EDGAR 10-K Filing

Company CIK: 728391
Filing Year: 2022
Filename: 728391_10-K_2022_0000728391-22-000010.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 Segment Information” 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 516,000 retail customers in the city of Indianapolis and neighboring areas within the state of Indiana; the most distant point being about 40 miles from Indianapolis. 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 977,000. 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 2021.
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, 2021, AES Indiana had 1,163 employees, of whom 1,090 were full time. Of the total employees, 801 were represented by the IBEW in two bargaining units: a physical unit and a clerical-technical unit. In February 2020, the membership of the IBEW clerical-technical unit ratified a three-year labor agreement with AES Indiana
that expires on February 13, 2023. In December 2021, the IBEW physical unit ratified a three-year agreement with AES Indiana that expires on December 4, 2024. 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 January 31, 2021, 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. Ensuring safe operations at our facilities, so 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 non-injury near misses. 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.
In response to the COVID-19 pandemic, we implemented significant changes that we determined were in the best interest of our employees, as well as the communities in which we operate. This includes having employees work from home to the extent they were able, while implementing additional safety measures for employees continuing critical on-site work.
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 companies that are part of the U.S. SBU, 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. Our largest generating station, Petersburg, is coal-fired. AES Indiana retired 230 MW Petersburg Unit 1 on May 31, 2021 and has plans to retire 415 MW Petersburg Unit 2 in 2023 (for further discussion, see Note 2, “Regulatory Matters - IRP Filing and Replacement Generation”). The second largest station, Harding Street, uses natural gas and fuel oil to power 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 small peaking station that uses natural gas to power combustion turbines. For electric generation, the net winter design capacity is 3,475 MW and net summer design capacity is 3,330 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
Coal Petersburg(1)
3 1,479 1,479 Pike County, Indiana
Total 3 1,479 1,479
Gas Harding Street 6 1,026 963 Marion County, Indiana
Eagle Valley 1 709 679 Morgan County, Indiana
Georgetown 2 200 158 Marion County, Indiana
Total 9 1,935 1,800
Oil Petersburg 3 8 8 Pike County, Indiana
Harding Street 3 53 43 Marion County, Indiana
Total 6 61 51
Grand Total 18 3,475 3,330
(1) AES Indiana retired 230 MW Petersburg Unit 1 on May 31, 2021 and has plans to retire 415 MW Petersburg Unit 2 in 2023 (for further discussion, see Note 2, “Regulatory Matters - IRP Filing and Replacement Generation”).
Net electrical generation during 2021 at our Petersburg, Harding Street, Eagle Valley and Georgetown plants accounted for approximately 71.0%, 15.3%, 12.3% and 1.4%, respectively, of our total net generation. Going forward, the generation fuel mix will continue to change primarily due to the expected return of service at Eagle Valley in 2022.
As part of the 2019 IRP Filing (see Note 2, “Regulatory Matters - IRP Filing and Replacement Generation”) and to procure replacement generation, AES Indiana completed the acquisition of a 195 MW solar project ("Hardy Hills Solar Project") to be developed in Clinton County, Indiana and executed an agreement to acquire and develop a 250 MW solar and 180 MWh energy storage facility ("Petersburg Solar Project") to be developed in Pike County, Indiana. The following table summarizes these projects that have not yet been placed into service:
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 2023 Clinton County, Indiana
Solar & Storage Petersburg Solar Project 250 180 7/30/2021 11/24/2021 2024 Pike County, Indiana
Our electric system is directly interconnected with the electric systems of Indiana Michigan Power Company, 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 5,115 circuit miles of underground primary and secondary cables and 6,119 circuit miles of overhead primary and secondary wire. Underground street lighting facilities include 780 circuit miles of underground cable. Also included in the system are 136 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 114 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 revenues 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, the economic impact of the COVID-19 pandemic, 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 2021, AES Indiana’s retail kWh sales have decreased at a compound annual rate of 0.9%. This decrease also includes the demand impacts of COVID-19 in 2020 and 2021. Conversely, the number of our retail customers grew at a compound annual rate of 1.0% during that same period. Going forward, we expect flat or modest retail kWh sales growth annually, which will continue to be negatively impacted 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 2017 through 2021 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 revenues as many of our retail customers use electricity to power air conditioners, electric furnaces and heat pumps. The impact 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 revenues 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 $59.5 million and $69.9 million as of December 31, 2021 and 2020, 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: (i) a rider to reflect changes in fuel and purchased power costs to meet AES Indiana’s retail load requirements, referred to as the FAC, (ii) a rider for the timely recovery of costs (including a return) incurred to comply with environmental laws and regulations, referred to as the ECCRA, (iii) a rider to reflect changes in ongoing MISO costs, referred to as the RTO Adjustment, (iv) 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, (v) 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, (vi) a rider for a return on and of investments for eligible TDSIC improvements, and (vii) 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 into the environment; 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.
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 four Petersburg units have been and remain in 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 May 22, 2020, the EPA published a final finding that it is not “appropriate and necessary” to regulate hazardous air pollutant emissions from coal- and oil-fired electric generating units (EGUs) (reversing its prior 2016 finding), but that the EPA would not remove the source category from the CAA Section 112(c) list of
source categories and would not change the MATS requirements. Several petitioners have filed for judicial review of the final finding and the D.C. Circuit, on February 16, 2021, granted EPA's request that the rule be held in abeyance pending he EPA's review. On January 31, 2022, the EPA released a pre-publication version of a proposed rule to revoke its May 2020 finding and reaffirm its 2016 finding that it is appropriate and necessary to regulate these emissions. 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 do not usually physically dispose of waste materials on our property. Instead, they are usually shipped off-site for final disposal, treatment or recycling. Some of our CCRs are beneficially used on-site and off-site, 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 using 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 October 13, 2021, IDEM issued a First Notice of Comment Period regarding establishment of a state-level CCR permit program.
The EPA has indicated that they will implement a phased approach to amending the CCR Rule, which is ongoing.
The CCR Rule, current or proposed amendments to the CCR Rule, 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 - Coal Ash Insurance Litigation” to the Financial Statements of this Annual Report on Form 10-K for further discussion.
On August 28, 2020, the EPA published the CCR Part A Rule that, among other amendments, required certain CCR units to cease waste receipt and initiate closure by April 11, 2021. The CCR Part A Rule also allowed for extensions of the April 11, 2021 deadline if EPA determines certain criteria are met. Facilities seeking such an extension were required to submit a demonstration to EPA by November 30, 2020. On January 11, 2022, EPA released pre-publication versions of proposed determinations regarding nine CCR Part A Rule demonstrations. On the same day, EPA issued four compliance-related letters notifying certain other facilities of their compliance obligations under the federal CCR regulations. While AES Indiana did not receive 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.
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. The deadline for submittal of the SIP covering the second planning
period was extended to July 31, 2018. While Indiana did not meet this deadline, on September 28, 2021, IDEM published its Draft Indiana Regional Haze SIP for the Second Implementation Period for public comment. The draft 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 recover of capital expenditures; however, there is no guarantee we would be successful.
Environmental Wastewater Requirements
In November 2015, the EPA published its final ELG rule to reduce toxic pollutants discharged into waterways by steam-electric power plants through technology applications. The wastewater treatment technologies installed and operated for compliance with the requirements of the October 2012 NPDES permit described above and the dry bottom ash handling system installed for compliance with the CCR Rule at Petersburg meet the requirements of the final ELG rule. However, it is too early to determine whether any outcome of litigation or current or future revisions to the ELG rule might have a material impact on our business, financial condition and results of operations.
In June 2016, the EPA published the final national chronic aquatic life criterion for the pollutant, selenium, in fresh
water. On August 11, 2021, updates to IDEM’s water quality criteria for specific metals, including selenium, were adopted as final to reflect EPA’s criterion. AES Indiana facilities’ NPDES permits may be updated to include selenium water-quality based effluent limits based on a site-specific evaluation process, which includes determining if there is a reasonable potential to exceed the revised final selenium water quality standards for the specific receiving water body utilizing actual and/or projected discharge information for the AES Indiana generating facilities. As a result, it is not yet possible to predict the potential impacts of this criteria. 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.
"Waters of the U.S." and “Navigable Waters Protection” Rules
In June 2015, the EPA and the U.S. Army Corps of Engineers ("the agencies") published a rule defining federal
jurisdiction over waters of the U.S., known as the "Waters of the U.S." (WOTUS) rule. This rule, which initially became effective in August 2015, could expand or otherwise change the number and types of waters or features subject to CWA permitting. However, after repealing the 2015 WOTUS rule on October 22, 2019, the agencies, on April 21, 2020, issued the final “Navigable Waters Protection” (NWP) rule which again revised the definition of waters of the U.S. On August 30, 2021, the U.S. District Court for the District of Arizona issued an order vacating and remanding the NWP Rule. This vacatur of the NWP Rule applies nationwide. As such, the agencies are interpreting waters of the U.S. consistent with the pre-2015 regulatory regime until further notice. On December 7, 2021, the Agencies published a proposed rule to define the scope of waters regulated under the CWA. The proposed rule would restore regulations defining WOTUS that were in place prior to 2015, with updates to be consistent with relevant Supreme Court decisions. A second rulemaking process is planned to further build upon this proposed rule. On January 24, 2022, the U.S. Supreme Court granted certiorari on a wetlands case (Sackett v. EPA) on the limited question of: “whether the Ninth Circuit set forth the proper test for determining whether wetlands are ‘waters of the United States’ under the Clean Water Act.” The Ninth Circuit employed Justice Kennedy’s “significant nexus” test from his concurring opinion in the 2006 Rapanos v. United States decision; the plurality opinion in Rapanos required a water body to have a “continuous surface connection” with a water of the United States in order to be considered a wetland covered by the CWA. In Sackett v. EPA, the Court may finally provide clarity on which of these two tests from the 2006 Rapanos decision controls. It is too early to determine whether any outcome of litigation or current or future revisions to rules interpreting federal jurisdiction over waters over the U.S. might have a material impact on our business, financial condition and results of operations.
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 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;
▪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;
▪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; 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.
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. In January 2021, EPA issued a final rule determining when standards are appropriate for GHG emissions from stationary source categories for new source but did not take final action on the 2018 proposal to revise the
2015 final NSPS. On April 5, 2021, the D.C. Circuit vacated and remanded the final January 2021 final rule. Challenges to the GHG NSPS remain held in abeyance at this time.
On August 31, 2018, the EPA published in the Federal Register proposed Emission Guidelines for Greenhouse Gas
Emissions from Existing Electric Utility Generating Units, known as the ACE Rule. On July 8, 2019, the EPA
published the final ACE Rule along with associated revisions to implementing regulations. The final ACE Rule
established CO2 emission rules for existing power plants under CAA Section 111(d) and replaced the EPA's 2015
CPP. In accordance with the ACE rule, the EPA determined that heat rate improvement measures are the Best
System of Emissions Reductions for existing coal-fired electric generating units. The final rule required the State of
Indiana to develop a State Plan to establish CO2 emission limits for designated facilities, including AES Indiana Petersburg's coal-fired electric generating units. States had three years to develop their plans under the rule. However, on January 19, 2021, the D.C. Circuit vacated and remanded to EPA the ACE Rule, but withheld issuance of the mandate that would effectuate its decision. On February 22, 2021, the D.C. Circuit granted EPA’s unopposed motion for a partial stay of the issuance of the mandate on vacating the repeal of the CPP. On March 5, 2021, the D.C. Circuit issued the partial mandate effectuating the vacatur of the ACE Rule. In effect, the CPP will not take effect while EPA is addressing the remand of the ACE rule by promulgating a new Section 111(d) rule to regulate greenhouse gases from existing electric generating units. On October 29, 2021, the U.S. Supreme Court granted petitions to review the decision by the D.C. Circuit to vacate the ACE Rule.The case is set for oral argument before the U.S. Supreme Court on February 28, 2022. The impact of the results of such litigation and potential future greenhouse gas emissions regulations remains uncertain, but it could be material.
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 2021, the international community gathered in Glasgow at the 26th Conference to the Parties on the UN Framework Convention on Climate Change (“COP26”), during which multiple announcements were made, including a call for parties to eliminate certain fossil fuel subsidies and pursue further action on non-carbon dioxide GHGs.
Based on the above, there is some uncertainty with respect to the impact of GHG rules on AES Indiana. The NSPS will not require us to comply with an emissions standard until we construct a new electric generating unit. We do not have any planned major modifications of an existing source or plans to construct a new major source which are expected to be subject to these regulations at this time. Furthermore, 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
Four coal-fired units at AES Indiana’s Eagle Valley Station site in Indiana were retired in April 2016. AES Indiana replaced this generation with a 671 MW CCGT at the Eagle Valley site, which was completed in April 2018, at a cost of $597 million. AES Indiana also completed a refuel of its Harding Street Station Units 5, 6 and 7 from coal to natural gas (approximately 610 total MW net capacity) at a total cost of approximately $105 million. The Harding Street 5 and 6 refueling projects were completed in December 2015 and the Harding Street 7 refuel was completed in the second quarter of 2016. The costs to build and operate the CCGT and the Harding Street Station refueling projects, including a return, are reflected in the basic rates and charges from AES Indiana's 2018 Base Rate Order effective on December 5, 2018.
In December 2019, AES Indiana filed its IRP, which describes AES Indiana's Preferred Resource Portfolio for meeting generation capacity needs for serving its retail customers over the next several years, 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 on May 31, 2021. See Note 2, "Regulatory Matters - IRP Filing" to the Financial Statements of this Annual Report on Form 10-K for additional details.
New Source Review and Other CAA NOVs
See Note 10, “Commitments and Contingencies - Environmental Loss Contingencies - New Source Review and other CAA NOVs” to the Financial Statements of this Annual Report on Form 10-K for additional details.
CSAPR
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. The 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 (the “CSAPR Update Rule”). The CSAPR Update Rule found that NOx ozone
season emissions in 22 states (including Indiana) affect the ability of downwind states to attain and maintain the
2008 ozone NAAQS, and accordingly, the EPA issued federal implementation plans that both generally provide
updated CSAPR NOx ozone season emission budgets for electric generating units within these states and that
implement these budgets through modifications to the CSAPR NOx ozone season allowance trading program.
Implementation began in the 2017 ozone season (May through September 2017). Affected facilities receive fewer
ozone season NOx allowances in 2017 and later, possibly resulting in the need to purchase additional allowances.
Additionally, on September 13, 2019, the D.C. Circuit remanded a portion of the October 2016 CSAPR Update Rule
to the EPA. In December 2018, EPA determined that the 2016 CSAPR Update Rule fully satisfied 20 states
(including Indiana) good neighbor obligations with respect to the 2008 Ozone NAAQS (“CSAPR Close-Out Rule”),
obviating the need for EPA to promulgate Federal Implementation Plans (FIPs) in these states. In October 2019, the
D.C. Circuit vacated and remanded the CSAPR Close-Out Rule. On July 28, 2020, the D.C. Circuit ordered EPA to
issue FIPs addressing seven states’ (including Indiana) outstanding 2008 NAAQS “good neighbor” obligations by
March 15, 2021. On April 30, 2021, EPA published a final rule to address the 2020 D.C. Circuit decision. EPA is issuing new or amended federal implementation plans for 12 states, including Indiana, with revised CSAPR NOx ozone season emission budgets for electric generating units within these states via a new CSAPR NOx Ozone Season Group 3 Trading Program. Implementation began during the 2021 ozone season (May through September 2021) with an effective date of June 29, 2021. AES Indiana facilities will receive fewer ozone season NOx allowances for future NOx Ozone Seasons beginning in 2021 and later, possibly resulting in the need to purchase additional allowances.
At this time we cannot predict what the impact of these rule revisions or potential future legal outcomes, but any such impact could be material to our business, financial condition or results of operation.
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.
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 State Implementation Plan 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 these new ambient standards, but it could be material.
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 will be updated with the requirements of this rule, including any source-specific requirements arising from the evaluation process described above. As a result, 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 - Regulation of Water Discharge
AES Indiana and other utilities at times apply the Nationwide Permit 12 (NWP 12) issued by the U.S. Army Corps of Engineers (Corps) in completing transmission and distribution projects that may involve waters of the U.S. NWP 12 is the nationwide permit for Utility Line Activities, specifically activities required for construction and maintenance, provided the activity does not result in the loss of greater than ½-acre of waters of the U.S. for each single and complete project.
On April 15, 2020, in a proceeding involving the construction of the Keystone XL pipeline, the U.S. District Court for the District of Montana (Montana District Court) vacated NWP 12 and enjoined its application. On July 6, 2020, the U.S. Supreme Court stayed the district court order, allowing the use of NWP 12 for oil and gas pipeline projects except for Keystone XL. On January 13, 2021, the U.S. Army Corps of Engineers published a final rulemaking for the reissuance and modification of NWPs, including NWP 12 relating exclusively to the construction of oil or natural gas pipelines and the new NWP 57 for construction of electric or telecommunication utility lines. It is too early to determine whether future outcomes or decisions related to this matter may have a material impact on our business, financial condition or 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. It is too early to determine whether the Supreme Court decision or the result of litigation to "functional equivalent" may have a material impact on our business, financial condition or results of operations.
Biden Administration Actions Affecting Environmental Regulations
On January 20, 2021, President Biden issued an Executive Order (EO) titled “Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis” directing Agencies to, among other tasks, review regulations issued under the prior Administration to determine whether they should be suspended, revoked, or revised. As provided for by the EO, EPA submitted a letter to DOJ seeking to obtain abeyances or stays of proceedings in pending litigation that seeks review of regulations promulgated during the Trump Administration. The Biden Administration also issued a Memorandum titled “Regulatory Freeze Pending Review” directing Agencies to refrain from proposing or issuing any rules until the Biden Administration has reviewed and approved those rules. These actions may have an impact on regulations that may affect our business, financial condition, or results of operations.
Summary
Environmental laws and regulations presently require us to incur material capital expenditures and operating costs. See “Capital Expenditures” discussion in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Capital Requirements" for additional details regarding our environmental capital projects. We would expect to seek recovery of both capital and operating costs related to such compliance, although there can be no assurances that we would be successful. In addition, environmental laws and regulations are complex, change frequently and have tended to become more stringent over time. As a result, our operating expenses and continuing capital expenditures associated with environmental matters may increase. More stringent standards may also limit our operating flexibility and have a negative impact on our wholesale volumes and margins. Depending on the level and timing of recovery allowed by the IURC, these costs could materially and adversely affect our results of operations, financial condition and cash flows. We may seek recovery of any operating or capital expenditures; however, there can be no assurances that we would be successful.
ENERGY SUPPLY
Approximately 72% of the total kWh we generated in 2021 was from coal as compared to approximately 48% and 58% in 2020 and 2019, respectively. In 2021, coal was a higher percentage of kWh generated due to an extended outage at the Eagle Valley plant, and we expect this percentage to be lower going forward. Our existing coal contracts provide for approximately 100% of our current projected requirements in 2022 and approximately 45% in total for the three-year period ending December 31, 2024. We have long-term coal contracts with three suppliers.
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 within our target range.
