance this $300 million Term Loan Agreement with new long-term debt.
In June 2022, AES Indiana entered into an unsecured $200 million 364-day term loan agreement ("$200 million Term Loan Agreement"). The $200 million Term Loan Agreement was fully drawn at closing with the proceeds being used for general corporate purposes. This agreement was set to mature on June 22, 2023, but was fully repaid in November 2022.
AES Indiana First Mortgage Bonds and Recent Indiana Finance Authority Bond Issuances
In November 2022, AES Indiana issued $350 million aggregate principal amount of first mortgage bonds, 5.65% Series, due December 2032, pursuant to Rule 144A and Regulation S under the Securities Act. Net proceeds from this offering were approximately $345.6 million, after deducting the initial purchasers’ discounts and fees and expenses for the offering. The net proceeds from this offering were used to repay amounts due under the Credit Agreement and the $200 million Term Loan Agreement, and for general corporate purposes.
In July 2021, the Indiana Finance Authority issued at the request of AES Indiana an aggregate principal amount of $95 million of Environmental Facilities Refunding Revenue Bonds, Series 2021A&B. AES Indiana issued $95 million aggregate principal amount of first mortgage bonds to the Indiana Finance Authority in two series: $55 million Series 2021A bonds at an interest rate of 1.40% due August 1, 2029 and $40 million Series 2021B notes at an interest rate of 0.65% due August 1, 2025 to secure the loan of proceeds from these bonds issued by the Indiana Finance Authority. Proceeds of the bond offering were used to refund $95 million of Indiana Finance Authority Environmental Facilities Refunding Revenue Bonds Series 2011A&B at a redemption price of 100% of par.
IPALCO’s Senior Secured Notes and Term Loan
The 2024 IPALCO Notes are due September 1, 2024. Although current liquid funds are not sufficient to repay the collective amounts due under the 2024 IPALCO Notes at maturity, the Company believes it will be able to refinance the 2024 IPALCO Notes based on conversations with investment bankers, which currently indicate more than adequate demand for new IPALCO debt at its current credit ratings, and considering the Company's previous successful debt issuances.
Pursuant to a registration rights agreement dated April 14, 2020, IPALCO agreed to register the 2030 IPALCO Notes under the Securities Act by filing an exchange offer registration statement or, under specified circumstances, a shelf registration statement with the SEC. IPALCO filed a registration statement on Form S-4 with respect to the 2030 IPALCO Notes with the SEC on March 22, 2021 in respect of its obligations under such registration rights agreement, and this registration statement was declared effective on April 7, 2021. The exchange offer closed on May 11, 2021.
Restrictions on Issuance of Debt
All of AES Indiana’s long-term borrowings must first be approved by the IURC and the aggregate amount of AES Indiana’s short-term indebtedness must be approved by the FERC. AES Indiana has approval from FERC to borrow up to $750 million of short-term indebtedness outstanding at any time through July 26, 2024. In November 2021, AES Indiana received an order from the IURC granting AES Indiana authority through December 31, 2024 to, among other things, issue up to $740 million in aggregate principal amount of long-term debt, of which $390 million remains available as of December 31, 2023. This order also grants AES Indiana authority to have up to $750 million of long-term credit agreements and liquidity facilities outstanding at any one time, of which $100.0 million remains available under the order as of December 31, 2023. As an alternative to the sale of all or a portion of $65 million in principal of the long-term debt mentioned above, we have authority to issue up to $65 million of new preferred stock, all of which authority remains available under the order as of December 31, 2023. AES Indiana also has restrictions on the amount of new debt that may be issued due to contractual obligations of AES and by financial covenant restrictions under our existing debt obligations. Under such restrictions, AES Indiana is generally allowed to fully draw the amounts available on its Credit Agreement, refinance existing debt and issue new debt approved by the IURC and issue certain other indebtedness. On September 29, 2023, AES Indiana filed a petition for approval of a financing program for the approximately three-year period ending December 31, 2026. The OUCC filed testimony on December 1, 2023 with certain recommended parameters for future debt issuances that AES Indiana accepted. A hearing was held January 10, 2024 and an agreed proposed order between AES Indiana and the OUCC was submitted on that date. AES Indiana awaits an IURC order in the matter and it remains pending.
The mortgage and deed of trust of AES Indiana, together with the supplemental indentures thereto, secure the first mortgage bonds issued by AES Indiana. Pursuant to the terms of the mortgage, substantially all property owned by AES Indiana is subject to a first mortgage lien securing indebtedness of $2,153.8 million as of December 31, 2023. The AES Indiana first mortgage bonds require net income as calculated thereunder be at least two and one-half times the annual interest requirements before additional bonds can be authenticated on the basis of property additions. AES Indiana was in compliance with such requirements as of December 31, 2023.
Credit Ratings
Our ability to borrow money or to refinance existing indebtedness and the interest rates at which we can borrow money or refinance existing indebtedness are affected by our credit ratings. In addition, the applicable interest rates on AES Indiana’s Credit Agreement are dependent upon the credit ratings of AES Indiana. Downgrades in the credit ratings of AES could result in AES Indiana’s and/or IPALCO’s credit ratings being downgraded.
7. INCOME TAXES
IPALCO follows a policy of comprehensive interperiod income tax allocation. Investment tax credits related to utility property have been deferred and are being amortized over the estimated useful lives of the related property.
AES files federal and state income tax returns which consolidate IPALCO and its subsidiaries. Under a tax sharing agreement with AES, IPALCO is responsible for the income taxes associated with its own taxable income and records the provision for income taxes as if IPALCO and its subsidiaries each filed separate income tax returns. IPALCO is no longer subject to U.S. or state income tax examinations for tax years through 2016, but is open for all subsequent periods. IPALCO made tax sharing payments to AES of $0.0 million, $31.0 million and $27.5 million in 2023, 2022 and 2021, respectively.
Income Tax Provision
Federal and state income taxes charged to income are as follows:
2023 2022 2021
(In Thousands)
Components of income tax expense:
Current income taxes:
Federal $ (14,222) $ 22,539 $ 28,100
State (3,716) 6,026 8,218
Total current income taxes (17,938) 28,565 36,318
Deferred income taxes:
Federal 24,885 (6,920) (7,286)
State 7,768 214 (91)
Total deferred income taxes 32,653 (6,706) (7,377)
Total income tax expense $ 14,715 $ 21,859 $ 28,941
Effective and Statutory Rate Reconciliation
The provision for income taxes (including net investment tax credit adjustments) is different than the amount computed by applying the statutory tax rate to pretax income. The reasons for the difference, stated as a percentage of pretax income, are as follows:
2023 2022 2021
Federal statutory tax rate 21.0 % 21.0 % 21.0 %
State income tax, net of federal tax benefit 3.9 % 3.9 % 4.0 %
Depreciation flow through and amortization (12.9) % (7.8) % (6.3) %
AFUDC - equity (0.3) % 0.9 % 0.4 %
Noncontrolling interests in subsidiaries 9.0 % - % - %
Other - net (0.2) % 0.4 % 0.4 %
Effective tax rate 20.5 % 18.4 % 19.5 %
Deferred Income Taxes
The significant items comprising IPALCO’s net accumulated deferred tax liability recognized on the audited Consolidated Balance Sheets as of December 31, 2023 and 2022 are as follows:
2023 2022
(In Thousands)
Deferred tax liabilities:
Relating to utility property, net $ 409,675 $ 341,473
Regulatory assets recoverable through future rates 108,823 123,669
Other 17,694 17,953
Total deferred tax liabilities 536,192 483,095
Deferred tax assets:
Investment tax credit 5 6
Regulatory liabilities including ARO 168,619 167,725
Investments in tax partnerships 2,501 -
Other 3,579 2,723
Total deferred tax assets 174,704 170,454
Deferred income tax liability - net $ 361,488 $ 312,641
Uncertain Tax Positions
The following is a reconciliation of the beginning and ending amounts of unrecognized tax benefits for the years ended December 31, 2023, 2022 and 2021:
2023 2022 2021
(In Thousands)
Unrecognized tax benefits at January 1 $ - $ - $ 7,368
Gross decreases - prior period tax positions - - (7,368)
Unrecognized tax benefits at December 31 $ - $ - $ -
The prior period unrecognized tax benefits represent tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. As a result of the resolution of federal and state audits in 2021, IPALCO reviewed its uncertain positions and determined that they are more likely than not to be sustained upon examination by taxing authorities. Consequently, the uncertain tax positions were reversed; because of the impact of deferred tax accounting the reversal did not affect the annual effective tax rate but were reclassified to plant related deferred tax balances.
Tax years subsequent to 2016 remain open to examination by taxing authorities. While it is often difficult to predict the final outcome or the timing of resolution of any particular uncertain tax position, we believe unrecognized tax benefits of $0 at December 31, 2023 and 2022, respectively, is the appropriate accrual for our uncertain tax positions. However, audit outcomes and the timing of audit settlements and future events that would impact our previously recorded unrecognized tax benefits are subject to significant uncertainty. It is possible that the ultimate outcome of future examinations may exceed our provision for current unrecognized tax benefits.
Tax-related interest expense and income is reported as part of the provision for federal and state income taxes. Penalties, if incurred, would also be recognized as a component of tax expense. There are no interest or penalties applicable to the periods contained in this report.
8. BENEFIT PLANS
Defined Contribution Plans
All of AES Indiana’s employees are covered by one of two defined contribution plans, the Thrift Plan or the RSP:
The Thrift Plan
Approximately 77% of AES Indiana’s active employees are covered by the Thrift Plan, a qualified defined contribution plan. All union new hires are covered under the Thrift Plan. Participants elect to make contributions to the Thrift Plan based on a percentage of their base compensation. Each participant’s contribution is matched up to certain thresholds of base compensation. The IBEW clerical-technical union new hires receive an annual lump sum company contribution into the Thrift Plan in addition to the company match. Employer contributions to the Thrift Plan were $3.7 million, $3.6 million and $3.4 million for 2023, 2022 and 2021, respectively.
The RSP
Approximately 23% of AES Indiana’s active employees are covered by the RSP, a qualified defined contribution plan containing both match and nondiscretionary components. All non-union new hires are covered under the RSP. Participants elect to make contributions to the RSP based on a percentage of their eligible compensation. Each participant’s contribution is matched in amounts up to, but not exceeding, 5% of the participant’s eligible compensation. Starting in 2018, the RSP also includes a 4% nondiscretionary contribution based as a percentage of each participant's eligible compensation. Employer contributions (by AES Indiana) relating to the RSP were $2.5 million, $2.1 million and $1.9 million for 2023, 2022 and 2021, respectively.
Defined Benefit Plans
Approximately 65% of AES Indiana’s active employees are covered by the qualified Defined Benefit Pension Plan; while approximately 12% of active employees are IBEW clerical-technical unit employees who are only eligible for the Thrift Plan. The remaining 23% of active employees are covered by the RSP. All non-union new hires are covered under the RSP, while IBEW physical unit union new hires are covered under the Defined Benefit Pension Plan and Thrift Plan. The IBEW clerical-technical unit new hires are no longer covered under the Defined Benefit Pension Plan but do receive an annual lump sum company contribution into the Thrift Plan, in addition to the company match. The Defined Benefit Pension Plan is noncontributory and is funded by AES Indiana through a trust. Benefits for non-union participants in the Defined Benefit Pension Plan are based on salary, years of service and accrued benefits at April 1, 2015. Benefits for eligible union participants are based on each individual employee's pension band and years of service as opposed to their compensation. Pension bands are based primarily on job duties and responsibilities.
Additionally, a small group of former officers and their surviving spouses are covered under a funded non-qualified Supplemental Retirement Plan. The total number of participants in the plan as of December 31, 2023 was 19. The plan is closed to new participants.
AES Indiana also provides postretirement health care benefits to certain active or retired employees and the spouses of certain active or retired employees. Approximately 123 active employees and 26 retirees (including spouses) were receiving such benefits or entitled to future benefits as of January 1, 2023. The plan is unfunded. These postretirement health care benefits and the related unfunded obligation of $3.0 million and $3.2 million at December 31, 2023 and 2022, respectively, were not material to the consolidated financial statements in the periods covered by this report.
The following table presents information relating to the Pension Plans:
Pension benefits
as of December 31,
2023 2022
(In Thousands)
Change in benefit obligation:
Projected benefit obligation at January 1 $ 577,530 $ 772,040
Service cost 5,189 8,949
Interest cost 29,818 18,099
Actuarial loss (gain) 9,681 (182,590)
Amendments (primarily increases in pension bands) 653 -
Settlements - (394)
Benefits paid (73,325) (38,575)
Projected benefit obligation at December 31 549,546 577,529
Change in plan assets:
Fair value of plan assets at January 1 611,125 820,684
Actual return/(loss) on plan assets 52,905 (171,002)
Employer contributions 114 412
Settlements - (394)
Benefits paid (73,325) (38,575)
Fair value of plan assets at December 31 590,819 611,125
Funded status $ 41,273 $ 33,596
Amounts recognized in the statement of financial position:
Non-current assets $ 41,273 $ 33,611
Non-current liabilities - (15)
Net amount recognized at end of year $ 41,273 $ 33,596
Sources of change in regulatory assets(1):
Prior service cost arising during period $ 653 $ -
Net (gain)/loss arising during period (10,117) 24,069
Amortization of prior service cost (2,172) (2,589)
Amortization of loss (6,145) (2,622)
Total recognized in regulatory assets $ (17,781) $ 18,858
Amounts included in regulatory assets:
Net loss $ 115,297 $ 131,559
Prior service cost 10,136 11,655
Total amounts included in regulatory assets $ 125,433 $ 143,214
(1)Amounts that would otherwise be charged/credited to Accumulated Other Comprehensive Income or Loss upon application of ASC 715, “Compensation - Retirement Benefits,” are recorded as a regulatory asset or liability because AES Indiana has historically recovered and currently recovers pension and other postretirement benefit expenses in rates. These are unrecognized amounts not yet recognized as components of net periodic benefit costs.
Significant Loss / (Gain) Related to Changes in the Benefit Obligation for the Period
As shown in the table above, an actuarial loss of $9.7 million and an actuarial gain of $182.6 million for the year ended December 31, 2023 and December 31, 2022, respectively, were recognized in the benefit obligation, primarily due to changes in the discount rate.
Pension Benefits and Expense
Reported expenses relevant to the Defined Benefit Pension Plan are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience, including the performance of plan assets and actual benefits paid out in future years. Pension costs associated with the Defined Benefit Pension Plan are
impacted by the level of contributions made to the plan, income on plan assets, the adoption of new mortality tables, and employee demographics, including age, job responsibilities, salary and employment periods. Changes made to the provisions of the Defined Benefit Pension Plan may impact current and future pension costs. Pension costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the corporate bond discount rates, as well as, the adoption of a new mortality table used in determining the projected benefit obligation and pension costs.
The 2023 net actuarial gain of $10.1 million recognized in regulatory assets is comprised of two parts: (1) a $9.7 million pension liability actuarial loss primarily due to a decrease in the discount rate used to value pension liabilities; and (2) a $19.8 million pension asset actuarial gain primarily due to higher than expected return on assets. The unrecognized net loss of $115.3 million in the Pension Plans has accumulated over time primarily due to the long-term declining trend in corporate bond rates and the adoption of new mortality tables which have historically increased the expected benefit obligation due to the longer expected lives of plan participants. In 2023, the accumulated net loss decrease was primarily attributed to an annuity buyout involving a small portion of retirees, which was partially offset by factors such as a reduced discount rate utilized in valuing pension liabilities, along with the amortization of accumulated losses incurred during the year. The unrecognized net loss, to the extent that it exceeds 10% of the greater of the benefit obligation or the assets, will be amortized and included as a component of net periodic benefit cost in future years. The amortization period is approximately 11.66 years based on estimated demographic data as of December 31, 2023. The projected benefit obligation of $549.5 million less the fair value of assets of $590.8 million results in an overfunded status of $41.3 million at December 31, 2023.
Pension benefits for
years ended December 31,
2023 2022 2021
(In Thousands)
Components of net periodic benefit cost / (credit):
Service cost $ 5,189 $ 8,949 $ 9,339
Interest cost 29,818 18,099 15,660
Expected return on plan assets (33,107) (35,656) (41,815)
Amortization of prior service cost 2,172 2,589 2,944
Amortization of actuarial loss 6,145 2,424 5,529
Amortization of settlement loss - 199 -
Net periodic benefit cost / (credit) 10,217 (3,396) (8,343)
Less: amounts capitalized 1,689 (316) (771)
Amount charged to expense $ 8,528 $ (3,080) $ (7,572)
Rates relevant to each year’s expense calculations:
Discount rate - defined benefit pension plan 5.41 % 2.83 % 2.46 %
Discount rate - supplemental retirement plan 5.32 % 2.62 % 2.31 %
Expected return on defined benefit pension plan assets 5.60 % 4.45 % 5.05 %
Expected return on supplemental retirement plan assets 6.45 % 5.50 % 3.60 %
Pension expense / (income) for the following year is determined as of the December 31 measurement date based on the fair value of the Pension Plans’ assets, the expected long-term rate of return on plan assets, a mortality table assumption that reflects the life expectancy of plan participants, and a discount rate used to determine the projected benefit obligation. For 2023, pension expense / (income) was determined using an assumed long-term rate of return on plan assets of 5.60% for the Defined Benefit Pension Plan and 6.45% for the Supplemental Retirement Plan. As of the December 31, 2023 measurement date, AES Indiana decreased the discount rate from 5.41% to 5.15% for the Defined Benefit Pension Plan and increased the discount rate from 5.32% to 5.66% for the Supplemental Retirement Plan. The discount rate assumptions affect the pension expense / (income) determined for 2024. In addition, AES Indiana decreased the expected long-term rate of return on plan assets from 5.60% to 5.20% for the Defined Benefit Pension Plan and from 6.45% to 6.35% for the Supplemental Retirement Plan for 2024. The expected long-term rate of return assumptions affect the pension expense / (income) determined for 2024. The effect on 2024 total pension expense / (income) of a 25 basis point increase and decrease in the assumed discount rate is $(0.8) million and $0.8 million, respectively.
In determining the discount rate to use for valuing liabilities, we use the market yield curve on high-quality fixed income investments as of December 31, 2023. We project the expected benefit payments under the plan based on participant data and based on certain assumptions concerning mortality, retirement rates, termination rates, etc. The expected benefit payments for each year are discounted back to the measurement date using the appropriate spot rate for each half-year from the yield curve, thereby obtaining a present value of all expected future benefit payments using the yield curve. Finally, an equivalent single discount rate is determined which produces a present value equal to the present value determined using the full yield curve.
Pension Plan Assets and Fair Value Measurements
Pension plan assets consist of investments in cash and cash equivalents, government debt securities, and mutual funds (equity and debt). Differences between actual portfolio returns and expected returns may result in increased or reduced pension costs in future periods. Pension costs for 2024 are determined as of the plans' measurement date of December 31, 2023. Pension costs are determined for the following year based on the market value of pension plan assets, expected employer contributions, a discount rate used to determine the projected benefit obligation and the expected long-term rate of return on plan assets.
Fair value is defined under ASC 820 as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (i.e., an exit price). The fair value hierarchy prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets and liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).
Purchases and sales of securities are recorded on a trade-date basis. Interest income is recorded as earned. Dividends are recorded on the ex-dividend date. Net appreciation includes the Pension Plans’ gains and losses on investments bought and sold, as well as held, during the year.
A description of the valuation methodologies used for each major class of assets and liabilities measured at fair value follows:
•The non-qualified Supplemental Retirement Plan investments have quoted market prices and are categorized as Level 1 in the fair value hierarchy.
•The qualified Defined Benefit Pension Plan investments in common collective trusts are valued based on the daily net asset value and are categorized as Level 2 in the fair value hierarchy, except for cash and cash equivalents which are categorized as level 1.
The primary objective of the Pension Plans’ is to provide a source of retirement income for its participants and beneficiaries, while the primary financial objective is to improve the funded status of the Pension Plans. A secondary financial objective is, where possible, to minimize pension expense volatility. The objective is based on a long-term investment horizon, so that interim fluctuations should be viewed with appropriate perspective. There can be no assurance that these objectives will be met.
In establishing our expected long-term rate of return assumption, we utilize a methodology developed by the plan’s investment consultant who maintains a capital market assumption model that takes into consideration risk, return and correlation assumptions across asset classes. A combination of quantitative analysis of historical data and qualitative judgment is used to capture trends, structural changes and potential scenarios not reflected in historical data.
The result of the analyses is a series of inputs that produce a picture of how the plan consultant believes portfolios are likely to behave through time. Capital market assumptions are intended to reflect the behavior of asset classes observed over several market cycles. Stress assumptions are also examined, since the characteristics of asset classes are constantly changing. A dynamic model is employed to manage the numerous assumptions required to estimate portfolio characteristics under different base currencies, time horizons and inflation expectations.
The Pension Plans’ consultant develops forward-looking, long-term capital market assumptions for risk, return and correlations for a variety of global asset classes, interest rates and inflation. These assumptions are created using a combination of historical analysis, current market environment assessment and by applying the consultant’s own
judgment. The consultant then determines an equilibrium long-term rate of return. We then take into consideration the investment manager/consultant expenses, as well as any other expenses expected to be paid out of the Pension Plans’ trust. Finally, we have the Pension Plans’ actuary perform a tolerance test of the consultant’s equilibrium expected long-term rate of return. We use an expected long-term rate of return compatible with the actuary’s tolerance level.
The following table summarizes the Company’s target pension plan allocation for 2023:
Asset Category: Target Allocations
Equity Securities 13.5%
Debt Securities 86.5%
Fair Value Measurements at
December 31, 2023
(in thousands)
Quoted Prices in Active Markets for Identical Assets Significant Observable Inputs
Asset Category Total (Level 1) (Level 2) %
Common collective trusts:
Equities (a)
$ 82,652 $ 2,267 $ 80,385 14 %
Debt securities (b)
387,979 1,168 386,811 66 %
Government debt securities (c)
117,397 178 117,219 20 %
Total common collective trusts 588,028 3,613 584,415 100 %
Cash and cash equivalents (d)
2,791 2,791 - - %
Total pension plan assets $ 590,819 $ 6,404 $ 584,415 100 %
(a) This category represents investments that invest in equity securities of U.S. companies of any market capitalization and other investments (i.e.: futures, swaps, currency forwards) of foreign, emerging markets and seeks to provide long-term total return, which includes capital appreciation and income. The funds are valued using the net asset value method.
(b) This category represents investments that invest in high quality issues within the U.S. corporate bond markets and global high yield bonds and emerging markets debt denominated in local currency. The funds seek to provide current income and long-term capital preservation along with access to higher yielding, relatively liquid fixed income securities. The funds are valued using the net asset value method.
(c) This category represents investments that invest in U.S. treasury strips, U.S. government agency obligations, and U.S. treasury obligations. The funds seek investment returns over the long term and are valued using the net asset value method.
(d) This category represents an investment that seeks to maximize current income on cash reserves to the extent consistent with principal preservation and maintenance of liquidity from a portfolio of obligations of the U.S. Government, its agencies or municipalities, and related money market instruments. Principal preservation is a primary objective. The fund is valued at cost.
Fair Value Measurements at
December 31, 2022
(in thousands)
Quoted Prices in Active Markets for Identical Assets Significant Observable Inputs
Asset Category Total (Level 1) (Level 2) %
Common collective trusts:
Equities (a)
$ 85,341 $ 2,017 $ 83,324 14 %
Debt securities (b)
400,291 1,254 399,037 66 %
Government debt securities (c)
122,704 420 122,284 20 %
Total common collective trusts 608,336 3,691 604,645 100 %
Cash and cash equivalents (d)
2,789 2,789 - - %
Total pension plan assets $ 611,125 $ 6,480 $ 604,645 100 %
(a) This category represents investments that invest in equity securities of U.S. companies of any market capitalization and other investments (i.e.: futures, swaps, currency forwards) of foreign, emerging markets and seeks to provide long-term total return, which includes capital appreciation and income. The funds are valued using the net asset value method.
(b) This category represents investments that invest in high quality issues within the U.S. corporate bond markets and global high yield bonds and emerging markets debt denominated in local currency. The funds seek to provide current income and long-term capital preservation along with access to higher yielding, relatively liquid fixed income securities. The funds are valued using the net asset value method.
(c) This category represents investments that invest in U.S. treasury strips, U.S. government agency obligations, and U.S. treasury obligations. The funds seek investment returns over the long term and are valued using the net asset value method.
(d) This category represents an investment that seeks to maximize current income on cash reserves to the extent consistent with principal preservation and maintenance of liquidity from a portfolio of obligations of the U.S. Government, its agencies or municipalities, and related money market instruments. Principal preservation is a primary objective. The fund is valued at cost.
Pension Funding
We contributed $0.1 million, $0.4 million, and $0.0 million to the Pension Plans in 2023, 2022 and 2021, respectively. Funding for the qualified Defined Benefit Pension Plan is based upon actuarially determined contributions that take into account the amount deductible for income tax purposes and the minimum contribution required under ERISA, as amended by the Pension Protection Act of 2006, as well as targeted funding levels necessary to meet certain thresholds.
From an ERISA funding perspective, AES Indiana’s funded target liability percentage was estimated to be 98%. In general, AES Indiana must contribute the normal service cost earned by active participants during the plan year; however, this amount can be offset by any surplus or credit balance carried by the Pension Plan. The normal cost is expected to be approximately $6.3 million in 2024 (including $0.4 million for plan expenses), which is expected to be fully offset by the surplus amount. Each year thereafter, if the Pension Plans’ underfunding increases to more than the present value of the remaining annual installments, the excess is separately amortized over a seven-year period. AES Indiana does not expect to make an employer contribution for the calendar year 2024. AES Indiana’s funding policy for the Pension Plans is to contribute annually no less than the minimum required by applicable law, and no more than the maximum amount that can be deducted for federal income tax purposes.
Benefit payments made from the Pension Plans for the years ended December 31, 2023, 2022 and 2021 were $73.3 million, $38.6 million and $63.2 million, respectively. Benefit payments, which reflect future service, are expected to be paid out of the Pension Plans as follows:
Year Pension Benefits
(In Thousands)
2024 $ 37,997
2025 38,794
2026 39,665
2027 40,085
2028 41,477
2029 through 2033 200,574
9. EQUITY AND CUMULATIVE PREFERRED STOCK
Cumulative Preferred Stock
On December 30, 2022 (the “Redemption Date”), AES Indiana redeemed all of its issued and outstanding preferred stock for $60.1 million On the Redemption Date, the Preferred Stock of each series was redeemed with all applicable premiums, plus, in each case an amount equal to all accrued dividends payable with respect to such Preferred Stock to the Redemption Date. Dividends on the Preferred Stock ceased to accrue on the Redemption Date. Upon redemption, the Preferred Stock was no longer outstanding, and all rights of the holders thereof as shareholders of AES Indiana ceased to exist, except for the right to payment of the redemption price. AES Indiana recorded a charge of $0.3 million on the redemption for the difference between the carrying value and redemption value of the preferred shares.