Natural gas and fuel oil provided the remaining kWh generation in 2021. Natural gas is used in our steam boiler units at Harding Street Station, our CCGT at Eagle Valley and combustion turbines. 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 interstate pipeline 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 of approximately 75% of the expected consumption at Eagle Valley during the 2022 winter period, which are fixed price. With Eagle Valley currently in outage, we may use the gas supply at Harding Street natural gas generation units or sell the natural gas back versus the daily natural gas index for the respective physical hubs. We do not maintain a natural gas inventory; however, our experience has
been that natural gas is readily available at liquid supply points on interstate pipelines, and we expect this availability to continue in the future. Fuel oil 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 April 2018, the Harding Street Station refueling projects, the retirement of coal-fired units at Eagle Valley in the second quarter of 2016, and the 2021 and future retirement of coal-fired units at Petersburg, we generally have experienced an increase in the percentage of generation from natural gas. Due to outages at the Eagle Valley CCGT this was not the case in 2021, however we expect to continue experiencing an increase in the percentage of generation from natural gas 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 Filing and Replacement Generation” 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 Solar Project.
Additionally, we meet the electricity demands of our retail customers with energy purchased under power purchase agreements and by purchases in MISO. We are 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. 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, 2021. We also purchase up to 8 MW of energy from a combined heat and power facility located in Indianapolis, Indiana.
Total electricity sold to our retail customers in 2021 came from the following sources: 56.2% from AES Indiana-owned coal-fired steam generation, 22.2% from AES Indiana-owned natural gas-fired units, and 21.6% from power purchased under power purchase agreements (primarily wind and solar) and from the wholesale power market.
After the retirements of the Petersburg Units 1 and 2 and the commencement of the Hardy Hills and Petersburg renewable projects, we expect our installed capacity to be approximately 47% from AES Indiana-owned natural gas-fired units, 29% from AES Indiana-owned coal-fired steam generation, 13% from AES Indiana-owned renewable projects, and 11% 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,
2021 2020 2019 2018 2017
Revenues (In Thousands):
Residential $ 607,260 $ 575,329 $ 597,809 $ 592,625 $ 541,055
Small commercial and industrial 212,169 194,904 215,878 217,896 205,473
Large commercial and industrial 541,471 500,208 564,216 565,720 561,194
Public lighting 8,994 9,257 7,335 9,797 9,906
Other(1)
16,785 14,402 14,136 10,427 9,967
Retail electric revenues 1,386,679 1,294,100 1,399,374 1,396,465 1,327,595
Wholesale 25,059 46,482 68,474 38,789 8,574
Miscellaneous 14,394 12,403 13,795 15,251 13,419
Total revenues $ 1,426,132 $ 1,352,985 $ 1,481,643 $ 1,450,505 $ 1,349,588
kWh Sales (In Millions):
Residential 5,172 5,115 5,200 5,335 4,915
Small commercial and industrial 1,774 1,709 1,840 1,907 1,800
Large commercial and industrial 6,006 5,839 6,283 6,558 6,448
Public lighting 21 30 42 51 53
Sales - retail customers 12,973 12,693 13,365 13,851 13,216
Wholesale 908 1,866 2,718 1,241 268
Total kWh sold 13,881 14,559 16,083 15,092 13,484
Retail Customers at End of Year:
Residential 455,756 451,735 448,210 443,184 439,741
Small commercial and industrial 55,078 54,253 53,751 49,239 48,684
Large commercial and industrial 4,506 4,567 4,635 4,680 4,705
Public lighting 983 986 980 976 959
Total retail customers 516,323 511,541 507,576 498,079 494,089
(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” 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 could result in unscheduled plant outages, unanticipated operation and/or maintenance expenses, increased fuel or purchased power costs and other significant liabilities for which we may not have adequate insurance coverage.
We operate coal, oil and natural gas generating facilities, 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 Fuel Adjustment Charge (“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.
The current outbreak of the novel coronavirus, or COVID-19, has adversely affected, and it or the future outbreak of any other highly infectious or contagious diseases could materially and adversely affect, our generation facilities, transmission and distribution systems, results of operations, financial condition and cash flows. Further, the spread of the COVID-19 outbreak has caused disruptions in the U.S. and global economy and financial markets and could potentially create widespread business continuity issues of an as yet unknown magnitude and duration.
In December 2019, a novel strain of coronavirus (COVID-19) was reported to have surfaced in Wuhan, China. COVID-19 has since spread to over 150 countries, including every state in the U.S. On March 11, 2020 the World Health Organization declared COVID-19 a pandemic, and on March 13, 2020 the U.S. declared a national emergency with respect to COVID-19.
The outbreak of COVID-19 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 addition to reduced revenues and lower margins resulting from decreased energy demand within our service territory, we also have incurred and expect to continue to incur expenses relating to COVID-19, including expenses relating to events outside of our control. The impact of the outbreak continues to evolve and many countries, including the U.S., have implemented various types of social distancing and other measures to address the outbreak. 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.
We continue to review and modify our plans as conditions change. Despite our efforts to manage and remedy these impacts to the Company, their ultimate impact also depends on factors beyond our knowledge or control, including the duration and severity of this outbreak as well as third-party actions taken to contain its spread and mitigate its public health effects.
COVID-19 continues to 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.
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 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 availability and cost of fuel and other commodities have experienced and could continue to experience significant volatility and we may not be able to hedge the entire exposure of our operations from availability and price volatility. In addition, a significant amount of our electricity is generated by coal.
Our business is sensitive to changes in the price of coal, natural gas, 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.
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 72% of the energy we produced in 2021 was generated by coal as compared to approximately 48% and 58% in 2020 and 2019, respectively. While we have approximately 45% in total of our current coal requirements for the three-year period ending December 31, 2024 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 significant 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, 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 revenues 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 revenues 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, 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. As interest rates decrease, the discounted liabilities increase benefit expense and funding requirements. Further, changes in demographics, including increased numbers of retirements or changes in life expectancy assumptions, may also increase the funding requirements for the obligations related to the pension and other postemployment benefit plans. Declines in market values and increased funding requirements could have a material adverse effect on our results of operations, financial condition and cash flows. Please see Note 9, “Benefit Plans” to the Financial Statements of this Annual Report on Form 10-K for further discussion.
Counterparties providing materials or services may fail to perform their obligations, which could materially and adversely impact our results of operations, financial condition and cash flows.
We enter into transactions with and rely on many counterparties in connection with our business, including for the purchase and delivery of inventory, including fuel and equipment components, for our capital improvements and additions and to provide professional services, such as actuarial calculations, payroll processing and various consulting services. If any of these counterparties fails to perform its obligations to us or becomes unavailable, our business plans may be materially disrupted, we may be forced to discontinue or delay certain operations if a cost-effective alternative is not readily available or we may be forced to enter into alternative arrangements at then-current market prices that may exceed our contractual prices and cause delays. Although our agreements are designed to mitigate the consequences of a potential default by the counterparty, our actual exposure may be greater than the relief provided by these mitigation provisions. Any of the foregoing could result in regulatory actions, cost overruns, delays or other losses, any of which (or a combination of which) could have a material adverse effect on our results of operations, financial condition and cash flows.
Further, our construction program calls for extensive expenditures for capital improvements and additions, including the installation of environmental upgrades, 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.
Accidental improprieties and undetected errors in our internal controls and information reporting could result in the disallowance of cost recovery, noncompliant disclosure 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, unanticipated and unauthorized actions of employees, temporary lapses in internal controls due to shortfalls in oversight or resource constraints could lead to improprieties and undetected errors that could result in the disallowance of cost recovery, noncompliant disclosure and reporting or incorrect payment processing. The consequences of these events could have a material adverse effect on our results of operations, financial condition and cash flows.
If we are unable to maintain a qualified and properly motivated workforce, it could have a material adverse effect on our results of operations, financial condition and cash flows.
One of the challenges we face is to retain a skilled, efficient and cost-effective workforce while recruiting new talent to replace losses in knowledge and skills due to resignations, terminations or retirements. This undertaking could require us to make additional financial commitments and incur increased costs. If we are unable to successfully attract and retain an appropriately qualified workforce, it could have a material adverse effect on our results of operations, financial condition and cash flows. In addition, we have employee compensation plans that reward the performance of our employees. We seek to ensure that our compensation plans encourage acceptable levels for risk and high performance through pay mix, performance metrics and timing. We also have policies and procedures in place to mitigate potential excessive risk-taking by employees to achieve performance targets which could result in events that could have a material adverse effect on our results of operations, financial condition and cash flows.
We are subject to collective bargaining agreements that could adversely affect our business, results of operations, financial condition and cash flows.
We are subject to collective bargaining agreements with employees who are members of a union. Approximately 69% 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 cyber-security 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 cyber-security attacks and other
causes. 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. 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 cyber-security 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 cyber-security 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 revenues 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 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.
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 2021, AES Indiana emitted approximately 11 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. In addition, in July 2019, the EPA published the final ACE Rule along with associated revisions to implementing regulations, which established CO2 emission rules for existing power plants under CAA Section 111(d) and replaced the EPA's 2015 CPP, although the D.C. Circuit vacated and remanded the ACE Rule in January 2021. In addition, it is likely that there will be increased focus on climate change from a President Biden administration and a Democrat-controlled U.S. Congress, both of which may result in additional legislation and regulations regarding GHG emissions.
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 2021, the international community gathered in Glasgow at the 26th Conference to the Parties on the UN Framework Convention on Climate Change (“COP26”), during which multiple announcements were made, including a call for parties to eliminate certain fossil fuel subsidies and pursue further action on non-carbon dioxide GHGs.
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, the price and availability of offsets, the extent to which market-based compliance options are 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 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 revenues. In addition, while revenues 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 revenues 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 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, cyber security, 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 7, “Debt” to the Financial Statements of this Annual Report on Form 10-K for information regarding indebtedness. See also “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” for information related to market risks.
The level of our indebtedness, and the security provided for this indebtedness, could adversely affect our financial flexibility.
As of December 31, 2021, we had on a consolidated basis $2,731.9 million of indebtedness, including finance lease obligations, and total common shareholders’ equity of $794.6 million. AES Indiana had $1,803.8 million of first mortgage bonds outstanding as of December 31, 2021, which are secured by the pledge of substantially all of the assets of AES Indiana under the terms of AES Indiana’s mortgage and deed of trust. This level of indebtedness and related security has important consequences, including the following:
•increasing our vulnerability to general adverse economic and industry conditions;
•requiring us to dedicate a substantial portion of our cash flow from operations to make payments on our indebtedness, thereby reducing the availability of our cash flow to fund other corporate purposes;
•limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and
•limiting, along with the financial and other restrictive covenants in our indebtedness, our ability to borrow additional funds, as needed.
We expect to incur additional debt in the future, subject to the terms of our debt agreements and regulatory approvals for any AES Indiana debt. To the extent we become more leveraged, the risks described above would increase. Further, actual cash requirements in the future may be greater than expected. Accordingly, our cash flow from operations may not be sufficient to repay at maturity all of the outstanding debt as it becomes due and, in that event, we may not be able to borrow money, sell assets or otherwise raise funds on acceptable terms or at all to refinance our debt as it becomes due. For a further discussion of outstanding debt, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources” and Note 7, “Debt” to the Financial Statements of this Annual Report on Form 10-K.
We have variable rate debt that bears interest based on a prevailing rate that is reset based on a market index that can be affected by market demand, supply, market interest rates and other market conditions. We also maintain both cash on deposit and investments in cash equivalents from time to time that could be impacted by interest rate fluctuations. As such, any event which impacts market interest rates could have a material effect on our results of operations, financial condition and cash flows. In addition, ratings agencies issue credit ratings on us and our debt that affect our borrowing costs under our financial arrangements and affect our potential pool of investors and funding sources. Our credit ratings also govern the collateral provisions of certain of our contracts. If rating agencies downgrade our credit ratings, our borrowing costs would likely further increase, our potential pool of investors and funding resources could be reduced, and we could be required to post additional cash collateral under selected contracts. These events would likely reduce our liquidity and profitability and could have a material adverse effect on our results of operations, financial condition and cash flows.
IPALCO is a holding company and parent of AES Indiana and other subsidiaries. IPALCO’s cash flow is dependent on operating cash flows of AES Indiana and its ability to pay cash to IPALCO.
IPALCO is a holding company with no material assets other than the common stock of its subsidiaries, and accordingly all cash is generated by the operating activities of our subsidiaries, principally AES Indiana. As such, IPALCO’s cash flow is largely dependent on the operating cash flows of AES Indiana and its ability to pay cash to IPALCO. AES Indiana’s mortgage and deed of trust, its amended articles of incorporation and its Credit Agreement contain restrictions on AES Indiana’s ability to issue certain securities or pay cash dividends to IPALCO. For example, there are restrictions that require maintenance of a leverage ratio which could limit the ability of AES Indiana to pay dividends. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity” for a discussion of these restrictions. See Note 7, “Debt” to the Financial Statements of this Annual Report on Form 10-K for information regarding indebtedness. In addition, AES Indiana is regulated by the IURC, which possesses broad oversight powers to ensure that the needs of utility customers are being met. The IURC could impose additional restrictions on the ability of AES Indiana to distribute, loan or advance cash to IPALCO pursuant to these broad powers. While we do not expect any of the foregoing restrictions to significantly affect AES Indiana’s ability to pay funds to IPALCO in the future, a significant limitation on AES Indiana’s ability to pay dividends or loan or advance funds to IPALCO would have a material adverse effect on IPALCO’s results of operations, financial condition and cash flows.
Our ownership by AES subjects us to potential risks that are beyond our control.
All of AES Indiana’s common stock is owned by IPALCO, all of whose common stock is owned by AES U.S. Investments (82.35%) and CDPQ (17.65%). Due to our relationship with AES, any adverse developments and announcements concerning AES may impair our ability to access the capital markets and to otherwise conduct business. In particular, downgrades in AES’s credit ratings could result in AES Indiana’s or IPALCO’s credit ratings being downgraded.

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

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ITEM 2. PROPERTIES
ITEM 2. PROPERTIES
Information relating to our properties is contained in “Item 1. Business - Properties.”
Mortgage Financing on Properties
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 $1,803.8 million at December 31, 2021. 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.

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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 PURCHASE OF EQUITY SECURITIES
As of February 28, 2022, 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, 2021, 2020 and 2019, we declared and paid distributions to our shareholders totaling $131.5 million, $108.7 million and $136.4 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.
Dividend 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. As of December 31, 2021, 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, 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, 2021, 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, 2021, 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. SELECTED FINANCIAL DATA
The following table presents our selected consolidated financial data which should be read in conjunction with our Financial Statements of this Annual Report on Form 10-K and the related notes thereto and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The “Results of Operations” discussion in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” addresses significant fluctuations in operating data. IPALCO is owned by AES U.S. Investments and CDPQ, and therefore does not report earnings or dividends on a per-share basis. Other data that management believes is important in understanding trends in our business is also included in this table.
Years Ended December 31,
2021 2020 2019 2018 2017
(In Thousands)
Statement of Operations Data:
Revenues $ 1,426,132 $ 1,352,985 $ 1,481,643 $ 1,450,505 $ 1,349,588
Operating income $ 250,670 $ 262,532 $ 296,752 $ 236,358 $ 239,198
Earnings from operations before income tax $ 148,123 $ 138,559 $ 167,921 $ 147,474 $ 157,744
Net income $ 119,182 $ 109,967 $ 132,393 $ 134,025 $ 108,793
Balance Sheet Data (end of period):
Total assets $ 5,239,767 $ 4,969,919 $ 4,928,669 $ 4,862,053 $ 4,740,561
Long-term debt (less current maturities) $ 2,671,656 $ 2,556,278 $ 2,092,430 $ 2,649,064 $ 2,477,538
Common shareholders’ equity $ 794,600 $ 520,988 $ 546,476 $ 573,266 $ 572,276
Cumulative preferred stock of subsidiary $ 59,784 $ 59,784 $ 59,784 $ 59,784 $ 59,784
Other Data:
Capital expenditures(1)
$ 291,546 $ 235,736 $ 219,242 $ 235,764 $ 228,861
(1)Capital expenditures includes $0.0 million, $0.0 million, $5.6 million, $11.4 million and $10.6 million of payments for financed capital expenditures in 2021, 2020, 2019, 2018 and 2017, respectively.

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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 abbreviations or acronyms in this discussion, see “Defined Terms” at the beginning of this Form 10-K.
EXECUTIVE SUMMARY
Compared with the prior year, the results for the year ended December 31, 2021 reflect higher earnings from operations before income tax of $9.6 million, or 7%, primarily due to factors including, but not limited to:
•a net increase in margin due to higher volumes of retail kWh sold mostly due to favorable weather and higher weather-normalized demand resulting from unfavorable demand impacts of the COVID-19 pandemic in the prior year;
•higher DSM shared savings and lost revenue recoveries; and
•lower pension costs.
These were partially offset by:
•an increase in operation and maintenance expenses,
See "Results of Operations" below for further discussion.
OVERVIEW OF 2021 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, 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 non-injury near misses. Our lagging safety metrics track lost workday cases, severity rate, and recordable incidents. We are committed to excellence in safety and have implemented various programs to increase safety awareness and improve work practices.
AES Indiana measures delivery reliability by Customer Average Interruption Duration Index ("CAIDI"), System Average Interruption Duration Index ("SAIDI") and System Average Interruption Frequency Index ("SAIFI") and benchmarks the reliability metrics against other utilities at both the state and national levels. AES Indiana also measures customer centricity on more of an individual basis by the industry metric of Customers that Experience
Multiple Interruption of five or more times ("CEMI-5"). AES Indiana measures generation reliability by Commercial Availability (“CA”), Equivalent Forced Outage Factor (“EFOF”) and Equivalent Availability Factor (“EAF”) metrics and benchmarks both EFOF and EAF results nationally. We measure Customer Satisfaction using J.D. Power in their Electric Utility Residential Customer Satisfaction Study and Research America Market Research - Consumer Insight. Monitoring performance in the areas such as competitive rates, operational reliability and customer service supports our ongoing work to deliver reliable service to our customers.
RESULTS OF OPERATIONS
The following review of consolidated results of operations and "Capital Resources and Liquidity" sections compare the results for the year ended December 31, 2021 to the results for the year ended December 31, 2020. For discussion comparing the results for the year ended December 31, 2020 to the results for the year ended December 31, 2019, see Item 7.-Management's Discussion and Analysis of Financial Condition and Results of Operations of our 2020 Annual Report on Form 10-K, filed with the SEC on February 24, 2021.
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.
Statements of Operations Highlights
Years Ended December 31, Change 2021 vs. 2020 Change 2020 vs. 2019
(In Thousands) 2021 2020 2019 $ % $ %
REVENUES $ 1,426,132 $ 1,352,985 $ 1,481,643 $ 73,147 5.4 % $ (128,658) (8.7) %
OPERATING COSTS AND EXPENSES:
Fuel 255,817 247,105 340,466 8,712 3.5 % (93,361) (27.4) %
Power purchased 175,025 135,767 133,674 39,258 28.9 % 2,093 1.6 %
Operation and maintenance 449,746 416,169 428,201 33,577 8.1 % (12,032) (2.8) %
Depreciation and amortization 256,085 246,896 240,314 9,189 3.7 % 6,582 2.7 %
Taxes other than income taxes 44,419 44,516 42,236 (97) (0.2) % 2,280 5.4 %
Other, net (5,630) - - (5,630) - % - - %
Total operating costs and expenses 1,175,462 1,090,453 1,184,891 85,009 7.8 % (94,438) (8.0) %
OPERATING INCOME 250,670 262,532 296,752 (11,862) (4.5) % (34,220) (11.5) %
OTHER INCOME / (EXPENSE), NET:
Allowance for equity funds used during construction 5,412 4,574 3,486 838 18.3 % 1,088 31.2 %
Interest expense (125,626) (129,493) (121,771) 3,867 (3.0) % (7,722) 6.3 %
Loss on early extinguishment of debt - (2,424) - 2,424 (100.0) % (2,424) - %
Other income / (expense), net 17,667 3,370 (10,546) 14,297 424.2 % 13,916 (132.0) %
Total other income / (expense), net (102,547) (123,973) (128,831) 21,426 (17.3) % 4,858 (3.8) %
EARNINGS FROM OPERATIONS BEFORE INCOME TAX 148,123 138,559 167,921 9,564 6.9 % (29,362) (17.5) %
Less: income tax expense 28,941 28,592 35,528 349 1.2 % (6,936) (19.5) %
NET INCOME 119,182 109,967 132,393 9,215 8.4 % (22,426) (16.9) %
Less: dividends on preferred stock 3,213 3,213 3,213 - - % - - %
NET INCOME APPLICABLE TO COMMON STOCK $ 115,969 $ 106,754 $ 129,180 $ 9,215 8.6 % $ (22,426) (17.4) %
Revenues
Revenues increased in 2021 from the prior year by $73.1 million, which resulted from the following changes (dollars in thousands):
2021 2020 Change % Change
Revenues:
Retail Revenues $ 1,386,679 $ 1,294,100 $ 92,579 7.2 %
Wholesale Revenues 25,059 46,482 (21,423) (46.1) %
Miscellaneous Revenues 14,394 12,403 1,991 16.1 %
Total Revenues $ 1,426,132 $ 1,352,985 $ 73,147 5.4 %
Heating Degree Days(1):
Actual 4,946 4,905 41 0.8 %
30-year Average 5,250 5,245
Cooling Degree Days(1):
Actual 1,308 1,192 116 9.7 %
30-year Average 1,152 1,154
(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:
2021 2020 kWh Change % Change
kWh Sales (In Millions):
Residential 5,172 5,115 57 1.1 %
Small commercial and industrial 1,774 1,709 65 3.8 %
Large commercial and industrial 6,006 5,839 167 2.9 %
Public lighting 21 30 (9) (30.0) %
Sales - retail customers 12,973 12,693 280 2.2 %
Wholesale 908 1,866 (958) (51.3) %
Total kWh sold 13,881 14,559 (678) (4.7) %
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, 2021 as compared to the prior year:
The increase in revenues of $73.1 million was primarily due to the following:
$ in millions 2021 vs. 2020
Retail revenues:
Volume:
Net increase in the volume of kWh sold, primarily due to favorable weather in our service territory versus the comparable period and higher weather-normalized demand attributable to the unfavorable demand impacts of the COVID-19 pandemic in the prior year $ 24.8
Price:
Net increase in the weighted average price of retail kWh sold, primarily due to higher fuel revenues, higher Off System Sales Margin rider revenues. and higher TDSIC rider revenues, partially offset by unfavorable block rate(1) and other retail rate variances
54.9
Other:
Mostly due to increases in alternative revenue programs as a result of higher DSM shared savings and lost revenue recoveries
12.9
Net change in retail revenues 92.6
Wholesale revenues:
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 (23.9)
Price:
Net increase in the weighted average price of wholesale kWh sold. Our ability to be dispatched in the MISO market is primarily driven by the locational marginal price of electricity and variable generation costs. 2.4
Net change in wholesale revenues (21.5)
Miscellaneous revenues 2.0
Net change in revenues $ 73.1
(1)Block rate variances are primarily attributable to 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 and vice versa.
Operating Costs and Expenses
The following table illustrates changes in Operating costs and expenses from 2020 to 2021 (in thousands):
Years Ended
December 31,
2021 2020 $ Change % Change
Operating costs and expenses:
Fuel $ 255,817 $ 247,105 $ 8,712 3.5 %
Power purchased 175,025 135,767 39,258 28.9 %
Operation and maintenance 449,746 416,169 33,577 8.1 %
Depreciation and amortization 256,085 246,896 9,189 3.7 %
Taxes other than income taxes 44,419 44,516 (97) (0.2) %
Other, net (5,630) - (5,630) - %
Total operating costs and expenses $ 1,175,462 $ 1,090,453 $ 85,009 7.8 %
Fuel
The increase in fuel costs of $8.7 million was primarily due to the following:
$ in millions 2021 vs. 2020
Volume:
Coal $ 44.0
Natural gas (49.2)
Oil 0.1
Net change in volume (5.1)
Price:
Coal 7.0
Natural gas 80.1
Oil 0.4
Deferred fuel (73.7)
Net change in price 13.8
Net change in fuel expense $ 8.7
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. For further discussion, 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. Additionally, fuel and purchased power costs incurred for wholesale energy sales are considered in the Off System Sales Margin rider.
Power Purchased
The increase in purchased power costs of $39.3 million was primarily due to the following:
$ in millions 2021 vs. 2020
Net change in the volume of power purchased primarily due to AES Indiana's generation units running less frequently, as well as the timing and duration of outages during these respective periods $ 41.1
Net change in the price of power purchased is primarily due to timing of FAC deferrals and amortization, variances in market prices, and changes in mix of contracted renewable and market power purchases
(1.5)
Other, net (0.3)
Net change in power purchased costs $ 39.3
The volume of power purchased each period is primarily influenced by retail demand, generating unit capacity and outages, and the relative cost of producing power versus purchasing power in the market. The increase in the volume of power purchased during 2021 is mostly attributed to lower unit availability due to the timing and duration of outages, primarily an extended outage at Eagle Valley that began earlier in 2021 and currently remains in progress. The Eagle Valley CCGT has been on unplanned outage since late April 2021, impacting several FAC periods. The IURC has initiated an ongoing sub-docket in FAC-133 (IURC Cause No. 38703-FAC-133 S1) to examine the impact of the Eagle Valley extended outage. Recovery of the increased volume of power purchased during 2021 is subject to approval by the IURC. 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. The market price of purchased power is influenced primarily by changes in the market price of delivered fuel (primarily natural gas), the supply of and demand for electricity, and the time of day during which power is purchased.
Operation and Maintenance
The increase in Operation and maintenance expense of $33.6 million was primarily due to the following:
$ in millions 2021 vs. 2020
Increase in maintenance expenses primarily due to the timing of plant-related projects and increased outage costs
$ 10.8
Increase in contracted services expenses primarily due to storm costs 6.0
Increase in chemical expenses 3.0
Increase in insurance premiums 2.9
Increase in charges from the Service Company 2.8
Increase in compensation expenses, primarily pension service cost 2.7
Increase in write-offs of obsolete materials and supplies inventory 1.9
Increase in MISO non-purchased power costs (primarily transmission related expenses) 1.4
Other, net 2.1
Net change in operation and maintenance costs $ 33.6
Depreciation and Amortization
The increase in Depreciation and amortization expense of $9.2 million was mostly attributed to the impact of additional assets placed in service.
Other, Net
The change in Other, net of $5.6 million was attributed to a gain on acquisition for the difference between the consideration transferred and the assets and liabilities recognized related to the Hardy Hills Solar Project. See Note 2, "Regulatory Matters - IRP Filing and Replacement Generation - Hardy Hills Solar Project " to the Financial Statements of this Annual Report on Form 10-K for more information.
Other Income / (Expense), Net
The following table illustrates changes in Other income / (expense), net from 2020 to 2021 (in thousands):
Years Ended
December 31,
2021 2020 $ Change % Change
Other income/(expense), net
Allowance for equity funds used during construction $ 5,412 $ 4,574 $ 838 18.3 %
Interest expense (125,626) (129,493) 3,867 (3.0) %
Loss on early extinguishment of debt - (2,424) 2,424 (100.0) %
Other income / (expense), net 17,667 3,370 14,297 424.2 %
Total other income/(expense), net $ (102,547) $ (123,973) $ 21,426 (17.3) %
Interest Expense
The decrease in Interest expense of $3.9 million was primarily due to increased capitalized interest.
Loss on Early Extinguishment of Debt
The decrease in Loss on Early Extinguishment of Debt of $2.4 million was primarily due to a make-whole premium and write-off of deferred financing costs due to the redemption of $405 million of 2020 IPALCO Notes and $65 million IPALCO Term Loan in the second quarter of 2020.
Other Income/(Expense), Net
The increase in Other income/(expense), net of $14.3 million was primarily due to an increase in defined benefit plan income of $14.2 million due to lower interest cost and a a higher expected return on plan assets compared to the prior year.
KEY TRENDS AND UNCERTAINTIES
During 2022 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.
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.
COVID-19 Pandemic
The COVID-19 pandemic has impacted global economic activity, including electricity and energy consumption, and caused significant volatility in financial markets. Responses to the COVID-19 pandemic by the State of Indiana and its residents and businesses continue to evolve as virus variants emerge, vaccine availability and usage continues and the State and businesses review and adjust the scope and requirements of social distancing measures.
Social distancing measures designed to slow the spread of the virus, such as business closures and operations limitations, impact energy demand within our service industry. In addition to the impacts to demand within our
service territory, we also have incurred and expect to continue to incur expenses relating to COVID-19, and such expenses may include those that relate to events outside of our control. We experienced impacts from the pandemic in 2021 and into 2022 and expect to continue to experience impacts for the remainder of 2022. The following discussion highlights our assessment of the impacts of the COVID-19 pandemic on our current financial and operating status, and our financial and operational outlook based on information known as of this filing. Any impacts in future periods could have material and adverse effects on our results of operations, financial condition and cash flows. Also see "Item 1A. Risk Factors" of this Annual Report on Form 10-K.
Business Continuity - During the COVID-19 pandemic, we are taking a variety of measures to ensure our ability to generate, transmit, distribute and sell electric energy, to ensure the health and safety of our employees, contractors, customers and communities and to provide essential services to the communities in which we operate. We continue to respond to this global crisis through comprehensive measures to protect our employees and others while fulfilling our vital role in providing our customers with electric energy. While stay-at-home restrictions have been lifted in our service territory, most of our management and administrative personnel are able to work remotely, and we have not experienced significant issues affecting our operations or ability to maintain effective internal controls and produce reliable financial information. We prioritize the safety of our people and continue to develop targeted strategies, in line with legal and regulatory requirements, to promote vaccination in our business.
Demand - As the economic impact of the COVID-19 pandemic started to materialize in Indiana in March 2020 and continued for the duration of 2020 and into 2021, the COVID-19 pandemic primarily impacted our retail sales demand. Retail sales demand decreased in 2020 mostly from small and large commercial and industrial customers, but started to recover in 2021 as shown by the changes in weather-normalized volumes of kWh sold by customer class as follows:
For the three For the three For the three For the three For the
months ended months ended months ended months ended year ended
March 31, June 30, September 30, December 31, December 31,
Customer Class 2021 vs. 2020 2020 vs. 2019 2021 vs. 2020 2020 vs. 2019 2021 vs. 2020 2020 vs. 2019 2021 vs. 2020 2020 vs. 2019 2021 vs. 2020 2020 vs. 2019
Residential (0.9) % 1.6 % (3.3) % 6.6 % (0.5) % 3.9 % (1.9) % 2.4 % (1.5) % 3.4 %
Small commercial and industrial (1.8) % (1.8) % 8.2 % (10.3) % 3.4 % (4.2) % 0.8 % (5.3) % 2.3 % (5.2) %
Large commercial and industrial (4.1) % (2.8) % 7.9 % (11.0) % 3.0 % (7.9) % 3.8 % (5.7) % 2.6 % (6.9) %
Total (2.4) % (0.8) % 3.6 % (4.9) % 1.6 % (3.1) % 0.9 % (2.5) % 0.8 % (2.8) %
As noted above, we also have incurred and expect to continue to incur expenses relating to COVID-19, however see Note 2, “Regulatory Matters - IURC COVID-19 Orders” to the Financial Statements of this Annual Report on Form 10-K for a discussion of regulatory measures which partially mitigate the impact of these expenses. While we have continued to experience COVID-19 impacts into 2022, we continue to expect that such impacts would not be material, particularly if less expansive social distancing measures and improvements in energy demand continue. The magnitude and duration of the COVID-19 pandemic is unknown at this time, however, and could have material and adverse effects on our results of operations, financial condition and cash flows in future periods.
Liquidity - We anticipate continuing to have sufficient liquidity to make all required payments, including payments for salaries and wages owed to our employees, during the COVID-19 pandemic. We also continue to not foresee a significant impact to our access to capital or our liquidity position as a result of the COVID-19 pandemic. For further discussion of our financial condition, liquidity, and 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.
Credit Exposures - We continue to monitor and manage our credit exposures in a prudent manner. During the year ended December 31, 2020, we experienced credit-related impacts from utility customers due to the prohibition of electric utilities, including us, from discontinuing electric utility service to customers (prohibition ended August 14, 2020), and due to the economic impacts of the COVID-19 pandemic. AES Indiana implemented and continues to offer extended payment plans to customers during the pandemic. In 2021, collections improved and credit-related impacts were not significant. See Note 1, "Overview and Summary of Significant Accounting Policies - Accounts Receivable" for further discussion of our allowance for credit losses. If credit-related impacts from the COVID-19 pandemic occur in 2022 or beyond, deterioration in our credit exposures and customer collections may result. See Note 2, “Regulatory Matters - IURC COVID-19 Orders” to this Annual Report on Form 10-K for a discussion of regulatory measures which mitigate this impact.
Supply Chain - We continue to closely manage and monitor developments in our supply chain. We are experiencing some indications of delays and price increases. The cost of fuel for example, specifically coal and natural gas, has risen and may remain at current levels or continue to rise through the winter months and further into 2022. 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.
Capital Projects - During the COVID-19 pandemic, our construction projects have experienced some indications of delays and price increases; 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.
CARES Act - The Coronavirus Aid, Relief, and Economic Security (“CARES”) Act was passed by the U.S. Congress and signed into law on March 27, 2020. While we currently expect a limited impact from this legislation on our business, we have deferred the payment of federal payroll taxes in accordance with the provisions of this act. As a result of this act, we deferred a total of approximately $5.0 million, of which $2.7 million remained unpaid as of December 31, 2021.
See Note 15, "Risks and Uncertainties" to the Financial Statements and "Item 1A. Risk Factors" of this Annual Report on Form 10-K for more information.
Operational
As part of AES Indiana's December 2019 Integrated Resource Plan filing, AES Indiana retired 230 MW Petersburg Unit 1 on May 31, 2021 and has plans to retire 415 MW Petersburg Unit 2 in 2023. AES Indiana issued an all-source request for proposal to competitively procure replacement capacity by June 1, 2023, which is the first year AES Indiana is expected to have a capacity shortfall. In December 2021, AES Indiana completed the acquisition of the Hardy Hills Solar Project, which is a 195 MW solar project to be developed and expected to commence operations in 2023. AES Indiana received an order from the IURC approving the project on June 16, 2021. In July 2021, AES Indiana executed an agreement to acquire the Petersburg Solar Project, which is a 250 MW solar and 180 MWh energy storage facility expected to commence operations in 2024, and on November 24, 2021, AES Indiana received an order from the IURC approving the project.
In January 2022, AES Indiana held its first public advisory meeting for the 2022 IRP. In February 2022, AES announced its intent to exit coal generation by year-end 2025 versus prior expectation of a reduction to below 10% by year-end 2025, subject to necessary approvals. Changes to AES Indiana's generation portfolio are evaluated and decided through the IRP.
For further discussion, see Note 2, "Regulatory Matters - IRP Filing and Replacement Generation" to the Financial Statements of this Annual Report on Form 10-K.
Regulatory Environment
For a discussion of the regulatory environment related to our business, see “Item 1. Business - Regulation” and Note 2, “Regulatory Matters” to the Financial Statements of this Annual Report on Form 10-K.
Macroeconomic and Political
Reference Rate Reform
In July 2017, the UK Financial Conduct Authority announced that it intends to phase out LIBOR by the end of 2021. In the U.S., the Alternative Reference Rate Committee at the Federal Reserve identified the Secured Overnight Financing Rate ("SOFR") as its preferred alternative rate for LIBOR; alternative reference rates in other key markets are under development. On November 30, 2020, the ICE Benchmark Association ("IBA") announced it had begun consultation on its intention to cease publication of two specific LIBOR rates by December 31, 2021, while extending the timeline for the overnight, one-month, three-month, six-month, and 12-month USD LIBOR rates through June 30, 2023. The IBA expects to make separate announcements in this regard following the outcome of
the consultation. We maintain financial instruments that use LIBOR as an interest rate benchmark and will continue to engage with counterparties to make this transition.
Inflation
In the markets in which we operate, there have been higher rates of inflation in recent months. 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.
CAPITAL RESOURCES AND LIQUIDITY
As of December 31, 2021, we had unrestricted cash and cash equivalents of $6.9 million and available borrowing capacity of $190 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 $500 million of short-term indebtedness outstanding at any time through July 26, 2022. 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, all of which authority remains available under the order as of December 31, 2021. 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 $500 million remains available under the order as of December 31, 2021. 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, 2021. 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.
AES Indiana First Mortgage Bonds
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. For further discussion, please see Note 7, “Debt - AES Indiana First Mortgage Bonds” to the Financial Statements of this Annual Report on Form 10-K.
In December 2020, the Indiana Finance Authority issued on behalf of AES Indiana an aggregate principal amount of $90 million of Environmental Facilities Refunding Revenue Bonds, Series 2020A&B due December 2038. For further discussion, please see Note 7, " Debt - AES Indiana First Mortgage Bonds" to the Financial Statements of this Annual Report on Form 10-K.
IPALCO’s Senior Secured Notes and Term Loan
In April 2020, IPALCO completed the sale of the $475 million 2030 IPALCO Notes priced at 4.25%, with the net proceeds from this offering used to retire the Term Loan on April 14, 2020. The remaining net proceeds, together with cash on hand, were used to redeem the 2020 IPALCO Notes on May 14, 2020, and to pay certain related fees, expenses and make-whole premiums. For further discussion, please see Note 7, “Debt - IPALCO's Senior Secured Notes and Term Loan” to the Financial Statements of this Annual Report on Form 10-K.