Prior to the redemption, AES Indiana had five separate series of cumulative preferred stock. Holders of the preferred stock were entitled to receive dividends at rates per annum ranging from 4.0% to 5.65%. During the years ended December 31, 2023, 2022 and 2021, total preferred stock dividends declared were $0.0 million, $3.2 million, and $3.2 million, respectively. Holders of preferred stock were entitled to two votes per share for AES Indiana matters, and if four full quarterly dividends are in default on all shares of the preferred stock then outstanding, they were entitled to elect the smallest number of AES Indiana directors to constitute a majority of AES Indiana’s Board of Directors. Based on the preferred stockholders’ ability to elect a majority of AES Indiana’s Board of Directors in this circumstance, the redemption of the preferred shares was considered to be not solely within the control of the issuer and the preferred stock was considered temporary equity and presented in the mezzanine level of the audited consolidated balance sheets in accordance with the relevant accounting guidance for non-controlling interests and redeemable securities.
Paid In Capital
On December 12, 2022, AES U.S. Investments received equity capital contributions totaling $208.3 million, of which $177.0 million was contributed by AES U.S. Holdings, LLC and $31.3 million was contributed by CDPQ. IPALCO then received equity capital contributions totaling $253.0 million, of which $208.3 million was contributed by AES U.S. Investments and $44.7 million was contributed by CDPQ.
On December 13, 2021, AES U.S. Investments received equity capital contributions totaling $226.5 million, of which $192.5 million was contributed by AES U.S. Holdings, LLC and $34.0 million was contributed by CDPQ. IPALCO then received equity capital contributions totaling $275.0 million, of which $226.5 million was contributed by AES U.S. Investments and $48.5 million was contributed by CDPQ.
IPALCO then made the same investments in AES Indiana in 2021 and 2022. The proceeds are intended primarily for funding needs related to AES Indiana’s TDSIC and replacement generation projects. The capital contributions were made on a proportional share basis and, therefore, did not change CDPQ’s or AES’ ownership interests in IPALCO or AES U.S. Investments.
Dividend Restrictions
AES Indiana’s mortgage and deed of trust and its amended articles of incorporation contain restrictions on AES Indiana’s ability to issue certain securities or pay cash dividends. So long as any of the several series of bonds of AES Indiana issued under its mortgage remains outstanding, and subject to certain exceptions, AES Indiana is restricted in the declaration and payment of dividends, or other distribution on shares of its capital stock of any class, or in the purchase or redemption of such shares, to the aggregate of its net income, as defined in the mortgage, after December 31, 1939. In addition, pursuant to AES Indiana’s articles, no dividends may be paid or accrued, and no other distribution may be made on AES Indiana’s common stock unless dividends on all outstanding shares of AES Indiana preferred stock have been paid or declared and set apart for payment. As of December 31, 2023, and as of the filing of this report, AES Indiana was in compliance with these restrictions. Additionally, all of AES Indiana's preferred stock was redeemed on December 30, 2022 (see "Cumulative Preferred Stock" above for further details).
AES Indiana is also restricted in its ability to pay dividends if it is in default under the terms of its Credit Agreement and $300 million Term Loan Agreement, which could happen if AES Indiana fails to comply with certain covenants. These covenants, among other things, require AES Indiana to maintain a ratio of total debt to total capitalization not in excess of 0.67 to 1. As of December 31, 2023, and as of the filing of this report, AES Indiana was in compliance with all covenants and no event of default existed.
IPALCO’s Third Amended and Restated Articles of Incorporation contain provisions which state that IPALCO may not make a distribution to its shareholders or make a loan to any of its affiliates (other than its subsidiaries), unless: (a) there exists no event of default (as defined in the articles) and no such event of default would result from the making of the distribution or loan; and either (b)(i) at the time of, and/or as a result of, the distribution or loan, IPALCO’s leverage ratio does not exceed 0.67 to 1 and IPALCO’s interest coverage ratio is not less than 2.50 to 1 or, (b)(ii) if such ratios are not within the parameters, IPALCO’s senior long-term debt rating from one of the three major credit rating agencies is at least investment grade. As of December 31, 2023, and as of the filing of this report, IPALCO was in compliance with all covenants and no event of default existed.
During the years ended December 31, 2023, 2022 and 2021, IPALCO declared and paid distributions to its shareholders totaling $104.3 million, $102.0 million and $131.5 million, respectively.
Equity Transactions with Noncontrolling Interests
The Hardy Hills Solar Project has been financed with a tax equity structure, in which a tax equity investor receives a portion of the economic attributes of the facility, including tax attributes, that vary over the life of the project. On December 1, 2023, the Class B Member and the Class A Member, entered into an Equity Capital Contribution Agreement, pursuant to which each member made certain capital contributions to Hardy Hills JV. The Class A member made total contributions of $79.3 million through December 31, 2023. A noncontrolling interest was recorded by AES Indiana at the amount of cash contributed by the Class A Member.
10. COMMITMENTS AND CONTINGENCIES
Contractual Obligations and Commercial Commitments
We enter into various contractual obligations and other commercial commitments that may affect the liquidity of our operations. At December 31, 2023, these include:
Payments due in:
Total Less Than 1 Year 1 - 3
Years 3 - 5
Years More Than
5 Years
(In Millions)
Purchase obligations:
Coal, gas, purchased power and
related transportation $ 933.5 $ 249.7 $ 267.3 $ 225.7 $ 190.8
Other $ 409.1 $ 355.0 $ 32.8 $ 20.2 $ 1.1
Purchase obligations:
Purchase commitments for coal, gas, purchased power and related transportation:
AES Indiana enters into long-term contracts for the purchase of coal, gas, purchased power and related transportation. In general, these contracts are subject to variable quantities or prices and are terminable only in limited circumstances.
Purchase orders and other contractual obligations:
At December 31, 2023, we had various other contractual obligations including contracts to purchase goods and services with various terms and expiration dates, as well as obligations under long-term construction contracts. Due to uncertainty regarding the timing and payment of future obligations to the Service Company, and our ability to terminate such obligations upon 90 days' notice, we have excluded such amounts in the contractual obligations table above. This table also does not include (i) regulatory liabilities (see Note 2, "Regulatory Matters"), (ii) derivatives (see Note 5, "Derivative Instruments and Hedging Activities"), (iii) taxes (see Note 7, "Income Taxes"), (iv) pension and other postretirement employee benefit liabilities (see Note 8, "Benefit Plans") and (v) contingencies (see Note 10, "Commitments and Contingencies"). See the indicated notes to the Financial Statements for additional information on the items excluded.
Contingencies
Legal Matters
IPALCO and AES Indiana are involved in litigation arising in the normal course of business. We accrue for litigation and claims when it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. While the ultimate outcome of outstanding litigation cannot be predicted with certainty, management believes that final outcomes will not have a material adverse effect on IPALCO’s results of operations, financial condition and cash flows. Accruals for legal loss contingencies were not material as of December 31, 2023 and 2022.
Coal Ash Insurance Litigation
In August 2021, AES Indiana filed a civil action against various third-party insurance providers. The complaint seeks damages for breach of contract and a declaratory judgment declaring that such insurers must defend and indemnify AES Indiana under liability insurance policies issued between 1950 and the filing of the civil action against certain environmental liabilities arising from CCR at Harding Street, Petersburg and Eagle Valley. At this time, we cannot predict the outcome of this matter.
Environmental Matters
We are subject to various federal, state, regional and local environmental protection and health and safety laws and regulations governing, among other things, the generation, storage, handling, use, disposal and transportation of regulated materials, including ash; the use and discharge of water used in generation boilers and for cooling purposes; the emission and discharge of hazardous and other materials, including GHGs, into the environment; climate change; and the health and safety of our employees. These laws and regulations often require a lengthy and complex process of obtaining and renewing permits and other governmental authorizations from federal, state and local agencies. Violation of these laws, regulations or permits can result in substantial fines, other sanctions, permit revocation and/or facility shutdowns. We cannot assure that we have been or will be at all times in full compliance with such laws, regulations and permits. Accruals for environmental contingencies were not material as of December 31, 2023 and 2022.
NSR and other CAA NOVs
In October 2009, AES Indiana received a NOV and Finding of Violation from the EPA pursuant to the CAA Section 113(a). The NOV alleged violations of the CAA at AES Indiana’s three primarily coal-fired electric generating facilities at the time, dating back to 1986. The alleged violations primarily pertain to the PSD and non-attainment NSR requirements under the CAA. In addition, on October 1, 2015, AES Indiana received a NOV from the EPA pursuant to CAA Section 113(a) alleging violations of the CAA, the Indiana SIP, and the Title V operating permit related to alleged particulate matter and opacity violations at AES Indiana Petersburg Unit 3. Also, on February 5, 2016, the EPA issued a NOV pursuant to CAA Section 113(a) alleging violations of PSD, non-attainment NSR and other CAA regulations, the Indiana SIP, and the Title V operating permit at Petersburg Generating Station. On August 31, 2020, AES Indiana reached a settlement with the EPA, the DOJ and IDEM resolving the purported violations of the CAA with respect to the coal-fired generation units at AES Indiana's Petersburg location. The settlement agreement, in the form of a proposed judicial consent decree was approved and entered by the U.S. District Court for the Southern District of Indiana on March 23, 2021, and includes, among other items, the following requirements: annual caps on NOx and SO2 emissions and more stringent emissions limits than AES Indiana's prior Title V air permit; payment of civil penalties totaling $1.525 million (the payment of which was satisfied by AES Indiana in April 2021); a $5 million environmental mitigation project consisting of the construction and operation of a new, non-emitting source of generation at the site; expenditure of $0.325 million on a state-only environmentally beneficial project to preserve local, ecologically-significant lands; and retirement of Units 1 and 2 prior to July 1, 2023 (which has occurred). AES Indiana previously had a contingent liability recorded related to these NSR and other CAA NOV matters.
11. RELATED PARTY TRANSACTIONS
AES Indiana participates in a property insurance program in which AES Indiana buys insurance from AES Global Insurance Company, a wholly-owned subsidiary of AES. AES Indiana is not self-insured on property insurance, but does take a $5 million per occurrence deductible. Except for AES Indiana’s large substations, AES Indiana does not carry insurance on transmission and distribution assets, which are considered to be outside the scope of property insurance. AES and other AES subsidiaries, including IPALCO, also participate in the AES global insurance program. AES Indiana pays premiums for a policy that is written and administered by a third-party insurance company. The premiums paid to this third-party administrator by the participants are paid to AES Global Insurance Company and all claims are paid from a trust fund funded by and owned by AES Global Insurance Company, but controlled by the third-party administrator. AES Indiana also has third-party insurance in which the premiums are paid directly to the third-party insurers. The cost to AES Indiana of coverage under the property insurance program with AES Global Insurance Company was approximately $11.7 million, $9.5 million, and $7.0 million in 2023, 2022 and 2021, respectively, and is recorded in “Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations. As of December 31, 2023 and 2022, we had prepaid approximately $7.5 million and $3.4 million, respectively, for coverage under these plans, which is recorded in "Prepayments and other current assets" on the accompanying Consolidated Balance Sheets.
AES Indiana participates in an agreement with Health and Welfare Benefit Plans LLC, an affiliate of AES, to participate in a group benefits program, including but not limited to, health, dental, vision and life benefits. Health and Welfare Benefit Plans LLC administers the financial aspects of the group insurance program, receives all premium payments from the participating affiliates, and makes all vendor payments. The cost of coverage under this program was approximately $19.0 million, $25.2 million, and $23.7 million in 2023, 2022 and 2021, respectively, and
is recorded in “Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations. We had no prepaids for coverage under this plan as of December 31, 2023 and 2022, respectively.
AES files federal and state income tax returns which consolidate IPALCO and its subsidiaries. Under a tax sharing agreement with AES, IPALCO is responsible for the income taxes associated with its own taxable income and records the provision for income taxes using a separate return method. IPALCO had a receivable balance under this agreement of $36.5 million and $18.0 million as of December 31, 2023 and 2022, respectively, which is recorded in “Taxes receivable” on the accompanying Consolidated Balance Sheets. See Note 7, "Income Taxes" for more information.
Long-term Compensation Plan
During 2023, 2022 and 2021, many of AES Indiana’s non-union employees received benefits under the AES Long-term Compensation Plan, a deferred compensation program. This type of plan is a common employee retention tool used in our industry. Benefits under this plan are granted in the form of performance units payable in cash and AES restricted stock units. Restricted stock units vest ratably over a three-year period. The performance units payable in cash vest at the end of the three-year performance period and are subject to certain AES performance criteria. Total deferred compensation expense recorded during 2023, 2022 and 2021 was $0.3 million, $0.2 million and $0.2 million, respectively, and was included in “Operating expenses - Operation and maintenance” on IPALCO’s Consolidated Statements of Operations. The value of these benefits is being recognized over the 36 month vesting period and a portion is recorded as miscellaneous deferred credits with the remainder recorded as “Paid in capital” on IPALCO’s Consolidated Balance Sheets in accordance with ASC 718 “Compensation - Stock Compensation.”
See also Note 8, “Benefit Plans” to the Financial Statements for a description of benefits awarded to AES Indiana employees by AES under the RSP.
Service Company
Total costs incurred by the Service Company on behalf of IPALCO were $73.8 million, $60.3 million and $58.4 million during 2023, 2022 and 2021, respectively. Total costs incurred by IPALCO on behalf of the Service Company during 2023, 2022 and 2021 were $11.9 million, $10.0 million and $10.4 million, respectively, which are included as a reduction to charges from the Service Company. These costs were included in “Operating expenses - Operation and maintenance” on IPALCO’s Consolidated Statements of Operations. IPALCO had a payable balance with the Service company of $25.6 million and $2.1 million as of December 31, 2023 and 2022, respectively, which is recorded in "Accounts payable" on the accompanying Consolidated Balance Sheets.
Other
In the second quarter of 2023, AES Indiana engaged a vendor that is a related party through a competitive RFP process as part of its replacement capacity resource construction projects. AES Indiana had payments of $223.3 million to this vendor during the year ended December 31, 2023, which are included in "Other non-current assets" on the accompanying Consolidated Balance Sheets. Transactions with various other related parties were $7.4 million, $5.7 million and $4.3 million during 2023, 2022 and 2021, respectively. These expenses were primarily recorded in “Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations.
12. BUSINESS SEGMENTS
IPALCO manages its business through one reportable operating segment, the Utility segment. The primary segment performance measure is income / (loss) from continuing operations before income tax as management has concluded that this measure best reflects the underlying business performance of IPALCO and is the most relevant measure considered in IPALCO's internal evaluation of the financial performance of its segment. The Utility segment is comprised of AES Indiana, a vertically integrated electric utility, with all other nonutility business activities aggregated separately. See Note 1, "Overview and Summary of Significant Accounting Policies" for further information on AES Indiana. The “Other” nonutility category primarily includes the 2024 IPALCO Notes and 2030 IPALCO Notes and related interest expense, balance associated with IPALCO's interest rate hedges, cash and other immaterial balances. The accounting policies of the identified segment are consistent with those policies and procedures described in the summary of significant accounting policies.
The following table provides information about IPALCO’s business segments (in thousands):
2023 2022 2021
Utility Other Total Utility Other Total Utility Other Total
Revenue $ 1,649,917 $ - $ 1,649,917 $ 1,791,711 $ - $ 1,791,711 $ 1,426,132 $ - $ 1,426,132
Depreciation and amortization $ 287,863 $ - $ 287,863 $ 266,504 $ - $ 266,504 $ 256,085 $ - $ 256,085
Interest expense $ 99,051 $ 43,875 $ 142,926 $ 87,428 $ 43,804 $ 131,232 $ 84,256 $ 41,370 $ 125,626
Income/(loss) before income tax $ 115,763 $ (44,021) $ 71,742 $ 162,862 $ (44,377) $ 118,485 $ 189,548 $ (41,425) $ 148,123
Capital expenditures(1)
$ 902,705 $ - $ 902,705 $ 496,510 $ - $ 496,510 $ 291,546 $ - $ 291,546
(1) Capital expenditures includes $0 thousand, $0 thousand and $36 thousand of payments for financed capital expenditures in 2023, 2022 and 2021, respectively.
As of December 31, 2023 As of December 31, 2022 As of December 31, 2021
Total assets $ 6,129,581 $ 51,942 $ 6,181,523 $ 5,559,977 $ 29,237 $ 5,589,214 $ 5,222,987 $ 16,780 $ 5,239,767
13. REVENUE
Revenue is primarily earned from retail and wholesale electricity sales and electricity transmission and distribution delivery services. Revenue is recognized upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Revenue is recorded net of any taxes assessed on and collected from customers, which are remitted to the governmental authorities.
Retail revenue - AES Indiana energy sales to utility customers are based on the reading of meters at the customer’s location that occurs on a systematic basis throughout the month. AES Indiana sells electricity directly to end-users, such as homes and businesses, and bills customers directly. Retail revenue have a single performance obligation, as the promise to transfer energy and other distribution and/or transmission services are not separately identifiable from other promises in the contracts and, therefore, are not distinct. Additionally, as the performance obligation is satisfied over time as energy is delivered, and the same method is used to measure progress, the performance obligation meets the criteria to be considered a series.
In exchange for the exclusive right to sell or distribute electricity in our service area, AES Indiana is subject to rate regulation by federal and state regulators. This regulation sets the framework for the prices (“tariffs”) that AES Indiana is allowed to charge customers for electric services. Since tariffs are approved by the regulator, the price that AES Indiana has the right to bill corresponds directly with the value to the customer of AES Indiana’s performance completed in each period. Therefore, revenue under these contracts is recognized using an output method measured by the MWhs delivered each month at the approved tariff. Customer payments are typically due on a monthly basis.
Wholesale revenue - Power produced at the generation stations in excess of our retail load is sold into the MISO market. Such sales are made at either the day-ahead or real-time hourly market price, and these sales are classified as wholesale revenue. We sell to and purchase power from MISO, and such sales and purchases are settled and accounted for on a net hourly basis.
In the MISO market, wholesale revenue is recorded at the spot price based on the quantities of MWh delivered in each hour during each month. As a member of MISO, we are obligated to declare the availability of our energy production into the wholesale energy market, but we are not obligated to commit our previously declared availability. As such, contract terms end as the energy for each day is delivered to the market in the case of the day-ahead market and for each hour in the case of the real-time market.
Miscellaneous revenue - Miscellaneous revenue is mainly comprised of MISO transmission revenue and capacity revenue. MISO transmission revenue is earned when AES Indiana’s power lines are used in transmission of energy by power producers other than AES Indiana. As AES Indiana owns and operates transmission lines in central and southern Indiana, demand charges collected from network customers by MISO are allocated to the appropriate transmission owners (including AES Indiana) and recognized as transmission revenue. Capacity revenue is also included in miscellaneous revenue, and represent compensation received from MISO for making installed generation capacity available to satisfy system integrity and reliability requirements through the annual MISO capacity auction. Capacity, which is a stand-ready obligation to deliver energy when called upon by the RTO, is measured using MWs.
Transmission and capacity revenue each have a single performance obligation, as they each represent a distinct service or good. Additionally, as these performance obligations are satisfied over time and the same method is used to measure progress, the performance obligations meet the criteria to be considered a series. For transmission revenue, the price that the transmission operator has the right to bill corresponds directly with the value to the customer of AES Indiana’s performance completed in each period as the price paid is the transmission operator's allocation of the tariff rate (as approved by the regulator) charged to network participants. For capacity revenue, the capacity price that clears at the auction is fixed and AES Indiana is compensated based on the cleared MWs and cleared price.
AES Indiana’s revenue from contracts with customers was $1,616.5 million, $1,760.0 million and $1,389.2 million for the years ended December 31, 2023, 2022 and 2021, respectively. The following table presents our revenue from contracts with customers and other revenue (in thousands):
For the Years Ended December 31,
2023 2022 2021
Retail Revenue
Retail revenue from contracts with customers:
Residential $ 660,559 $ 688,487 $ 595,692
Small commercial and industrial 241,800 247,655 211,997
Large commercial and industrial 619,899 625,351 518,069
Public lighting 9,767 9,832 8,888
Other (1)
14,016 17,845 16,785
Total retail revenue from contracts with customers 1,546,041 1,589,170 1,351,431
Alternative revenue programs 30,414 29,171 35,248
Wholesale Revenue
Wholesale revenue from contracts with customers 56,557 148,517 25,059
Miscellaneous Revenue
Capacity revenue 8,210 11,750 734
Transmission and other revenue 5,654 10,534 11,480
Total miscellaneous revenue from contracts with customers 13,864 22,284 12,214
Other miscellaneous revenue (2)
3,041 2,569 2,180
Total Revenue $ 1,649,917 $ 1,791,711 $ 1,426,132
(1) Other retail revenue from contracts with customers includes miscellaneous charges to customers, including reconnection and late fee charges.
(2) Other miscellaneous revenue includes lease and other miscellaneous revenue not accounted for under ASC 606.
The balances of receivables from contracts with customers were $218.8 million and $198.3 million as of December 31, 2023 and 2022, respectively. Payment terms for all receivables from contracts with customers typically do not extend beyond 30 days, unless a customer qualifies for payment extension.
The Company has elected to apply the optional disclosure exemptions under ASC 606. Therefore, the Company has not included disclosure pertaining to revenue expected to be recognized in any future year related to remaining performance obligations, as we exclude contracts with an original length of one year or less, contracts for which we recognize revenue based on the amount we have the right to invoice for services performed, and contracts with variable consideration allocated entirely to a wholly unsatisfied performance obligation when the consideration relates specifically to our efforts to satisfy the performance obligation and depicts the amount to which we expect to be entitled.
14. LEASES
LESSEE
The Company is the lessee under financing leases primarily for land. Right-of-use assets are long-term by nature. The following table summarizes the amounts recognized on the Consolidated Balance Sheets related to lease asset and liability balances as of the periods indicated (in thousands):
Consolidated Balance Sheet Classification December 31, 2023 December 31, 2022
Assets
Right-of-use assets - finance leases Other non-current assets $ 16,357 $ 15,819
Liabilities
Finance lease liabilities (noncurrent) Long-term debt $ 17,769 $ 16,361
Total finance lease liabilities $ 17,769 $ 16,361
The following table summarizes supplemental balance sheet information related to leases as of the periods indicated:
Lease Term and Discount Rate December 31, 2023 December 31, 2022
Weighted-average remaining lease term - finance leases 35 years
36 years
Weighted-average discount rate - finance leases 5.30 % 5.650 %
The following table summarizes the components of lease expense recognized in "Operating Costs and Expenses" on the accompanying Consolidated Statements of Operations for the years ended December 31, 2023, 2022 and 2021, respectively (in thousands):
For the Year Ended December 31,
Components of Lease Cost 2023 2022 2021
Finance lease cost:
Amortization of right-of-use assets $ 445 $ 542 $ -
Interest on lease liabilities 933 782 -
Total lease cost $ 1,378 $ 1,324 $ -
Operating cash outflows from finance leases were $0.6 million, $0.3 million and $0.0 million for the years ended December 31, 2023, 2022 and 2021, respectively.
The following table shows the future lease payments under finance leases together with the present value of the net lease payments as of December 31, 2023 for 2024 through 2028 and thereafter (in thousands):
Finance Leases
2024 $ 891
2025 909
2026 927
2027 945
2028 965
Thereafter 39,958
Total $ 44,595
Less: Imputed interest (26,826)
Present value of lease payments $ 17,769
LESSOR
The Company is the lessor under operating leases for land, office space and operating equipment. Lease receipts from such contracts are recognized as operating lease revenue on a straight-line basis over the lease term whereas contingent rentals are recognized when earned.
The following table presents lease revenue from operating leases in which the Company is the lessor for the periods indicated (in thousands):
For the Year Ended December 31,
2023 2022 2021
Total lease revenue $ 1,537 $ 1,134 $ 1,439
The following table presents the underlying gross assets and accumulated depreciation of operating leases included in Property, plant and equipment, net for the periods indicated (in thousands):
Property, Plant and Equipment, Net December 31, 2023 December 31, 2022
Gross assets $ 4,341 $ 4,334
Less: Accumulated depreciation (1,222) (1,060)
Net assets $ 3,119 $ 3,274
The option to extend or terminate a lease is based on customary early termination provisions in the contract.
The following table shows the future minimum lease receipts through 2028 and thereafter (in thousands):
Operating Leases
2024 $ 544
2025 553
2026 554
2027 554
2028 354
Thereafter 891
Total $ 3,450
Report of Independent Registered Public Accounting Firm
To the Shareholders and the Board of Directors of Indianapolis Power & Light Company
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Indianapolis Power & Light Company and subsidiaries, d/b/a AES Indiana, (the Company) as of December 31, 2023 and 2022, the related consolidated statements of operations, changes in equity, and cash flows for each of the three years in the period ended December 31, 2023, and the related notes and financial statement schedule listed in the Index at Item 15 (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023 in conformity with U.S. generally accepted accounting principles.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the Board of Directors and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Regulatory Accounting
Regulatory Accounting
Description of the Matter As described in Note 2 to the consolidated financial statements, the Company applies the provisions of FASB Accounting Standards Codification 980 “Regulated Operations”, which gives recognition to the ratemaking and accounting practices of the Indiana Utility Regulatory Commission and the Federal Energy Regulatory Commission. Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in customer rates. Regulatory assets can also represent performance incentives permitted by the regulator. Regulatory liabilities generally represent obligations to provide refunds or future rate reductions to customers for previous overcollections or the deferral of revenues collected for costs that the Company expects to incur in the future. Accounting for the economics of rate regulation affects multiple consolidated financial statement line items, including property, plant, and equipment; regulatory assets and liabilities; revenues; and depreciation expense, and related disclosures in the Company’s consolidated financial statements.
Auditing the Company’s regulatory accounting was complex due to significant judgments made by management to support its assertions about the impact of future regulatory orders on the consolidated financial statements. In particular, there is subjectivity involved in assessing the impact of current and future regulatory orders on events that have occurred through December 31, 2023, judgment required to evaluate the relevance and reliability of audit evidence to support impacted account balances and disclosures, and judgments involved in assessing the probability of recovery in future rates of incurred costs or refunds to customers. These assumptions have a significant effect on the consolidated financial statements and related disclosures.
How We Addressed the Matter in Our Audit To evaluate the Company’s significant judgments in accounting for regulatory assets and liabilities, our audit procedures included, among others, reviewing relevant regulatory orders, statutes and interpretations; filings made by intervening parties; and other publicly available information, to assess the likelihood of recovery of regulatory assets in future rates or of a refund or future reduction in rates for regulatory liabilities based on precedents for the treatment of similar costs under similar circumstances. We evaluated the Company’s assertions regarding the probability of recovery of regulatory assets or refund or future reduction in rates for regulatory liabilities, to assess the Company’s assertion that amounts are probable of recovery or of a refund or future reduction in rates.