Cash Flows
The following table provides a summary of our cash flows:
Years ended December 31, $ Change
2021 2020 2019 2021 vs. 2020
(in thousands) (in thousands)
Net cash provided by operating activities $ 225,217 $ 295,425 $ 397,815 $ (70,208)
Net cash used in investing activities (368,715) (275,769) (237,448) (92,946)
Net cash provided by (used in) financing activities 123,793 (41,586) (145,414) 165,379
Net change in cash and cash equivalents (19,705) (21,930) 14,953 2,225
Cash, cash equivalents and restricted cash at beginning of period 26,622 48,552 33,599 (21,930)
Cash and cash equivalents at end of period $ 6,917 $ 26,622 $ 48,552 $ (19,705)
2021 versus 2020
Operating Activities
The following table summarizes the key components of our consolidated operating cash flows:
Years ended December 31, $ Change
2021 2020 2019 2021 vs. 2020
(in thousands) (in thousands)
Net income $ 119,182 $ 109,967 $ 132,393 $ 9,215
Depreciation and amortization 256,085 246,896 240,314 9,189
Amortization of debt premium 3,915 3,942 4,109 (27)
Deferred income taxes and investment tax credit adjustments (7,378) 2,854 15,277 (10,232)
Loss on early extinguishment of debt - 2,424 - (2,424)
Allowance for equity funds used during construction (5,412) (4,574) (3,486) (838)
Gain on acquisition (5,630) - - (5,630)
Net income, adjusted for non-cash items 360,762 361,509 388,607 (747)
Net change in operating assets and liabilities (135,545) (66,084) 9,208 (69,461)
Net cash provided by operating activities $ 225,217 $ 295,425 $ 397,815 $ (70,208)
The net change in operating assets and liabilities for the year ended December 31, 2021 compared to the year ended December 31, 2020 was driven by the following (in thousands):
Decrease from short-term and long-term regulatory assets and liabilities is primarily due to higher deferred fuel expense in 2021 $ (91,369)
Decrease from accrued and other current liabilities primarily due to current year legal settlements (13,466)
Decrease from higher accounts receivable balances primarily due to higher current year revenue and timing of collections (9,840)
Increase from accounts payable due to timing of payments 41,739
Other 3,475
Net change in operating assets and liabilities $ (69,461)
Investing Activities
Net cash used in investing activities increased $92.9 million for the year ended December 31, 2021 compared to the year ended December 31, 2020, which was primarily driven by (in thousands):
Higher cash outflows for capital expenditures due to higher growth related capital expenditures primarily from TDSIC Plan investments, partially offset by lower maintenance and environmental related capital expenditures $ (55,810)
Higher cash outflows from purchase of intangibles in 2021 (26,261)
Higher cash outflows on cost of removal and regulatory recoverable ARO payments due to timing of such payments (11,166)
Other 291
Net change in investing activities $ (92,946)
Financing Activities
Net cash used in financing activities decreased $165.4 million for the year ended December 31, 2021 compared to the year ended December 31, 2020, which was primarily driven by (in thousands):
Increase from equity capital contributions of $226.5 million from AES U.S. Investments and $48.5 million from CDPQ for funding needs related to AES Indiana’s TDSIC and replacement generation projects
$ 275,000
Decrease from net borrowings under revolving credit facilities due to higher net repayments on AES Indiana's line of credit in 2021 (90,000)
Higher distributions to shareholders (22,737)
Other 3,116
Net change in financing activities $ 165,379
Capital Requirements
Capital Expenditures
Our capital expenditure program, including development and permitting costs, for the three-year period from 2022 through 2024 is currently estimated to cost approximately $1.8 billion (excluding environmental compliance), and includes estimates as follows (amounts in millions):
For the three-year period
2022 2023 2024 from 2022 through 2024
Transmission and distribution related additions, improvements and extensions $ 157 $ 112 $ 117 $ 386 (1)
TDSIC Plan investments 176 188 165 529 (2)
Power generation related projects 493 249 94 836 (3)
Other miscellaneous equipment 45 27 20 92
Total estimated costs of capital expenditure program $ 871 $ 576 $ 396 $ 1,843
(1) 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
(2) 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, 2021 were $310.9 million.
(3) Includes spending for AES Indiana's power generation and renewable energy projects, excluding any future tax equity contributions
Additionally, estimated capital expenditure spending on environmental compliance costs for the three-year period from 2022 through 2024 includes plans to spend approximately $7.2 million for studies related to cooling water intake requirements in section 316(b) of the CWA. Please see “Item 1. Business - Environmental Matters - Cooling Water Intake Regulations" 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 facilities 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 2022 and subsequent years, we expect to satisfy these requirements with a combination of cash from operations, funds from debt financing, and funds from tax equity and capital contributions as our internal liquidity needs and market conditions warrant. We also expect that the borrowing capacity under our existing credit facilities will continue to be available to manage working capital requirements during those periods. The absence of adequate liquidity could adversely affect our ability to operate our business and have a material adverse effect on our results of operations, financial condition and cash flows.
Indebtedness
Significant Debt Transactions
For further discussion of our significant debt transactions, please see Note 7, “Debt” to the Financial Statements of this Annual Report on Form 10-K.
Line of Credit
AES Indiana entered into an amendment and restatement of its $250 million revolving Credit Agreement on June 19, 2019 with a syndication of bank lenders, as discussed in Note 7, “Debt - Line of Credit” to the Financial Statements of this Annual Report on Form 10-K.
We had the following amounts available under the revolving Credit Agreement:
$ in millions Type Maturity Commitment Amounts available at December 31, 2021
AES Indiana Revolving June 2024 $ 250.0 $ 190.0
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)
Positive
Credit ratings IPALCO AES Indiana Outlook
Fitch Ratings BBB- BBB+ Stable
Moody’s Investors Service - Baa1 Stable
S&P Global Ratings BBB BBB Positive
(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 Cash Obligations
Our non-contingent contractual obligations as of December 31, 2021 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 $ 2,743.8 $ 60.0 $ 445.0 $ 130.0 $ 2,108.8
Interest obligations 1,818.5 118.2 229.9 201.4 1,269.0
Finance lease obligations 39,518.2 298.5 1,930.5 2,015.3 35,273.9
Purchase obligations:
Coal, gas, purchased power and
related transportation 1,241.8 280.6 310.3 234.3 416.6
Other 321.2 241.6 57.3 2.8 14.6 7.7
Total $ 45,643.5 $ 998.9 $ 2,973.0 $ 2,595.6 $ 39,076.0
Short-term and long-term debt:
Our short-term and long-term debt at December 31, 2021 consists of outstanding borrowings on the Credit 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 7, "Debt" to the Financial Statements of this Annual Report on Form 10-K.
Interest obligations:
Interest payment obligations 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, 2021.
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, 2021, 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 and incentive compensation (see Note 5, "Derivative Instruments and Hedging Activities"), (iii) taxes (see Note 8, "Income Taxes"), (iv) pension and other postretirement employee benefit liabilities (see Note 9, "Benefit Plans") and (v) contingencies (see Note 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 revenues 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
Please see Note 1, “Overview and Summary of Significant Accounting Policies - Revenues and Accounts Receivable” and Note 13, "Revenue" to the Financial Statements of this Annual Report on Form 10-K for more information.
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, 2021, it is possible that the ultimate outcome of future examinations may be materially different than our current assessment of uncertain tax positions. Please see Note 1, “Overview and Summary of Significant Accounting Policies - Income Taxes” and Note 8, "Income Taxes" to the Financial Statements of this Annual Report on Form 10-K for more information.
Regulation
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 revenues 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 earnings. 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 Costs
Please see Note 1, “Overview and Summary of Significant Accounting Policies - Pension and Postretirement Benefits” and Note 9, "Benefit Plans" to the Financial Statements of this Annual Report on Form 10-K for more information.
Contingencies
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 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 revenues are generated primarily from sales directly to the MISO energy market. The average price per MWh we sold in the wholesale market was $27.60, $24.91 and $25.19 in 2021, 2020 and 2019, 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 revenues represented 3.6% of our total electric revenues 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 2022 and approximately 45% of our current projected burn for the three-year period ending December 31, 2024, under long-term contracts. In addition, AES Indiana has established physical natural gas hedges for firm gas supply of approximately 75% of the expected consumption at Eagle Valley during the 2022 winter period, which price off the daily natural gas index for the respective physical hubs. 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 energy from two wind projects 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. 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 $18.3 million reduction in fair value as of December 31, 2021 and approximately a $8.0 million increase to the 2022 pension expense. Please see Note 9, “Benefit Plans” to the Financial Statements of this Annual Report on Form 10-K for additional Pension Plan information.
Interest Rate Risk
We use long-term debt as a significant source of capital in our business, which exposes us to interest rate risk. We do not enter into market risk sensitive instruments for trading purposes. We manage our exposure to interest rate risk through the use of fixed-rate debt and by refinancing existing long-term debt at times when it is deemed economic and prudent. In addition, AES Indiana’s Credit Agreement bears interest at a variable rate based either on the Prime interest rate or on the LIBOR. Fair values relating to financial instruments are dependent upon prevalent market rates of interest, primarily the LIBOR. At December 31, 2021, we had approximately $2,683.8 million principal amount of fixed rate debt and $60.0 million principal amount of 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.
Variable rate debt at December 31, 2021 was comprised of $60.0 million under AES Indiana's Credit Agreement. Based on amounts outstanding as of December 31, 2021, the effect of a 25 basis point change in the applicable rates on our variable-rate debt would change our annual interest expense and cash paid for interest by $0.2 million and $(0.2 million), respectively.
The following table shows our consolidated indebtedness (in millions) by maturity as of December 31, 2021:
2022 2023 2024 2025 2026 Thereafter Total Fair Value
Fixed-rate $ - $ - $ 445.0 $ 40.0 $ 90.0 $ 2,108.8 $ 2,683.8 $ 3,169.1
Variable-rate 60.0 - - - - - 60.0 60.0
Total Indebtedness $ 60.0 $ - $ 445.0 $ 40.0 $ 90.0 $ 2,108.8 $ 2,743.8 $ 3,229.1
Weighted Average Interest Rates by Maturity 1.235% N/A 3.648% 0.650% 0.883% 4.749% 4.307%
For further discussion of our fair value of our indebtedness and book value of our indebtedness please see Note 4, “Fair Value” and Note 7, “Debt” to the Financial Statements of this Annual Report on Form 10-K.
Retail Energy Market
The legislatures of several states have enacted laws that allow various forms of competition or that experiment with allowing some form of customer choice of electricity suppliers for retail sales of electric energy. Indiana has not done so. In Indiana, competition among electric energy providers for sales has focused primarily on the sale of bulk power to other public and municipal utilities. Indiana law provides for electricity suppliers to have exclusive retail service areas. In order to increase sales, we work to attract new customers into our service territory. Although the retail sales of electric energy are regulated, we face competition from other energy sources. For example, customers have a choice of installing electric or natural gas home and hot water heating systems or installing qualified generation facilities on their premises.
Counterparty Credit Risk
At times, we may utilize forward purchase contracts to manage the risk associated with power purchases and could be exposed to counterparty credit risk in these contracts. We manage this exposure to counterparty credit risk by entering into contracts with companies that are expected to fully perform under the terms of the contract. Individual credit limits are generally implemented for each counterparty to further mitigate credit risk. We may also require a counterparty to provide collateral in the event certain financial benchmarks are not maintained, or certain credit ratings are not maintained.
We are also exposed to counterparty credit risk related to our ability to collect electricity sales from our customers, which may be impacted by volatility in the financial markets and the economy. Historically, our write-offs of customer accounts have been immaterial, which is common for the electric utility industry.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page No.
IPALCO Enterprises, Inc. and Subsidiaries - Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm - 2021, 2020 and 2019 (PCAOB ID: 42) 57
Consolidated Statements of Operations for the Years Ended December 31, 2021, 2020 and 2019 59
Consolidated Statements of Comprehensive Income/(Loss) for the Years Ended December 31, 2021, 2020 and 2019 60
Consolidated Balance Sheets as of December 31, 2021 and 2020 61
Consolidated Statements of Cash Flows for the Years Ended December 31, 2021, 2020 and 2019 62
Consolidated Statements of Common Shareholders’ Equity and Cumulative Preferred Stock of Subsidiaries
for the Years Ended December 31, 2021, 2020 and 2019 63
Notes to Consolidated Financial Statements 64
AES Indiana and Subsidiaries - Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm - 2021, 2020 and 2019 106
Consolidated Statements of Operations for the Years Ended December 31, 2021, 2020 and 2019 108
Consolidated Balance Sheets as of December 31, 2021 and 2020 109
Consolidated Statements of Cash Flows for the Years Ended December 31, 2021, 2020 and 2019 110
Consolidated Statements of Common Shareholder’s Equity and Cumulative Preferred Stock
for the Years Ended December 31, 2021, 2020 and 2019 111
Notes to Consolidated Financial Statements 111
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, 2021 and 2020, the related consolidated statements of operations, comprehensive income / (loss), common shareholders’ equity and noncontrolling interest, and cash flows for each of the three years in the period ended December 31, 2021, 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, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021 in conformity with U.S. generally accepted accounting principles.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. 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 matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of the critical audit matter 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 matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulatory Accounting
Regulatory Accounting
Description of the Matter As described in Note 2 to the consolidated financial statements, the Company applies the provisions of FASC 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 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 over-collections 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 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, 2021, 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 financial statements and related disclosures.
How We Addressed the Matter in Our Audit To test the Company’s 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.
/s/ Ernst & Young LLP
We have served as the Company’s auditor since 2008.
Indianapolis, Indiana
February 28, 2022
IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Consolidated Statements of Operations
For the Years Ended December 31, 2021, 2020 and 2019
(In Thousands)
2021 2020 2019
REVENUES $ 1,426,132 $ 1,352,985 $ 1,481,643
OPERATING COSTS AND EXPENSES:
Fuel 255,817 247,105 340,466
Power purchased 175,025 135,767 133,674
Operation and maintenance 449,746 416,169 428,201
Depreciation and amortization 256,085 246,896 240,314
Taxes other than income taxes 44,419 44,516 42,236
Other, net (5,630) - -
Total operating costs and expenses 1,175,462 1,090,453 1,184,891
OPERATING INCOME 250,670 262,532 296,752
OTHER INCOME / (EXPENSE), NET:
Allowance for equity funds used during construction 5,412 4,574 3,486
Interest expense (125,626) (129,493) (121,771)
Loss on early extinguishment of debt - (2,424) -
Other income / (expense), net 17,667 3,370 (10,546)
Total other income / (expense), net (102,547) (123,973) (128,831)
EARNINGS FROM OPERATIONS BEFORE INCOME TAX 148,123 138,559 167,921
Less: income tax expense 28,941 28,592 35,528
NET INCOME 119,182 109,967 132,393
Less: dividends on preferred stock 3,213 3,213 3,213
NET INCOME APPLICABLE TO COMMON STOCK $ 115,969 $ 106,754 $ 129,180
See notes to consolidated financial statements.
IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Consolidated Statements of Comprehensive Income/(Loss)
For the Years Ended December 31, 2021, 2020 and 2019
(In Thousands)
2021 2020 2019
Net income applicable to common stock $ 115,969 $ 106,754 $ 129,180
Derivative activity:
Change in derivative fair value, net of income tax benefit/(expense) of $(3,441), $8,876 and $6,810, for each respective period
10,393 (27,779) (19,750)
Reclassification to earnings, net of income tax benefit of $1,199, $1,313 and $0, for each respective period
3,620 4,109 -
Net change in fair value of derivatives 14,013 (23,670) (19,750)
Other comprehensive income/(loss) 14,013 (23,670) (19,750)
Net comprehensive income $ 129,982 $ 83,084 $ 109,430
See notes to consolidated financial statements.
IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Consolidated Balance Sheets
(In Thousands)
December 31, 2021 December 31, 2020
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 6,912 $ 20,502
Restricted cash 5 6,120
Accounts receivable, net of allowance for credit losses of $647 and $3,155, respectively
179,136 165,193
Inventories 101,899 95,506
Regulatory assets, current 63,813 45,430
Taxes receivable 15,566 24,384
Prepayments and other current assets 40,168 17,842
Total current assets 407,499 374,977
NON-CURRENT ASSETS:
Property, plant and equipment 6,643,929 6,530,395
Less: Accumulated depreciation 2,895,881 2,643,695
3,748,048 3,886,700
Construction work in progress 210,297 209,584
Total net property, plant and equipment 3,958,345 4,096,284
OTHER NON-CURRENT ASSETS:
Intangible assets - net 106,316 59,141
Regulatory assets, non-current 656,977 392,801
Pension plan assets 49,182 8,669
Other non-current assets 61,448 38,047
Total other non-current assets 873,923 498,658
TOTAL ASSETS $ 5,239,767 $ 4,969,919
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Short-term debt and current portion of long-term debt (see Notes 7 and 12) $ 60,294 $ 169,907
Accounts payable 179,834 127,089
Accrued taxes 25,898 26,620
Accrued interest 30,634 31,733
Customer deposits 28,916 27,929
Regulatory liabilities, current 4,241 30,036
Accrued and other current liabilities 18,696 19,453
Total current liabilities 348,513 432,767
NON-CURRENT LIABILITIES:
Long-term debt (see Notes 7 and 12) 2,671,656 2,556,278
Deferred income tax liabilities 290,727 275,714
Taxes payable - 7,458
Regulatory liabilities, non-current 826,709 839,360
Accrued other postretirement benefits 4,290 5,334
Asset retirement obligations 189,509 195,236
Derivative liabilities, non-current 49,382 63,215
Other non-current liabilities 4,597 13,785
Total non-current liabilities 4,036,870 3,956,380
Total liabilities 4,385,383 4,389,147
COMMITMENTS AND CONTINGENCIES (see Note 10)
SHAREHOLDERS' EQUITY:
Paid in capital 848,565 588,966
Accumulated other comprehensive loss (29,407) (43,420)
Accumulated deficit (24,558) (24,558)
Total common shareholders' equity 794,600 520,988
Preferred stock of subsidiary 59,784 59,784
Total shareholders' equity 854,384 580,772
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 5,239,767 $ 4,969,919
See notes to consolidated financial statements.
IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Consolidated Statements of Cash Flows
For the Years Ended December 31, 2021, 2020 and 2019
(In Thousands)
2021 2020 2019
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 119,182 $ 109,967 $ 132,393
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization 256,085 246,896 240,314
Amortization of deferred financing costs and debt discounts 3,915 3,942 4,109
Deferred income taxes and investment tax credit adjustments - net (7,378) 2,854 15,277
Loss on early extinguishment of debt - 2,424 -
Allowance for equity funds used during construction (5,412) (4,574) (3,486)
Gain on acquisition (5,630) - -
Change in certain assets and liabilities:
Accounts receivable (13,943) (4,103) 6,469
Inventories (12,017) (15,240) 13,574
Accounts payable 21,417 (20,322) 3,047
Accrued and other current liabilities (21,680) (8,214) 4,413
Accrued taxes payable/receivable 638 6,695 (15,698)
Accrued interest (1,099) (3,601) 544
Pension and other postretirement benefit assets and liabilities (16,592) (6,991) 5,414
Short-term and long-term regulatory assets and liabilities (104,759) (13,390) 921
Prepayments and other current assets 4,135 (578) (2,119)
Other - net 8,355 (340) (7,357)
Net cash provided by operating activities 225,217 295,425 397,815
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (291,510) (235,700) (213,619)
Project development costs (1,304) (2,401) (2,269)
Cost of removal and regulatory recoverable ARO payments (48,952) (37,786) (21,838)
Purchase of intangibles (26,261) - -
Other (688) 118 278
Net cash used in investing activities (368,715) (275,769) (237,448)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under revolving credit facilities 320,000 115,000 10,000
Repayments under revolving credit facilities (335,000) (40,000) (10,000)
Long-term borrowings, net of discount 95,000 564,568 -
Retirement of long-term debt, including early payment premium (95,000) (562,135) -
Distributions to shareholders (131,476) (108,739) (136,426)
Equity contributions from shareholders 275,000 - -
Preferred dividends of subsidiary (3,213) (3,213) (3,213)
Deferred financing costs paid (1,387) (6,914) -
Payments for financed capital expenditures (36) (36) (5,623)
Other (95) (117) (152)
Net cash provided by (used in) financing activities 123,793 (41,586) (145,414)
Net change in cash, cash equivalents and restricted cash (19,705) (21,930) 14,953
Cash, cash equivalents and restricted cash at beginning of period 26,622 48,552 33,599
Cash, cash equivalents and restricted cash at end of period $ 6,917 $ 26,622 $ 48,552
Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest (net of amount capitalized) $ 118,052 $ 122,938 $ 117,457
Income taxes 27,500 27,000 29,600
Non-cash investing activities:
Accruals for capital expenditures $ 81,325 $ 54,360 $ 35,471
See notes to consolidated financial statements.
IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Consolidated Statements of Common Shareholders' Equity
and Cumulative Preferred Stock of Subsidiary
For the Years Ended December 31, 2021, 2020 and 2019
(In Thousands)
Paid in
Capital Accumulated Other Comprehensive Income (Loss) Accumulated
Deficit Total Common Shareholders' Equity Cumulative Preferred Stock of Subsidiary
Balance at January 1, 2019 $ 597,824 $ - $ (24,558) $ 573,266 $ 59,784
Net comprehensive income/(loss) - (19,750) 129,180 109,430 3,213
Preferred stock dividends - - - - (3,213)
Distributions to shareholders(1)
(7,246) - (129,180) (136,426) -
Other 206 - - 206 -
Balance at December 31, 2019 590,784 (19,750) (24,558) 546,476 59,784
Net comprehensive income/(loss) - (23,670) 106,754 83,084 3,213
Preferred stock dividends - - - - (3,213)
Distributions to shareholders(1)
(1,985) - (106,754) (108,739) -
Other 167 - - 167 -
Balance at December 31, 2020 588,966 (43,420) (24,558) 520,988 59,784
Net comprehensive income - 14,013 115,969 129,982 3,213
Preferred stock dividends - - - - (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 $ 848,565 $ (29,407) $ (24,558) $ 794,600 $ 59,784
(1) IPALCO made return of capital payments of $15.5 million, $2.0 million and $7.2 million in 2021, 2020 and 2019, respectively, for the portion of current year distributions to shareholders in excess of current year net income.
See notes to consolidated financial statements.
IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Notes to Consolidated Financial Statements
For the Years Ended December 31, 2021, 2020 and 2019
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 516,000 retail customers in the city of Indianapolis and neighboring cities, towns and communities, and adjacent rural areas all within the state of Indiana, with the most distant point being approximately forty miles from Indianapolis. 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. Our largest generating station, Petersburg, is coal-fired, and AES Indiana retired 230 MW Petersburg Unit 1 on May 31, 2021 and has plans to retire 415 MW Petersburg Unit 2 in 2023, which would result in 630 MW of total retired economic capacity at this station (for further discussion, see Note 2, "Regulatory Matters - IRP Filing and Replacement Generation"). The second largest station, Harding Street, uses natural gas and fuel oil to power 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 small peaking station that uses natural gas to power combustion turbines. As of December 31, 2021, AES Indiana’s net electric generation capacity for winter is 3,475 MW and net summer capacity is 3,330 MW. On December 17, 2021, AES Indiana, through its wholly-owned subsidiary AES Indiana Devco Holdings 1, LLC, completed the acquisition of Hardy Hills Solar Energy LLC, including the development of a 195 MW solar project (the "Hardy Hills Solar Project"). In July 2021, AES Indiana, through its wholly-owned subsidiary AES Indiana Devco Holdings 2, LLC, executed an agreement to acquire a 250 MW solar and 180 MWh energy storage facility (the "Petersburg Solar Project").
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. 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.
Use of Management Estimates
The preparation of financial statements in conformity with GAAP requires that management make certain estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements. The reported amounts of revenues and expenses during the reporting period may also be affected by the estimates and assumptions management is required to make. Actual results may differ from those estimates.
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.
Cash, Cash Equivalents and Restricted Cash
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 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 as shown on the Consolidated Statements of Cash Flows:
As of December 31,
2021 2020
(In Thousands)
Cash, cash equivalents and restricted cash
Cash and cash equivalents $ 6,912 $ 20,502
Restricted cash 5 6,120
Total cash, cash equivalents and restricted cash $ 6,917 $ 26,622
Revenues and Accounts Receivable
Revenues related to the sale of energy are 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 complex models that consider various factors including daily generation volumes; known amounts of energy usage by nearly all residential, commercial and industrial customers; estimated line losses; 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. The effect on 2021 revenues and ending unbilled revenues of a one percentage point change in estimated line losses for the month of December 2021 is immaterial. 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 $3.0 million, $4.8 million and $4.3 million for the years ended December 31, 2021, 2020 and 2019, 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.
The following table summarizes our accounts receivable balances at December 31:
As of December 31,
2021 2020
(In Thousands)
Accounts receivable, net
Customer receivables $ 100,952 $ 91,335
Unbilled revenue 64,758 72,334
Amounts due from related parties 169 490
Other 13,904 4,189
Allowance for credit losses (647) (3,155)
Total accounts receivable, net $ 179,136 $ 165,193
The following table is a rollforward of our allowance for credit losses related to the accounts receivable balances for the periods indicated (in Thousands):
Year Ended December 31, 2021 Beginning Allowance Balance at January 1, 2021 Current Period Provision Write-offs Charged Against Allowances Recoveries Collected Ending Allowance Balance at
December 31, 2021
Allowance for credit losses $ 3,155 $ 2,035 $ (6,448) $ 1,905 $ 647
Year Ended December 31, 2020 Beginning Allowance Balance at January 1, 2020 Current Period Provision Write-offs Charged Against Allowances Recoveries Collected Ending Allowance Balance at
December 31, 2020
Allowance for credit losses $ 921 $ 5,861 $ (5,473) $ 1,846 $ 3,155
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, including the economic impacts of the COVID-19 pandemic on our receivable balance as of December 31, 2021. Amounts are written off when reasonable collections efforts have been exhausted. An Executive Order issued by the Governor of Indiana on March 19, 2020 and extended by the IURC prohibited electric utilities, including us, from discontinuing electric utility service to customers through August 14, 2020 due to the economic impacts of COVID-19. This order along with the economic impacts of COVID-19 resulted in an increase in past due customer receivable balances in 2020, and thus the current period provision and the allowance for credit losses increased during the prior year. During 2021, the current period provision and allowance for credit losses decreased due to lower past due customer receivable balances. Please see additional discussion in Note 2, "Regulatory Matters - IURC COVID-19 Order” and Note 15, "Risks and Uncertainties - COVID-19 Pandemic."
Inventories
We maintain coal, fuel oil, 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,
2021 2020
(In Thousands)
Inventories
Fuel $ 41,626 $ 36,953
Materials and supplies, net 60,273 58,553
Total inventories $ 101,899 $ 95,506
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% during 2021, 2020 and 2019, respectively. Depreciation expense was $239.1 million, $232.8 million, and $228.2 million for the years ended December 31, 2021, 2020 and 2019, 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.
Allowance For Funds Used During Construction
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 5.7%, 6.9% and 6.9% during 2021, 2020 and 2019, respectively.
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 $4.0 billion and $4.1 billion as of December 31, 2021 and 2020, respectively. As of December 31, 2021 and 2020, AES Indiana had $300.1 million and $74.5 million, respectively, of long-term regulatory assets associated with the Petersburg Unit 1 retirement and the probable Petersburg Unit 2 retirement (for further discussion, see Note 2, “Regulatory Matters - IRP Filing 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 include capitalized software and project development intangible assets amortized over their useful lives. Capitalized software of $162.0 million and $144.5 million and its corresponding accumulated amortization of $95.8 million and $85.3 million is recorded as of December 31, 2021 and 2020, respectively. Amortization expense for capitalized software was $11.2 million, $10.6 million and $7.5 million for the years ended December 31, 2021, 2020 and 2019, respectively. These capitalized software intangible assets have a 7 year-weighted average amortization period and the estimated amortization expense is approximately $52.5 million over the next 5 years ($10.5 million in 2022, $10.5 million in 2023, $10.5 million in 2024, $10.5 million in 2025 and $10.5 million in 2026). IPALCO recorded project development intangible assets of $39.5 million during the year ended December 31, 2021. These project development intangible assets have a 30 year-weighted average amortization period and the estimated amortization expense is approximately $4.9 million over the next 5 years ($0.0 million in 2022, $1.0 million in 2023, $1.3 million in 2024, $1.3 million in 2025 and $1.3 million in 2026).
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 $9.1 million and $8.8 million as of December 31, 2021 and 2020, respectively, which are recorded within "Other non-current assets" on the accompanying Consolidated Balance Sheets.
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 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. As of December 31, 2021 and 2020, total loss contingencies accrued were $0.2 million and $15.4 million, respectively, which were included in “Accrued and Other Current Liabilities” and "Other Non-Current Liabilities", respectively, on the accompanying Consolidated Balance Sheets.
Concentrations of Risk
Substantially all of AES Indiana’s customers are located within the Indianapolis area. Approximately 69% 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 13, 2023. Additionally, AES Indiana has long-term coal contracts with three suppliers, and substantially all of AES Indiana's coal is currently mined in the state of Indiana.
Financial Derivatives
All derivatives are recognized as either assets or liabilities in the balance sheets and are measured at fair value. Changes in the fair value are recorded in earnings unless the derivative is designated as a cash flow hedge of a forecasted transaction or it qualifies for the normal purchases and sales exception.
AES Indiana has contracts involving the physical delivery of energy and fuel. 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'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 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 of our variable rate 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.
AOCL
The amounts reclassified out of AOCL by component during the years ended December 31, 2021, 2020 and 2019 are as follows (in thousands):
Details about AOCL components Affected line item in the Consolidated Statements of Operations For the Years Ended December 31,
2021 2020 2019
Net (gains) / losses on cash flow hedges (Note 5): Interest expense $ 4,819 $ 5,422 $ -
Income tax benefit (1,199) (1,313) -
Total reclassifications for the period, net of income taxes $ 3,620 $ 4,109 $ -
See Note 5, "Derivative Instruments and Hedging Activities - Cash Flow Hedges" for further information on the changes in the components of AOCL.
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, 2021, the $5.6 million represents a gain on acquisition.
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 8, "Income Taxes" for additional information.
Pension and Postretirement Benefits
We recognize in our Consolidated Balance Sheets an asset or liability reflecting the funded status of pension and other postretirement plans with current-year changes in the funded status, that would otherwise be recognized in AOCI, recorded as a regulatory asset as this can be recovered through future rates. All plan assets are recorded at fair value. We follow the measurement date provisions of the accounting guidance, which require a year-end measurement date of plan assets and obligations for all defined benefit plans.
We account for and disclose pension and postretirement benefits in accordance with the provisions of GAAP relating to the accounting for pension and other postretirement plans. These GAAP provisions require the use of assumptions, such as the discount rate for liabilities and long-term rate of return on assets, in determining the obligations, annual cost and funding requirements of the plans. Consistent with the requirements of ASC 715, we apply a disaggregated discount rate approach for determining service cost and interest cost for our defined benefit pension plans and postretirement plans.
See Note 9, "Benefit Plans" for more information.
Repair and Maintenance Costs
Repair and maintenance costs are expensed as incurred.
Per Share Data
IPALCO is owned by AES U.S. Investments and CDPQ. IPALCO does not report earnings on a per-share basis.
New Accounting Pronouncements
The following table provides a brief description of recent accounting pronouncements that had an impact on the Company’s Financial Statements. Accounting pronouncements not listed below were assessed and determined to be either not applicable or did not have a material impact on the Company’s Financial Statements.
New Accounting Standards Adopted
ASU Number and Name Description Date of Adoption Effect on the Financial Statements upon adoption
2016-13, 2018-19, 2019-04, 2019-05, 2019-10, 2019-11, 2020-02, 2020-03, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments See discussion of the ASU below.
January 1, 2020 See impact upon adoption of the standard below.
ASC 326 - Financial Instruments - Credit Losses
On January 1, 2020, the Company adopted ASC 326 Financial Instruments - Credit Losses and its subsequent corresponding updates ("ASC 326"). The new standard updates the impairment model for financial assets measured at amortized cost, known as the Current Expected Credit Loss ("CECL") model. For trade and other receivables, held-to-maturity debt securities, loans and other instruments, entities are required to use a new forward-looking "expected loss" model that generally results in the earlier recognition of an allowance for credit losses. For available-for-sale debt securities with unrealized losses, entities measure credit losses as it was done under previous GAAP, except that unrealized losses due to credit-related factors are now recognized as an allowance on the balance sheet with a corresponding adjustment to earnings in the income statement.
The Company applied the modified retrospective method of adoption for ASC 326. Under this transition method, the Company applied the transition provisions starting at the date of adoption. The CECL model primarily impacts the calculation of the Company's expected credit losses in gross customer trade accounts receivable. The adoption of ASC 326 and the application of CECL on our trade accounts receivable did not have a material impact on our 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.
New Accounting Standards Issued But Not Yet Effective
ASU Number and Name Description Date of Adoption Effect on the Financial Statements upon adoption
2021-05, Leases (Topic 842), Lessors-Certain Leases with Variable Lease Payments The amendments in this update affect lessors with lease contracts that (1) have variable lease payments that do not depend on a reference index or a rate and (2) would have resulted in the recognition of a selling loss at lease commencement if classified as sales-type or direct financing. Lessors should classify and account for a lease with variable lease payments that do not depend on a reference index or a rate as an operating lease if both of the following criteria are met: (a) The lease would have been classified as a sales-type lease or a direct financing lease in accordance with the classification criteria in paragraphs 842-10-25-2 through 25-3, (b) The lessor would have otherwise recognized a day-one loss. This update could be applied either (1) retrospectively to leases that commenced or were modified on or after the adoption of Update 2016-02 or (2) prospectively to leases that commence or are modified on or after the date that an entity first applies the amendments. Earlier application is permitted. For fiscal years beginning after December 15, 2021, including interim periods within those fiscal years. The Company is currently evaluating the impact of adopting the standard on its consolidated financial statements.
2020-04 and 2021-01, Reference Rate Form (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting The amendments in these updates provide optional expedients and exceptions for applying GAAP to contracts, hedging relationships and other transactions that reference to LIBOR or another reference rate expected to be discontinued by reference rate reform, and clarify that certain optional expedients and exceptions in Topic 848 for contract modifications and hedge accounting apply to derivatives that are affected by the discounting transition. These amendments are effective for a limited period of time (March 12, 2020 - December 21, 2022).
March 12, 2020 - December 31, 2022
The Company is currently evaluating the impact of adopting the standard on the 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 revenues. 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.
Base Rate Orders
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 revenues (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 also provides customers approximately $50 million in benefits, which flowed to customers over the two-year period that began March 2019, via the ECCRA rate adjustment mechanism. As of December 31, 2021, these credits have been fully returned to customers. This liability, less amounts returned to AES Indiana's customers, is recorded primarily in "Regulatory liabilities, current" ($0.0 million and $4.7 million as of December 31, 2021 and 2020, respectively) on the accompanying Consolidated Balance Sheets. In addition, 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. Prior to the 2018 Base Rate Order, wholesale sales margins were shared with customers 50% above and below an established benchmark of $6.3 million. 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. The 2018 Base Rate Order also approved changes to AES Indiana's depreciation and amortization rates (including no longer deferring depreciation on the CCGT at Eagle Valley) which altogether represent a net expense increase of approximately $28.7 million annually.
Other
The DOE issued a Notice of Proposed Rule Making on September 29, 2017, which directed the FERC to exercise its authority to set just and reasonable rates that recognize the “resiliency” value provided by generation plants with certain characteristics, including having 90-days or more of on-site fuel and operating in markets where they do not receive rate base treatment through state ratemaking. Nuclear and coal-fired generation plants would have been most likely to be able to meet the requirements. As proposed, the DOE would value resiliency through rates that recover “compensable costs” that were defined to include the recovery of operating and fuel expenses, debt service and a fair return on equity. On January 8, 2018, the FERC issued an order terminating this docket stating that it failed to satisfy the legal requirements of Section 206 of the Federal Power Act of 1935. The FERC initiated a new docket to take additional steps to explore resilience issues in RTOs/ISOs. The goal of this new proceeding is to: (1) develop a common understanding among the FERC, State Commissions, RTOs/ISOs, transmission owners, and others as to what resilience of the bulk power system means and requires; (2) understand how each RTO and ISO assesses resilience in its geographic footprint; and (3) use this information to evaluate whether additional action regarding resilience is appropriate at this time. It is not possible to predict the impact of this proceeding on our business, financial condition and results of operations.
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 each of the last three calendar years, AES Indiana has reported earnings in excess of the authorized level for each of the four quarterly reporting periods in those years. AES Indiana was not required to reduce its fuel cost recovery in 2019 because of its Cumulative Deficiencies. During 2020, AES Indiana's Cumulative Deficiencies dropped to zero and thus AES Indiana recorded a reduction to revenue of $5.5 million and $10.0 million in 2021 and 2020, respectively. AES Indiana's regulatory liability attributed to the Cumulative Deficiencies calculation was $0.5 million and $7.7 million as of December 31, 2021 and 2020, respectively, which is recorded within "Regulatory liabilities, current" on the accompanying Consolidated Balance Sheets.
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. The total amount of AES Indiana’s equipment approved for ECCRA recovery as of December 31, 2021 was $23.4 million. The jurisdictional revenue requirement approved by the IURC to be included in AES Indiana’s rates for the twelve-month period ending February 2022 is a net cost to customers of $1.0 million. This amount is higher than the ECCRA periods in 2019 and 2020 due to AES Indiana fully crediting customers for the approximately $50 million of customer benefits that flowed through the ECCRA as a result of the 2018 Base Rate Order, as described above. The only equipment still remaining in the ECCRA as of December 31, 2021 are certain projects associated with NAAQS compliance.
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 2021, 2020 and 2019, AES Indiana also had the ability to receive performance incentives, dependent upon the level of success of the programs. Performance incentives included in revenues for the years ended December 31, 2021, 2020 and 2019 were $7.2 million, $6.0 million and $7.5 million, respectively.
On February 7, 2018, the IURC approved a settlement agreement approving a three year DSM plan for AES Indiana through 2020. 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 revenues, consistent with the provisions of the settlement agreement.
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 revenues, consistent with the provisions of the settlement agreement.
Wind and Solar Power Purchase Agreements
We are committed under a power purchase agreement to purchase all wind-generated electricity through 2029 from a wind project in Indiana. 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, 2021. 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 revenues.
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 approved for TDSIC recovery as of December 31, 2021 was $159.5 million. The jurisdictional revenue requirement approved by the IURC to be included in AES Indiana’s rates for the twelve-month period ending October 2022 is a net cost to customers of $12.8 million.
IRP Filing and Replacement Generation
In December 2019, AES Indiana filed its IRP, 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. AES Indiana's Preferred Resource Portfolio is its reasonable least cost option and provides a cleaner and more diverse generation mix for customers. AES Indiana's Preferred Resource Portfolio includes 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 has determined that the cost of operating Petersburg Units 1 and 2 exceeds the value customers receive compared to alternative resources. Retirement of these units allows 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 is the first year AES Indiana is 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, but AES Indiana continues to assess the type, size, and location of resources in the bids we received. As a result of the plans to retire Petersburg Units 1 and 2, AES Indiana recorded $0.8 million, $0.0 million, and $6.2 million of obsolescence losses, during the periods ended December 31, 2021, 2020, and 2019, respectively, for materials and supplies inventory AES Indiana does 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.
On February 26, 2021, as a result of the plans to retire approximately 630 MW of coal-fired generation at Petersburg Units 1 and 2 in 2021 and 2023, respectively, AES Indiana filed a petition with the IURC 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 on May 31, 2021 and expects to retire Unit 2 in 2023. AES Indiana had recorded $74.5 million of net property, plant and equipment associated with the probable Petersburg Unit 1 retirement as a long-term regulatory assets as of December 31, 2020, and recorded $60.1 million and $239.9 million of Petersburg
Units 1 and 2 retirement costs, respectively, net of accumulated amortization, as long-term regulatory assets as of December 31, 2021.