Asset Retirement Obligations
Regulatory Accounting
Description of the Matter At December 31, 2023, the Company’s asset retirement obligations (“ARO”) totaled $249.9 million. As described in Note 3 to the consolidated financial statements, the Company’s ARO liabilities relate primarily to environmental issues involving asbestos-containing materials, ash ponds, landfills and miscellaneous contaminants associated with its generating plants, transmission system and distribution system. The Company recorded adjustments to its ARO liabilities of $30.0 million during 2023. ARO liabilities incurred in 2023 primarily related to FGD residual water disposal. ARO liabilities were revised in 2023 primarily to reflect revisions to cash flow estimates due to increases to estimated ash pond closure costs.
Auditing the Company’s ARO liabilities was complex and highly judgmental due to the significant estimation required by management to determine the estimated cost estimates of the legal obligations associated with the Company’s generating plants, transmission system and distribution system. In particular, the estimate was sensitive to significant assumptions including the scope and method of decommissioning and timing of related cash flows.
How We Addressed the Matter in Our Audit To test the Company’s ARO liability estimates, our audit procedures included evaluating the appropriateness of the Company’s methodology, interviewing members of the Company’s environmental staff and testing significant assumptions and inputs including the timing of activities, projected closure dates and the method of decommissioning. We involved our specialists in our assessment of the Company’s ARO liabilities including reviewing the Company’s methodology, evaluating the reasonableness of the cost estimates and assumptions, and assessing completeness of the estimates with respect to regulatory requirements.
/s/ Ernst & Young LLP
We have served as the Company’s auditor since 2008.
Indianapolis, Indiana
February 26, 2024
AES INDIANA and SUBSIDIARIES
Consolidated Statements of Operations
For the Years Ended December 31, 2023, 2022 and 2021
2023 2022 2021
(In Thousands)
REVENUE $ 1,649,917 $ 1,791,711 $ 1,426,132
OPERATING COSTS AND EXPENSES:
Fuel 494,000 568,676 255,817
Power purchased 159,908 199,860 175,025
Operation and maintenance 477,497 493,454 449,317
Depreciation and amortization 287,863 266,504 256,085
Taxes other than income taxes 24,865 33,048 44,419
Other, net (361) (3,201) (5,630)
Total operating costs and expenses 1,443,772 1,558,341 1,175,033
OPERATING INCOME 206,145 233,370 251,099
OTHER INCOME / (EXPENSE), NET:
Allowance for equity funds used during construction 9,315 4,784 5,412
Interest expense (99,051) (87,428) (84,257)
Other income, net (646) 12,136 17,294
Total other expense, net (90,382) (70,508) (61,551)
INCOME BEFORE INCOME TAX 115,763 162,862 189,548
Income tax expense 25,666 32,887 39,305
NET INCOME 90,097 129,975 150,243
Dividends on and redemption of preferred stock - 3,509 3,213
Net loss attributable to noncontrolling interests (26,093) - -
NET INCOME ATTRIBUTABLE TO COMMON STOCK $ 116,190 $ 126,466 $ 147,030
See Notes to Consolidated Financial Statements.
AES INDIANA and SUBSIDIARIES
Consolidated Balance Sheets
December 31, 2023 December 31, 2022
(In Thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 25,767 $ 199,103
Accounts receivable, net of allowance for credit losses of $2,283 and $1,117, respectively
233,970 216,572
Inventories 143,590 123,608
Regulatory assets, current 89,419 119,723
Taxes receivable 5,140 6,682
Prepayments and other current assets 27,741 27,422
Total current assets 525,627 693,110
NON-CURRENT ASSETS:
Property, plant and equipment 7,082,443 6,982,314
Less: Accumulated depreciation 2,954,555 3,243,968
4,127,888 3,738,346
Construction work in progress 359,014 294,985
Total net property, plant and equipment 4,486,902 4,033,331
OTHER NON-CURRENT ASSETS:
Intangible assets - net 235,656 138,978
Regulatory assets, non-current 541,784 593,939
Pension plan assets 41,172 33,611
Other non-current assets 298,439 67,008
Total other non-current assets 1,117,051 833,536
TOTAL ASSETS $ 6,129,580 $ 5,559,977
LIABILITIES AND SHAREHOLDER'S EQUITY
CURRENT LIABILITIES:
Short-term debt and current portion of long-term debt (see Note 6) $ 494,685 $ -
Accounts payable 292,835 189,806
Accrued taxes 22,580 22,474
Accrued interest 25,245 25,054
Customer deposits 29,308 35,097
Regulatory liabilities, current 23,371 23,348
Accrued and other current liabilities 34,748 26,214
Total current liabilities 922,772 321,993
NON-CURRENT LIABILITIES:
Long-term debt (see Notes 6 and 14) 2,106,146 2,143,147
Deferred income tax liabilities 342,557 305,107
Regulatory liabilities, non-current 527,224 612,585
Accrued other postretirement benefits 2,776 3,085
Asset retirement obligations 249,930 218,729
Other non-current liabilities 5,129 11,621
Total non-current liabilities 3,233,762 3,294,274
Total liabilities 4,156,534 3,616,267
COMMITMENTS AND CONTINGENCIES (see Note 10)
EQUITY:
Common shareholder's equity
Common stock (no par value, 20,000,000 shares authorized; 17,206,630 shares issued and outstanding at December 31, 2023 and 2022)
324,537 324,537
Paid in capital 1,193,199 1,193,107
Retained earnings 402,056 426,066
Total common shareholder's equity 1,919,792 1,943,710
Noncontrolling interests 53,254 -
Total equity 1,973,046 1,943,710
TOTAL LIABILITIES AND EQUITY $ 6,129,580 $ 5,559,977
See Notes to Consolidated Financial Statements.
AES INDIANA and SUBSIDIARIES
Consolidated Statements of Cash Flows
For the Years Ended December 31, 2023, 2022 and 2021
2023 2022 2021
(In Thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 90,097 $ 129,975 $ 150,243
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization 287,863 266,504 256,085
Amortization of deferred financing costs and debt discounts 2,406 2,511 2,536
Deferred income taxes and investment tax credit adjustments - net 23,582 (6,584) (7,373)
Allowance for equity funds used during construction (9,315) (4,784) (5,412)
Gain on acquisition - - (5,630)
Change in certain assets and liabilities:
Accounts receivable (17,398) (37,391) (13,746)
Inventories (30,171) (47,489) (12,017)
Prepayments and other current assets (6,476) 19,016 (4,556)
Accounts payable 47,016 32,232 21,502
Accrued and other current liabilities 2,790 6,532 (13,017)
Accrued taxes payable/receivable 1,647 (3,452) (2,302)
Accrued interest 192 2,813 (1,099)
Pension and other postretirement benefit assets and liabilities 1,625 (8,727) (16,592)
Current and non-current regulatory assets and liabilities 54,358 38,863 (104,759)
Other non-current liabilities (16,663) (21,717) 5,566
Other - net (4,074) 4,967 (1,645)
Net cash provided by operating activities 427,479 373,269 247,784
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (902,705) (496,510) (291,510)
Project development costs (4,462) (3,910) (1,304)
Cost of removal payments (45,595) (23,948) (35,260)
Insurance proceeds 4,900 - -
Loan repayments from parent - - 6,110
Purchase of intangibles (44,650) - (26,261)
Other (361) (719) (14,380)
Net cash used in investing activities (992,873) (525,087) (362,605)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings from revolving credit facilities 435,000 300,000 320,000
Repayments from revolving credit facilities (280,000) (360,000) (335,000)
Short-term borrowings 300,000 200,000 -
Repayment of short-term borrowings - (200,000) -
Long-term borrowings - 350,000 95,000
Retirement of long-term debt - - (95,000)
Dividends on common stock (140,200) (127,200) (155,700)
Dividends on preferred stock - (3,213) (3,213)
Payments of deferred financings costs and discounts (350) (4,309) (1,325)
Purchase of preferred stock - (60,080) -
Equity contributions from IPALCO - 253,000 275,000
Sales to noncontrolling interests 77,921 - -
Other (313) (33) (131)
Net cash provided by financing activities 392,058 348,165 99,631
Net change in cash, cash equivalents and restricted cash (173,336) 196,347 (15,190)
Cash, cash equivalents and restricted cash at beginning of year 199,108 2,761 17,951
Cash, cash equivalents and restricted cash at end of year $ 25,772 $ 199,108 $ 2,761
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the period for:
Interest (net of amount capitalized) $ 93,544 $ 80,104 $ 82,880
Income taxes $ - $ 39,500 $ 40,800
Non-cash investing activities:
Accruals for capital expenditures $ 124,626 $ 66,949 $ 81,325
Recognition and changes to right-of-use assets - finance leases $ 983 $ (3,402) $ 19,763
Non-cash financing activities:
Recognition and changes to financing lease liabilities $ (1,408) $ (3,402) $ 19,763
See Notes to Consolidated Financial Statements.
AES INDIANA and SUBSIDIARIES
Consolidated Statements of Changes in Equity
For the Years Ended December 31, 2023, 2022 and 2021
Common Shareholder's Equity
Common Stock
(in Thousands)
Outstanding Shares
Amount
Paid in Capital Retained Earnings Total Common Shareholder's Equity Cumulative Preferred Stock Noncontrolling Interests
Balance at January 1, 2021 17,207 $ 324,537 $ 664,886 $ 435,470 $ 1,424,893 $ 59,784 $ -
Net income - - 150,243 150,243 3,213 -
Preferred stock dividends - - (3,213) (3,213) (3,213) -
Cash dividends declared on common stock - - (155,700) (155,700) - -
Contributions from IPALCO - 275,000 - 275,000 - -
Other - 107 - 107 - -
Balance at December 31, 2021 17,207 324,537 939,993 426,800 1,691,330 59,784 -
Net income - - 129,975 129,975 3,213 -
Preferred stock dividends - - (3,213) (3,213) (3,213) -
Redemption of preferred stock - - (296) (296) (59,784) -
Cash dividends declared on common stock - - (127,200) (127,200) - -
Contributions from IPALCO - 253,000 - 253,000 - -
Other - 114 - 114 - -
Balance at December 31, 2022 17,207 324,537 1,193,107 426,066 1,943,710 - -
Net income / (loss) - - 116,190 116,190 - (26,093)
Cash dividends declared on common stock - - (140,200) (140,200) - -
Sales to noncontrolling interests - - - - - 79,347
Other - 92 - 92 - -
Balance at December 31, 2023 17,207 $ 324,537 $ 1,193,199 $ 402,056 $ 1,919,792 $ - $ 53,254
See Notes to Consolidated Financial Statements.
AES INDIANA and SUBSIDIARIES
Notes to Consolidated Financial Statements
For the Years Ended December 31, 2023, 2022 and 2021
1. OVERVIEW AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
IPL, which does business as AES Indiana, was incorporated under the laws of the state of Indiana in 1926. All of the outstanding common stock of AES Indiana is owned by IPALCO. IPALCO, acquired by AES in March 2001, is owned by AES U.S. Investments and CDPQ. AES U.S. Investments is owned by AES (85%) and CDPQ (15%). AES Indiana is engaged primarily in generating, transmitting, distributing and selling of electric energy to approximately 523,000 retail customers in the city of Indianapolis and neighboring cities, towns and communities, and adjacent rural areas all within the state of Indiana. AES Indiana has an exclusive right to provide electric service to those customers.
AES Indiana owns and operates four generating stations all within the state of Indiana. The first station, Petersburg, is coal-fired, and AES Indiana retired 230 MW Petersburg Unit 1 in May 2021 and 415 MW Petersburg Unit 2 in June 2023, which resulted in 630 MW of total retired economic capacity at this station. AES Indiana plans to convert the remaining two coal units at Petersburg to natural gas (for further discussion, see Note 2, "Regulatory Matters - IRP Filings and Replacement Generation 2022 IRP"). The second station, Harding Street, consists of three natural gas-fired boilers and steam turbines and uses natural gas and fuel oil to power five combustion turbines. In addition, AES Indiana operates a 20 MW battery energy storage unit at this location, which provides frequency response. The third station, Eagle Valley, is a CCGT natural gas plant. The fourth station, Georgetown, is a peaking station that uses natural gas to power combustion turbines. As of December 31, 2023, AES Indiana’s net electric generation capacity for winter is 3,070 MW and net summer capacity is 2,925 MW.
In December 2021, AES Indiana, through a wholly-owned subsidiary, completed the acquisition of Hardy Hills Solar Energy LLC, including the development of a 195 MW solar project (the "Hardy Hills Solar Project"). In December 2023, the first stage of construction for the Hardy Hills Solar Project was completed and placed in service, with initial operations for over half of the project commencing on December 28, 2023. The final stage for construction of the project is expected to be completed during the first half of 2024.
In August 2023, AES Indiana, through a wholly-owned subsidiary, completed the acquisition of Petersburg Energy Center, LLC, including the development of a 250 MW solar and 45 MW (180 MWh) energy storage facility (the "Petersburg Energy Center Project"). The Petersburg Energy Center Project is expected to be completed in 2025.
In June 2023, AES Indiana, through a wholly-owned subsidiary, executed an agreement for the construction of the 200 MW (800 MWh) Pike County BESS Project to be developed at the AES Indiana Petersburg Plant site in Pike County, Indiana, subject to IURC approval, which was received in January 2024. The Pike County BESS Project is expected to be completed in 2024.
For further discussion about AES Indiana's plans for wind, solar, and battery energy storage projects, please see Note 2, "Regulatory Matters - IRP Filings and Replacement Generation."
Principles of Consolidation
AES Indiana’s consolidated financial statements are prepared in accordance with GAAP and in conjunction with the rules and regulations of the SEC. The consolidated financial statements include the accounts of AES Indiana and its wholly owned subsidiaries. Furthermore, VIEs in which the Company has an ownership interest and is the primary beneficiary, thus controlling the VIE, as described below, have been consolidated. All intercompany items have been eliminated in consolidation. Certain costs for shared resources amongst AES Indiana and IPALCO, such as labor and benefits, are allocated to each entity based on allocation methodologies that management believes to be reasonable. We have evaluated subsequent events through the date this report is issued.
If AES Indiana enters into transactions impacting equity interests in its affiliates, AES Indiana must determine whether the transaction impacts the Company's consolidation conclusion by first determining whether the transaction should be evaluated under the variable interest model or the voting model. In determining which
consolidation model applies to the transaction, AES Indiana is required to make judgments about how the entity operates, the most significant of which are whether (i) the entity has sufficient equity to finance its activities, (ii) the equity holders, as a group, have the characteristics of a controlling financial interest, and (iii) whether the entity has non-substantive voting rights. If the entity is determined to be a variable interest entity and AES Indiana is determined to have power and benefits, the entity will be consolidated by AES Indiana.
Noncontrolling Interests
Noncontrolling interests are classified as a separate component of equity in the Consolidated Balance Sheets and Consolidated Statements of Changes in Equity. Additionally, net income attributable to noncontrolling interests is reflected separately from consolidated net income on the Consolidated Statements of Operations. Any change in ownership of a subsidiary while the controlling financial interest is retained is accounted for as an equity transaction between the controlling and noncontrolling interests. Losses continue to be attributed to the noncontrolling interests, even when the noncontrolling interests' basis has been reduced to zero.
Allocation of Earnings
Hardy Hills JV is subject to profit-sharing arrangements where the allocation of earnings, cash distributions, and tax benefits are not based on fixed ownership percentages. This arrangement exists to designate different allocations of value among the investors, where the allocations change in form or percentage over the life of the partnership. AES Indiana uses the HLBV method when it is a reasonable approximation of the profit-sharing arrangement. The HLBV method calculates the proceeds that would be attributable to each partner based on the liquidation provisions of the respective operating partnership agreement if the partnership was to be liquidated at book value at the balance sheet date. Each partner’s share of income in the period is equal to the change in the amount of net equity they are legally able to claim based on a hypothetical liquidation of the entity at the end of a reporting period compared to the beginning of that period, adjusted for any capital transactions (for further discussion about the Equity Capital Contribution Agreement, see Note 2, "Regulatory Matters - IRP Filings and Replacement Generation").
The HLBV method is used to calculate the earnings attributable to noncontrolling interest when the business is consolidated by AES Indiana. In the early months of operations of a renewable generation facility where HLBV results in a significant decrease in the hypothetical liquidation proceeds attributable to the tax equity investor due to the recognition of investment tax credits ("ITCs") or other adjustments as required by the U.S. Internal Revenue Code, the Company records the impact (sometimes referred to as the ‘Day one gain’) to income in the same period.
Use of Management Estimates
The preparation of financial statements in conformity with GAAP requires that management make certain estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements. The reported amounts of revenue and expenses during the reporting period may also be affected by the estimates and assumptions management is required to make. Actual results may differ from those estimates. Significant items subject to such estimates and assumptions include: recognition of revenue including unbilled revenue; the carrying value of property, plant and equipment; the valuation of insurance and claims liabilities; the valuation of allowances for credit losses and deferred income taxes; regulatory assets and liabilities; liabilities recorded for income tax exposures; litigation; contingencies; and assets and liabilities related to AROs and employee benefits.
Reclassifications
Certain immaterial amounts from prior periods have been reclassified to conform to the current year presentation.
Cash and Cash Equivalents
Cash and cash equivalents are stated at cost, which approximates fair value. All highly liquid short-term investments with original maturities of three months or less are considered cash equivalents.
Restricted Cash
Restricted cash includes cash which is restricted as to withdrawal or usage. The nature of the restrictions includes restrictions imposed by agreements related to deposits held as collateral.
The following table provides a summary of cash, cash equivalents, and restricted cash amounts reported within the Consolidated Balance Sheets that reconcile to the total of such amounts as shown on the Consolidated Statements of Cash Flows:
As of December 31,
2023 2022
(In Thousands)
Cash, cash equivalents and restricted cash
Cash and cash equivalents $ 25,767 $ 199,103
Restricted cash (included in Prepayments and other current assets) 5 5
Total cash, cash equivalents and restricted cash $ 25,772 $ 199,108
Accounts Receivable and Allowance for Credit Losses
The following table summarizes our accounts receivable balances at December 31:
As of December 31,
2023 2022
(In Thousands)
Accounts receivable, net
Customer receivables $ 125,715 $ 125,540
Unbilled revenue 91,463 74,488
Amounts due from related parties 5,227 288
Other 13,848 17,373
Allowance for credit losses (2,283) (1,117)
Total accounts receivable, net $ 233,970 $ 216,572
The following table is a rollforward of our allowance for credit losses related to the accounts receivable balances for the periods indicated:
For the Years Ended December 31,
2023 2022
(In Thousands)
Allowance for credit losses:
Beginning balance $ 1,117 $ 647
Current period provision 7,413 5,851
Write-offs charged against allowance
(7,764) (7,008)
Recoveries collected 1,517 1,627
Ending Balance $ 2,283 $ 1,117
The allowance for credit losses primarily relates to utility customer receivables, including unbilled amounts. Expected credit loss estimates are developed by disaggregating customers into those with similar credit risk characteristics and using historical credit loss experience. In addition, we also consider how current and future economic conditions are expected to impact collectability, as applicable, of our receivable balance. Amounts are written off when reasonable collections efforts have been exhausted.
Inventories
AES Indiana maintains coal, fuel oil, natural gas, materials and supplies inventories for use in the production of electricity. These inventories are accounted for at the lower of cost or net realizable value, using the average cost. The following table summarizes our inventories balances at December 31:
As of December 31,
2023 2022
(In Thousands)
Inventories
Fuel $ 77,198 $ 60,497
Materials and supplies, net 66,392 63,111
Total inventories $ 143,590 $ 123,608
Regulatory Accounting
The retail utility operations of AES Indiana are subject to the jurisdiction of the IURC. AES Indiana’s wholesale power transactions are subject to the jurisdiction of the FERC. These agencies regulate AES Indiana’s utility business operations, tariffs, accounting, depreciation allowances, services, issuances of securities and the sale and acquisition of utility properties. The financial statements of AES Indiana are based on GAAP, including the provisions of FASB ASC 980 “Regulated Operations,” which gives recognition to the ratemaking and accounting practices of these agencies. See also Note 2, “Regulatory Matters - Regulatory Assets and Liabilities” for a discussion of specific regulatory assets and liabilities.
Property, Plant and Equipment
Property, plant and equipment is stated at original cost as defined for regulatory purposes. The cost of additions to property, plant and equipment and replacements of retirement units of property are charged to plant accounts. Units of property replaced or abandoned in the ordinary course of business are retired from the plant accounts at cost; such amounts, less salvage, are charged to accumulated depreciation. Depreciation is computed by the straight-line method based on functional rates approved by the IURC and averaged 3.7%, 3.8% and 3.7% during 2023, 2022 and 2021, respectively. Depreciation expense was $244.8 million, $247.5 million, and $239.1 million for the years ended December 31, 2023, 2022 and 2021, respectively. "Depreciation and amortization" expense on the accompanying Consolidated Statements of Operations is presented net of regulatory deferrals of depreciation expense and also includes amortization of intangible assets and amortization of previously deferred regulatory costs.
AFUDC
In accordance with the Uniform System of Accounts prescribed by FERC, AES Indiana capitalizes an allowance for the net cost of funds (interest on borrowed funds and a reasonable rate of return on equity funds) used for construction purposes during the period of construction with a corresponding credit to income. AES Indiana capitalized amounts using pretax composite rates of 7.1%, 5.4% and 5.7% during 2023, 2022 and 2021, respectively. AFUDC equity and AFUDC debt were as follows for the years ended December 31, 2023, 2022 and 2021:
2023 2022 2021
(In Thousands)
AFUDC equity $ 9,315 $ 4,784 $ 5,412
AFUDC debt $ 13,739 $ 8,215 $ 4,815
Impairment of Long-lived Assets
GAAP requires that AES Indiana test long-lived assets for impairment when indicators of impairment exist. If an asset is deemed to be impaired, AES Indiana is required to write down the asset to its fair value with a charge to
current earnings. The net book value of AES Indiana’s property, plant, and equipment was $4.5 billion and $4.0 billion as of December 31, 2023 and 2022, respectively. As of December 31, 2023 and 2022, AES Indiana had $259.9 million and $287.5 million, respectively, of long-term regulatory assets associated with Petersburg Unit 1 and 2 retirement costs (for further discussion, see Note 2, “Regulatory Matters - IRP Filings and Replacement Generation” and Note 3, "Property, Plant and Equipment"). AES Indiana does not believe any of these assets are currently impaired. In making this assessment, AES Indiana considers such factors as: the overall condition and generating and distribution capacity of the assets; the expected ability to recover additional expenditures in the assets; the anticipated demand and relative pricing of retail electricity in its service territory and wholesale electricity in the region; and the cost of fuel.
Intangible Assets
Finite-lived intangible assets primarily include capitalized software and project development intangible assets amortized on a straight-line basis over their useful lives. The following table presents information related to the Company's intangible assets, including the gross amount capitalized and related amortization:
December 31,
$ in thousands
Weighted average amortization periods (in years)
Capitalized software
8 $ 261,872 $ 205,910
Project development intangible assets
28 84,097 39,455
Other
Various
797 797
Less: Accumulated amortization
(111,110) (107,184)
Intangible assets - net
$ 235,656 $ 138,978
For the Years Ended December 31,
2023 2022 2021
Amortization expense
$ 14,570 $ 10,122 $ 11,241
Estimated future amortization
Years ending December 31,
2024 $ 20,764
2025 20,764
2026 22,550
2027 22,550
2028 22,550
Total
$ 109,178
Implementation Costs Related to Software as a Service
AES Indiana has recorded prepayments for implementation costs related to software as a service in support of utility customer services of $7.1 million and $8.2 million as of December 31, 2023 and 2022, respectively, which are recorded within "Other non-current assets" on the accompanying Consolidated Balance Sheets.
Debt Issuance Costs
Costs incurred in connection with the issuance of long-term debt are deferred and presented as a direct reduction from the face amount of that debt and amortized over the related financing period using the effective interest method. Debt issuance costs related to a line-of-credit or revolving credit facility are deferred and presented as an asset and amortized over the related financing period. Make-whole payments in connection with early debt retirements are classified as cash flows from financing activities.
Contingencies
AES Indiana accrues for loss contingencies when the amount of the loss is probable and estimable. AES Indiana is subject to various environmental regulations and is involved in certain legal proceedings. If AES Indiana’s actual environmental and/or legal obligations are different from our estimates, the recognition of the actual amounts may have a material impact on our results of operations, financial condition and cash flows; although that has not been
the case during the periods covered by this report. Accruals for loss contingencies were not material as of December 31, 2023 and 2022. See Note 10, "Commitments and Contingencies - Contingencies" for additional information.
Concentrations of Risk
Substantially all of AES Indiana’s customers are located within the Indianapolis area. Approximately 68% of AES Indiana’s employees are covered by collective bargaining agreements in two bargaining units: a physical unit and a clerical-technical unit. AES Indiana’s contract with the physical unit expires on December 4, 2024, and the contract with the clerical-technical unit expires February 12, 2026. Additionally, AES Indiana has long-term coal contracts with one supplier, and substantially all of AES Indiana's coal is currently mined in the state of Indiana.
Financial Derivatives
All derivatives are recognized as either assets or liabilities in the balance sheets and are measured at fair value. Changes in the fair value are recorded in earnings unless the derivative is designated as a cash flow hedge of a forecasted transaction or it qualifies for the normal purchases and sales exception.
AES Indiana has contracts involving the physical delivery of energy and fuel. Because some of these contracts qualify for the normal purchases and normal sales scope exception in ASC 815, AES Indiana has elected to account for them as accrual contracts, which are not adjusted for changes in fair value. AES Indiana has or previously had FTRs and forward power contracts that do not qualify for hedge accounting or the normal purchases and sales exceptions under ASC 815. Accordingly, FTRs are recorded at fair value when acquired and subsequently amortized over the annual period as they are used. FTRs are initially recorded at fair value using the income approach. The forward power contracts are recorded at fair value with changes in the fair value charged or credited to the Consolidated Statements of Operations in the period in which the change occurred. Forward power contracts are fair valued using the market approach.
Leases
The Company has finance leases primarily for land in which the Company is the lessee. Operating leases with an initial term of 12 months or less are not recorded on the balance sheet, but are expensed on a straight-line basis over the lease term. The Company’s leases do not contain any material residual value guarantees, restrictive covenants or subleases.
Right-of-use assets represent our right to use an underlying asset for the lease term while lease liabilities represent our obligation to make lease payments arising from the lease. Right-of-use assets and lease liabilities are recognized on commencement of the lease based on the present value of lease payments over the lease term. Generally, the rate implicit in the lease is not readily determinable; as such, we use the incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The Company determines discount rates based on its existing credit rates of its borrowings, which are then adjusted for the appropriate lease term. The right-of-use asset also includes any lease payments made and excludes lease incentives that are paid or payable to the lessee at commencement. The lease term includes periods covered by the option to extend if it is reasonably certain that the option will be exercised and periods covered by an option to terminate if it is reasonably certain that the option will not be exercised.