Hardy Hills Solar Project
In January 2021, AES Indiana, through its wholly-owned subsidiary AES Indiana Devco Holdings 1, LLC, executed an agreement for the acquisition and construction of the 195 MW Hardy Hills Solar Project to be developed in Clinton County, Indiana, which is expected to be completed in 2023. On February 12, 2021, AES Indiana filed a petition and case-in-chief with the IURC seeking a CPCN for this solar project and on June 16, 2021, AES Indiana received an order from the IURC approving the project, including a joint venture structure between an AES Indiana subsidiary and one or more tax equity partners upon completion. 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.
Petersburg Solar Project
In July 2021, AES Indiana, through its wholly-owned subsidiary AES Indiana Devco Holdings 2, LLC, executed an agreement for the acquisition and construction of a 250 MW solar and 180 MWh energy storage facility to be developed in Pike County, Indiana, which is expected to be completed in 2024. On July 30, 2021, AES Indiana filed a petition and case-in-chief with the IURC seeking a CPCN for this solar project and on November 24, 2021, AES Indiana received an order from the IURC approving the project, including a joint venture structure between an AES Indiana subsidiary and one or more tax equity partners upon completion.
In January 2022, AES Indiana held its first public advisory meeting for the 2022 IRP.
IURC COVID-19 Orders
In its June 29, 2020 order, the IURC extended the disconnection moratorium for IURC-jurisdictional utilities through August 14, 2020, which has lapsed. Additionally, the IURC authorized Indiana utilities to use regulatory accounting for any impacts associated with prohibiting utility disconnections, waiver or exclusion of certain utility fees (i.e., late fees, convenience fees, deposits, and reconnection fees), and also required utilities to use expanded payment arrangements to aid customers. The IURC also authorized regulatory accounting treatment for COVID-19 related uncollectible and incremental bad debt expense.
On August 12, 2020, the IURC required all jurisdictional utilities to continue offering extended payment arrangements for a minimum of six months to all customers for an additional 60 days, until October 12, 2020, which the IURC again extended through December 31, 2020 for residential customers on October 27, 2020. The IURC also continued to suspend the collection of certain utility fees (late fees, deposits, and disconnection/reconnection fees) from residential customers for an additional 60 days, until October 12, 2020, after which utilities were allowed to resume charging convenience fees as set forth in the rate and charges established in their Commission-approved tariffs.
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 and $6.4 million as of December 31, 2021 and 2020, respectively. On August 25, 2021, the IURC closed the investigation to consider and address the impacts of the COVID-19 pandemic. For further discussion on the COVID-19 pandemic, see Note 15, "Risks and Uncertainties - COVID-19 Pandemic."
Excess Distributed Generation Rates
On March 1, 2021, AES Indiana filed a petition with the IURC for approval of its proposed rate for the procurement of excess distributed generation ("EDG") and related consumer EDG credit issues. The EDG rate will replace the current net metering program and will be offered beginning July 2022, when net metering is no longer available to new customers. The IURC approved the EDG rate by order dated January 26, 2022, and the case remains subject
to a petition for reconsideration filed by the other parties on February 15, 2022 and a notice of appeal filed by the other parties on February 22, 2022.
Electric Vehicle Portfolio Program
On March 2, 2021, AES Indiana filed with the IURC a request to approve its Electric Vehicle (EV) portfolio and associated accounting and ratemaking treatment. The EV portfolio aims to accelerate electric car adoption by reducing friction in the car buying process, and by providing customers incentives to optimize electric car charging during off-peak periods. 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 $5.1 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. On August 26, 2021, AES Indiana’s request to vacate the procedural schedule and hold case in abeyance was granted. AES Indiana is required to update the IURC on the Company’s plans for this docket on or before February 12, 2022. On February 10, 2022, AES Indiana filed a notice of voluntary dismissal of this request without prejudice. The IURC dismissed the case on February 11, 2022.
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 44 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:
2021 2020 Recovery Period
(In Thousands)
Regulatory Assets
Current:
Undercollections of rate riders $ 49,998 $ 31,569 Approximately 1 year(1)
Costs being recovered through basic rates and charges 13,815 13,861 Approximately 1 year(1)
Total current regulatory assets 63,813 45,430
Long-term:
Unrecognized pension and other
postretirement benefit plan costs 114,887 149,374 Various(2)
Deferred MISO costs 47,875 61,267 Through 2026(1)
Unamortized Petersburg Unit 4 carrying
charges and certain other costs 4,921 5,975 Through 2026(1)(3)
Unamortized reacquisition premium on debt 15,703 17,018 Over remaining life of debt
Environmental projects 71,201 74,637 Through 2046(1)(3)
COVID-19 5,426 6,391 To be determined
TDSIC projects 8,540 2,747 36.3 years(1)(3)
Petersburg Unit 1 and 2 retirement costs 300,067 74,545 Through 2034(1)(3)
Hardy Hills Solar Project 2,907 - To be determined
Petersburg Solar Project 881 - To be determined
Fuel costs 83,513 - To be determined
Other miscellaneous 1,056 847 Various(4)
Total long-term regulatory assets 656,977 392,801
Total regulatory assets $ 720,790 $ 438,231
Regulatory Liabilities
Current:
Overcollections and other credits being passed
to customers through rate riders $ 3,006 $ 29,493 Approximately 1 year(1)
FTRs 1,235 543 Approximately 1 year(1)
Total current regulatory liabilities 4,241 30,036
Long-term:
ARO and accrued asset removal costs 722,774 723,897 Not applicable
Deferred income taxes payable to customers through rates 100,171 112,957 Various
Other miscellaneous 3,764 2,506 To be determined
Total long-term regulatory liabilities 826,709 839,360
Total regulatory liabilities $ 830,950 $ 869,396
(1)Recovered (credited) per specific rate orders
(2)AES Indiana receives a return on its discretionary funding
(3)Recovered with a current return
(4) The majority of these costs are being recovered in basic rates and charges through 2026. For the remainder, recovery is probable, but the
timing is not yet determined.
(5) Recovered per regulatory precedent.
Current Regulatory Assets and Liabilities
Current regulatory assets and liabilities primarily represent costs that are being recovered per specific rate order; recovery for the remaining costs is probable, but not certain. As current assets, this includes undercollection of adjustment mechanisms for: (i) DSM, (ii) Off System Sales Margin Sharing, (iii) Capacity Cost Recovery, (iv) Green Power, (v) Deferred Fuel Costs and (vi) TDSIC. It also includes the current portion of deferred MISO costs and environmental costs collected through base rates which are described in greater detail below. As current liabilities, this includes overcollection of MISO rider costs, ECCRA costs, and the NOI liability that is credited to customers in the FAC filing.
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 FAC 133 IURC Order issued on November 24, 2021 approved the FAC 133 fuel cost factor on an interim basis subject to refund pending the outcome of a sub-docket created to examine the Eagle Valley CCGT extended outage. The FAC 134 IURC Order issued on February 23, 2022 approved a reduced FAC factor requested by AES Indiana in order to mitigate the rate impact on customers, primarily caused by rising commodity pricing and the Eagle Valley extended outage, that would defer the collection of variances until a future FAC filing or the resolution in the FAC sub-docket for the Eagle Valley outage. The order also approved deferral on an interim basis subject to refund pending the outcome of the sub-docket. Because the timing of collection is currently unknown, AES Indiana reclassified these variances to a long-term regulatory asset as of December 31, 2021 and will continue to record the FAC deferral as a long-term regulatory asset until AES Indiana seeks recovery.
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 are recorded based on the benefit plan’s actuarially determined pension liability and associated level of annual expenses 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 Allowance for Funds Used During Construction ("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 44 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 31 years. See "TDSIC" above for additional discussion.
Petersburg Unit 1 and 2 Retirement Costs
These consist of the estimated remaining net book value of Petersburg Unit 1 and 2 at its anticipated date of retirement. 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 Filing and Replacement Generation" above for additional discussion.
Hardy Hills Solar Project
These consist of project development costs, mainly legal and consulting fees, incurred for the Hardy Hills Solar Project. These costs were approved for recovery through AES Indiana’s Hardy Hills Solar Project regulatory proceedings, but amortization will be determined in a future rate case filing.
Petersburg Solar Project
These consist of project development costs, mainly legal and consulting fees, incurred for the Petersburg Solar Project. These costs were approved for recovery through AES Indiana’s Petersburg Solar Project regulatory proceedings, but amortization 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 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 $100.2 million and $113.0 million as of December 31, 2021 and 2020, respectively.
3. PROPERTY, PLANT AND EQUIPMENT
The original cost of property, plant and equipment segregated by functional classifications follows:
As of December 31,
2021 2020
(In Thousands)
Production $ 4,099,110 $ 4,191,223
Transmission 436,257 408,380
Distribution 1,831,029 1,671,861
General plant 277,533 258,931
Total property, plant and equipment $ 6,643,929 $ 6,530,395
As of December 31, 2021 and 2020, AES Indiana had $300.1 million and $74.5 million, respectively, of net property, plant and equipment associated with the probable Petersburg Unit 1 and Unit 2 retirements recorded as long-term regulatory assets (for further discussion, see Note 2, “Regulatory Matters - IRP Filing”).
Substantially all of AES Indiana’s property is subject to a $1,803.8 million direct first mortgage lien, as of December 31, 2021, securing AES Indiana’s first mortgage bonds. Total non-contractually or legally required accrued removal costs of utility plant in service at December 31, 2021 and 2020 were $846.1 million and $818.0 million, respectively; and total contractually or legally required removal costs of property, plant and equipment at December 31, 2021 and 2020 were $189.5 million and $195.2 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:
2021 2020
(In Thousands)
Balance as of January 1 $ 195,236 $ 204,219
Liabilities settled (13,692) (18,302)
Revisions to cash flow and timing estimates - 1,120
Accretion expense 7,965 8,199
Balance as of December 31 $ 189,509 $ 195,236
AES Indiana recorded adjustments to its ARO liabilities of $0.0 million and $1.1 million in 2021 and 2020, respectively, primarily to reflect increases to estimated ash pond closure costs, including groundwater remediation. As of December 31, 2021 and 2020, AES Indiana did not have any assets that are legally restricted for settling its ARO liability.
4. FAIR VALUE
The fair value of 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. As 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 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, 2021, 2020, or 2019. Any unrealized gains or losses are recorded in "Other income / (expense), net" on the accompanying Consolidated Statements of Operations.
FTRs
In connection with AES Indiana’s participation in MISO, in the second quarter of each year AES Indiana is granted financial instruments that can be converted into cash or FTRs based on AES Indiana’s forecasted peak load for the period. FTRs are used in the MISO market to hedge AES Indiana’s exposure to congestion charges, which result from constraints on the transmission system. AES Indiana’s FTRs are valued at the cleared auction prices for FTRs in MISO’s annual auction. Because of the infrequent nature of this valuation, the fair value assigned to the FTRs is considered a Level 3 input under the fair value hierarchy required by ASC 820. An offsetting regulatory liability has been recorded as these revenues or costs will be flowed through to customers through the FAC. As such, there is no impact on our Consolidated Statements of Operations.
Forward Power Contracts
In 2021, we entered into forward purchase power contracts. As of December 31, 2021, all outstanding forward power contracts had all 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.
Financial Liabilities
Interest Rate Hedges
In March 2019, we entered into forward interest rate hedges, which were amended in April 2020. The 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 AOCL. See also Note 5, "Derivative Instruments and Hedging Activities - Cash Flow Hedges" for further information.
Recurring Fair Value Measurements
The fair value of assets and liabilities at December 31, 2021 measured on a recurring basis and the respective category within the fair value hierarchy for IPALCO was determined as follows:
Assets and Liabilities at Fair Value
Level 1 Level 2 Level 3
Fair value at December 31, 2021 Based on quoted market prices in active markets Other observable inputs Unobservable inputs
(In Thousands)
Financial assets:
VEBA investments:
Money market funds $ 11 $ 11 $ - $ -
Mutual funds 3,594 - 3,594 -
Total VEBA investments 3,605 11 3,594 -
Financial transmission rights 1,235 - - 1,235
Total financial assets measured at fair value $ 4,840 $ 11 $ 3,594 $ 1,235
Financial liabilities:
Interest rate hedges $ 49,382 $ - $ 49,382 $ -
Total financial liabilities measured at fair value $ 49,382 $ - $ 49,382 $ -
The fair value of assets and liabilities at December 31, 2020 measured on a recurring basis and the respective category within the fair value hierarchy for IPALCO was determined as follows:
Assets and Liabilities at Fair Value
Level 1 Level 2 Level 3
Fair value at December 31, 2020 Based on quoted market prices in active markets Other observable inputs Unobservable inputs
(In Thousands)
Financial assets:
VEBA investments:
Money market funds $ 16 $ 16 $ - $ -
Mutual funds 3,209 - 3,209 -
Total VEBA investments 3,225 16 3,209 -
Financial transmission rights 543 - - 543
Total financial assets measured at fair value $ 3,768 $ 16 $ 3,209 $ 543
Financial liabilities:
Interest rate hedges $ 63,215 $ - $ 63,215 $ -
Total financial liabilities measured at fair value $ 63,215 $ - $ 63,215 $ -
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, 2020 $ 864
Issuances 1,889
Settlements (2,210)
Balance at December 31, 2020 $ 543
Issuances 2,971
Settlements (2,279)
Balance at December 31, 2021 $ 1,235
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, 2021 December 31, 2020
Face Value Fair Value Face Value Fair Value
(In Thousands)
Fixed-rate $ 2,683,800 $ 3,169,118 $ 2,683,800 $ 3,295,588
Variable-rate 60,000 60,000 75,000 75,000
Total indebtedness $ 2,743,800 $ 3,229,118 $ 2,758,800 $ 3,370,588
The difference between the face value and the carrying value of this indebtedness represents the following:
•unamortized deferred financing costs of $25.2 million and $26.0 million at December 31, 2021 and 2020, respectively; and
•unamortized discounts of $6.4 million and $6.6 million at December 31, 2021 and 2020, 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, 2021, AES Indiana's outstanding derivative instruments were as follows:
Commodity Accounting Treatment (a)
Unit Purchases
(in thousands) Sales
(in thousands) Net Purchases/(Sales)
(in thousands)
Interest rate hedges Designated USD $ 400,000 $ - $ 400,000
FTRs Not Designated MWh 6,091 - 6,091
(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 periods indicated:
Interest Rate Hedges for the Year Ended December 31,
$ in thousands (net of tax) 2021 2020 2019
Beginning accumulated derivative loss in AOCL $ (43,420) $ (19,750) $ -
Net gains / (losses) associated with current period hedging transactions 10,393 (27,779) (19,750)
Net (gains) / losses reclassified to interest expense, net of tax 3,620 4,109 -
Ending accumulated derivative loss in AOCL $ (29,407) $ (43,420) $ (19,750)
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) 33
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 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. 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 $6.0 million related to forward power contracts during the year ended December 31, 2021. The net gains resulting from these contracts have been deferred and included with deferred fuel costs in "Regulatory assets, non-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 mark to market 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, 2021 and 2020, IPALCO had $0.0 million and $6.1 million, respectively, of collateral in a broker margin account which offsets our loss positions on the interest rate hedges.
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 2021 2020
Financial transmission rights Not a Cash Flow Hedge Prepayments and other current assets $ 1,235 $ 543
Interest rate hedges Cash Flow Hedge Derivative liabilities, non-current $ 49,382 $ 63,215
6. EQUITY
Paid In Capital
On December 13, 2021, IPALCO received equity capital contributions of $226.5 million from AES U.S. Investments and $48.5 million from CDPQ. IPALCO then made the same investments in AES Indiana. 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.
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, 2021, 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, 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, 2021, 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, 2021, 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, 2021, 2020 and 2019, IPALCO declared and paid distributions to its shareholders totaling $131.5 million, $108.7 million and $136.4 million, respectively.
Cumulative Preferred Stock
AES Indiana has five separate series of cumulative preferred stock. Holders of preferred stock are entitled to receive dividends at rates per annum ranging from 4.0% to 5.65%. During each year ended December 31, 2021, 2020 and 2019, total preferred stock dividends declared were $3.2 million. Holders of preferred stock are 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 are 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 is 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. AES Indiana has issued and outstanding 500,000 shares of 5.65% preferred stock, which are redeemable at par value, subject to certain restrictions, in whole or in part. Additionally, AES Indiana has 91,353 shares of preferred stock which are redeemable at the option of AES Indiana and can be redeemed in whole or in part at any time at specific call prices.
At December 31, 2021, 2020 and 2019, preferred stock consisted of the following:
December 31, 2021 December 31,
Shares
Outstanding Call Price 2021 2020 2019
Par Value, plus premium, if applicable
(In Thousands)
Cumulative $100 par value,
authorized 2,000,000 shares
4% Series
47,611 $ 118.00 $ 5,410 $ 5,410 $ 5,410
4.2% Series
19,331 $ 103.00 1,933 1,933 1,933
4.6% Series
2,481 $ 103.00 248 248 248
4.8% Series
21,930 $ 101.00 2,193 2,193 2,193
5.65% Series
500,000 $ 100.00 50,000 50,000 50,000
Total cumulative preferred stock 591,353 $ 59,784 $ 59,784 $ 59,784
7. DEBT
Long-Term Debt
The following table presents our long-term debt:
December 31,
Series Due 2021 2020
(In Thousands)
AES Indiana first mortgage bonds:
3.875% (1)
August 2021 $ - $ 55,000
3.875% (1)
August 2021 - 40,000
3.125% (1)
December 2024 40,000 40,000
0.65% (1)
August 2025 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 -
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 (5,855) (6,006)
Deferred financing costs (17,913) (17,384)
Total AES Indiana first mortgage bonds 1,780,032 1,780,410
Total long-term debt - AES Indiana 1,780,032 1,780,410
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 (527) (625)
Deferred financing costs (7,319) (8,600)
Total long-term debt - IPALCO 872,154 870,775
Total consolidated IPALCO long-term debt 2,652,186 2,651,185
Less: current portion of long-term debt - 94,907
Net consolidated IPALCO long-term debt $ 2,652,186 $ 2,556,278
(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.
Debt Maturities
Maturities on long-term indebtedness subsequent to December 31, 2021, are as follows:
Year Amount
(In Thousands)
2022 $ -
2023 -
2024 445,000
2025 40,000
2026 90,000
Thereafter 2,108,800
Total $ 2,683,800
Significant Transactions
AES Indiana First Mortgage Bonds and Recent Indiana Finance Authority Bond Issuances
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 $1,803.8 million as of December 31, 2021. The AES Indiana first mortgage bonds require net earnings 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, 2021.
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.
In December 2020, the Indiana Finance Authority issued at the request of AES Indiana an aggregate principal amount of $90 million of Environmental Facilities Refunding Revenue Bonds, Series 2020A&B due December 2038. AES Indiana issued $90 million aggregate principal amount of first mortgage bonds to the Indiana Finance Authority in two series: $30 million Series 2020A notes at an interest rate of 0.75% and $60 million Series 2020B notes at an interest rate of 0.95% to secure the loan of proceeds from these bonds issued by the Indiana Finance Authority. These bonds are subject to a mandatory put date of April 1, 2026. Proceeds of the bond offering were used to refund $90 million of Indiana Finance Authority Environmental Facilities Refunding Revenue Bonds Series 2015A&B at a redemption price of 100% of par.
IPALCO’s Senior Secured Notes and Term Loan
In April 2020, IPALCO completed the sale of $475 million aggregate principal amount of 4.25% 2030 IPALCO Notes pursuant to Rule 144A and Regulation S under the Securities Act of 1933, as amended. We used the net proceeds from this offering to retire the $65 million Term Loan on April 14, 2020. The remaining net proceeds, together with cash on hand, were used to redeem the 2020 IPALCO Notes on May 14, 2020, and to pay certain related fees, expenses and make-whole premiums. A loss on early extinguishment of debt of $2.4 million for the 2020 IPALCO Notes is included as a separate line item within "Other Income/(Expense), Net" in the accompanying Consolidated Statements of Operations.
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.
Line of Credit
AES Indiana entered into an amendment and restatement of its $250 million revolving Credit Agreement on June 19, 2019 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 June 19, 2024, 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 June 19, 2023, 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, 2021 and 2020, AES Indiana had $60.0 million and $75.0 million in outstanding borrowings on the committed Credit Agreement, respectively.
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 $500 million of short-term indebtedness outstanding at any time through July 26, 2022. 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, all of which authority remains available as of December 31, 2021. 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 $500.0 million remains available under the order as of December 31, 2021. 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, 2021. 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.
Credit Ratings
Our ability to borrow money or to refinance existing indebtedness and the interest rates at which we can borrow money or refinance existing indebtedness are affected by our credit ratings. In addition, the applicable interest rates on AES Indiana’s Credit Agreement are dependent upon the credit ratings of AES Indiana. Downgrades in the credit ratings of AES could result in AES Indiana’s and/or IPALCO’s credit ratings being downgraded.
8. INCOME TAXES
IPALCO follows a policy of comprehensive interperiod income tax allocation. Investment tax credits related to utility property have been deferred and are being amortized over the estimated useful lives of the related property.
AES files federal and state income tax returns which consolidate IPALCO and its subsidiaries. Under a tax sharing agreement with AES, IPALCO is responsible for the income taxes associated with its own taxable income and records the provision for income taxes as if IPALCO and its subsidiaries each filed separate income tax returns. IPALCO is no longer subject to U.S. or state income tax examinations for tax years through March 27, 2001, but is open for all subsequent periods. IPALCO made tax sharing payments to AES of $27.5 million, $27.0 million and $29.6 million in 2021, 2020 and 2019, respectively.
On March 25, 2014, the state of Indiana amended Indiana Code 6-3-2-1 through Senate Bill 001, which phases in an additional 1.6% reduction to the state corporate income tax rate that was initially being reduced by 2%. While the statutory state income tax rate decreased to 5.075% for the calendar year 2021, the deferred tax balances were adjusted according to the anticipated reversal of temporary differences. The statutory state corporate income tax rate will be 4.9% for 2022 and beyond.
Income Tax Provision
Federal and state income taxes charged to income are as follows:
2021 2020 2019
(In Thousands)
Components of income tax expense:
Current income taxes:
Federal $ 28,100 $ 19,489 $ 17,229
State 8,218 6,249 3,022
Total current income taxes 36,318 25,738 20,251
Deferred income taxes:
Federal (7,286) 323 7,547
State (91) 2,531 7,745
Total deferred income taxes (7,377) 2,854 15,292
Net amortization of investment credit - - (15)
Total income tax expense $ 28,941 $ 28,592 $ 35,528
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:
2021 2020 2019
Federal statutory tax rate 21.0 % 21.0 % 21.0 %
State income tax, net of federal tax benefit 4.0 % 4.2 % 4.4 %
Depreciation flow through and amortization (6.3) % (6.8) % (5.7) %
Additional funds used during construction - equity 0.4 % 1.0 % 0.2 %
Other - net 0.4 % 1.2 % 1.3 %
Effective tax rate 19.5 % 20.6 % 21.2 %
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, 2021 and 2020 are as follows:
2021 2020
(In Thousands)
Deferred tax liabilities:
Relating to utility property, net $ 369,783 $ 408,291
Regulatory assets recoverable through future rates 126,531 82,783
Other 14,326 5,485
Total deferred tax liabilities 510,640 496,559
Deferred tax assets:
Investment tax credit 7 6
Regulatory liabilities including ARO 200,948 197,657
Employee benefit plans - 3,866
Other 18,958 19,316
Total deferred tax assets 219,913 220,845
Deferred income tax liability - net $ 290,727 $ 275,714
Uncertain Tax Positions
The following is a reconciliation of the beginning and ending amounts of unrecognized tax benefits for the years ended December 31, 2021, 2020 and 2019:
2021 2020 2019
(In Thousands)
Unrecognized tax benefits at January 1 $ 7,368 $ 7,056 $ 7,056
Gross increases - current period tax positions - 312 -
Gross decreases - prior period tax positions (7,368) - -
Unrecognized tax benefits at December 31 $ - $ 7,368 $ 7,056
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 March 27, 2001 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, 2021 is the appropriate accrual for our uncertain tax positions.
However, audit outcomes and the timing of audit settlements and future events that would impact our previously recorded unrecognized tax benefits are subject to significant uncertainty. It is possible that the ultimate outcome of future examinations may exceed our provision for current unrecognized tax benefits.
Tax-related interest expense and income is reported as part of the provision for federal and state income taxes. Penalties, if incurred, would also be recognized as a component of tax expense. There are no interest or penalties applicable to the periods contained in this report.
9. BENEFIT PLANS
Defined Contribution Plans
All of AES Indiana’s employees are covered by one of two defined contribution plans, the Thrift Plan or the RSP:
The Thrift Plan
Approximately 79% 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 $3.4 million, $3.4 million and $3.3 million for 2021, 2020 and 2019, respectively.
The RSP
Approximately 21% 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 $1.9 million, $1.8 million and $1.6 million for 2021, 2020 and 2019, respectively.
Defined Benefit Plans
Approximately 70% of AES Indiana’s active employees are covered by the qualified Defined Benefit Pension Plan; while approximately 9% of active employees are IBEW clerical-technical unit employees who are only eligible for the Thrift Plan. The remaining 21% 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, 2021 was 21. 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 136 active employees and 19 retirees (including spouses) were receiving such benefits or entitled to future benefits as of January 1, 2021. The plan is unfunded. These postretirement health care benefits and the related unfunded obligation of $3.9 million and $4.3 million at December 31, 2021 and 2020, 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,
2021 2020
(In Thousands)
Change in benefit obligation:
Projected benefit obligation at January 1 $ 842,525 $ 782,795
Service cost 9,339 8,272
Interest cost 15,660 22,151
Actuarial (gain)/loss (37,858) 66,827
Amendments (primarily increases in pension bands) 5,575 967
Benefits paid (63,201) (38,487)
Projected benefit obligation at December 31 772,040 842,525
Change in plan assets:
Fair value of plan assets at January 1 850,020 769,704
Actual return on plan assets 33,841 118,716
Employer contributions 24 87
Benefits paid (63,201) (38,487)
Fair value of plan assets at December 31 820,684 850,020
Funded status $ 48,644 $ 7,495
Amounts recognized in the statement of financial position:
Non-current assets $ 49,182 $ 8,669
Non-current liabilities (538) (1,174)
Net amount recognized at end of year $ 48,644 $ 7,495
Sources of change in regulatory assets(1):
Prior service cost arising during period $ 5,575 $ 967
Net gain arising during period (29,884) (14,110)
Amortization of prior service cost (2,944) (3,677)
Amortization of loss (5,529) (8,115)
Total recognized in regulatory assets $ (32,782) $ (24,935)
Amounts included in regulatory assets:
Net loss $ 110,113 $ 145,526
Prior service cost 14,244 11,613
Total amounts included in regulatory assets $ 124,357 $ 157,139
(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 Gains and Losses Related to Changes in the Benefit Obligation for the Period
As shown in the table above, an actuarial gain of $37.9 million decreased the benefit obligation for the year ended December 31, 2021 and an actuarial loss of $66.8 million increased the benefit obligation for the year ended December 31, 2020. The actuarial gain in 2021 was primarily due to an increase in the discount rate. The actuarial loss in 2020 was primarily due to a decrease 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, earnings 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 2021 net actuarial gain of $29.9 million recognized in regulatory assets is comprised of two parts: (1) a $37.9 million pension liability actuarial gain primarily due to an increase in the discount rate used to value pension liabilities; partially offset by (2) a $8.0 million pension asset actuarial loss primarily due to lower than expected return on assets. The unrecognized net loss of $110.1 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 increased the expected benefit obligation due to the longer expected lives of plan participants. During 2021, the accumulated net gain decreased due to lower than expected return on pension assets, which was partially offset by a combination of higher discount rates used to value pension liabilities, as well as the year 2021 amortization of accumulated loss. 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 11.43 years based on estimated demographic data as of December 31, 2021. The projected benefit obligation of $772.0 million less the fair value of assets of $820.7 million results in an overfunded status of $48.6 million at December 31, 2021.
Pension benefits for
years ended December 31,
2021 2020 2019
(In Thousands)
Components of net periodic benefit (credit) / cost:
Service cost $ 9,339 $ 8,272 $ 7,412
Interest cost 15,660 22,151 27,343
Expected return on plan assets (41,815) (37,779) (29,907)
Amortization of prior service cost 2,944 3,677 3,823
Amortization of actuarial loss 5,529 8,115 11,084
Net periodic benefit (credit) / cost (8,343) 4,436 19,755
Less: amounts capitalized 771 372 1,237
Amount charged to expense $ (7,572) $ 4,064 $ 18,518
Rates relevant to each year’s expense calculations:
Discount rate - defined benefit pension plan 2.46 % 3.33 % 4.36 %
Discount rate - supplemental retirement plan 2.31 % 3.05 % 4.24 %
Expected return on defined benefit pension plan assets 5.05 % 5.05 % 4.50 %
Expected return on supplemental retirement plan assets 3.60 % 4.45 % 4.50 %
Pension expense / (income) for the following year is determined as of the December 31 measurement date based on the fair value of the Pension Plans’ assets, the expected long-term rate of return on plan assets, a mortality table assumption that reflects the life expectancy of plan participants, and a discount rate used to determine the projected benefit obligation. For 2021, pension expense / (income) was determined using an assumed long-term rate of return on plan assets of 5.05% for the Defined Benefit Pension Plan and 3.60% for the Supplemental Retirement Plan. As of the December 31, 2021 measurement date, AES Indiana increased the discount rate from 2.46% to 2.83% for the Defined Benefit Pension Plan and from 2.31% to 2.62% for the Supplemental Retirement Plan. The discount rate assumptions affect the pension expense / (income) determined for 2022. In addition, AES Indiana decreased the expected long-term rate of return on plan assets from 5.05% to 4.45% for the Defined Benefit Pension Plan and increased the expected long-term rate of return for the Supplemental Retirement Plan from 3.60% to 5.50% for 2022. The expected long-term rate of return assumption affects the pension expense / (income) determined for 2022. The effect on 2022 total pension expense / (income) of a 25 basis point increase and decrease in the assumed discount rate is $(1.3) million and $1.4 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, 2021. 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 are determined as of the plans' measurement date of December 31, 2021. 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 unfunded 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 2021:
Asset Category: Target Allocations
Equity Securities 22.5%
Debt Securities 77.5%
Fair Value Measurements at
December 31, 2021
(in thousands)
Quoted Prices in Active Markets for Identical Assets Significant Observable Inputs
Asset Category Total (Level 1) (Level 2) %
Cash and cash equivalents $ 2,353 $ 2,490 $ - - %
Government debt securities 154,051 324 153,727 19 %
Mutual fund - equities 183,203 2,778 180,425 22 %
Mutual fund - debt 481,077 1,637 479,440 59 %
Total $ 820,684 $ 7,229 $ 813,592 100 %
Fair Value Measurements at
December 31, 2020
(in thousands)
Quoted Prices in Active Markets for Identical Assets Significant Observable Inputs
Asset Category Total (Level 1) (Level 2) %
Cash and cash equivalents $ 2,221 $ 2,221 $ - - %
Government debt securities 118,255 131 118,124 14 %
Mutual fund - equities 323,253 2,839 320,414 38 %
Mutual fund - debt 406,291 1,578 404,713 48 %
Total(1)
$ 850,020 $ 6,769 $ 843,251 100 %
Pension Funding
We contributed $0.0 million, $0.1 million, and $0.0 million to the Pension Plans in 2021, 2020 and 2019, 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 117%. In general, AES Indiana must contribute the normal service cost earned by active participants during the plan year; however, this amount can be offset by any surplus or credit balance carried by the Pension Plan. The normal cost is expected to be approximately $5.6 million in 2022 (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 2022. 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, 2021, 2020 and 2019 were $63.2 million, $38.5 million and $37.5 million, respectively. Expected benefit payments are expected to be paid out of the Pension Plans as follows:
Year Pension Benefits
(In Thousands)
2022 $ 39,994
2023 40,782
2024 41,509
2025 42,344
2026 42,893
2027 through 2031 216,332
10. COMMITMENTS AND CONTINGENCIES
Guarantees
We and certain of our subsidiaries enter into agreements from time to time providing financial or performance assurance to third parties for certain of our subsidiaries as part of our business, including guarantees and stand-by letters of credit. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to the subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiary's intended commercial purposes. At December 31, 2021, AES Indiana had issued $226.2 million of guarantees and no stand-by letters of credit.
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, 2021, 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 $ 1,241.8 $ 280.6 $ 310.3 $ 234.3 $ 416.6
Other $ 321.2 $ 241.6 $ 57.3 $ 14.6 $ 7.7
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, 2021, 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 and incentive compensation (see Note 5, "Derivative Instruments and Hedging Activities"), (iii) taxes (see Note 8, "Income Taxes"), (iv) pension and other postretirement employee benefit liabilities (see Note 9, "Benefit Plans") and (v) contingencies (see Note 10, "Commitments and Contingencies"). See the indicated notes to the Financial Statements for additional information on the items excluded.
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. As of December 31, 2021 and 2020, total legal loss contingencies accrued were $0.2 million and $13.4 million, respectively, which primarily related to personal injury litigation. During 2021, we entered into settlements resolving a significant portion of the legal loss contingencies previously accrued. The legal loss contingencies and settlement related accruals are included in "Accrued and other current liabilities" and "Other Non-Current Liabilities" on the accompanying Consolidated Balance Sheets. We maintain an amount of insurance protection for such litigation that we believe is adequate. As of December 31, 2021 and 2020, we have $12.5 million and $11.3 million, respectively, of receivables for insurance recoveries determined to be probable recorded in "Prepayments and other current assets" and "Other non-current assets" on the accompanying Consolidated Balance Sheets. 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.
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.
New Source Review 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 New Source Review (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 current 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. If AES Indiana does not meet this retirement obligation, it must install a Selective Non-Catalytic Reduction System (SNCR) on Unit 4. AES Indiana has a contingent liability recorded related to these New Source Review and other CAA NOV matters.
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.
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 $7.0 million, $5.6 million, and $4.3 million in 2021, 2020 and 2019, respectively, and is recorded in “Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations. As of December 31, 2021 and 2020, we had prepaid approximately $2.3 million and $2.3 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 $23.7 million, $21.0 million, and $20.2 million in 2021, 2020 and 2019, 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, 2021 and 2020, 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 $15.6 million and $24.4 million as of December 31, 2021 and 2020, respectively, which is recorded in “Taxes receivable” on the accompanying Consolidated Balance Sheets. See Note 8, "Income Taxes" for more information.
Long-term Compensation Plan
During 2021, 2020 and 2019, 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 2021, 2020 and 2019 was $0.2 million, $0.3 million and $0.3 million, respectively, and was included in “Operating expenses - Operation and maintenance” on IPALCO’s Consolidated Statements of Operations. The value of these benefits is being recognized over the 36 month vesting period and a portion is recorded as miscellaneous deferred credits with the remainder recorded as “Paid in capital” on IPALCO’s Consolidated Balance Sheets in accordance with ASC 718 “Compensation - Stock Compensation.”
See also Note 9, “Benefit Plans” 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 $58.4 million, $55.7 million and $42.0 million during 2021, 2020 and 2019, respectively. Total costs incurred by IPALCO on behalf of the Service Company during 2021, 2020 and 2019 were $10.4 million, $10.6 million and $9.7 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 $5.9 million and $4.5 million as of December 31, 2021 and December 31, 2020, respectively, which is recorded in “Accounts payable” on the accompanying Consolidated Balance Sheets.
Other
Transactions with various other related parties were $4.3 million, $6.5 million and $3.0 million during 2021, 2020 and 2019, respectively. These expenses were primarily recorded in “Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations.
12. BUSINESS SEGMENT INFORMATION
Operating segments are components of an enterprise that engage in business activities from which it may earn revenues 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. Substantially all of our business consists of the generation, transmission, distribution and sale of electric energy conducted through AES Indiana which is a vertically integrated electric utility. IPALCO’s reportable business segment is its utility segment, with all other non-utility business activities aggregated separately. The "All Other" non-utility category primarily includes the 2024 IPALCO Notes and 2030 IPALCO Notes and related interest expense, balances associated with IPALCO's interest rate hedges, cash and other immaterial balances. The accounting policies of the identified segment are consistent with those policies and procedures described in the summary of significant accounting policies.
The following table provides information about IPALCO’s business segments (in thousands):
2021 2020 2019
Utility All Other Total Utility All Other Total Utility All Other Total
Revenues $ 1,426,132 $ - $ 1,426,132 $ 1,352,985 $ - $ 1,352,985 $ 1,481,643 $ - $ 1,481,643
Depreciation and amortization $ 256,085 $ - $ 256,085 $ 246,896 $ - $ 246,896 $ 240,314 $ - $ 240,314
Interest expense $ 84,256 $ 41,370 $ 125,626 $ 87,281 $ 42,212 $ 129,493 $ 89,014 $ 32,757 $ 121,771
Earnings/(loss) from operations before income tax $ 189,548 $ (41,425) $ 148,123 $ 184,174 $ (45,615) $ 138,559 $ 200,707 $ (32,786) $ 167,921
Capital expenditures(1)
$ 291,546 $ - $ 291,546 $ 235,736 $ - $ 235,736 $ 219,242 $ - $ 219,242
(1) Capital expenditures includes $0.0 million, $0.0 million and $5.6 million of payments for financed capital expenditures in 2021, 2020 and 2019, respectively.
As of December 31, 2021 As of December 31, 2020 As of December 31, 2019
Total assets $ 5,222,987 $ 16,780 $ 5,239,767 $ 4,952,408 $ 17,511 $ 4,969,919 $ 4,918,408 $ 10,261 $ 4,928,669
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 revenues - 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 revenues 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, though see Note 2, "Regulatory Matters - IURC COVID-19 Orders" for a discussion of the orders requiring expanded payment arrangements for customers.
Wholesale revenues - 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 revenues. 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 revenues - Miscellaneous revenues are mainly comprised of MISO transmission revenues. MISO transmission revenues are 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 revenues. Capacity revenues are also included in miscellaneous revenues, but these were not material for the period presented.
Transmission revenues have a single performance obligation, as transmission services represent a distinct service. Additionally, as the performance obligation is satisfied over time and the same method is used to measure progress, the performance obligation meets the criteria to be considered a series. 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.