Revenue Recognition
Revenue related to the sale of energy is generally recognized when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to certain customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is accrued. In making its estimates of unbilled revenue, AES Indiana uses models that consider various factors including daily generation volumes; known amounts of energy usage by nearly all residential, commercial and industrial customers; and estimated customer rates based on prior period billings. Given the use of these models, and that customers are billed on a monthly cycle, we believe it is unlikely that materially different results will occur in future periods when revenue is billed. An allowance for potential credit losses is maintained and amounts are written off when normal collection efforts have been exhausted. AES Indiana’s provision for expected credit losses included in “Operating expenses - Operation and maintenance” on the accompanying Consolidated
Statements of Operations was $7.5 million, $5.9 million and $3.0 million for the years ended December 31, 2023, 2022 and 2021, respectively.
AES Indiana’s basic rates include a provision for fuel costs as established in AES Indiana’s most recent rate proceeding, which last adjusted AES Indiana’s rates in December 2018. AES Indiana is permitted to recover actual costs of purchased power and fuel consumed, subject to certain restrictions. This is accomplished through quarterly FAC proceedings, in which AES Indiana estimates the amount of fuel and purchased power costs in future periods. Through these proceedings, AES Indiana is also permitted to recover, in future rates, underestimated fuel and purchased power costs from prior periods, subject to certain restrictions, and therefore the over or underestimated costs are deferred or accrued and amortized into fuel expense in the same period that AES Indiana’s rates are adjusted. See also Note 2, “Regulatory Matters” for a discussion of other costs that AES Indiana is permitted to recover through periodic rate adjustment proceedings and the status of current rate adjustment proceedings.
In addition, AES Indiana is one of many transmission system owner members of MISO, a RTO which maintains functional control over the combined transmission systems of its members and manages one of the largest energy markets in the U.S. See Note 13, "Revenue" for additional information of MISO sales and other revenue streams.
Operating Expenses - Other, Net
Operating expenses - Other, net generally includes gains or losses on asset sales, dispositions or acquisitions, gains or losses on the sale or acquisition of businesses, and other expense or income from miscellaneous operating transactions. For the year ended December 31, 2022, the $3.2 million is primarily due to a gain on remeasurement of contingent consideration associated with the Hardy Hills Solar Project acquisition. For the year ended December 31, 2021, the $5.6 million represents a gain on acquisition.
Pension and Postretirement Benefits
AES Indiana recognizes in its Consolidated Balance Sheets an asset or liability reflecting the funded status of pension and other postretirement plans with current-year changes in the funded status, that would otherwise be recognized in AOCI, recorded as a regulatory asset as this can be recovered through future rates. All plan assets are recorded at fair value. AES Indiana follows the measurement date provisions of the accounting guidance, which require a year-end measurement date of plan assets and obligations for all defined benefit plans.
AES Indiana accounts for and discloses pension and postretirement benefits in accordance with the provisions of GAAP relating to the accounting for pension and other postretirement plans. These GAAP provisions require the use of assumptions, such as the discount rate for liabilities and long-term rate of return on assets, in determining the obligations, annual cost and funding requirements of the plans. Consistent with the requirements of ASC 715, AES Indiana applies a disaggregated discount rate approach for determining service cost and interest cost for its defined benefit pension plans and postretirement plans.
See Note 8, "Benefit Plans" for more information.
Income Taxes
Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of the existing assets and liabilities, and their respective income tax bases. AES Indiana establishes a valuation allowance when it is more likely than not that all or a portion of a deferred tax asset will not be realized. AES Indiana’s tax positions are evaluated under a more likely than not recognition threshold and measurement analysis before they are recognized for financial statement reporting.
Uncertain tax positions are classified as noncurrent income tax liabilities unless expected to be paid within one year. AES Indiana’s policy for interest and penalties is to recognize interest and penalties as a component of the provision for income taxes in the Consolidated Statements of Operations.
Income tax assets or liabilities which are included in allowable costs for ratemaking purposes in future years are recorded as regulatory assets or liabilities with a corresponding deferred tax liability or asset. Investment tax credits that reduced federal income taxes in the years they arose have been deferred and are being amortized to income over the useful lives of the properties in accordance with regulatory treatment. See Note 2, "Regulatory Matters" for additional information.
AES Indiana files U.S. federal income tax returns as part of the consolidated U.S. income tax return filed by AES. The consolidated tax liability is allocated to each subsidiary based on the separate return method which is specified in our tax allocation agreement and which provides a consistent, systematic and rational approach. See Note 7, "Income Taxes" for additional information.
Repair and Maintenance Costs
Repair and maintenance costs are expensed as incurred.
Per Share Data
IPALCO owns all of the outstanding common stock of AES Indiana. AES Indiana does not report earnings on a per-share basis.
New Accounting Pronouncements
We have assessed and determined that the new accounting pronouncements adopted did not have a material impact on AES Indiana's Financial Statements.
New Accounting Pronouncements Issued But Not Yet Effective
The following table provides a brief description of recent accounting pronouncements that could have a material impact on the AES Indiana's Financial Statements once adopted. Accounting pronouncements not listed below were assessed and determined to be either not applicable or are expected to have no material impact on AES Indiana's Financial Statements.
ASU Number and Name Description Date of Adoption Effect on the Financial Statements upon adoption
2023-06 Disclosure Improvements: Codification Amendments in Response to the SEC’s Disclosure Update and Simplification Initiative
In U.S. Securities and Exchange Commission (SEC) Release No. 33-10532, Disclosure Update and Simplification, issued August 17, 2018, the SEC referred certain of its disclosure requirements that overlap with, but require incremental information to, generally accepted accounting principles (GAAP) to the FASB for potential incorporation into the Codification. The amendments in this Update are the result of the Board’s decision to incorporate into the Codification 14 of the 27 disclosures referred by the SEC.
The amendments in this Update represent changes to clarify or improve disclosure and presentation requirements of a variety of Topics. Many of the amendments allow users to more easily compare entities subject to the SEC’s existing disclosures with those entities that were not previously subject to the SEC’s requirements. Also, the amendments align the requirements in the Codification with the SEC’s regulations.
The effective date for each amendment will be the date on which the SEC's removal of that related disclosure becomes effective, with early adoption prohibited. The amendments in this Update should be applied prospectively.
AES Indiana will provide the required disclosures on a prospective basis on the date each amendment becomes effective. AES Indiana does not expect ASU 2023-06 will have any impact to its Financial Statements.
2023-07 Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures
The amendments in this section are designed to improve the disclosures related to Segment reporting on an interim and annual basis. Public companies must disclose significant segment expenses and an amount for other segment items. This will also require that a company disclose its annual disclosures under Topic 280 in each interim period. Furthermore, companies will need to disclose the Chief Operating Decision Maker (CODM) and how the CODM assesses the performance of a segment. Lastly, public companies that have a single reportable segment must report the required disclosures under topic 280.
The amendments in this Update are effective for fiscal years beginning after
December 15, 2023, and interim periods within fiscal years beginning after
December 15, 2024. Early adoption is permitted.
AES Indiana is currently evaluating the impact of adopting the standard on its Financial Statements.
2023-09 Income Taxes (Topic 740): Improvements to Income Tax Disclosures
The amendments in this Update require that public business entities on an annual basis (1) disclose specific categories in the rate reconciliation and (2) provide additional information for reconciling items that meet a quantitative threshold. Furthermore, companies are required to disclose a disaggregated amount of income taxes paid at a federal, state, and foreign level as well as a break down of income taxes paid in a jurisdiction that comprises 5% of a company's total income taxes paid. Lastly, this ASU requires that companies disclose income (loss) from continuing operations before income tax at a domestic and foreign level and that companies disclose income tax expense from continuing operations on a federal, state, and foreign level.
The amendments in this Update are effective for fiscal years beginning after December 15, 2024.
AES Indiana is currently evaluating the impact of adopting the standard on its Financial Statements.
2. REGULATORY MATTERS
General
AES Indiana is subject to regulation by the IURC as to its services and facilities, the valuation of property, the construction, purchase, or lease of electric generating facilities, the classification of accounts, rates of depreciation, retail rates and charges, the issuance of securities (other than evidences of indebtedness payable less than twelve months after the date of issue), the acquisition and sale of some public utility properties or securities and certain other matters.
In addition, AES Indiana is subject to the jurisdiction of the FERC with respect to, among other things, short-term borrowings not regulated by the IURC, the sale of electricity at wholesale, the transmission of electric energy in interstate commerce, the classification of accounts, reliability standards, and the acquisition and sale of utility property in certain circumstances as provided by the Federal Power Act. As a regulated entity, AES Indiana is required to use certain accounting methods prescribed by regulatory bodies which may differ from those accounting methods required to be used by unregulated entities.
AES Indiana is also affected by the regulatory jurisdiction of the EPA at the federal level, and the IDEM at the state level. Other significant regulatory agencies affecting AES Indiana include, but are not limited to, the NERC, the U.S. Department of Labor and the IOSHA.
Basic Rates and Charges
AES Indiana’s basic rates and charges represent the largest component of its annual revenue. AES Indiana’s basic rates and charges are determined after giving consideration, on a pro-forma basis, to all allowable costs for ratemaking purposes including a fair return on the fair value of the utility property used and useful in providing service to customers. These basic rates and charges are set and approved by the IURC after public hearings. Such proceedings, which have occurred at irregular intervals, involve AES Indiana, the IURC, the Indiana Office of Utility Consumer Counselor, and other interested stakeholders. Pursuant to statute, the IURC is to conduct a periodic review of the basic rates and charges of all Indiana utilities at least once every four years, but the IURC has the authority to review the rates of any Indiana utility at any time. Once set, the basic rates and charges authorized do not assure the realization of a fair return on the fair value of property.
AES Indiana’s declining block rate structure generally provides for residential and commercial customers to be charged a lower per kWh rate at higher consumption levels. Therefore, as volumes increase, the weighted average price per kWh decreases. Numerous factors including, but not limited to, weather, inflation, customer growth and usage, the level of actual operating and maintenance expenditures, fuel costs, generating unit availability, and capital expenditures including those required by environmental regulations can affect the return realized.
Regulatory Rate Review and Base Rate Orders
AES Indiana filed a petition with the IURC on June 28, 2023, for authority to increase its basic rates and charges to cover the rising operational costs and needs associated with continuing to serve its customers safely and reliably. The factors leading to AES Indiana's first base rate increase request in five years include inflationary impacts on operations and maintenance expenses, investments in the transmission and distribution systems, and modernization of its customer systems. AES Indiana is also seeking recovery of increased costs to support its vegetation management plan, which covers the removal of overhang and tree trimming in its service territory. AES Indiana also seeks to better align depreciation expense with the period in which the generation plants provide service to customers and remove operational costs of the retired Petersburg units from rates. On November 22, 2023, AES Indiana entered into a unanimous stipulation and settlement agreement (the "settlement") with the OUCC and the intervening parties which, if approved by the IURC, would increase its annual revenue requirement by $73 million. AES Indiana expects to receive an order from the IURC and place new rates into effect by the end of the second quarter of 2024.
On October 31, 2018, the IURC issued an order approving an uncontested settlement agreement previously filed with the IURC by AES Indiana for a $43.9 million, or 3.2%, increase to annual revenue (the "2018 Base Rate Order"). The 2018 Base Rate Order includes recovery through rates of the CCGT at Eagle Valley completed in the first half of 2018, as well as other construction projects and changes to operating income since the 2016 Base Rate Order. New basic rates and charges became effective on December 5, 2018. The 2018 Base Rate Order provides that annual wholesale margins earned above (or below) the benchmark of $16.3 million shall be passed back (or charged) to customer rates through a rate adjustment mechanism. Similarly, the 2018 Base Rate Order provides that all capacity sales above (or below) a benchmark of $11.3 million shall be passed back (or charged) to customer rates through a rate adjustment mechanism.
FAC and Authorized Annual Jurisdictional Net Operating Income
AES Indiana may apply to the IURC for a change in AES Indiana’s fuel charge every three months to recover AES Indiana’s estimated fuel costs, including the energy portion of purchased power costs, which may be above or below the levels included in AES Indiana’s basic rates and charges. AES Indiana must present evidence in each
FAC proceeding that it has made every reasonable effort to acquire fuel and generate or purchase power or both so as to provide electricity to its retail customers at the lowest fuel cost reasonably possible.
Independent of the IURC’s ability to review basic rates and charges, Indiana law requires electric utilities under the jurisdiction of the IURC to meet operating expense and income test requirements as a condition for approval of requested changes in the FAC. A utility may be unable to recover all of its fuel costs if its rolling twelve-month operating income, determined at quarterly measurement dates, exceeds its authorized annual jurisdictional net operating income and there are not sufficient applicable cumulative net operating income deficiencies (“Cumulative Deficiencies”) to offset it. The Cumulative Deficiencies calculation provides that only five years’ worth of historical earnings deficiencies or surpluses are included, unless it has been greater than five years since the most recent rate case.
In calendar years 2021 and 2022, AES Indiana reported earnings in excess of the authorized level for certain quarterly reporting periods in those years. AES Indiana has not reported earnings in excess of the authorized level for any FAC periods in the calendar year 2023. Prior to 2020, AES Indiana was not required to reduce its fuel cost recovery because of its Cumulative Deficiencies. During 2020, AES Indiana's Cumulative Deficiencies dropped to zero. AES Indiana recorded a reduction to revenue of $0.0 million, $0.3 million and $5.5 million in 2023, 2022 and 2021, respectively. As of the FAC period ending with the twelve months of October 31, 2023, AES Indiana has Cumulative Deficiencies; therefore, AES will not be required to reduce its fuel cost recovery for future earnings in excess of the authorized level until there are no longer Cumulative Deficiencies.
ECCRA
AES Indiana may apply to the IURC for approval of a rate adjustment known as the ECCRA periodically to recover costs (including a return) to comply with certain environmental regulations applicable to AES Indiana’s generating stations and to recover certain investments in renewable and battery storage projects. The total amount of AES Indiana’s environmental equipment and renewable projects approved for ECCRA recovery as of December 31, 2023 was $129.7 million. The jurisdictional revenue requirement approved by the IURC to be included in AES Indiana’s rates for the twelve-month period ending February 2024 is a net cost to customers of $8.9 million.
DSM
Through various rate orders from the IURC, AES Indiana has been able to recover its costs of implementing various DSM programs throughout the periods covered by this report. In 2023, 2022 and 2021, AES Indiana also had the ability to receive performance incentives, dependent upon the level of success of the programs. Performance incentives included in rates for the years ended December 31, 2023, 2022 and 2021 were $2.7 million, $8.3 million and $7.2 million, respectively.
On December 29, 2020, the IURC approved a settlement agreement establishing a new three year DSM plan for AES Indiana through 2023. The approval included cost recovery of programs as well as performance incentives, depending on the level of success of the programs. The order also approved recovery of lost revenue, consistent with the provisions of the settlement agreement.
AES Indiana filed a petition with the IURC on May 26, 2023 asking for approval of a one year DSM interim plan. On December 27, 2023, the IURC approved a one year DSM plan for AES Indiana through 2024. The approval included cost recovery of programs as well as performance incentives, depending on the level of success of the programs. The order also approved recovery of lost revenue, consistent with the provisions of the settlement agreement.
Wind and Solar Power Purchase Agreements
AES Indiana is currently committed under a power purchase agreement to purchase all wind-generated electricity through 2029 from a wind project in Indiana ("Hoosier Wind Project"). On July 28, 2023, AES Indiana executed the Purchase Agreement and is currently in the process of acquiring this project. The existing power purchase agreement will be terminated upon closing (see "IRP Filings and Replacement Generation - Hoosier Wind Project" below for further information). AES Indiana is also committed under another agreement to purchase all wind-generated electricity through 2031 from a project in Minnesota. The Indiana project has a maximum output capacity of approximately 100 MW and the Minnesota project has a maximum output capacity of approximately 200 MW. In addition, AES Indiana has 94.5 MW of solar-generated electricity in its service territory under long-term contracts
(these long-term contracts have expiration dates ranging from 2026 to 2033), of which 94.0 MW was in operation as of December 31, 2023. AES Indiana has authority from the IURC to recover the costs for all of these agreements through an adjustment mechanism administered within the FAC. If and when AES Indiana sells the renewable energy attributes (in the form of renewable energy credits) generated from these facilities, the proceeds would pass back to benefit AES Indiana’s retail customers through the FAC.
TDSIC
In 2013, Senate Enrolled Act 560, the Transmission, Distribution, and Storage System Improvement Charge ("TDSIC") statute, was signed into law. The TDSIC statute was revised in 2019. Among other provisions, this legislation provides for cost recovery outside of a base rate proceeding for new or replacement electric and gas transmission, distribution, and storage projects that a public utility undertakes for the purposes of safety, reliability, system modernization, or economic development. Provisions of the TDSIC statute require that, among other things, requests for recovery include a plan of at least five years and not more than seven for eligible investments. The first eighty percent of eligible costs can be recovered using a periodic rate adjustment mechanism. The cost recovery mechanism is referred to as a TDSIC mechanism. Recoverable costs include a return on, and of, the investment, including AFUDC, post-in-service carrying charges, operation and maintenance expenses, depreciation and property taxes. The remaining twenty percent of recoverable costs are to be deferred for future recovery in the public utility’s next base rate case. The periodic rate adjustment mechanism is capped at an annual increase of no more than two percent of total retail revenue.
On March 4, 2020, the IURC issued an order approving the projects in a seven-year TDSIC Plan for eligible transmission, distribution and storage system improvements totaling $1.2 billion from 2020 through 2026. Beginning in June 2020, AES Indiana files an annual TDSIC rate adjustment for a return on and of investments through March 31 with rates requested to be effective each November. Annual TDSIC plan update filings are required to be staggered by six months as ordered by the IURC and are filed each December. The total amount of AES Indiana’s equipment net of depreciation, including carrying costs, approved for TDSIC recovery as of December 31, 2023 was $399.6 million, The jurisdictional revenue requirement approved by the IURC to be included in AES Indiana’s rates for the twelve-month period ending October 2024 is a net cost to customers of $56.5 million.
IRP Filings and Replacement Generation
Electric utilities in Indiana are required to submit Integrated Resource Plans (IRPs) every three years. The IRPs are subject to a rigorous stakeholder process. IRPs describe how the utility plans to deliver safe, reliable, and efficient electricity at just and reasonable rates.
2022 IRP
AES Indiana held public advisory meetings for the 2022 IRP in January, April, June, September and October of 2022. Changes to our generation portfolio are evaluated and decided through the IRP. AES Indiana issued an all-source Request for Proposal on April 14, 2022, in order to competitively procure energy and capacity in the near term; such need was evaluated in AES Indiana's 2022 IRP.
In December 2022, AES Indiana filed its 2022 IRP with the IURC, which describes AES Indiana's Preferred Resource Portfolio for meeting generation capacity needs for serving AES Indiana's retail customers over the next several years. The Preferred Resource Portfolio is AES Indiana's reasonable least cost option and provides a cleaner and more diverse generation mix for customers. The 2022 IRP short-term action plan includes converting the two remaining coal units at Petersburg to natural gas. AES Indiana has not yet filed for the regulatory approvals from the IURC to convert Petersburg units 3 and 4; however, AES Indiana expects to do so in the first half of 2024. Construction is expected to begin in 2025 and be completed by the end of 2026. Additionally, AES Indiana plans to add up to 1,300 MW of wind, solar, and battery energy storage by 2027. As new technologies, such as green hydrogen, small modular reactors and carbon capture are developed and cost effective, AES Indiana will evaluate them in the future planning processes. As a result of the plan to convert Petersburg units 3 and 4 to natural gas, AES Indiana recorded a $1.5 million write off of capital projects during the period ended December 31, 2022 to "Operating expenses - Operation and maintenance" on the accompanying Consolidated Statements of Operations.
2019 IRP
In December 2019, AES Indiana filed its 2019 IRP, which included the retirement of approximately 630 MW of coal-fired generation at Petersburg Units 1 and 2 in 2021 and 2023, respectively. Based on extensive modeling, AES Indiana determined that the cost of operating Petersburg Units 1 and 2 exceeded the value customers received compared to alternative resources. Retirement of these units allowed the company to cost-effectively diversify the portfolio and transition to lower cost and cleaner resources while maintaining a reliable system.
AES Indiana issued an all-source Request for Proposal on December 20, 2019, in order to competitively procure replacement capacity by June 1, 2023, which was the first year AES Indiana was expected to have a capacity shortfall. AES Indiana's modeling indicated that a combination of wind, solar, storage, and energy efficiency would be the lowest reasonable cost option for the replacement capacity. As a result of the plans to retire Petersburg Units 1 and 2, AES Indiana recorded $0.7 million, $2.1 million, and $0.8 million of obsolescence losses, during the periods ended December 31, 2023, 2022, and 2021, respectively, for materials and supplies inventory AES Indiana did not believe will be utilized by the planned retirement dates, which is recorded in "Operating expenses - Operation and maintenance" on the accompanying Consolidated Statements of Operations.
As a result of the plans to retire Petersburg Units 1 and 2, AES Indiana filed a petition with the IURC on February 26, 2021 for approvals and cost recovery associated with these retirements. On August 6, 2021, AES Indiana filed an uncontested Stipulation and Settlement Agreement with the other parties in the case which includes: (1) AES Indiana's creation of regulatory assets for the net book value of Petersburg units 1 and 2 upon retirement; (2) a method for amortization of the regulatory assets; and (3) recovery of the regulatory assets through ongoing amortization in AES Indiana’s future rate cases. The Settlement Agreement also reserves all rights of all the parties with respect to the ratemaking treatment related to the regulatory assets, including the proper rate of return and mechanisms for recovery. On November 17, 2021, the IURC approved the Settlement Agreement without modification. AES Indiana retired 230 MW Petersburg Unit 1 in May 2021 and 415 MW Petersburg Unit 2 in June 2023.
AES Indiana had $35.7 million and $224.2 million of Petersburg Units 1 and 2 retirement costs, respectively, net of accumulated amortization, recorded as long-term regulatory assets as of December 31, 2023. AES Indiana had $47.6 million and $239.9 million of Petersburg Units 1 and 2 retirement costs, respectively, net of accumulated amortization, recorded as long-term regulatory assets as of December 31, 2022.
Hardy Hills Solar Project
In January 2021, AES Indiana, through a wholly-owned subsidiary, executed an agreement for the acquisition and construction of the 195 MW Hardy Hills Solar Project to be developed in Clinton County, Indiana. In December 2022, the agreement was amended to revise the project schedule, including shifting the completion date to 2024, and adjusting for increased project costs. On January 13, 2023, AES Indiana filed a petition with the IURC for approval of these revisions, which was approved in August 2023.
On June 16, 2021, AES Indiana received an order from the IURC approving a petition and case-in-chief seeking a CPCN for this solar project, including a joint venture structure between an AES Indiana subsidiary and one or more tax equity partners upon completion and approval for recovery of project development costs and carrying costs on AES Indiana's investment in the project. The transaction closed in December 2021 and was accounted for as an asset acquisition of a variable interest entity that did not meet the definition of a business; therefore, the individual assets and liabilities were recorded at their fair values. Total net assets of $51.6 million were recorded in the accompanying Consolidated Balance Sheets associated with the transaction, primarily consisting of a development project intangible asset (see Note 1, "Overview and Summary of Significant Accounting Policies - Intangible Assets"). A gain for the difference between the consideration transferred and the assets and liabilities recognized was recorded in “Operating costs and expenses - Other, net” on the accompanying Consolidated Statements of Operations. Total consideration included a future payment contingent on certain future costs incurred by the project. As such, a $3.2 million contingent liability was recorded in "Other Non-Current Liabilities" on the accompanying Consolidated Balance Sheets as of December 31, 2021. During 2022, this liability was remeasured due to updated cost estimates and was reduced to $0.0 million.
On December 1, 2023, AES Indiana, through a wholly-owned subsidiary (the "Class B Member"), and a third-party investor (the "Class A Member"), entered into an Equity Capital Contribution Agreement, pursuant to which each member made certain capital contributions to Hardy Hills JV. The Class A member made total contributions of
$79.3 million through December 31, 2023. Hardy Hills JV is consolidated by the Class B Member under the Variable Interest Model, and noncontrolling interest (“NCI”) was recorded by AES Indiana at the amount of cash contributed by the Class A Member. In December 2023, the first stage of the construction for the Hardy Hills Solar Project was completed and placed in service, with initial operations for over half of the project commencing on December 28, 2023. Upon the first stage of the project being placed in service, the Company recognized $26.1 million of earnings from tax attributes using the HLBV method. The final stage for construction of the project is expected to be completed during the first half of 2024.
Petersburg Energy Center Project
In July 2021, AES Indiana, through a wholly-owned subsidiary, executed an agreement for the acquisition and construction of a 250 MW solar and 45MW (180 MWh) energy storage facility to be developed in Pike County, Indiana. In October 2022, the agreement was amended to revise the project schedule, including shifting the completion date to 2025, and adjusting for increased project costs. On December 22, 2022, AES Indiana filed a petition with the IURC for approval of these revisions, which was approved in May 2023. On August 31, 2023, AES Indiana closed on the agreement for the acquisition and construction of the Petersburg Energy Center Project. This transaction was accounted for as an asset acquisition of a variable interest entity that did not meet the definition of a business; therefore, the individual assets were recorded at their fair values. Total net assets of $48.7 million were recorded in the accompanying Consolidated Balance Sheets associated with the transaction, primarily consisting of project development intangible assets (see Note 1, "Overview and Summary of Significant Accounting Policies - Intangible Assets" for further information).
Pike County BESS Project
In June 2023, AES Indiana, through a wholly-owned subsidiary, executed an agreement for the construction of the 200 MW (800 MWh) Pike County BESS Project to be developed at the AES Indiana Petersburg Plant site in Pike County, Indiana. On July 19, 2023, AES Indiana filed a petition and case-in-chief with the IURC seeking approval for a Clean Energy Project and associated timely cost recovery under Indiana Code for this project. A hearing for this case was held in October 2023, and IURC approval was received on January 17, 2024. The Pike County BESS Project is expected to be completed in 2024.
Hoosier Wind Project
On July 5, 2023, AES Indiana filed a Notice of Intent with the IURC to request approval of a Clean Energy Project and for issuance of a CPCN for the Hoosier Wind Project acquisition. The proposed Project is the acquisition of the Hoosier Wind Project, which is an existing 106 MW wind facility located in Benton County, Indiana. The Company executed the Purchase Agreement on July 28, 2023. A CPCN for this case was filed in early August 2023, and IURC approval was received on January 24, 2024. The acquisition of the Hoosier Wind Project is expected to be completed in the first quarter of 2024.
Incentives for Clean Energy Projects
Indiana Code 8-1-8 (the "clean energy statute") offers certain incentives for clean energy projects. Primarily, it allows for the timely recovery of costs and expenses incurred during construction and operation of eligible projects outside of a base rate proceeding. Clean energy projects eligible for incentives under this statute include renewable energy resources such as wind, photovoltaic cells and panels, solar energy, and energy storage systems or technologies, among others. AES Indiana filed for and received IURC approval of the Hoosier Wind Project and Pike County BESS Project under this statute. AES Indiana continues to evaluate projects which may also be filed under this statute.
IURC COVID-19 Orders
Due to the COVID-19 pandemic, there was a disconnection moratorium in 2020 for IURC-jurisdictional utilities, as well as suspension of certain utility fees (late fees, convenience fees, deposits, and disconnection/reconnection fees) from residential customers. The IURC authorized Indiana utilities to use regulatory accounting for any impacts associated with the moratorium and suspension. The IURC also authorized regulatory accounting treatment for COVID-19 related uncollectible and incremental bad debt expense. As a result of the IURC's COVID-19 related orders issued in 2020, AES Indiana has recorded a regulatory asset of $5.4 million as of December 31, 2023 and
2022, which will be recovered through base rates under the stipulation and settlement agreement entered into on November 22, 2023, if approved by the IURC.
EDG Rates
On March 1, 2021, AES Indiana filed a petition with the IURC for approval of its proposed rate for the procurement of EDG and related consumer EDG credit issues. The EDG rate replaced the net metering program beginning in July 2022, when net metering was no longer available to new customers. The IURC approved the EDG rate by order dated January 26, 2022, On March 16, 2022, the IURC denied the petition for reconsideration filed by the other parties on February 15, 2022. The matter was subject to an appeal filed by the other parties on February 22, 2022, which was held in abeyance by the Indiana Court of Appeals pending resolution of a petition to transfer to the Indiana Supreme Court filed in a similar case involving a different and unaffiliated utility. The stay was extended by the Indiana Court of Appeals on July 11, 2022. On January 4, 2023, the Indiana Supreme Court issued a final decision in favor of the utility in the similar case that served as the basis of the stay in the AES Indiana case. On February 3, 2023, the OUCC moved to dismiss the appeal, which motion was granted on February 13, 2023.
EV Portfolio Program
On January 27, 2023, AES Indiana filed with the IURC a request to approve its EV Portfolio and associated accounting and ratemaking treatment. The EV Portfolio includes two separate parts: (1) a set of EV specific rates, tariffs, and alternative pricing structures, and (2) a set of Public Use EV Pilot Programs. The EV portfolio is designed to produce net benefits for all customers through new retail margins and grid optimization. The projected costs to successfully implement the services proposed in the EV Portfolio are estimated at $16.2 million over the three-year period. AES Indiana requested approval to defer as a regulatory asset and recover in future base rates the cost necessary to implement the EV Portfolio, including carrying charges. A hearing on this request was held in July 2023. On November 22, 2023, the IURC issued an order approving AES Indiana's EV Portfolio filing with approval to defer as a regulatory asset and to seek recovery in future base rates the cost necessary to implement the EV Portfolio, including carrying charges with no other significant modifications.
Storm Outage Restoration Inquiry
On July 11, 2023, the OUCC and the Citizens Action Coalition (“CAC”) filed a Joint Petition through which they requested the IURC open an investigation into AES Indiana’s practices and procedures regarding storm outage restoration. A technical conference was held on October 2, 2023, to discuss AES Indiana’s response to outages and storm restoration; particularly the storms that occurred between June 29, 2023 and July 2, 2023.
House Bill 1002
In the first quarter of 2022, the 2022 Indiana General Assembly passed House Enrolled Act 1002, which includes language regarding the repeal of the URT. AES Indiana filed a rate adjustment with the IURC on April 29, 2022, which was approved by the IURC on June 28, 2022. AES Indiana began charging the new rates excluding URT in July 2022. Prior to the repeal, the URT was recoverable through a current charge to customer rates. After the repeal, the new rates approved by the IURC adjusted both revenue and tax expense. As a result, the repeal of the URT had no impact on AES Indiana's net income.
Regulatory Assets and Liabilities
Regulatory assets represent deferred costs or credits that have been included as allowable costs or credits for ratemaking purposes. AES Indiana has recorded regulatory assets or liabilities relating to certain costs or credits as authorized by the IURC or established regulatory practices in accordance with ASC 980. AES Indiana is amortizing non tax-related regulatory assets to expense over periods ranging from 1 to 43 years. Tax-related regulatory assets represent the net income tax costs to be considered in future regulatory proceedings generally as the tax-related amounts are paid.
The amounts of regulatory assets and regulatory liabilities at December 31 are as follows:
2023 2022 Recovery Period
(In Thousands)
Regulatory assets, current:
Undercollections of rate riders $ 75,416 $ 26,047 Approximately 1 year(1)
Fuel costs - 79,861 Approximately 1 year(1)
Unamortized reacquisition premium on debt 188 - Approximately 1 year
Costs being recovered through basic rates and charges 13,815 13,815 Approximately 1 year(1)
Total regulatory assets, current 89,419 119,723
Regulatory assets, non-current:
Unrecognized pension and other
postretirement benefit plan costs 115,847 131,907 Various(2)
Deferred MISO costs 21,091 34,483 Through 2026(1)
Unamortized Petersburg Unit 4 carrying
charges and certain other costs 2,812 3,866 Through 2026(1)(3)
Unamortized reacquisition premium on debt 13,379 14,429 Over remaining life of debt
Environmental costs 66,837 68,947 Through 2046(1)(3)
COVID-19 costs 5,426 5,426 4 years(4)
Major storm damage 1,493 - To be determined
TDSIC costs 35,979 18,547 36.3 years(1)(3)
Petersburg Unit 1 and 2 retirement costs 259,892 287,463 Through 2034(1)(3)
Hardy Hills Solar Project development costs 6,774 5,744 30 years(3)
Petersburg Energy Center Project development costs 2,469 1,582 30 years(3)
Pike County BESS Project development costs 2,623 - 20 years(3)
Fuel costs 4,275 20,518 Through 2025(1)
Other miscellaneous 2,887 1,027 Various(5)
Total regulatory assets, non-current 541,784 593,939
Total regulatory assets $ 631,203 $ 713,662
Regulatory liabilities, current:
Overcollections and other credits being passed
to customers through rate riders $ 19,649 $ 15,803 Approximately 1 year(1)
FTRs 3,722 7,545 Approximately 1 year(1)
Total regulatory liabilities, current 23,371 23,348
Regulatory liabilities, non-current:
ARO and accrued asset removal costs 451,886 518,797 Not applicable
Deferred income taxes payable to customers through rates 74,796 88,662 Various
Hardy Hills sponsor investment tax credit 542 - To be determined(6)
Major storm damage - 5,126 To be determined
Total regulatory liabilities, non-current 527,224 612,585
Total regulatory liabilities $ 550,595 $ 635,933
(1)Recovered (credited) per specific rate orders
(2)AES Indiana receives a return on its discretionary funding
(3)Recovered with a current return
(4)Per the signed stipulation in the 2023 distribution rate case, Cause No. 45911
(5)Some of these costs are being recovered in basic rates and charges through 2026. For the remainder, recovery over four years was agreed to in the signed stipulation in the 2023 distribution rate case, Cause No. 45911. AES Indiana will include this credit in a future ECR filing.
(6)Will be included in a future ECR filing
Current Regulatory Assets and Liabilities
Current regulatory assets and liabilities primarily represent costs that are being recovered per specific rate orders; recovery for the remaining costs is probable, but not certain. As current assets, this includes undercollection of adjustment mechanisms for: (i) DSM, (ii) ECCRA costs, (iii) Off System Sales Margin Sharing, (iv) Capacity rider costs and (v) TDSIC. It also includes the current portion of deferred MISO costs and environmental costs collected through base rates which are described in greater detail below. With the exception of environmental costs, these costs do not earn a return on investment. As current liabilities, this includes (i) overcollection of MISO rider costs, (ii) Green Power, and (iii) deferred fuel costs.
Deferred Fuel
Deferred fuel costs are a component of current and long-term regulatory assets or liabilities (which is a result of AES Indiana charging either more or less for fuel than our actual costs to our jurisdictional customers) and are expected to be recovered through future FAC proceedings. AES Indiana records deferred fuel in accordance with standards prescribed by the FERC. The deferred fuel adjustment is the result of variances between estimated fuel and purchased power costs in AES Indiana’s FAC and actual fuel and purchased power costs. AES Indiana is generally permitted to recover underestimated fuel and purchased power costs in future rates through the FAC proceedings and therefore the costs are deferred when incurred and amortized into fuel expense in the same period that AES Indiana’s rates are adjusted to reflect these costs.
The Eagle Valley CCGT was on unplanned outage from late April 2021 until mid-March 2022, impacting several FAC periods. In November 2021, a sub-docket was created with the IURC to examine the unplanned outage. On October 25, 2022, AES Indiana and various intervening parties reached a unanimous settlement regarding the Eagle Valley CCGT unplanned outage, resolving all issues related to the FAC sub-docket and all outage related costs including energy purchases, Off-System Sales margins, Capacity trackers and base rate proceedings. As part of this comprehensive settlement, AES Indiana agreed not to recover $21.0 million of previously deferred costs and to credit an additional $6.8 million to customers in future rates. As such, AES Indiana recorded a $27.8 million charge to "Power purchased" in the Consolidated Statements of Operations during the third quarter of 2022. On January 18, 2023, AES Indiana received an order from the IURC approving the settlement.
Unrecognized Pension and Postretirement Benefit Plan Costs
In accordance with ASC 715 “Compensation - Retirement Benefits” and ASC 980, we recognize a regulatory asset equal to the unrecognized actuarial gains and losses and prior service costs. Pension expenses or income are recorded based on the benefit plan’s actuarially determined pension liability or asset and associated level of annual expenses or income to be recognized. The other postretirement benefit plan’s deferred benefit cost is the excess of the other postretirement benefit liability over the amount previously recognized.
Deferred MISO Costs
These consist of administrative costs for transmission services, transmission expansion cost sharing, and certain other operational and administrative costs from the MISO market. These costs are being recovered per specific rate order.
Unamortized Petersburg Unit 4 Carrying Charges and Certain Other Costs
These consist of deferred debt carrying costs, depreciation, and post-in-service AFUDC on Petersburg Unit 4. These costs are being recovered per specific rate order.
Unamortized Reacquisition Premium on Debt
This regulatory asset represents losses on long-term debt reacquired or redeemed in prior periods that have been deferred. These deferred losses are being amortized over the lives of the original issues in accordance with the rules of the FERC and the IURC.
Environmental Costs
These consist of various costs incurred to comply with environmental regulations. These costs were approved for recovery either through AES Indiana's ECCRA proceedings or in the 2018 Base Rate Order. Amortization periods vary, ranging from 3 to 43 years.
COVID-19 Costs
These consist of deferred fees (foregone late fees, reconnection fees and disconnection fees), as well as deferred convenience payments and incremental bad debt expense as the result of COVID-19. See "IURC COVID-19 Orders" above for additional discussion.
TDSIC Costs
These consist of various costs incurred for AES Indiana's approved TDSIC Plan. These costs were approved for recovery through AES Indiana's TDSIC proceedings and amortization periods range from 1 to 36 years. See "TDSIC" above for additional discussion.
Petersburg Unit 1 and 2 Retirement Costs
These consist of the remaining unamortized net book value of Petersburg Unit 1 and 2. In accordance with ASC 980, it was determined that the Petersburg Unit 1 retirement became probable, in the fourth quarter of 2020, and the Petersburg Unit 2 retirement became probable in the fourth quarter of 2021. As the entire carrying value of these assets will be recoverable through future rates, no loss on abandonment was recorded and the asset was reclassified from net property, plant and equipment to a long-term regulatory asset. See "IRP Filings and Replacement Generation" above for additional discussion.
Hardy Hills Solar Project Development Costs
These consist of project development costs, mainly legal and consulting fees, incurred for the Hardy Hills Solar Project as well as carrying costs on AES Indiana's investment in the project. The investment costs were approved for recovery via the ECCRA rider through AES Indiana’s Hardy Hills Solar Project regulatory proceedings with an amortization period of 30 years. Amortization of the project development costs will be determined in a future rate case filing.
Petersburg Energy Center Project Development Costs
These consist of project development costs, mainly legal and consulting fees, incurred for the Petersburg Energy Center Project as well as carrying costs on AES Indiana's investment in the project. The investment costs were approved for recovery via the ECCRA rider through AES Indiana’s Petersburg Energy Center Project regulatory proceedings with an amortization period of 30 years. Amortization of the project development costs will be determined in a future rate case filing.
Pike County BESS Project Development Costs
These consist of project development costs, mainly legal and consulting fees, incurred for the Pike County BESS Project as well as carrying costs on AES Indiana's investment in the project. The investment costs were approved for recovery via the ECCRA rider through AES Indiana’s Pike County BESS Project regulatory proceedings with an amortization period of 20 years. Amortization of the project development costs will be determined in a future rate case filing.
FTRs
In connection with AES Indiana’s participation in MISO, in the second quarter of each year AES Indiana is granted financial instruments that can be converted into cash or FTRs based on AES Indiana’s forecasted peak load for the period. See Note 4, "Fair Value - Fair Value Hierarchy and Valuation Techniques - Financial Assets - FTRs" for additional information.
ARO and Accrued Asset Removal Costs
In accordance with ASC 410 and ASC 980, AES Indiana recognizes the amount collected in customer rates for costs of removal not yet incurred that do not have an associated legal retirement obligation as a deferred regulatory liability. This amount is net of the portion of legal ARO costs that are deferred that is also being recovered in rates.
Deferred Income Taxes Recoverable/Payable Through Rates
A deferred income tax asset or liability is created from a difference in timing of income recognition between tax laws and accounting methods. As a regulated utility, AES Indiana includes in ratemaking the impacts of current income taxes and changes in deferred income tax liabilities or assets.
On December 22, 2017, the U.S. federal government enacted the TCJA, which, among other things, reduced the federal corporate income tax rate from 35% to 21%, beginning January 1, 2018. As required by GAAP, on December 31, 2017, AES Indiana remeasured their deferred income tax assets and liabilities using the new tax rate. The impact of the reduction of the income tax rate on deferred income taxes was utilized in the 2018 Base Rate Order to reduce jurisdictional retail rates. Accordingly, AES Indiana has a net regulatory deferred income tax liability of $74.8 million and $88.7 million as of December 31, 2023 and 2022, respectively.
3. PROPERTY, PLANT AND EQUIPMENT
The original cost of property, plant and equipment segregated by functional classifications follows:
As of December 31,
2023 2022
(In Thousands)
Production $ 3,942,052 $ 4,164,416
Transmission 487,527 461,245
Distribution 2,304,526 2,045,579
General plant 348,338 311,074
Total property, plant and equipment $ 7,082,443 $ 6,982,314
As of December 31, 2023 and 2022, AES Indiana had $259.9 million and $287.5 million, respectively, of net property, plant and equipment associated with the Petersburg Unit 1 and Unit 2 retirements recorded as long-term regulatory assets (for further discussion, see Note 2, “Regulatory Matters - IRP Filings and Replacement Generation”).
Substantially all of AES Indiana’s property is subject to a $2,153.8 million direct first mortgage lien, as of December 31, 2023, securing AES Indiana’s first mortgage bonds. Total non-contractually or legally required accrued removal costs of utility plant in service at December 31, 2023 and 2022 were $680.9 million and $694.0 million, respectively; and total contractually or legally required removal costs of property, plant and equipment at December 31, 2023 and 2022 were $249.9 million and $218.7 million, respectively. Please see “ARO” below for further information.
ARO
ASC 410 “Asset Retirement and Environmental Obligations” addresses financial accounting and reporting for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal operation. A legal obligation for purposes of ASC 410 is an obligation that a party is required to settle as a result of an existing law, statute, ordinance, written or oral contract or the doctrine of promissory estoppel.
AES Indiana’s ARO relates primarily to environmental issues involving asbestos-containing materials, ash ponds, landfills and miscellaneous contaminants associated with its generating plants, transmission system and distribution system. The following is a roll forward of the ARO legal liability year end balances:
2023 2022
(In Thousands)
Balance as of January 1 $ 218,729 $ 189,509
Liabilities incurred 17,080 1,159
Liabilities settled (11,902) (24,699)
Revisions to cash flow and timing estimates 12,921 44,679
Accretion expense 13,102 8,081
Balance as of December 31 $ 249,930 $ 218,729
ARO liabilities incurred in 2023 and 2022 primarily relate to FGD residual water disposal and AES Indiana's solar projects. AES Indiana recorded revisions to its ARO liabilities in 2023 and 2022 primarily to reflect revisions to cash flow estimates and timing due to increases to estimated ash pond closure costs and changes to expected landfill closure dates. As of December 31, 2023 and 2022, AES Indiana did not have any assets that are legally restricted for settling its ARO liability.
4. FAIR VALUE
The fair value of current financial assets and liabilities approximate their reported carrying amounts. The estimated fair values of AES Indiana’s assets and liabilities have been determined using available market information. Because these amounts are estimates and based on hypothetical transactions to sell assets or transfer liabilities, the use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.
Fair Value Hierarchy and Valuation Techniques
ASC 820 defines and establishes a framework for measuring fair value and expands disclosures about fair value measurements for financial assets and liabilities that are adjusted to fair value on a recurring basis and/or financial assets and liabilities that are measured at fair value on a nonrecurring basis, which have been adjusted to fair value during the period. In accordance with ASC 820, AES Indiana has categorized its financial assets and liabilities that are adjusted to fair value, based on the priority of the inputs to the valuation technique, following the three-level fair value hierarchy prescribed by ASC 820 as follows:
Level 1 - unadjusted quoted prices for identical assets or liabilities in an active market;
Level 2 - inputs from quoted prices in markets where trading occurs infrequently or quoted prices of instruments with similar attributes in active markets; and
Level 3 - unobservable inputs reflecting management’s own assumptions about the inputs used in pricing the asset or liability.
Whenever possible, quoted prices in active markets are used to determine the fair value of AES Indiana’s financial instruments. AES Indiana’s financial instruments are not held for trading or other speculative purposes. The estimated fair value of financial instruments has been determined by using available market information and appropriate valuation methodologies. However, considerable judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that AES Indiana could realize in a current market exchange. The use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.
Financial Assets
FTRs
In connection with AES Indiana’s participation in MISO, in the second quarter of each year AES Indiana is granted financial instruments that can be converted into cash or FTRs based on AES Indiana’s forecasted peak load for the period. FTRs are used in the MISO market to hedge AES Indiana’s exposure to congestion charges, which result from constraints on the transmission system. AES Indiana’s FTRs are valued at the cleared auction prices for FTRs in MISO’s annual auction. Because of the infrequent nature of this valuation, the fair value assigned to the FTRs is considered a Level 3 input under the fair value hierarchy required by ASC 820. An offsetting regulatory liability has been recorded as these revenue or costs will be flowed through to customers through the FAC. As such, there is no impact on AES Indiana’s Consolidated Statements of Operations.
Forward Power Contracts
As of December 31, 2023 and 2022, all outstanding forward power contracts had settled and there was no notional amount outstanding. All changes in the market value of the forward power contracts were recorded in the Consolidated Statements of Operations in the period in which the change occurred. See also Note 5, "Derivative Instruments and Hedging Activities - Derivatives Not Designated as Hedge" for further information.
Recurring Fair Value Measurements
The fair value of assets at December 31, 2023 and 2022 measured on a recurring basis and the respective category within the fair value hierarchy for AES Indiana was determined as follows:
Fair Value as of December 31, 2023 Fair Value as of December 31, 2022
Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
(In Thousands)
Financial assets:
FTRs $ - $ - $ 1,388 $ 1,388 $ - $ - $ 7,545 $ 7,545
Total financial assets measured at fair value $ - $ - $ 1,388 $ 1,388 $ - $ - $ 7,545 $ 7,545
The following table sets forth a roll forward of financial instruments, measured at fair value on a recurring basis, classified as Level 3 in the fair value hierarchy (note, amounts in this table indicate carrying values, which approximate fair values):
Reconciliation of Financial Instruments Classified as Level 3
(In Thousands)
Balance at January 1, 2022 $ 1,235
Issuances 15,338
Settlements (9,028)
Balance at December 31, 2022 7,545
Issuances 3,624
Settlements (9,781)
Balance at December 31, 2023 $ 1,388
Financial Instruments not Measured at Fair Value in the Consolidated Balance Sheets
Debt
The fair value of AES Indiana’s outstanding fixed-rate debt has been determined on the basis of the quoted market prices of the specific securities issued and outstanding. In certain circumstances, the market for such securities was inactive and therefore the valuation was adjusted to consider changes in market spreads for similar securities. Accordingly, the purpose of this disclosure is not to approximate the value on the basis of how the debt might be refinanced.
The following table shows the face value and the fair value of fixed-rate and variable-rate indebtedness (Level 2) for the periods ending:
December 31, 2023 December 31, 2022
Face Value Fair Value Face Value Fair Value
(In Thousands)
Fixed-rate $ 2,153,800 $ 2,020,997 $ 2,153,800 $ 1,959,233
Variable-rate 455,000 455,000 - -
Total indebtedness $ 2,608,800 $ 2,475,997 $ 2,153,800 $ 1,959,233
The difference between the face value and the carrying value of this indebtedness represents the following:
•unamortized deferred financing costs of $20.2 million and $20.4 million at December 31, 2023 and 2022, respectively; and
•unamortized discounts of $6.4 million and $6.7 million at December 31, 2023 and 2022, respectively.
5. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
AES Indiana uses derivatives principally to manage the risk of price changes for purchased power. The derivatives that AES Indiana uses to economically hedge this risk is governed by our risk management policies for forward and futures contracts. AES Indiana's net positions are continually assessed within its structured hedging programs to determine whether new or offsetting transactions are required. AES Indiana monitors and values derivative positions monthly as part of its risk management processes. AES Indiana uses published sources for pricing, when possible, to mark positions to market. All of AES Indiana's derivative instruments are used for risk management purposes and are designated as cash flow hedges if they qualify under ASC 815 for accounting purposes.
At December 31, 2023, AES Indiana's outstanding derivative instruments were as follows:
Commodity Accounting Treatment (a)
Unit Notional
(in thousands) Sales
(in thousands) Net Notional
(in thousands)
FTRs Not Designated MWh 3,919 - 3,919
(a) Refers to whether the derivative instruments have been designated as a cash flow hedge.
Derivatives Not Designated as Hedge
AES Indiana's FTRs and forward power contracts do not qualify for hedge accounting or the normal purchases and sales exceptions under ASC 815. Accordingly, FTRs are recorded at fair value using the income approach when acquired and subsequently amortized over the annual period as they are used. The forward power contracts are recorded at fair value using the market approach with changes in the fair value charged or credited to the Consolidated Statements of Operations in the period in which the change occurred. This is commonly referred to as "MTM accounting." Realized gains and losses on the forward power contracts are included in future FAC filings, therefore any realized and unrealized gains and losses are deferred as regulatory liabilities or regulatory assets. There were net realized gains of $0.0 million and $1.3 million related to forward power contracts during the years ended December 31, 2023 and 2022, respectively, related to the forward power contracts that were deferred and included with deferred fuel costs in "Regulatory assets, current" on the accompanying Consolidated Balance Sheets.
Certain qualifying derivative instruments have been designated as normal purchases or normal sales contracts, as provided under GAAP. Derivative contracts that have been designated as normal purchases or normal sales under GAAP are not subject to hedge or MTM accounting and are recognized in the Consolidated Statements of Operations on an accrual basis.
When applicable, AES Indiana has elected not to offset derivative assets and liabilities and not to offset net derivative positions against the right to reclaim cash collateral pledged (an asset) or the obligation to return cash collateral received (a liability) under derivative agreements. As of December 31, 2023 and 2022, AES Indiana did not have any offsetting positions.
The following table summarizes the fair value, balance sheet classification and hedging designation of AES Indiana's derivative instruments (in thousands):
December 31,
Commodity Hedging Designation Balance sheet classification 2023 2022
FTRs Not a Cash Flow Hedge Prepayments and other current assets $ 1,388 $ 7,545
6. DEBT
The following table presents AES Indiana’s long-term debt:
December 31,
Series Due 2023 2022
(In Thousands)
AES Indiana first mortgage bonds:
3.125% (1)
December 2024 $ 40,000 $ 40,000
0.65% (1)
August 2025 40,000 40,000
0.75% (2)
April 2026 30,000 30,000
0.95% (2)
April 2026 60,000 60,000
1.40% (1)
August 2029 55,000 55,000
5.650% December 2032 350,000 350,000
6.60% January 2034 100,000 100,000
6.05% October 2036 158,800 158,800
6.60% June 2037 165,000 165,000
4.875% November 2041 140,000 140,000
4.65% June 2043 170,000 170,000
4.50% June 2044 130,000 130,000
4.70% September 2045 260,000 260,000
4.05% May 2046 350,000 350,000
4.875% November 2048 105,000 105,000
Unamortized discount - net (6,449) (6,651)
Deferred financing costs (19,058) (20,362)
Total AES Indiana first mortgage bonds 2,128,293 2,126,787
Total consolidated AES Indiana long-term debt 2,128,293 2,126,787
Less: current portion of long-term debt 40,000 -
Net consolidated AES Indiana long-term debt $ 2,088,293 $ 2,126,787
(1)First mortgage bonds issued to the Indiana Finance Authority, to secure the loan of proceeds from tax-exempt bonds issued by the Indiana Finance Authority.
(2)First mortgage bonds issued to the Indiana Finance Authority, to secure the loan of proceeds from tax-exempt bonds issued by the Indiana Finance Authority. The notes have a final maturity date of December 31, 2038, but are subject to a mandatory put in April 2026.
Line of Credit
AES Indiana entered into a second amendment and restatement of its $350 million revolving Credit Agreement on December 22, 2022 with a syndication of bank lenders. This Credit Agreement is an unsecured committed line of credit to be used: (i) to finance capital expenditures; (ii) to refinance certain existing indebtedness, (iii) to support working capital; and (iv) for general corporate purposes. This agreement matures on December 22, 2027, and bears interest at variable rates as described in the Credit Agreement. It includes an uncommitted $150 million accordion feature to provide AES Indiana with an option to request an increase in the size of the facility at any time prior to December 22, 2026, subject to approval by the lenders. The Credit Agreement also includes two one-year extension options, allowing AES Indiana to extend the maturity date subject to approval by the lenders. As of December 31, 2023 and 2022, AES Indiana had $155.0 million and $0.0 million in outstanding borrowings on the committed Credit Agreement, respectively.
Debt Maturities
Maturities on long-term indebtedness subsequent to December 31, 2023 are as follows:
Year Amount
(In Thousands)
2024 $ 40,000
2025 40,000
2026 90,000
2027 -
2028 -
Thereafter 1,983,800
2,153,800
Unamortized discounts (6,449)
Deferred financing costs, net (19,058)
Total long-term debt $ 2,128,293
Significant Transactions
AES Indiana Term Loans
In November 2023, AES Indiana entered into an unsecured$300 million 364-day term loan agreement ("$300 million Term Loan Agreement"). The $300 million Term Loan Agreement was fully drawn at closing with the proceeds being used for general corporate purposes. This agreement matures on November 19, 2024, and bears interest at variable rates as described in the $300 million Term Loan Agreement. The $300 million Term Loan Agreement contains customary representations, warranties and covenants, including a leverage covenant consistent with the leverage covenant contained in AES Indiana's Credit Agreement. AES Indiana has classified this $300 million Term Loan Agreement as short-term indebtedness as it matures November 2024. Although current liquid funds are not sufficient to repay the amount due at maturity, management plans to refinance this $300 million Term Loan Agreement with new long-term debt.
In June 2022, AES Indiana entered into an unsecured $200 million 364-day term loan agreement ("$200 million Term Loan Agreement"). The $200 million Term Loan Agreement was fully drawn at closing with the proceeds being used for general corporate purposes. This agreement was set to mature on June 22, 2023, but was fully repaid in November 2022.
AES Indiana First Mortgage Bonds and Recent Indiana Finance Authority Bond Issuances
In November 2022, AES Indiana issued $350 million aggregate principal amount of first mortgage bonds, 5.65% Series, due December 2032, pursuant to Rule 144A and Regulation S under the Securities Act. Net proceeds from this offering were approximately $345.6 million, after deducting the initial purchasers’ discounts and fees and expenses for the offering. The net proceeds from this offering were used to repay amounts due under the Credit Agreement and the $200 million Term Loan Agreement, and for general corporate purposes.
In July 2021, the Indiana Finance Authority issued at the request of AES Indiana an aggregate principal amount of $95 million of Environmental Facilities Refunding Revenue Bonds, Series 2021A&B. AES Indiana issued $95 million aggregate principal amount of first mortgage bonds to the Indiana Finance Authority in two series: $55 million Series 2021A bonds at an interest rate of 1.40% due August 1, 2029 and $40 million Series 2021B notes at an interest rate of 0.65% due August 1, 2025 to secure the loan of proceeds from these bonds issued by the Indiana Finance Authority. Proceeds of the bond offering were used to refund $95 million of Indiana Finance Authority Environmental Facilities Refunding Revenue Bonds Series 2011A&B at a redemption price of 100% of par.
Restrictions on Issuance of Debt
All of AES Indiana’s long-term borrowings must first be approved by the IURC and the aggregate amount of AES Indiana’s short-term indebtedness must be approved by the FERC. AES Indiana has approval from FERC to borrow up to $750 million of short-term indebtedness outstanding at any time through July 26, 2024. In November 2021, AES Indiana received an order from the IURC granting AES Indiana authority through December 31, 2024 to, among other things, issue up to $740 million in aggregate principal amount of long-term debt, of which $390 million remains available as of December 31, 2023. This order also grants AES Indiana authority to have up to $750 million of long-term credit agreements and liquidity facilities outstanding at any one time, of which $100.0 million remains available under the order as of December 31, 2023. As an alternative to the sale of all or a portion of $65 million in principal of the long-term debt mentioned above, we have authority to issue up to $65 million of new preferred stock, all of which authority remains available under the order as of December 31, 2023. AES Indiana also has restrictions on the amount of new debt that may be issued due to contractual obligations of AES and by financial covenant restrictions under our existing debt obligations. Under such restrictions, AES Indiana is generally allowed to fully draw the amounts available on its Credit Agreement, refinance existing debt and issue new debt approved by the IURC and issue certain other indebtedness. On September 29, 2023, AES Indiana filed a petition for approval of a financing program for the approximately three-year period ending December 31, 2026. The OUCC filed testimony on December 1, 2023 with certain recommended parameters for future debt issuances that AES Indiana accepted. A hearing was held January 10, 2024 and an agreed proposed order between AES Indiana and the OUCC was submitted on that date. AES Indiana awaits an IURC order in the matter and it remains pending.
The mortgage and deed of trust of AES Indiana, together with the supplemental indentures thereto, secure the first mortgage bonds issued by AES Indiana. Pursuant to the terms of the mortgage, substantially all property owned by AES Indiana is subject to a first mortgage lien securing indebtedness of $2,153.8 million as of December 31, 2023. The AES Indiana first mortgage bonds require net income as calculated thereunder be at least two and one-half times the annual interest requirements before additional bonds can be authenticated on the basis of property additions. AES Indiana was in compliance with such requirements as of December 31, 2023.
Credit Ratings
AES Indiana’s ability to borrow money or to refinance existing indebtedness and the interest rates at which AES Indiana can borrow money or refinance existing indebtedness are affected by AES Indiana’s credit ratings. In addition, the applicable interest rates on AES Indiana’s Credit Agreement are dependent upon the credit ratings of AES Indiana. Downgrades in the credit ratings of AES and/or IPALCO could result in AES Indiana’s credit ratings being downgraded.
7. INCOME TAXES
AES Indiana follows a policy of comprehensive interperiod income tax allocation. Investment tax credits related to utility property have been deferred and are being amortized over the estimated useful lives of the related property.
AES files federal and state income tax returns which consolidate IPALCO and AES Indiana. Under a tax sharing agreement with IPALCO, AES Indiana is responsible for the income taxes associated with its own taxable income and records the provision for income taxes as if AES Indiana filed separate income tax returns. AES Indiana is no longer subject to U.S. or state income tax examinations for tax years through 2016, but is open for all subsequent periods. AES Indiana made tax sharing payments to IPALCO of $0.0 million, $39.5 million and $40.8 million in 2023, 2022 and 2021, respectively.
Income Tax Provision
Federal and state income taxes charged to income are as follows:
2023 2022 2021
(In Thousands)
Components of income tax expense:
Current income taxes:
Federal $ 1,816 $ 31,286 $ 36,353
State 268 8,185 10,325
Total current income taxes 2,084 39,471 46,678
Deferred income taxes:
Federal 17,631 (6,822) (7,283)
State 5,951 238 (90)
Total deferred income taxes 23,582 (6,584) (7,373)
Total income tax expense $ 25,666 $ 32,887 $ 39,305
Effective and Statutory Rate Reconciliation
The provision for income taxes (including net investment tax credit adjustments) is different than the amount computed by applying the statutory tax rate to pretax income. The reasons for the difference, stated as a percentage of pretax income, are as follows:
2023 2022 2021
Federal statutory tax rate 21.0 % 21.0 % 21.0 %
State income tax, net of federal tax benefit 3.9 % 3.9 % 4.0 %
Depreciation flow through and amortization (8.0) % (5.7) % (4.9) %
AFUDC - equity (0.2) % 0.7 % 0.3 %
Noncontrolling interests in subsidiaries 5.6 % - % - %
Other - net (0.1) % 0.3 % 0.3 %
Effective tax rate 22.2 % 20.2 % 20.7 %
Deferred Income Taxes
The significant items comprising AES Indiana’s net accumulated deferred tax liability recognized on the audited Consolidated Balance Sheets as of December 31, 2023 and 2022 are as follows:
2023 2022
(In Thousands)
Deferred tax liabilities:
Relating to utility property, net $ 409,675 $ 341,473
Regulatory assets recoverable through future rates 108,823 123,669
Other 7,975 22,717
Total deferred tax liabilities 526,473 487,859
Deferred tax assets:
Investment tax credit 5 6
Regulatory liabilities including ARO 168,619 167,726
Investments in tax partnerships 2,483 -
Operating loss carryforwards 9,230 -
Other 3,579 15,020
Total deferred tax assets 183,916 182,752
Deferred income tax liability - net $ 342,557 $ 305,107
Uncertain Tax Positions
The following is a reconciliation of the beginning and ending amounts of unrecognized tax benefits for the years ended December 31, 2023, 2022 and 2021:
2023 2022 2021
(In Thousands)
Unrecognized tax benefits at January 1 $ - $ - $ 7,368
Gross decreases - prior period tax positions - - (7,368)
Unrecognized tax benefits at December 31 $ - $ - $ -
The prior period unrecognized tax benefits represent tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. As a result of the resolution of federal and state audits in 2021, AES Indiana reviewed its uncertain positions and determined that they are more likely than not to be sustained upon examination by taxing authorities. Consequently, the uncertain tax positions were reversed; because of the impact of deferred tax accounting the reversal did not affect the annual effective tax rate but were reclassified to plant related deferred tax balances.
Tax years subsequent to 2016 remain open to examination by taxing authorities. While it is often difficult
to predict the final outcome or the timing of resolution of any particular uncertain tax position, AES Indiana believes
unrecognized tax benefits of $0 at December 31, 2023 and 2022, respectively, is the appropriate accrual for our uncertain tax positions. However, audit outcomes and the timing of audit settlements and future events that would impact AES Indiana's previously recorded unrecognized tax benefits are subject to significant uncertainty. It is possible that the ultimate outcome of future examinations may exceed AES Indiana's provision for current unrecognized tax benefits.
Tax-related interest expense and income is reported as part of the provision for federal and state income taxes. Penalties, if incurred, would also be recognized as a component of tax expense. There are no interest or penalties applicable to the periods contained in this report.
8. BENEFIT PLANS
Defined Contribution Plans
All of AES Indiana’s employees are covered by one of two defined contribution plans, the Thrift Plan or the RSP:
The Thrift Plan
Approximately 77% of AES Indiana’s active employees are covered by the Thrift Plan, a qualified defined contribution plan. All union new hires are covered under the Thrift Plan. Participants elect to make contributions to the Thrift Plan based on a percentage of their base compensation. Each participant’s contribution is matched up to certain thresholds of base compensation. The IBEW clerical-technical union new hires receive an annual lump sum company contribution into the Thrift Plan in addition to the company match. Employer contributions to the Thrift Plan were $3.7 million, $3.6 million and $3.4 million for 2023, 2022 and 2021, respectively.
The RSP
Approximately 23% of AES Indiana’s active employees are covered by the RSP, a qualified defined contribution plan containing both match and nondiscretionary components. All non-union new hires are covered under the RSP. Participants elect to make contributions to the RSP based on a percentage of their eligible compensation. Each participant’s contribution is matched in amounts up to, but not exceeding, 5% of the participant’s eligible compensation. Starting in 2018, the RSP also includes a 4% nondiscretionary contribution based as a percentage of each participant's eligible compensation. Employer contributions (by AES Indiana) relating to the RSP were $2.5 million, $2.1 million and $1.9 million for 2023, 2022 and 2021, respectively.
Defined Benefit Plans
Approximately 65% of AES Indiana’s active employees are covered by the qualified Defined Benefit Pension Plan; while approximately 12% of active employees are IBEW clerical-technical unit employees who are only eligible for the Thrift Plan. The remaining 23% of active employees are covered by the RSP. All non-union new hires are covered under the RSP, while IBEW physical unit union new hires are covered under the Defined Benefit Pension Plan and Thrift Plan. The IBEW clerical-technical unit new hires are no longer covered under the Defined Benefit Pension Plan but do receive an annual lump sum company contribution into the Thrift Plan, in addition to the company match. The Defined Benefit Pension Plan is noncontributory and is funded by AES Indiana through a trust. Benefits for non-union participants in the Defined Benefit Pension Plan are based on salary, years of service and accrued benefits at April 1, 2015. Benefits for eligible union participants are based on each individual employee's pension band and years of service as opposed to their compensation. Pension bands are based primarily on job duties and responsibilities.
Additionally, a small group of former officers and their surviving spouses are covered under a funded non-qualified Supplemental Retirement Plan. The total number of participants in the plan as of December 31, 2023 was 19. The plan is closed to new participants.
AES Indiana also provides postretirement health care benefits to certain active or retired employees and the spouses of certain active or retired employees. Approximately 123 active employees and 26 retirees (including spouses) were receiving such benefits or entitled to future benefits as of January 1, 2023. The plan is unfunded. These postretirement health care benefits and the related unfunded obligation of $3.0 million and $3.2 million at December 31, 2023 and 2022, respectively, were not material to the consolidated financial statements in the periods covered by this report.
The following table presents information relating to the Pension Plans:
Pension benefits
as of December 31,
2023 2022
(In Thousands)
Change in benefit obligation:
Projected benefit obligation at January 1 $ 577,530 $ 772,040
Service cost 5,189 8,949
Interest cost 29,818 18,099
Actuarial loss (gain) 9,681 (182,590)
Amendments (primarily increases in pension bands) 653 -
Settlements - (394)
Benefits paid (73,325) (38,575)
Projected benefit obligation at December 31 549,546 577,529
Change in plan assets:
Fair value of plan assets at January 1 611,125 820,684
Actual return/(loss) on plan assets 52,905 (171,002)
Employer contributions 114 412
Settlements - (394)
Benefits paid (73,325) (38,575)
Fair value of plan assets at December 31 590,819 611,125
Funded status $ 41,273 $ 33,596
Amounts recognized in the statement of financial position:
Non-current assets $ 41,273 $ 33,611
Non-current liabilities - (15)
Net amount recognized at end of year $ 41,273 $ 33,596
Sources of change in regulatory assets(1):
Prior service cost arising during period $ 653 $ -
Net (gain)/loss arising during period (10,117) 24,069
Amortization of prior service cost (2,172) (2,589)
Amortization of loss (6,145) (2,622)
Total recognized in regulatory assets $ (17,781) $ 18,858
Amounts included in regulatory assets:
Net loss $ 115,297 $ 131,559
Prior service cost 10,136 11,655
Total amounts included in regulatory assets $ 125,433 $ 143,214
(1)Amounts that would otherwise be charged/credited to Accumulated Other Comprehensive Income or Loss upon application of ASC 715, “Compensation - Retirement Benefits,” are recorded as a regulatory asset or liability because AES Indiana has historically recovered and currently recovers pension and other postretirement benefit expenses in rates. These are unrecognized amounts not yet recognized as components of net periodic benefit costs.
Significant Loss / (Gain) Related to Changes in the Benefit Obligation for the Period
As shown in the table above, an actuarial loss of $9.7 million and an actuarial gain of $182.6 million for the year ended December 31, 2023 and December 31, 2022, respectively, were recognized in the benefit obligation, primarily due to changes in the discount rate.
Pension Benefits and Expense
Reported expenses relevant to the Defined Benefit Pension Plan are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience, including the performance of plan assets and actual benefits paid out in future years. Pension costs associated with the Defined Benefit Pension Plan are
impacted by the level of contributions made to the plan, income on plan assets, the adoption of new mortality tables, and employee demographics, including age, job responsibilities, salary and employment periods. Changes made to the provisions of the Defined Benefit Pension Plan may impact current and future pension costs. Pension costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the corporate bond discount rates, as well as, the adoption of a new mortality table used in determining the projected benefit obligation and pension costs.
The 2023 net actuarial gain of $10.1 million recognized in regulatory assets is comprised of two parts: (1) a $9.7 million pension liability actuarial loss primarily due to a decrease in the discount rate used to value pension liabilities; and (2) a $19.8 million pension asset actuarial gain primarily due to higher than expected return on assets. The unrecognized net loss of $115.3 million in the Pension Plans has accumulated over time primarily due to the long-term declining trend in corporate bond rates and the adoption of new mortality tables which have historically increased the expected benefit obligation due to the longer expected lives of plan participants. In 2023, the accumulated net loss decrease was primarily attributed to an annuity buyout involving a small portion of retirees, which was partially offset by factors such as a reduced discount rate utilized in valuing pension liabilities, along with the amortization of accumulated losses incurred during the year. The unrecognized net loss, to the extent that it exceeds 10% of the greater of the benefit obligation or the assets, will be amortized and included as a component of net periodic benefit cost in future years. The amortization period is approximately 11.66 years based on estimated demographic data as of December 31, 2023. The projected benefit obligation of $549.5 million less the fair value of assets of $590.8 million results in an overfunded status of $41.3 million at December 31, 2023.
Pension benefits for
years ended December 31,
2023 2022 2021
(In Thousands)
Components of net periodic benefit cost / (credit):
Service cost $ 5,189 $ 8,949 $ 9,339
Interest cost 29,818 18,099 15,660
Expected return on plan assets (33,107) (35,656) (41,815)
Amortization of prior service cost 2,172 2,589 2,944
Amortization of actuarial loss 6,145 2,424 5,529
Amortization of settlement loss - 199 -
Net periodic benefit cost / (credit) 10,217 (3,396) (8,343)
Less: amounts capitalized 1,689 (316) (771)
Amount charged to expense $ 8,528 $ (3,080) $ (7,572)
Rates relevant to each year’s expense calculations:
Discount rate - defined benefit pension plan 5.41 % 2.83 % 2.46 %
Discount rate - supplemental retirement plan 5.32 % 2.62 % 2.31 %
Expected return on defined benefit pension plan assets 5.60 % 4.45 % 5.05 %
Expected return on supplemental retirement plan assets 6.45 % 5.50 % 3.60 %
Pension expense / (income) for the following year is determined as of the December 31 measurement date based on the fair value of the Pension Plans’ assets, the expected long-term rate of return on plan assets, a mortality table assumption that reflects the life expectancy of plan participants, and a discount rate used to determine the projected benefit obligation. For 2023, pension expense / (income) was determined using an assumed long-term rate of return on plan assets of 5.60% for the Defined Benefit Pension Plan and 6.45% for the Supplemental Retirement Plan. As of the December 31, 2023 measurement date, AES Indiana decreased the discount rate from 5.41% to 5.15% for the Defined Benefit Pension Plan and increased the discount rate from 5.32% to 5.66% for the Supplemental Retirement Plan. The discount rate assumptions affect the pension expense / (income) determined for 2024. In addition, AES Indiana decreased the expected long-term rate of return on plan assets from 5.60% to 5.20% for the Defined Benefit Pension Plan and from 6.45% to 6.35% for the Supplemental Retirement Plan for 2024. The expected long-term rate of return assumptions affect the pension expense / (income) determined for 2024. The effect on 2024 total pension expense / (income) of a 25 basis point increase and decrease in the assumed discount rate is $(0.8) million and $0.8 million, respectively.
In determining the discount rate to use for valuing liabilities, we use the market yield curve on high-quality fixed income investments as of December 31, 2023. We project the expected benefit payments under the plan based on participant data and based on certain assumptions concerning mortality, retirement rates, termination rates, etc. The expected benefit payments for each year are discounted back to the measurement date using the appropriate spot rate for each half-year from the yield curve, thereby obtaining a present value of all expected future benefit payments using the yield curve. Finally, an equivalent single discount rate is determined which produces a present value equal to the present value determined using the full yield curve.
Pension Plan Assets and Fair Value Measurements
Pension plan assets consist of investments in cash and cash equivalents, government debt securities, and mutual funds (equity and debt). Differences between actual portfolio returns and expected returns may result in increased or reduced pension costs in future periods. Pension costs for 2024 are determined as of the plans' measurement date of December 31, 2023. Pension costs are determined for the following year based on the market value of pension plan assets, expected employer contributions, a discount rate used to determine the projected benefit obligation and the expected long-term rate of return on plan assets.
Fair value is defined under ASC 820 as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (i.e., an exit price). The fair value hierarchy prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets and liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).
Purchases and sales of securities are recorded on a trade-date basis. Interest income is recorded as earned. Dividends are recorded on the ex-dividend date. Net appreciation includes the Pension Plans’ gains and losses on investments bought and sold, as well as held, during the year.
A description of the valuation methodologies used for each major class of assets and liabilities measured at fair value follows:
•The non-qualified Supplemental Retirement Plan investments have quoted market prices and are categorized as Level 1 in the fair value hierarchy.
•The qualified Defined Benefit Pension Plan investments in common collective trusts are valued based on the daily net asset value and are categorized as Level 2 in the fair value hierarchy, except for cash and cash equivalents which are categorized as level 1.
The primary objective of the Pension Plans’ is to provide a source of retirement income for its participants and beneficiaries, while the primary financial objective is to improve the funded status of the Pension Plans. A secondary financial objective is, where possible, to minimize pension expense volatility. The objective is based on a long-term investment horizon, so that interim fluctuations should be viewed with appropriate perspective. There can be no assurance that these objectives will be met.
In establishing AES Indiana’s expected long-term rate of return assumption, we utilize a methodology developed by the plan’s investment consultant who maintains a capital market assumption model that takes into consideration risk, return and correlation assumptions across asset classes. A combination of quantitative analysis of historical data and qualitative judgment is used to capture trends, structural changes and potential scenarios not reflected in historical data.
The result of the analyses is a series of inputs that produce a picture of how the plan consultant believes portfolios are likely to behave through time. Capital market assumptions are intended to reflect the behavior of asset classes observed over several market cycles. Stress assumptions are also examined, since the characteristics of asset classes are constantly changing. A dynamic model is employed to manage the numerous assumptions required to estimate portfolio characteristics under different base currencies, time horizons and inflation expectations.
The Pension Plans’ consultant develops forward-looking, long-term capital market assumptions for risk, return and correlations for a variety of global asset classes, interest rates and inflation. These assumptions are created using a
combination of historical analysis, current market environment assessment and by applying the consultant’s own judgment. The consultant then determines an equilibrium long-term rate of return. AES Indiana then takes into consideration the investment manager/consultant expenses, as well as any other expenses expected to be paid out of the Pension Plans’ trust. Finally, AES Indiana has the Pension Plans’ actuary perform a tolerance test of the consultant’s equilibrium expected long-term rate of return. AES Indiana uses an expected long-term rate of return compatible with the actuary’s tolerance level.
The following table summarizes AES Indiana’s target pension plan allocation for 2023:
Asset Category: Target Allocations
Equity Securities 13.5%
Debt Securities 86.5%
Fair Value Measurements at
December 31, 2023
(in thousands)
Quoted Prices in Active Markets for Identical Assets Significant Observable Inputs
Asset Category Total (Level 1) (Level 2) %
Common collective trusts:
Equities (a)
$ 82,652 $ 2,267 $ 80,385 14 %
Debt securities (b)
387,979 1,168 386,811 66 %
Government debt securities (c)
117,397 178 117,219 20 %
Total common collective trusts 588,028 3,613 584,415 100 %
Cash and cash equivalents (d)
2,791 2,791 - - %
Total pension plan assets $ 590,819 $ 6,404 $ 584,415 100 %
(a) This category represents investments that invest in equity securities of U.S. companies of any market capitalization and other investments (i.e.: futures, swaps, currency forwards) of foreign, emerging markets and seeks to provide long-term total return, which includes capital appreciation and income. The funds are valued using the net asset value method.
(b) This category represents investments that invest in high quality issues within the U.S. corporate bond markets and global high yield bonds and emerging markets debt denominated in local currency. The funds seek to provide current income and long-term capital preservation along with access to higher yielding, relatively liquid fixed income securities. The funds are valued using the net asset value method.
(c) This category represents investments that invest in U.S. treasury strips, U.S. government agency obligations, and U.S. treasury obligations. The funds seek investment returns over the long term and are valued using the net asset value method.
(d) This category represents an investment that seeks to maximize current income on cash reserves to the extent consistent with principal preservation and maintenance of liquidity from a portfolio of obligations of the U.S. Government, its agencies or municipalities, and related money market instruments. Principal preservation is a primary objective. The fund is valued at cost.
Fair Value Measurements at
December 31, 2022
(in thousands)
Quoted Prices in Active Markets for Identical Assets Significant Observable Inputs
Asset Category Total (Level 1) (Level 2) %
Common collective trusts:
Equities (a)
$ 85,341 $ 2,017 $ 83,324 14 %
Debt securities (b)
400,291 1,254 399,037 66 %
Government debt securities (c)
122,704 420 122,284 20 %
Total common collective trusts 608,336 3,691 604,645 100 %
Cash and cash equivalents (d)
2,789 2,789 - - %
Total pension plan assets $ 611,125 $ 6,480 $ 604,645 100 %
(a) This category represents investments that invest in equity securities of U.S. companies of any market capitalization and other investments (i.e.: futures, swaps, currency forwards) of foreign, emerging markets and seeks to provide long-term total return, which includes capital appreciation and income. The funds are valued using the net asset value method.
(b) This category represents investments that invest in high quality issues within the U.S. corporate bond markets and global high yield bonds and emerging markets debt denominated in local currency. The funds seek to provide current income and long-term capital preservation along with access to higher yielding, relatively liquid fixed income securities. The funds are valued using the net asset value method.
(c) This category represents investments that invest in U.S. treasury strips, U.S. government agency obligations, and U.S. treasury obligations. The funds seek investment returns over the long term and are valued using the net asset value method.
(d) This category represents an investment that seeks to maximize current income on cash reserves to the extent consistent with principal preservation and maintenance of liquidity from a portfolio of obligations of the U.S. Government, its agencies or municipalities, and related money market instruments. Principal preservation is a primary objective. The fund is valued at cost.
Pension Funding
AES Indiana contributed $0.1 million, $0.4 million, and $0.0 million to the Pension Plans in 2023, 2022 and 2021, respectively. Funding for the qualified Defined Benefit Pension Plan is based upon actuarially determined contributions that take into account the amount deductible for income tax purposes and the minimum contribution required under ERISA, as amended by the Pension Protection Act of 2006, as well as targeted funding levels necessary to meet certain thresholds.
From an ERISA funding perspective, AES Indiana’s funded target liability percentage was estimated to be 98%. In general, AES Indiana must contribute the normal service cost earned by active participants during the plan year; however, this amount can be offset by any surplus or credit balance carried by the Pension Plan. The normal cost is expected to be approximately $6.3 million in 2024 (including $0.4 million for plan expenses), which is expected to be fully offset by the surplus amount. Each year thereafter, if the Pension Plans' underfunding increases to more than the present value of the remaining annual installments, the excess is separately amortized over a seven-year period. AES Indiana does not expect to make an employer contribution for the calendar year 2024. AES Indiana’s funding policy for the Pension Plans is to contribute annually no less than the minimum required by applicable law, and no more than the maximum amount that can be deducted for federal income tax purposes.
Benefit payments made from the Pension Plans for the years ended December 31, 2023, 2022 and 2021 were $73.3 million, $38.6 million and $63.2 million, respectively. Benefit payments, which reflect future service, are expected to be paid out of the Pension Plans as follows:
Year Pension Benefits
(In Thousands)
2024 $ 37,997
2025 38,794
2026 39,665
2027 40,085
2028 41,477
2029 through 2033 200,574
9. EQUITY AND CUMULATIVE PREFERRED STOCK
Cumulative Preferred Stock
On December 30, 2022 (the “Redemption Date”), AES Indiana redeemed all of its issued and outstanding preferred stock for $60.1 million. On the Redemption Date, the Preferred Stock of each series was redeemed with all applicable premiums, plus, in each case an amount equal to all accrued dividends payable with respect to such Preferred Stock to the Redemption Date. Dividends on the Preferred Stock ceased to accrue on the Redemption Date. Upon redemption, the Preferred Stock was no longer outstanding, and all rights of the holders thereof as shareholders of AES Indiana ceased to exist, except for the right to payment of the redemption price. AES Indiana recorded a charge of $0.3 million on the redemption for the difference between the carrying value and redemption value of the preferred shares.
Prior to the redemption, AES Indiana had five separate series of cumulative preferred stock. Holders of the preferred stock were entitled to receive dividends at rates per annum ranging from 4.0% to 5.65%. During the years ended December 31, 2023, 2022 and 2021, total preferred stock dividends declared were $0.0 million, $3.2 million, and $3.2 million, respectively. Holders of preferred stock were entitled to two votes per share for AES Indiana matters, and if four full quarterly dividends are in default on all shares of the preferred stock then outstanding, they were entitled to elect the smallest number of AES Indiana directors to constitute a majority of AES Indiana’s Board of Directors. Based on the preferred stockholders’ ability to elect a majority of AES Indiana’s Board of Directors in this circumstance, the redemption of the preferred shares was considered to be not solely within the control of the issuer and the preferred stock was considered temporary equity and presented in the mezzanine level of the audited consolidated balance sheets in accordance with the relevant accounting guidance for non-controlling interests and redeemable securities.
Paid in Capital and Capital Stock
On December 12, 2022 and December 13, 2021, respectively, AES Indiana received equity capital contributions of $253.0 million and $275.0 million from IPALCO. The proceeds are intended primarily for funding needs related to AES Indiana’s TDSIC and replacement generation projects.
All of the outstanding common stock of AES Indiana is owned by IPALCO. AES Indiana’s common stock is pledged under the 2024 IPALCO Notes and 2030 IPALCO Notes. There have been no changes in the capital stock of AES Indiana during the three years ended December 31, 2023.
Dividend Restrictions
AES Indiana’s mortgage and deed of trust and its amended articles of incorporation contain restrictions on AES Indiana’s ability to issue certain securities or pay cash dividends. So long as any of the several series of bonds of AES Indiana issued under its mortgage remains outstanding, and subject to certain exceptions, AES Indiana is restricted in the declaration and payment of dividends, or other distribution on shares of its capital stock of any class, or in the purchase or redemption of such shares, to the aggregate of its net income, as defined in the mortgage, after December 31, 1939. In addition, pursuant to AES Indiana’s articles, no dividends may be paid or
accrued, and no other distribution may be made on AES Indiana’s common stock unless dividends on all outstanding shares of AES Indiana preferred stock have been paid or declared and set apart for payment. As of December 31, 2023, and as of the filing of this report, AES Indiana was in compliance with these restrictions.
Additionally, all of AES Indiana's preferred stock was redeemed on December 30, 2022 (see "Cumulative Preferred Stock" above for further details).
AES Indiana is also restricted in its ability to pay dividends if it is in default under the terms of its Credit Agreement and $300 million Term Loan Agreement, which could happen if AES Indiana fails to comply with certain covenants. These covenants, among other things, require AES Indiana to maintain a ratio of total debt to total capitalization not in excess of 0.67 to 1. As of December 31, 2023, and as of the filing of this report, AES Indiana was in compliance with all covenants and no event of default existed.
During the years ended December 31, 2023, 2022 and 2021, AES Indiana declared dividends to its shareholder totaling $140.2 million, $127.2 million, and $155.7 million, respectively.
Equity Transactions with Noncontrolling Interests
The Hardy Hills Solar Project has been financed with a tax equity structure, in which a tax equity investor receives a portion of the economic attributes of the facility, including tax attributes, that vary over the life of the project. On December 1, 2023, the Class B Member and the Class A Member, entered into an Equity Capital Contribution Agreement, pursuant to which each member made certain capital contributions to Hardy Hills JV. The Class A member made total contributions of $79.3 million through December 31, 2023. A noncontrolling interest was recorded by AES Indiana at the amount of cash contributed by the Class A Member.
10. COMMITMENTS AND CONTINGENCIES
Contractual Obligations and Commercial Commitments
We enter into various contractual obligations and other commercial commitments that may affect the liquidity of our operations. At December 31, 2023, these include:
Payments due in:
Total Less Than 1 Year 1 - 3
Years 3 - 5
Years More Than
5 Years
(In Millions)
Purchase obligations:
Coal, gas, purchased power and
related transportation $ 933.5 $ 249.7 $ 267.3 $ 225.7 $ 190.8
Other $ 409.1 $ 355.0 $ 32.8 $ 20.2 $ 1.1
Purchase obligations:
Purchase commitments for coal, gas, purchased power and related transportation:
AES Indiana enters into long-term contracts for the purchase of coal, gas, purchased power and related transportation. In general, these contracts are subject to variable quantities or prices and are terminable only in limited circumstances.
Purchase orders and other contractual obligations:
At December 31, 2023, we had various other contractual obligations including contracts to purchase goods and services with various terms and expiration dates, as well as obligations under long-term construction contracts. Due to uncertainty regarding the timing and payment of future obligations to the Service Company, and our ability to terminate such obligations upon 90 days' notice, we have excluded such amounts in the contractual obligations table above. This table also does not include (i) regulatory liabilities (see Note 2, "Regulatory Matters"), (ii) derivatives (see Note 5, "Derivative Instruments and Hedging Activities"), (iii) taxes (see Note 7, "Income Taxes"), (iv) pension and other postretirement employee benefit liabilities (see Note 8, "Benefit Plans") and (v) contingencies
(see Note 10, "Commitments and Contingencies"). See the indicated notes to the Financial Statements for additional information on the items excluded.
Contingencies
Legal Matters
AES Indiana is involved in litigation arising in the normal course of business. AES Indiana accrues for litigation and claims when it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. While the ultimate outcome of outstanding litigation cannot be predicted with certainty, management believes that final outcomes will not have a material adverse effect on AES Indiana’s results of operations, financial condition and cash flows. Accruals for legal loss contingencies were not material as of December 31, 2023 and 2022.
Coal Ash Insurance Litigation
In August 2021, AES Indiana filed a civil action against various third-party insurance providers. The complaint seeks damages for breach of contract and a declaratory judgment declaring that such insurers must defend and indemnify AES Indiana under liability insurance policies issued between 1950 and the filing of the civil action against certain environmental liabilities arising from CCR at Harding Street, Petersburg and Eagle Valley. At this time, we cannot predict the outcome of this matter.
Environmental Matters
AES Indiana is subject to various federal, state, regional and local environmental protection and health and safety laws and regulations governing, among other things, the generation, storage, handling, use, disposal and transportation of regulated materials, including ash; the use and discharge of water used in generation boilers and for cooling purposes; the emission and discharge of hazardous and other materials, including GHGs, into the environment; climate change; and the health and safety of AES Indiana's employees. These laws and regulations often require a lengthy and complex process of obtaining and renewing permits and other governmental authorizations from federal, state and local agencies. Violation of these laws, regulations or permits can result in substantial fines, other sanctions, permit revocation and/or facility shutdowns. AES Indiana cannot assure that it has been or will be at all times in full compliance with such laws, regulations and permits. Accruals for environmental contingencies were not material as of December 31, 2023 and 2022.
NSR and other CAA NOVs
In October 2009, AES Indiana received a NOV and Finding of Violation from the EPA pursuant to the CAA Section 113(a). The NOV alleged violations of the CAA at AES Indiana’s three primarily coal-fired electric generating facilities at the time, dating back to 1986. The alleged violations primarily pertain to the PSD and non-attainment NSR requirements under the CAA. In addition, on October 1, 2015, AES Indiana received a NOV from the EPA pursuant to CAA Section 113(a) alleging violations of the CAA, the Indiana SIP, and the Title V operating permit related to alleged particulate matter and opacity violations at AES Indiana Petersburg Unit 3. Also, on February 5, 2016, the EPA issued a NOV pursuant to CAA Section 113(a) alleging violations of PSD, non-attainment NSR and other CAA regulations, the Indiana SIP, and the Title V operating permit at Petersburg Generating Station. On August 31, 2020, AES Indiana reached a settlement with the EPA, the DOJ and IDEM resolving the purported violations of the CAA with respect to the coal-fired generation units at AES Indiana's Petersburg location. The settlement agreement, in the form of a proposed judicial consent decree was approved and entered by the U.S. District Court for the Southern District of Indiana on March 23, 2021, and includes, among other items, the following requirements: annual caps on NOx and SO2 emissions and more stringent emissions limits than AES Indiana's prior Title V air permit; payment of civil penalties totaling $1.525 million (the payment of which was satisfied by AES Indiana in April 2021); a $5 million environmental mitigation project consisting of the construction and operation of a new, non-emitting source of generation at the site; expenditure of $0.325 million on a state-only environmentally beneficial project to preserve local, ecologically-significant lands; and retirement of Units 1 and 2 prior to July 1, 2023 (which has occurred). AES Indiana previously had a contingent liability recorded related to these NSR and other CAA NOV matters.
11. RELATED PARTY TRANSACTIONS
AES Indiana participates in a property insurance program in which AES Indiana buys insurance from AES Global Insurance Company, a wholly-owned subsidiary of AES. AES Indiana is not self-insured on property insurance, but does take a $5 million per occurrence deductible. Except for AES Indiana’s large substations, AES Indiana does not carry insurance on transmission and distribution assets, which are considered to be outside the scope of property insurance. AES and other AES subsidiaries, including AES Indiana, also participate in the AES global insurance program. AES Indiana pays premiums for a policy that is written and administered by a third-party insurance company. The premiums paid to this third-party administrator by the participants are paid to AES Global Insurance Company and all claims are paid from a trust fund funded by and owned by AES Global Insurance Company, but controlled by the third-party administrator. AES Indiana also has third-party insurance in which the premiums are paid directly to the third-party insurers. The cost to AES Indiana of coverage under the property insurance program with AES Global Insurance Company was approximately $11.7 million, $9.5 million, and $7.0 million in 2023, 2022 and 2021, respectively, and is recorded in “Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations. As of December 31, 2023 and 2022, AES Indiana had prepaid approximately $7.5 million and $3.4 million, respectively, for coverage under these plans, which is recorded in "Prepayments and other current assets" on the accompanying Consolidated Balance Sheets.
AES Indiana participates in an agreement with Health and Welfare Benefit Plans LLC, an affiliate of AES, to participate in a group benefits program, including but not limited to, health, dental, vision and life benefits. Health and Welfare Benefit Plans LLC administers the financial aspects of the group insurance program, receives all premium payments from the participating affiliates, and makes all vendor payments. The cost of coverage under this program was approximately $19.0 million, $25.2 million, and $23.7 million in 2023, 2022 and 2021, respectively, and is recorded in “Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations. AES Indiana had no prepaids for coverage under this plan as of December 31, 2023 and 2022, respectively.
AES files federal and state income tax returns which consolidate IPALCO and its subsidiaries, including AES Indiana. Under a tax sharing agreement with IPALCO, AES Indiana is responsible for the income taxes associated with its own taxable income and records the provision for income taxes using a separate return method. AES Indiana had a receivable balance under this agreement of $5.1 million and $6.7 million as of December 31, 2023 and 2022, respectively, which is recorded in “Taxes receivable” on the accompanying Consolidated Balance Sheets. See Note 7, "Income Taxes" for more information.
Long-term Compensation Plan
During 2023, 2022 and 2021, many of AES Indiana’s non-union employees received benefits under the AES Long-term Compensation Plan, a deferred compensation program. This type of plan is a common employee retention tool used in our industry. Benefits under this plan are granted in the form of performance units payable in cash and AES restricted stock units. Restricted stock units vest ratably over a three-year period. The performance units payable in cash vest at the end of the three-year performance period and are subject to certain AES performance criteria. Total deferred compensation expense recorded during 2023, 2022 and 2021 was $0.3 million, $0.2 million and $0.2 million, respectively, and was included in “Operating expenses - Operation and maintenance” on AES Indiana’s Consolidated Statements of Operations. The value of these benefits is being recognized over the 36 month vesting period and a portion is recorded as miscellaneous deferred credits with the remainder recorded as “Paid in capital” on AES Indiana’s Consolidated Balance Sheets in accordance with ASC 718 “Compensation - Stock Compensation.”
See also Note 8, “Benefit Plans” to the audited consolidated financial statements of AES Indiana for a description of benefits awarded to AES Indiana employees by AES under the RSP.
Service Company
Total costs incurred by the Service Company on behalf of AES Indiana were $73.6 million, $60.1 million and $58.2 million during 2023, 2022 and 2021, respectively. Total costs incurred by AES Indiana on behalf of the Service Company during 2023, 2022 and 2021 were $11.9 million, $10.0 million and $10.4 million, respectively, which are included as a reduction to charges from the Service Company. These costs were included in “Operating expenses -
Operation and maintenance” on AES Indiana’s Consolidated Statements of Operations. AES Indiana had a payable balance with the Service company of $25.6 million and $2.1 million as of December 31, 2023 and 2022, respectively, which is recorded in "Accounts payable" on the accompanying Consolidated Balance Sheets.
Other
During the year ended December 31, 2021, AES Indiana received loan repayments of $6.1 million from IPALCO.
In the second quarter of 2023, AES Indiana engaged a vendor that is a related party through a competitive RFP process as part of its replacement capacity resource construction projects. AES Indiana had payments of $223.3 million to this vendor during the year ended December 31, 2023, which are included in "Other non-current assets" on the accompanying Consolidated Balance Sheets. Additionally, transactions with various other related parties were $7.4 million, $5.7 million and $4.3 million during 2023, 2022 and 2021, respectively. These expenses were primarily recorded in “Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations.
12. BUSINESS SEGMENTS
Operating segments are components of an enterprise that engage in business activities from which it may earn revenue and incur expenses, for which separate financial information is available, and is evaluated regularly by the chief operating decision maker in assessing performance and deciding how to allocate resources. All of AES Indiana’s current business consists of the generation, transmission, distribution and sale of electric energy, and therefore AES Indiana had only one reportable segment.
13. REVENUE
Revenue is primarily earned from retail and wholesale electricity sales and electricity transmission and distribution delivery services. Revenue is recognized upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Revenue is recorded net of any taxes assessed on and collected from customers, which are remitted to the governmental authorities.
Retail revenue - AES Indiana energy sales to utility customers are based on the reading of meters at the customer’s location that occurs on a systematic basis throughout the month. AES Indiana sells electricity directly to end-users, such as homes and businesses, and bills customers directly. Retail revenue have a single performance obligation, as the promise to transfer energy and other distribution and/or transmission services are not separately identifiable from other promises in the contracts and, therefore, are not distinct. Additionally, as the performance obligation is satisfied over time as energy is delivered, and the same method is used to measure progress, the performance obligation meets the criteria to be considered a series.
In exchange for the exclusive right to sell or distribute electricity in our service area, AES Indiana is subject to rate regulation by federal and state regulators. This regulation sets the framework for the prices (“tariffs”) that AES Indiana is allowed to charge customers for electric services. Since tariffs are approved by the regulator, the price that AES Indiana has the right to bill corresponds directly with the value to the customer of AES Indiana’s performance completed in each period. Therefore, revenue under these contracts is recognized using an output method measured by the MWhs delivered each month at the approved tariff. Customer payments are typically due on a monthly basis.
Wholesale revenue - Power produced at the generation stations in excess of our retail load is sold into the MISO market. Such sales are made at either the day-ahead or real-time hourly market price, and these sales are classified as wholesale revenue. We sell to and purchase power from MISO, and such sales and purchases are settled and accounted for on a net hourly basis.
In the MISO market, wholesale revenue is recorded at the spot price based on the quantities of MWh delivered in each hour during each month. As a member of MISO, we are obligated to declare the availability of our energy production into the wholesale energy market, but we are not obligated to commit our previously declared availability. As such, contract terms end as the energy for each day is delivered to the market in the case of the day-ahead market and for each hour in the case of the real-time market.
Miscellaneous revenue - Miscellaneous revenue is mainly comprised of MISO transmission revenue and capacity revenue. MISO transmission revenue is earned when AES Indiana’s power lines are used in transmission of energy by power producers other than AES Indiana. As AES Indiana owns and operates transmission lines in central and southern Indiana, demand charges collected from network customers by MISO are allocated to the appropriate transmission owners (including AES Indiana) and recognized as transmission revenue. Capacity revenue is also included in miscellaneous revenue, and represent compensation received from MISO for making installed generation capacity available to satisfy system integrity and reliability requirements through the annual MISO capacity auction. Capacity, which is a stand-ready obligation to deliver energy when called upon by the RTO, is measured using MWs.
Transmission and capacity revenue each have a single performance obligation, as they each represent a distinct service or good. Additionally, as these performance obligations are satisfied over time and the same method is used to measure progress, the performance obligations meet the criteria to be considered a series. For transmission revenue, the price that the transmission operator has the right to bill corresponds directly with the value to the customer of AES Indiana’s performance completed in each period as the price paid is the transmission operator's allocation of the tariff rate (as approved by the regulator) charged to network participants. For capacity revenue, the capacity price that clears at the auction is fixed and AES Indiana is compensated based on the cleared MWs and cleared price.
AES Indiana’s revenue from contracts with customers was $1,616.5 million, $1,760.0 million and $1,389.2 million for the years ended December 31, 2023, 2022 and 2021, respectively. The following table presents AES Indiana's revenue from contracts with customers and other revenue (in thousands):
For the Years Ended December 31,
2023 2022 2021
Retail Revenue
Retail revenue from contracts with customers:
Residential $ 660,559 $ 688,487 $ 595,692
Small commercial and industrial 241,800 247,655 211,997
Large commercial and industrial 619,899 625,351 518,069
Public lighting 9,767 9,832 8,888
Other (1)
14,016 17,845 16,785
Total retail revenue from contracts with customers 1,546,041 1,589,170 1,351,431
Alternative revenue programs 30,414 29,171 35,248
Wholesale Revenue
Wholesale revenue from contracts with customers 56,557 148,517 25,059
Miscellaneous Revenue
Capacity revenue 8,210 11,750 734
Transmission and other revenue 5,654 10,534 11,480
Total miscellaneous revenue from contracts with customers 13,864 22,284 12,214
Other miscellaneous revenue (2)
3,041 2,569 2,180
Total Revenue $ 1,649,917 $ 1,791,711 $ 1,426,132
(1) Other retail revenue from contracts with customers includes miscellaneous charges to customers, including reconnection and late fee charges.
(2) Other miscellaneous revenue includes lease and other miscellaneous revenue not accounted for under ASC 606.
The balances of receivables from contracts with customers were $218.8 million and $198.3 million as of December 31, 2023 and 2022, respectively. Payment terms for all receivables from contracts with customers typically do not extend beyond 30 days, unless a customer qualifies for payment extension.
AES Indiana has elected to apply the optional disclosure exemptions under ASC 606. Therefore, AES Indiana has not included disclosure pertaining to revenue expected to be recognized in any future year related to remaining performance obligations, as we exclude contracts with an original length of one year or less, contracts for which we recognize revenue based on the amount we have the right to invoice for services performed, and contracts with variable consideration allocated entirely to a wholly unsatisfied performance obligation when the consideration
relates specifically to our efforts to satisfy the performance obligation and depicts the amount to which AES Indiana expects to be entitled.
14. LEASES
LESSEE
The Company is the lessee under financing leases primarily for land. Right-of-use assets are long-term by nature. The following table summarizes the amounts recognized on the Consolidated Balance Sheets related to lease asset and liability balances as of the periods indicated (in thousands):
Consolidated Balance Sheet Classification December 31, 2023 December 31, 2022
Assets
Right-of-use assets - finance leases Other non-current assets $ 16,357 $ 15,819
Liabilities
Finance lease liabilities (noncurrent) Long-term debt $ 17,769 $ 16,361
Total finance lease liabilities $ 17,769 $ 16,361
The following table summarizes supplemental balance sheet information related to leases as of the periods indicated:
Lease Term and Discount Rate December 31, 2023 December 31, 2022
Weighted-average remaining lease term - finance leases 35 years
36 years
Weighted-average discount rate - finance leases 5.30% 5.650%
The following table summarizes the components of lease expense recognized in "Operating Costs and Expenses" on the accompanying Consolidated Statements of Operations for the years ended December 31, 2023, 2022 and 2021, respectively (in thousands):
For the Year Ended December 31,
Components of Lease Cost 2023 2022 2021
Finance lease cost:
Amortization of right- of-use assets $ 445 $ 542 $ -
Interest on lease liabilities 933 782 -
Total lease cost $ 1,378 $ 1,324 $ -
Operating cash outflows from finance leases were $0.6 million, $0.3 million and $0.0 million for the years ended December 31, 2023, 2022 and 2021, respectively.
The following table shows the future lease payments under finance leases together with the present value of the net lease payments as of December 31, 2023 for 2024 through 2028 and thereafter (in thousands):
Finance Leases
2024 $ 891
2025 909
2026 927
2027 945
2028 965
Thereafter 39,958
Total $ 44,595
Less: Imputed interest (26,826)
Present value of lease payments $ 17,769
LESSOR
The Company is the lessor under operating leases for land, office space and operating equipment. Lease receipts from such contracts are recognized as operating lease revenue on a straight-line basis over the lease term whereas contingent rentals are recognized when earned.
The following table presents lease revenue from operating leases in which the Company is the lessor for the periods indicated (in thousands):
For the Year Ended December 31,
2023 2022 2021
Total lease revenue $ 1,537 $ 1,134 $ 1,439
The following table presents the underlying gross assets and accumulated depreciation of operating leases included in Property, plant and equipment, net for the periods indicated (in thousands):
Property, Plant and Equipment, Net December 31, 2023 December 31, 2022
Gross assets $ 4,341 $ 4,334
Less: Accumulated depreciation (1,222) (1,060)
Net assets $ 3,119 $ 3,274
The option to extend or terminate a lease is based on customary early termination provisions in the contract.
The following table shows the future minimum lease receipts through 2028 and thereafter (in thousands):
Operating Leases
2024 $ 544
2025 553
2026 554
2027 554
2028 354
Thereafter 891
Total $ 3,450

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
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, 2023, our disclosure controls and procedures were not effective due to a material weakness in our internal control over financial reporting described below.
Management’s Report on Internal Control over Financial Reporting
Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rule 13a-15(f) under the Exchange Act. The Company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP and includes those policies and procedures that:
•pertain to the maintenance of records that in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;
•provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and
•provide reasonable assurance that unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements are prevented or detected timely.
A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be prevented or detected on a timely basis.
The Company conducted an assessment of the effectiveness of its internal control over financial reporting as of December 31, 2023 based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework). As of December 31, 2023, we have identified material weaknesses in internal controls related to the fourth quarter implementation of SAP IS-U, a software solution that SAP developed for businesses operating in the utility industries. We identified control deficiencies that aggregated to a material weakness in the design and operation of information technology general controls (“ITGCs”) which support the Company’s internal control processes for revenue recognition and related accounts and disclosures impacted by revenue recognition. The design deficiencies relate to user access and program change-management controls. Business process controls (automated and manual) and management review controls reliant on SAP IS-U were deemed ineffective as they were adversely impacted by the ineffective information technology general controls.
Management has implemented and continues to implement measures designed to ensure that control deficiencies contributing to the material weakness are remediated. The remediation actions include: (i) changes to our ITGC attributes in the areas of user access and program change-management for systems supporting the Company’s
revenue internal control processes to ensure that internal controls are designed and operating effectively; and (ii) training and educating the control owners on ITGC policies concerning the requirements of each control, with a focus on those related to user access and change-management over IT systems impacting our revenue process. Management has performed a lookback analysis to determine if any unauthorized activity occurred related to the control deficiencies; none was identified.
We believe that these actions will remediate the foregoing material weakness. The material weakness will not be considered remediated, however, until the applicable controls operate for a sufficient period of time, and management has concluded, through testing, that these controls are operating effectively.
Management, including our CEO and CFO, does not expect that our internal controls will prevent or detect all misstatements and all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. In addition, any evaluation of the effectiveness of controls is subject to risks that those internal controls may become inadequate in future periods because of changes in business conditions, or that the degree of compliance with the policies or procedures deteriorates.
Changes in Internal Control Over Financial Reporting
Except for the implementation of the SAP IS-U system discussed above, there has been no change in the Company’s internal control over financial reporting during the quarter ended December 31, 2023, that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.
Notwithstanding the existence of the material weaknesses as described above, we believe that the consolidated financial statements in this Annual Report present fairly, in all material respects, our financial position, results of operations and cash flows as of the dates, and for the periods presented, in conformity with U.S. GAAP.

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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,
2023 2022
Audit Fees $ 1,442,837 $ 945,033
Audit Related Fees:
Fees for the audit of AES Indiana’s employee benefit plans 70,000 68,096
Other 10,000 8,500
Total Principal Accountant Fees and Services $ 1,522,837 $ 1,021,629
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 - 2023, 2022 and 2021 (PCAOB ID: 42)
Consolidated Statements of Operations for the Years Ended December 31, 2023, 2022 and 2021 63
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2023, 2022, and 2021 64
Consolidated Balance Sheets as of December 31, 2023 and 2022 65
Consolidated Statements of Cash Flows for the Years Ended December 31, 2023, 2022 and 2021 66
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2023, 2022 and 2021
Notes to Consolidated Financial Statements 68
Schedule I - Condensed Financial Information of Registrant 166
Schedule II - Valuation and Qualifying Accounts and Reserves 175
AES Indiana - Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm - 2023, 2022 and 2021 (PCAOB ID: 42)
Consolidated Statements of Operations for the Years Ended December 31, 2023, 2022 and 2021 115
Consolidated Balance Sheets as of December 31, 2023 and 2022 116
Consolidated Statements of Cash Flows for the Years Ended December 31, 2023, 2022 and 2021 117
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2023, 2022 and 2021
Notes to Consolidated Financial Statements 119
Schedule II - Valuation and Qualifying Accounts and Reserves 175
(b) Exhibits
Exhibit No. Document
3.1 Third Amended and Restated Articles of Incorporation of IPALCO Enterprises, Inc. (Incorporated by reference to Exhibit No. 3.1 to IPALCO’s Form 8-K dated as of February 18, 2015)
3.2 Amended and Restated By-Laws of IPALCO Enterprises, Inc. (Incorporated by reference to Exhibit No. 3.2 to IPALCO’s Form 8-K dated as of February 18, 2015)
4.1 Pledge Agreement between IPALCO Enterprises, Inc. and The Bank of New York Mellon Trust Company, N.A. dated as of November 14, 2001 (Incorporated by reference to Exhibit No 4.1 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
4.2 Mortgage and Deed of Trust, dated as of May 1, 1940, between IPL and the Bank of New York Mellon Trust Company, NA, as successor in interest to American National Bank & Trust Company of Chicago, Trustee (Incorporated by reference to Exhibit No. 4.2 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
4.3 The following supplemental indentures to the Mortgage and Deed of Trust referenced in 4.2 above:
Third Supplemental Indenture, dated as of April 1, 1949 (Incorporated by reference to Exhibit No. 4.3 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
Tenth Supplemental Indenture, dated as of October 1, 1960 (Incorporated by reference to Exhibit No. 4.3 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
Eighteenth Supplemental Indenture, dated as of February 15, 1974 (Incorporated by reference to Exhibit No. 4.3 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
Forty-Eighth Supplemental Indenture, dated as of January 1, 2004 (Incorporated by reference to Exhibit No. 4.3 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
Fifty-Third Supplemental Indenture, dated as of October 1, 2006 (Incorporated by reference to Exhibit No. 4.3 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
Fifty-Fourth Supplemental Indenture, dated as of June 1, 2007 (Incorporated by reference to Exhibit No. 4.3 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
Sixtieth Supplemental Indenture, dated as of November 1, 2011 (Incorporated by reference to Exhibit No. 4.3 to IPALCO’s December 31, 2011 Form 10-K)
Sixty-First Supplemental Indenture, dated as of June 1, 2013 (Incorporated by reference to Exhibit No. 4.1 to IPALCO’s June 30, 2013 Form 10-Q)
Sixty-Second Supplemental Indenture, dated as of June 1, 2014 (Incorporated by reference to Exhibit No. 4.1 to IPALCO’s June 30, 2014 Form 10-Q)
Sixty-Third Supplemental Indenture, dated as of September 1, 2015 (Incorporated by reference to Exhibit No. 4.3 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on September 28, 2015)
Sixty-Fourth Supplemental Indenture, dated as of May 1, 2016 (Incorporated by reference to Exhibit No. 4.1 to IPALCO’s June 30, 2016 Form 10-Q)
Sixty-Fifth Supplemental Indenture, dated as of December 1, 2016 (Incorporated by reference to Exhibit No. 4.3 to IPALCO’s December 31, 2016 Form 10-K)
Sixty-Sixth Supplemental Indenture, dated as of November 1, 2018 (Incorporated by reference to Exhibit No. 4.3 to IPALCO's December 31, 2018 Form 10-K)
Sixty-Seventh Supplemental Indenture, dated as of December 1, 2020 (Incorporated by reference to Exhibit No. 4.3A to IPALCO's December 31, 2020 Form 10-K)
Sixty-Eighth Supplemental Indenture, dated as of December 1, 2020 (Incorporated by reference to Exhibit No. 4.3B to IPALCO's December 31, 2020 Form 10-K)
Sixty-Ninth Supplemental Indenture, dated as of July 1, 2021 (Incorporated by reference to Exhibit No. 4.1 to IPALCO's June 30, 2021 Form 10-Q)
Seventieth Supplemental Indenture, dated as of July 1, 2021 (Incorporated by reference to Exhibit No. 4.2 to IPALCO's June 30, 2021 Form 10-Q)
Seventy-First Supplemental Indenture, dated as of November 15, 2022 (Incorporated by reference to Exhibit No. 4.3 to IPALCO's December 31, 2022 Form 10-K)
4.4 Indenture between IPALCO Enterprises, Inc. and U.S. Bank, National Association, as Trustee, dated August 22, 2017 for IPALCO’s 3.70% Senior Secured Notes due 2024 (Incorporated by reference to Exhibit No. 4.1 to IPALCO’s August 22, 2017 Form 8-K)
4.5 Pledge Agreement Supplement between IPALCO Enterprises, Inc. and The Bank of New York Mellon trust Company, N.A., as Collateral Agent, dated August 22, 2017 to the Pledge Agreement between IPALCO Enterprises, Inc. and The Bank of New York Mellon Trust Company dated November 14, 2001, as amended (Incorporated by reference to Exhibit No. 4.2 to IPALCO’s August 22, 2017 Form 8-K)
4.6 Indenture between IPALCO Enterprises, Inc. and U.S. Bank National Association, as Trustee, dated April 14, 2020 for the 4.250% Senior Secured Notes due 2030 (Incorporated by reference to Exhibit No. 4.1 to IPALCO's April 14, 2020 Form 8-K)
4.7 Pledge Agreement Supplement between IPALCO Enterprises, Inc. and The Bank of New York Mellon Trust Company, N.A., as Collateral Agent, dated April 14, 2020 to the Pledge Agreement between IPALCO Enterprises, Inc. and The Bank of New York Mellon Trust Company dated November 14, 2001, as amended and supplemented (Incorporated by reference to Exhibit No. 4.2 to IPALCO's April 14, 2020 Form 8-K)
10.1 Interconnection Agreement, dated April 1, 2008, between American Electric Power Service Corporation, as agent for Indiana Michigan Power Company, and IPL (Incorporated by reference to Exhibit No. 10.1 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
10.2 Interconnection Agreement, dated December 2, 1968, between IPL and Southern Indiana Gas and Electric Company as modified through Modification Number 11 (Incorporated by reference to Exhibit No. 10.2 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
10.3 Interconnection Agreement dated December 1, 1981, between IPL and Hoosier Energy Rural Electric Cooperative, Inc., as modified through Modification 6 (Incorporated by reference to Exhibit No. 10.3 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
10.4 Tenth Supplemental Agreement to the Interconnection Agreement between IPL and PSI Energy, Inc., dated as of June 26, 2002, amending and completely restating prior agreements (Incorporated by reference to Exhibit No. 10.4 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
10.5 $350,000,000 Revolving Credit Facility Amended and Restated Credit Agreement, dated December 22, 2022, among Indianapolis Power & Light Company, each lender from time to time party thereto, PNC Bank, National Association, as Administrative Agent, PNC Capital Markets LLC, as Joint Bookrunner and Joint Lead Arranger, U.S. Bank, National Association, as Syndication Agent, Joint Bookrunner and Joint Lead Arranger and The Huntington National Bank, as Documentation Agent (Incorporated by reference to Exhibit 10.1 to IPALCO's Current Report on Form 8-K filed on December 23, 2022)
10.6 $300,000,000 Term Loan Agreement by and among Indianapolis Power & Light Company, d/b/a AES Indiana the Lenders Party Hereto, PNC Bank, National Association, as Administrative Agent, PNC Capital Markets LLC, as Bookrunner and Joint Lead Arranger, U.S. Bank National Association, as Syndication Agent and Joint Lead Arranger, and The Huntington National Bank, as Documentation Agent and Joint Lead Arranger, dated as of November 21, 2023
10.7
Subscription Agreement by and between IPALCO and CDP Infrastructures Fund G.P., a wholly owned subsidiary of La Caisse de dépȏt et placement du Québec dated December 14, 2014 (Incorporated by reference to Exhibit 10.10 to IPALCO’s December 31, 2014 10-K/A)
10.8
IPALCO’s Shareholders’ Agreement by and among AES U.S. Investments, Inc., IPALCO Enterprises, Inc. and CDP Infrastructures Fund G.P. dated as of February 11, 2015 (Incorporated by reference to Exhibit No. 10.1 to IPALCO’s March 31, 2015 10-Q)
10.9
The AES Corporation 2023 Long Term Compensation Plan, as amended and restated, dated October 11, 2023 (Incorporated by reference to Exhibit 10.5 of The AES Corporation’s Form 10-K for the year ended December 31, 2023)
10.10
The AES Corporation Performance Incentive Plan, as amended and restated on April 23, 2015 (Incorporated by reference to Exhibit 99.2 of The AES Corporation’s Form 8-K filed on April 23, 2015)
10.11
The AES Corporation Severance Plan, as amended and restated on August 4, 2017 (Incorporated by reference to Exhibit 10.1 of The AES Corporation’s Form 10-Q for the quarter ended June 30, 2017)
10.12
The AES Corporation Restoration Supplemental Retirement Plan, as amended and restated, effective October 10, 2023 (Incorporated by reference to Exhibit 10.12 of The AES Corporation’s Form 10-K for the year ended December 31, 2023)
10.13
Form of AES Performance Stock Unit Award Agreement under The AES Corporation 2003 Long Term Compensation Plan (Incorporated by reference to Exhibit 10.13 of The AES Corporation’s Form 10-K for the year ended December 31, 2015)
10.14
Form of AES Restricted Stock Unit Award Agreement under The AES Corporation 2003 Long Term Compensation Plan (Incorporated by reference to Exhibit 10.14 of The AES Corporation’s Form 10-K for the year ended December 31, 2019)
10.15
Form of AES Performance Unit Award Agreement under The AES Corporation 2003 Long Term Compensation Plan (Incorporated by reference to Exhibit 10.15 of The AES Corporation’s Form 10-K for the year ended December 31, 2015)
10.16
Form of AES Nonqualified Stock Option Award Agreement under The AES Corporation 2003 Long Term Compensation Plan (Incorporated by reference to Exhibit 10.4 of The AES Corporation’s Form 10-Q for the quarter ended June 30, 2015)
10.17
Form of AES Performance Cash Unit Award Agreement under The AES Corporation 2003 Long Term Compensation Plan (Incorporated by reference to Exhibit 10.17 of The AES Corporation’s Form 10-K for the year ended December 31, 2019)
10.18
The AES Corporation Amended and Restated Executive Severance Plan dated October 5, 2018 is incorporated by reference to Exhibit 10.1 of the AES Corporation's Form 10-Q for the quarter ended September 30, 2018)
21 Subsidiaries of IPALCO Enterprises, Inc.
31.1 Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2 Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1 Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2 Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS XBRL Instance Document (furnished herewith as provided in Rule 406T of Regulation S-T)
101.SCH XBRL Taxonomy Extension Schema Document (furnished herewith as provided in Rule 406T of Regulation S-T)
101.CAL XBRL Taxonomy Extension Calculation Linkbase Document (furnished herewith as provided in Rule 406T of Regulation S-T)
101.DEF XBRL Taxonomy Extension Definition Linkbase Document (furnished herewith as provided in Rule 406T of Regulation S-T)
101.LAB XBRL Taxonomy Extension Label Linkbase Document (furnished herewith as provided in Rule 406T of Regulation S-T)
101.PRE XBRL Taxonomy Extension Presentation Linkbase Document (furnished herewith as provided in Rule 406T of Regulation S-T)
(c) Financial Statement Schedules
Schedules other than those listed below are omitted as the information is either not applicable, not required, or has been furnished in the financial statements or notes thereto included in Item 8 hereof.
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT
IPALCO ENTERPRISES, INC.
Schedule I - Condensed Financial Information of Registrant
Unconsolidated Statements of Operations
2023 2022 2021
(In Thousands)
OTHER INCOME / (EXPENSE), NET:
Equity in income of subsidiaries $ 116,190 $ 126,466 $ 147,030
Interest expense (43,877) (43,805) (41,380)
Other expense, net (121) (571) (45)
Total other income, net 72,192 82,090 105,605
INCOME FROM OPERATIONS BEFORE INCOME TAX 72,192 82,090 105,605
Income tax benefit (10,928) (11,027) (10,364)
NET INCOME $ 83,120 $ 93,117 $ 115,969
See Notes to Schedule I.
IPALCO ENTERPRISES, INC.
Schedule I - Condensed Financial Information of Registrant
Unconsolidated Statements of Comprehensive Income
2023 2022 2021
(In Thousands)
NET INCOME $ 83,120 $ 93,117 $ 115,969
Derivative activity:
Change in derivative fair value, net of income tax effect of $(528), $(15,309) and $(3,441), for each respective period
1,594 46,245 10,393
Reclassification to earnings, net of income tax effect of $(1,798), $(1,798) and $(1,199), for each respective period
5,431 5,431 3,620
Net change in fair value of derivatives 7,025 51,676 14,013
Other comprehensive income 7,025 51,676 14,013
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON STOCK
$ 90,145 $ 144,793 $ 129,982
See Notes to Schedule I.
IPALCO ENTERPRISES, INC.
Schedule I - Condensed Financial Information of Registrant
Unconsolidated Balance Sheets
December 31, 2023 December 31, 2022
(In Thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 537 $ 191
Taxes receivable 31,341 11,318
Derivative assets, current 14,294 -
Prepayments and other current assets 7,626 7,509
Total current assets 53,798 19,018
OTHER NON-CURRENT ASSETS:
Investment in subsidiaries 1,921,548 1,945,556
Derivative assets, non-current - 12,172
Other non-current assets 3,540 3,211
Total other non-current assets 1,925,088 1,960,939
TOTAL ASSETS
$ 1,978,886 $ 1,979,957
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Short-term and current portion of long-term debt $ 404,474 $ -
Accounts payable - 87
Accrued interest 8,360 8,360
Total current liabilities 412,834 8,447
NON-CURRENT LIABILITIES:
Long-term debt 470,653 873,663
Deferred tax liability - long-term 18,931 7,329
Total non-current liabilities 489,584 880,992
Total liabilities 902,418 889,439
SHAREHOLDERS' EQUITY
Paid in capital 1,021,992 1,068,357
Accumulated other comprehensive income 29,294 22,269
Retained earnings / (accumulated deficit) 25,182 (108)
Total shareholders' equity 1,076,468 1,090,518
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 1,978,886 $ 1,979,957
See Notes to Schedule I.
IPALCO ENTERPRISES, INC.
Schedule I - Condensed Financial Information of Registrant
Unconsolidated Statements of Cash Flows
2023 2022 2021
(In Thousands)
CASH FLOWS FROM OPERATIONS:
Net income $ 83,120 $ 93,117 $ 115,969
Adjustments to reconcile net income to net cash
provided by operating activities:
Equity in earnings of subsidiaries (116,190) (126,466) (147,030)
Cash dividends received from subsidiary companies 140,200 127,200 155,700
Amortization of deferred financing costs and debt premium 1,474 1,403 1,379
Deferred income taxes - net 9,276 (121) (5)
Change in certain assets and liabilities:
Accounts payable (23) (194) (85)
Accrued taxes payable/receivable (20,022) (2,406) 2,940
Other - net 6,798 7,744 4,265
Net cash provided by operating activities 104,633 100,277 133,133
CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in subsidiaries - (253,000) (275,000)
Net cash used in investing activities - (253,000) (275,000)
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayments of loans to subsidiary - - (6,110)
Distributions to shareholders (104,287) (101,986) (131,476)
Equity contributions from shareholders - 253,000 275,000
Deferred financing costs paid and other - (2) (62)
Net cash (used in) provided by financing activities (104,287) 151,012 137,352
Net change in cash, cash equivalents and restricted cash 346 (1,711) (4,515)
Cash, cash equivalents and restricted cash at beginning of period 191 1,902 6,417
Cash, cash equivalents and restricted cash at end of period $ 537 $ 191 $ 1,902
Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest (net of amount capitalized) $ 35,569 $ 35,173 $ 35,172
Income taxes - 31,000 27,500
See Notes to Schedule I.
IPALCO ENTERPRISES, INC.
Schedule I - Condensed Financial Information of Registrant
Unconsolidated Statements of Changes in Equity (Deficit)
Paid in Capital Accumulated Other Comprehensive Income (Loss) Retained Earnings (Accumulated
Deficit) Total Shareholders' Equity
(In Thousands)
Balance at January 1, 2021 $ 588,966 $ (43,420) $ (24,558) $ 520,988
Net comprehensive income - 14,013 115,969 129,982
Distributions to shareholders(1)
(15,507) - (115,969) (131,476)
Contributions from shareholders 275,000 - - 275,000
Other 106 - - 106
Balance at December 31, 2021 848,565 (29,407) (24,558) 794,600
Net comprehensive income - 51,676 93,117 144,793
Distributions to shareholders(1)
(33,319) - (68,667) (101,986)
Contributions from shareholders 253,000 - - 253,000
Other 111 - - 111
Balance at December 31, 2022 1,068,357 22,269 (108) 1,090,518
Net comprehensive income - 7,025 83,120 90,145
Distributions to shareholders(1)
(46,457) - (57,830) (104,287)
Other 92 - - 92
Balance at December 31, 2023 $ 1,021,992 $ 29,294 $ 25,182 $ 1,076,468
1) IPALCO made return of capital payments of $46.5 million, $33.3 million and $15.5 million in 2023, 2022 and 2021, respectively, for the portion of current year distributions to shareholders in excess of current year net income at the time of distribution.
See Notes to Schedule I.
IPALCO ENTERPRISES, INC.
Schedule I - Condensed Financial Information of Registrant
Notes to Schedule I
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Accounting for Subsidiaries and Affiliates - IPALCO has accounted for the earnings of its subsidiaries on the equity method in the unconsolidated condensed financial information.
2. FAIR VALUE
The fair value of current financial assets and liabilities approximate their reported carrying amounts. The estimated fair values of the Company’s assets and liabilities have been determined using available market information. Because these amounts are estimates and based on hypothetical transactions to sell assets or transfer liabilities, the use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.
Fair Value Hierarchy and Valuation Techniques
ASC 820 defined and established a framework for measuring fair value and expands disclosures about fair value measurements for financial assets and liabilities that are adjusted to fair value on a recurring basis and/or financial assets and liabilities that are measured at fair value on a nonrecurring basis, which have been adjusted to fair value during the period. In accordance with ASC 820, we have categorized our financial assets and liabilities that are adjusted to fair value, based on the priority of the inputs to the valuation technique, following the three-level fair value hierarchy prescribed by ASC 820 as follows:
Level 1 - unadjusted quoted prices for identical assets or liabilities in an active market;
Level 2 - inputs from quoted prices in markets where trading occurs infrequently or quoted prices of instruments with similar attributes in active markets; and
Level 3 - unobservable inputs reflecting management’s own assumptions about the inputs used in pricing the asset or liability.
Whenever possible, quoted prices in active markets are used to determine the fair value of our financial instruments. Our financial instruments are not held for trading or other speculative purposes. The estimated fair value of financial instruments has been determined by using available market information and appropriate valuation methodologies. However, considerable judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we could realize in a current market exchange. The use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.
Financial Assets
VEBA Assets
IPALCO has VEBA investments that are to be used to fund certain employee postretirement health care benefit plans. These assets are primarily comprised of open-ended mutual funds, which are valued using the net assets value per unit. These investments are recorded at fair value within "Other non-current assets" on the accompanying Unconsolidated Balance Sheets and classified as equity securities. All changes to fair value on the VEBA investments are included in income in the period that the changes occur. These changes to fair value were not material for the years ended December 31, 2023, 2022, or 2021. Any unrealized gains or losses are recorded in "Other income / (expense), net" on the accompanying Unconsolidated Statements of Operations.
Financial Assets
Interest Rate Hedges
IPALCO's interest rate hedges have a combined notional amount of $400.0 million. All changes in the market value of the interest rate hedges are recorded in AOCI. See also Note 3, "Derivative Instruments and Hedging Activities - Cash Flow Hedges" for further information.
Summary
The fair value of assets at December 31, 2023 and 2022 measured on a recurring basis and the respective category within the fair value hierarchy for IPALCO was determined as follows:
Fair Value as of December 31, 2023 Fair Value as of December 31, 2022
Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
(In Thousands)
Financial assets:
VEBA investments:
Money market funds $ 127 $ - $ - $ 127 $ 5 $ - $ - $ 5
Mutual funds 3,425 - - 3,425 3,223 - - 3,223
Total VEBA investments 3,552 - - 3,552 3,228 - - 3,228
Interest rate hedges - 14,294 - 14,294 - 12,172 - 12,172
Total financial assets measured at fair value $ 3,552 $ 14,294 $ - $ 17,846 $ 3,228 $ 12,172 $ - $ 15,400
Financial Instruments not Measured at Fair Value in the Unconsolidated Balance Sheets
Debt
The fair value of our outstanding fixed-rate debt has been determined on the basis of the quoted market prices of the specific securities issued and outstanding. In certain circumstances, the market for such securities was inactive and therefore the valuation was adjusted to consider changes in market spreads for similar securities. Accordingly, the purpose of this disclosure is not to approximate the value on the basis of how the debt might be refinanced.
The following table shows the face value and the fair value of fixed-rate indebtedness (Level 2) for the periods ending:
December 31, 2023 December 31, 2022
Face Value Fair Value Face Value Fair Value
(In Thousands)
Fixed-rate $ 880,000 $ 839,471 $ 880,000 $ 816,411
Total indebtedness $ 880,000 $ 839,471 $ 880,000 $ 816,411
The difference between the face value and the carrying value of this indebtedness represents the following:
•unamortized deferred financing costs of $4.6 million and $5.9 million at December 31, 2023 and 2022, respectively; and
•unamortized discounts of $0.3 million and $0.4 million at December 31, 2023 and 2022, respectively.
3. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
We use derivatives principally to manage the interest rate risk associated with refinancing our long-term debt. The derivatives that we use to economically hedge these risks are governed by our risk management policies for forward and futures contracts. Our net positions are continually assessed within our structured hedging programs to determine whether new or offsetting transactions are required. We monitor and value derivative positions monthly as part of our risk management processes. We use published sources for pricing, when possible, to mark positions to market. All of our derivative instruments are used for risk management purposes and are designated as cash flow hedges if they qualify under ASC 815 for accounting purposes.
At December 31, 2023, IPALCO's outstanding derivative instruments were as follows:
Commodity Accounting Treatment (a)
Unit Notional
(in thousands) Sales
(in thousands) Net Notional
(in thousands)
Interest rate hedges Designated USD $ 400,000 $ - $ 400,000
(a) Refers to whether the derivative instruments have been designated as a cash flow hedge.
Cash Flow Hedges
As part of our risk management processes, we identify the relationships between hedging instruments and hedged items, as well as the risk management objective and strategy for undertaking various hedge transactions. The fair values of cash flow hedges determined by current public market prices will continue to fluctuate with changes in market prices up to contract expiration. The change in the fair value of a hedging instrument is recorded in other comprehensive income and amounts deferred are reclassified to earnings in the same income statement line as the hedged item in the period in which it settles.
In March 2019, we entered into three forward interest rate swaps to hedge the interest risk associated with refinancing the IPALCO 2020 maturities. The three interest rate swaps had a combined notional amount of $400.0 million. In April 2020, we de-designated the swaps as cash flow hedges and froze the AOCL of $72.3 million at the date of de-designation. The interest rate swaps were then amended and re-designated as cash flow hedges to hedge the interest rate risk associated with refinancing the 2024 IPALCO Notes. The amended interest rate swaps have a combined notional amount of $400.0 million and will be settled when the 2024 IPALCO Notes are refinanced. The $72.3 million of AOCL associated with the interest rate swaps through the date of the amendment will be amortized out of AOCL into interest expense over the remaining life of the 2030 IPALCO Notes, while any changes in fair value associated with the amended interest rate swaps will be recognized in AOCL going forward.
The following tables provide information on gains or losses recognized in AOCL for the cash flow hedges for the period indicated:
Interest Rate Hedges for the Year Ended December 31,
$ in thousands (net of tax) 2023 2022 2021
Beginning accumulated derivative gain / (loss) in AOCL
$ 22,269 $ (29,407) $ (43,420)
Net gains associated with current period hedging transactions
1,594 46,245 10,393
Net losses reclassified to interest expense
5,431 5,431 3,620
Ending accumulated derivative gain / (loss) in AOCI / (AOCL)
$ 29,294 $ 22,269 $ (29,407)
Loss expected to be reclassified to earnings in the next twelve months
$ (5,375)
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months) 9
When applicable, IPALCO has elected not to offset derivative assets and liabilities and not to offset net derivative positions against the right to reclaim cash collateral pledged (an asset) or the obligation to return cash collateral received (a liability) under derivative agreements. As of December 31, 2023 and 2022, IPALCO did not have any offsetting positions.
The following table summarizes the fair value, balance sheet classification and hedging designation of IPALCO's derivative instruments:
December 31,
Commodity Hedging Designation Balance sheet classification 2023 2022
Interest rate hedges Cash Flow Hedge Derivative assets, current
$ 14,294 $ -
Interest rate hedges Cash Flow Hedge Derivative assets, non-current $ - $ 12,172
4. DEBT
The following table presents IPALCO’s long-term indebtedness:
December 31,
Series Due 2023 2022
(In Thousands)
Long-Term Debt
3.70% Senior Secured Notes
September 2024 405,000 405,000
4.25% Senior Secured Notes
May 2030 475,000 475,000
Unamortized discount - net (319) (425)
Deferred financing costs - net (4,554) (5,912)
Total long-term debt 875,127 873,663
Less: current portion of long-term debt 405,000 -
Net long-term debt $ 470,127 $ 873,663
IPALCO’s Senior Secured Notes and Term Loan
The 2024 IPALCO Notes are due September 1, 2024. Although current liquid funds are not sufficient to repay the collective amounts due under the 2024 IPALCO Notes at maturity, the Company believes it will be able to refinance the 2024 IPALCO Notes based on conversations with investment bankers, which currently indicate more than adequate demand for new IPALCO debt at its current credit ratings, and considering the Company's previous successful debt issuances.
Pursuant to a registration rights agreement dated April 14, 2020, IPALCO agreed to register the 2030 IPALCO Notes under the Securities Act by filing an exchange offer registration statement or, under specified circumstances, a shelf registration statement with the SEC. IPALCO filed a registration statement on Form S-4 with respect to the 2030 IPALCO Notes with the SEC on March 22, 2021 in respect of its obligations under such registration rights agreement, and this registration statement was declared effective on April 7, 2021. The exchange offer closed on May 11, 2021.
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Valuation and Qualifying Accounts and Reserves
For the Years Ended December 31, 2023, 2022 and 2021
(In Thousands)
Column A - Description Column B Column C - Additions Column D - Deductions Column E
Balance at Beginning
of Period Charged to
Income Charged to Other
Accounts Net
Write-offs Balance at
End of Period
Year ended December 31, 2023
Accumulated Provisions Deducted from
Assets - Doubtful Accounts $ 1,117 $ 8,930 $ - $ 7,764 $ 2,283
Deducted from Inventories
Valuation Allowance for Materials and Supplies $ 5,160 $ 736 $ - $ 2,456 $ 3,440
Year ended December 31, 2022
Accumulated Provisions Deducted from
Assets - Doubtful Accounts $ 647 $ 7,478 $ - $ 7,008 $ 1,117
Deducted from Inventories
Valuation Allowance for Materials and Supplies $ 3,107 $ 2,053 $ - $ - $ 5,160
Year ended December 31, 2021
Accumulated Provisions Deducted from
Assets - Doubtful Accounts $ 3,155 $ 3,940 $ - $ 6,448 $ 647
Deducted from Inventories
Valuation Allowance for Materials and Supplies $ 6,133 $ 758 $ - $ 3,784 $ 3,107
AES INDIANA and SUBSIDIARIES
Valuation and Qualifying Accounts and Reserves
For the Years Ended December 31, 2023, 2022 and 2021
(In Thousands)
Column A - Description Column B Column C - Additions Column D - Deductions Column E
Balance at Beginning
of Period Charged to
Income Charged to Other
Accounts Net
Write-offs Balance at
End of Period
Year ended December 31, 2023
Accumulated Provisions Deducted from
Assets - Doubtful Accounts $ 1,117 $ 8,930 $ - $ 7,764 $ 2,283
Deducted from Inventories
Valuation Allowance for Materials and Supplies $ 5,160 $ 736 $ - $ 2,456 $ 3,440
Year ended December 31, 2022
Accumulated Provisions Deducted from
Assets - Doubtful Accounts $ 647 $ 7,478 $ - $ 7,008 $ 1,117
Deducted from Inventories
Valuation Allowance for Materials and Supplies $ 3,107 $ 2,053 $ - $ - $ 5,160
Year ended December 31, 2021
Accumulated Provisions Deducted from
Assets - Doubtful Accounts $ 3,155 $ 3,940 $ - $ 6,448 $ 647
Deducted from Inventories
Valuation Allowance for Materials and Supplies $ 6,133 $ 758 $ - $ 3,784 $ 3,107