AES Indiana’s revenue from contracts with customers was $1,389.2 million, $1,326.6 million and $1,455.3 million for the years ended December 31, 2021, 2020 and 2019, respectively. The following table presents our revenue from contracts with customers and other revenue (in thousands):
For the Years Ended December 31,
2021 2020 2019
Retail Revenues
Retail revenue from contracts with customers:
Residential $ 595,692 $ 566,668 $ 589,719
Small commercial and industrial 211,997 194,904 215,878
Large commercial and industrial 518,069 484,230 548,551
Public lighting 8,888 9,115 7,249
Other (1)
16,785 14,402 14,136
Total retail revenue from contracts with customers 1,351,431 1,269,319 1,375,533
Alternative revenue programs 35,248 24,781 23,841
Wholesale Revenues
Wholesale revenues from contracts with customers 25,059 46,482 68,474
Miscellaneous Revenues
Transmission and other revenue from contracts with customers 12,671 10,794 11,335
Other miscellaneous revenues (2)
1,723 1,609 2,460
Total Revenues $ 1,426,132 $ 1,352,985 $ 1,481,643
(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 revenues not accounted for under ASC 606
The balances of receivables from contracts with customers are $163.0 million and $163.8 million as of December 31, 2021 and 2020, respectively. Payment terms for all receivables from contracts with customers typically do not extend beyond 30 days, though see Note 2, "Regulatory Matters - IURC COVID-19 Order" for a discussion of orders requiring expanded payment arrangements for customers.
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.
Contract Balances - The timing of revenue recognition, billings, and cash collections results in accounts receivable and contract liabilities. The contract liabilities from contracts with customers were $0.0 million and $0.5 million as of December 31, 2021 and 2020, respectively. During the years ended December 31, 2021 and 2020, we recognized revenue of $0.5 million and $1.3 million related to this contract liability balance, respectively.
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, 2021 December 31, 2020
Assets
Right-of-use assets - finance leases Other non-current assets $ 19,763 $ -
Liabilities
Finance lease liabilities (current) Short-term debt 294 -
Finance lease liabilities (noncurrent) Long-term debt 19,469 -
Total finance lease liabilities $ 19,763 $ -
The following table summarizes supplemental balance sheet information related to leases as of the periods indicated:
Lease Term and Discount Rate December 31, 2021 December 31, 2020
Weighted-average remaining lease term - finance leases 31 years
N/A
Weighted-average discount rate - finance leases 4.561%
N/A
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, 2021 for 2022 through 2026 and thereafter (in millions):
Finance Leases
2022 $ 298
2023 955
2024 975
2025 997
2026 1,019
Thereafter 35,274
Total $ 39,518
Less: Imputed interest (19,755)
Present value of lease payments $ 19,763
LESSOR
The Company is the lessor under operating leases for land, office space and operating equipment. Minimum lease payments 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. Lease revenue included in the Consolidated Statements of Operations was $1.4 million, $0.9 million and $1.0 million for the years ended December 31, 2021, 2020 and 2019, respectively. Underlying gross assets and accumulated depreciation of operating leases included in Total net property, plant and equipment on the Consolidated Balance Sheet were $4.4 million and $1.0 million, respectively, as of December 31, 2021 and $4.3 million and $0.8 million, respectively, as of December 31, 2020.
The option to extend or terminate a lease is based on customary early termination provisions in the contract. The Company has not recognized any early terminations as of December 31, 2021.
The following table shows the future minimum lease receipts through 2026 and thereafter (in thousands):
Operating Leases
2022 $ 903
2023 906
2024 786
2025 553
2026 554
Thereafter 1,559
Total $ 5,261
15. RISKS AND UNCERTAINTIES
COVID-19 Pandemic
The COVID-19 pandemic has impacted global economic activity, including electricity and energy consumption, and caused significant volatility in financial markets. Many countries, including the U.S., reacted to the pandemic by instituting quarantines and mandating business and school closures or limitations and other social distancing measures. Responses to the COVID-19 pandemic by the State of Indiana and its residents and businesses continue to evolve as virus variants emerge, vaccine availability and usage continues and the State and businesses review and adjust the scope and requirements of social distancing measures. Social distancing measures designed to slow the spread of the virus, such as business closures and operations limitations, impact energy demand within our service territory. We continue to take a variety of measures in response to the spread of COVID-19 to ensure our ability to generate, transmit, distribute and sell electric energy, ensure the health and safety of our employees, contractors, customers and communities and provide essential services to the communities in which we operate. In addition to the impacts to demand within our service territory, we also have incurred and expect to continue to incur expenses relating to COVID-19, including those that relate to events outside of our control. The magnitude and duration of the COVID-19 pandemic is unknown at this time and may have material and adverse effects on our results of operations, financial condition and cash flows in future periods.
16. SUBSEQUENT EVENT
In February 2022, AES announced its intent to exit coal generation by year-end 2025 versus prior expectation of a reduction to below 10% by year-end 2025, subject to necessary approvals. Changes to our generation portfolio are evaluated and decided through the IRP. The impact that this new goal may have on our financial statements will be evaluated as part of the 2022 IRP.
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, 2021 and 2020, the related consolidated statements of operations, common shareholder’s equity, and cash flows for each of the three years in the period ended December 31, 2021, 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, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021 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 matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of the critical audit matter 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 matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulatory Accounting
Regulatory Accounting
Description of the Matter As described in Note 2 to the consolidated financial statements, the Company applies the provisions of FASC 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 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 over-collections 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 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, 2021, 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 financial statements and related disclosures.
How We Addressed the Matter in Our Audit To test the Company’s 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.
/s/ Ernst & Young LLP
We have served as the Company’s auditor since 2008.
Indianapolis, Indiana
February 28, 2022
AES INDIANA and SUBSIDIARIES
Consolidated Statements of Operations
For the Years Ended December 31, 2021, 2020 and 2019
(In Thousands)
2021 2020 2019
REVENUES $ 1,426,132 $ 1,352,985 $ 1,481,643
OPERATING COSTS AND EXPENSES:
Fuel 255,817 247,105 340,466
Power purchased 175,025 135,767 133,674
Operations and maintenance 449,317 415,824 427,803
Depreciation and amortization 256,085 246,896 240,314
Taxes other than income taxes 44,419 44,516 42,229
Other, net (5,630) - -
Total operating costs and expenses 1,175,033 1,090,108 1,184,486
OPERATING INCOME 251,099 262,877 297,157
OTHER INCOME / (EXPENSE), NET:
Allowance for equity funds used during construction 5,412 4,574 3,486
Interest expense (84,257) (87,478) (89,014)
Other income / (expense), net 17,294 4,201 (10,922)
Total other income / (expense), net (61,551) (78,703) (96,450)
EARNINGS FROM OPERATIONS BEFORE INCOME TAX 189,548 184,174 200,707
Less: income tax expense 39,305 40,134 43,430
NET INCOME 150,243 144,040 157,277
Less: dividends on preferred stock 3,213 3,213 3,213
NET INCOME APPLICABLE TO COMMON STOCK $ 147,030 $ 140,827 $ 154,064
See notes to consolidated financial statements.
AES INDIANA and SUBSIDIARIES
Consolidated Balance Sheets
(In Thousands)
December 31, 2021 December 31, 2020
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 2,756 $ 17,946
Restricted cash 5 5
Accounts receivable, net of allowance for credit losses of $647 and $3,155, respectively
179,181 165,435
Inventories 101,899 95,506
Regulatory assets, current 63,813 45,430
Taxes receivable 6,653 12,531
Prepayments and other current assets 40,123 23,944
Total current assets 394,430 360,797
NON-CURRENT ASSETS:
Property, plant and equipment 6,643,929 6,530,395
Less: Accumulated depreciation 2,895,881 2,643,695
3,748,048 3,886,700
Construction work in progress 210,297 209,584
Total net property, plant and equipment 3,958,345 4,096,284
OTHER NON-CURRENT ASSETS:
Intangible assets - net 106,316 59,141
Regulatory assets, non-current 656,977 392,801
Pension plan assets 49,182 8,669
Other non-current assets 57,737 34,717
Total other non-current assets 870,212 495,328
TOTAL ASSETS $ 5,222,987 $ 4,952,409
LIABILITIES AND SHAREHOLDER'S EQUITY
CURRENT LIABILITIES:
Short-term debt and current portion of long-term debt (see Notes 7 and 12) $ 60,294 $ 169,907
Accounts payable 179,602 126,772
Accrued taxes 25,898 26,620
Accrued interest 22,241 23,340
Customer deposits 28,916 27,929
Regulatory liabilities, current 4,241 30,036
Accrued and other current liabilities 25,896 26,653
Total current liabilities 347,088 431,257
NON-CURRENT LIABILITIES:
Long-term debt (see Notes 7 and 12) 1,799,502 1,685,503
Deferred income tax liabilities 300,178 289,799
Taxes payable - 7,458
Regulatory liabilities, non-current 826,709 839,360
Accrued pension and other postretirement benefits 4,290 5,334
Asset retirement obligations 189,509 195,236
Other non-current liabilities 4,597 13,785
Total non-current liabilities 3,124,785 3,036,475
Total liabilities 3,471,873 3,467,732
COMMITMENTS AND CONTINGENCIES (see Note 10)
SHAREHOLDER'S EQUITY:
Common stock 324,537 324,537
Paid in capital 939,993 664,886
Retained earnings 426,800 435,470
Total shareholder's equity 1,691,330 1,424,893
Cumulative preferred stock 59,784 59,784
Total shareholder's equity 1,751,114 1,484,677
TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY $ 5,222,987 $ 4,952,409
See notes to consolidated financial statements.
AES INDIANA and SUBSIDIARIES
Consolidated Statements of Cash Flows
For the Years Ended December 31, 2021, 2020 and 2019
(In Thousands)
2021 2020 2019
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 150,243 $ 144,040 $ 157,277
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization 256,085 246,896 240,314
Amortization of deferred financing costs and debt discounts 2,536 2,335 2,262
Deferred income taxes and investment tax credit adjustments - net (7,373) 3,078 15,120
Allowance for equity funds used during construction (5,412) (4,574) (3,486)
Gain on acquisition (5,630) - -
Change in certain assets and liabilities:
Accounts receivable (13,746) (4,071) 6,504
Inventories (12,017) (15,240) 13,574
Accounts payable 21,502 (20,621) 2,816
Accrued and other current liabilities (21,680) (8,214) 4,416
Accrued taxes payable/receivable (2,302) 18,012 (15,437)
Accrued interest (1,099) (518) 546
Pension and other postretirement benefit assets and liabilities (16,592) (6,991) 5,414
Short-term and long-term regulatory assets and liabilities (104,759) (13,390) 921
Prepayments and other current assets 4,172 (569) (2,119)
Other - net 3,856 (6,174) (7,053)
Net cash provided by operating activities 247,784 333,999 421,069
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (291,510) (235,700) (213,619)
Project development costs (1,304) (2,401) (2,269)
Cost of removal and regulatory recoverable ARO payments (48,952) (37,786) (21,838)
Loans to parent - (26,110) -
Loan repayments from parent 6,110 20,000 -
Purchase of intangibles (26,261) - -
Other (688) 118 -
Net cash used in investing activities (362,605) (281,879) (237,726)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under revolving credit facilities 320,000 115,000 10,000
Repayments under revolving credit facilities (335,000) (40,000) (10,000)
Long-term borrowings, net of discount 95,000 90,000 -
Retirement of long-term debt (95,000) (90,000) -
Dividends on common stock (155,700) (147,600) (159,000)
Dividends on preferred stock (3,213) (3,213) (3,213)
Deferred financing costs paid (1,325) (792) -
Equity contributions from IPALCO 275,000 - -
Payments for financed capital expenditures (36) (36) (5,623)
Other (95) (117) (152)
Net cash provided by (used in) financing activities 99,631 (76,758) (167,988)
Net change in cash, cash equivalents and restricted cash (15,190) (24,638) 15,355
Cash, cash equivalents and restricted cash at beginning of period 17,951 42,589 27,234
Cash, cash equivalents and restricted cash at end of period $ 2,761 $ 17,951 $ 42,589
Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest (net of amount capitalized) $ 82,880 $ 84,869 $ 88,546
Income taxes 40,800 27,000 37,400
Non-cash investing activities:
Accruals for capital expenditures $ 81,325 $ 54,360 $ 35,471
See notes to consolidated financial statements.
AES INDIANA and SUBSIDIARIES
Consolidated Statements of Common Shareholder's Equity and Cumulative Preferred Stock
For the Years Ended December 31, 2021, 2020 and 2019
(In Thousands)
Common Stock Paid in Capital Retained Earnings Total Shareholder's Equity Cumulative Preferred Stock
Balance at January 1, 2019 $ 324,537 $ 664,513 $ 440,179 $ 1,429,229 $ 59,784
Net income - - 157,277 157,277 3,213
Preferred stock dividends - - (3,213) (3,213) (3,213)
Cash dividends declared on common stock - - (159,000) (159,000) -
Other - 206 - 206 -
Balance at December 31, 2019 324,537 664,719 435,243 1,424,499 59,784
Net income - - 144,040 144,040 3,213
Preferred stock dividends - - (3,213) (3,213) (3,213)
Cash dividends declared on common stock - - (140,600) (140,600) -
Other - 167 - 167 -
Balance at December 31, 2020 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 $ 324,537 $ 939,993 $ 426,800 $ 1,691,330 $ 59,784
See notes to consolidated financial statements.
AES INDIANA and SUBSIDIARIES
Notes to Consolidated Financial Statements
For the Years Ended December 31, 2021, 2020 and 2019
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 516,000 retail customers in the city of Indianapolis and neighboring cities, towns and communities, and adjacent rural areas all within the state of Indiana, with the most distant point being approximately forty miles from Indianapolis. 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. Our largest generating station, Petersburg, is coal-fired, and AES Indiana retired 230 MW Petersburg Unit 1 on May 31, 2021 and has plans to retire 415 MW Petersburg Unit 2 in 2023, which would result in 630 MW of total retired economic capacity at this station (for further discussion, see Note 2, "Regulatory Matters - IRP Filing and Replacement Generation"). The second largest station, Harding Street, uses natural gas and fuel oil to power 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 small peaking station that uses natural gas to power combustion turbines. As of December 31, 2021, AES Indiana’s net electric generation capacity for winter is 3,475 MW and net summer capacity is 3,330 MW. On December 17, 2021, AES Indiana, through its wholly-owned subsidiary AES Indiana Devco Holdings 1, LLC, completed the acquisition of Hardy Hills Solar Energy LLC, including the development of a 195 MW solar project (the "Hardy Hills Solar Project"). In July 2021, AES Indiana, through its wholly-owned subsidiary AES Indiana Devco Holdings 2, LLC, executed an agreement to acquire a 250 MW solar and 180 MWh energy storage facility (the "Petersburg Solar Project").
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 AES Indiana Devco Holdings 1, LLC and AES Indiana Devco Holdings 2, LLC (these entities were formed on November 18, 2020 and May 27, 2021, respectively, related to the replacement generation project for retired Petersburg units). 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.
Use of Management Estimates
The preparation of financial statements in conformity with GAAP requires that management make certain estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements. The reported amounts of revenues and expenses during the reporting period may also be affected by the estimates and assumptions management is required to make. Actual results may differ from those estimates.
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.
Cash, Cash Equivalents and Restricted Cash
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 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 as shown on the Consolidated Statements of Cash Flows:
As of December 31,
2021 2020
(In Thousands)
Cash, cash equivalents and restricted cash
Cash and cash equivalents $ 2,756 $ 17,946
Restricted cash 5 5
Total cash, cash equivalents and restricted cash $ 2,761 $ 17,951
Revenues and Accounts Receivable
Revenues related to the sale of energy are 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 complex models that consider various factors including daily generation volumes; known amounts of energy usage by nearly all residential, commercial and industrial customers; estimated line losses; 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. The effect on 2021 revenues and ending unbilled revenues of a one percentage point change in estimated line losses for the month of December 2021 is immaterial. 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 $3.0 million, $4.8 million and $4.3 million for the years ended December 31, 2021, 2020 and 2019, 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.
The following table summarizes our accounts receivable balances at December 31:
As of December 31,
2021 2020
(In Thousands)
Accounts receivable, net
Customer receivables $ 100,952 $ 91,335
Unbilled revenue 64,758 72,334
Amounts due from related parties 214 734
Other 13,904 4,187
Allowance for credit losses (647) (3,155)
Total accounts receivable, net $ 179,181 $ 165,435
The following table is a rollforward of our allowance for credit losses related to the accounts receivable balances for the periods indicated (in Thousands):
Year Ended December 31, 2021 Beginning Allowance Balance at January 1, 2021 Current Period Provision Write-offs Charged Against Allowances Recoveries Collected Ending Allowance Balance at
December 31, 2021
Allowance for credit losses $ 3,155 $ 2,035 $ (6,448) $ 1,905 $ 647
Year Ended December 31, 2020 Beginning Allowance Balance at January 1, 2020 Current Period Provision Write-offs Charged Against Allowances Recoveries Collected Ending Allowance Balance at
December 31, 2020
Allowance for credit losses $ 921 $ 5,861 (5,473) $ 1,846 $ 3,155
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, including the economic impacts of the COVID-19 pandemic on our receivable balance as of December 31, 2021. Amounts are written off when reasonable collections efforts have been exhausted. An Executive Order issued by the Governor of Indiana on March 19, 2020 and extended by the IURC prohibited electric utilities, including us, from discontinuing electric utility service to customers through August 14, 2020 due to the economic impacts of COVID-19. This order along with the economic impacts of COVID-19 resulted in an increase in past due customer receivable balances in 2020, and thus the current period provision and the allowance for credit losses increased during the prior year. During 2021, the current period provision and allowance for credit losses decreased due to lower past due customer receivable balances. Please see additional discussion in Note 2, "Regulatory Matters - IURC COVID-19 Order” and Note 15, "Risks and Uncertainties - COVID-19 Pandemic."
Inventories
AES Indiana maintains coal, fuel oil, 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,
2021 2020
(In Thousands)
Inventories
Fuel $ 41,626 $ 36,953
Materials and supplies, net 60,273 58,553
Total inventories $ 101,899 $ 95,506
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% during 2021, 2020 and 2019, respectively. Depreciation expense was $239.1 million, $232.8 million, and $228.2 million for the years ended December 31, 2021, 2020 and 2019, 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.
Allowance For Funds Used During Construction
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 5.7%, 6.9% and 6.9% during 2021, 2020 and 2019, respectively.
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 $4.0 billion and $4.1 billion as of December 31, 2021 and 2020, respectively. As of December 31, 2021 and 2020, AES Indiana had $300.1 million and $74.5 million, respectively, of long-term regulatory assets associated with the Petersburg Unit 1 retirement and the probable Petersburg Unit 2 retirement (for further discussion, see Note 2, “Regulatory Matters - IRP Filing 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 include capitalized software and project development intangible assets amortized over their useful lives. Capitalized software of $162.0 million and $144.5 million and its corresponding accumulated amortization of $95.8 million and $85.3 million is recorded as of December 31, 2021 and 2020, respectively. Amortization expense for capitalized software was $11.2 million, $10.6 million and $7.5 million for the years ended December 31, 2021, 2020 and 2019, respectively. These capitalized software intangible assets have a 7 year-weighted average amortization period and the estimated amortization expense is approximately $52.5 million over the next 5 years ($10.5 million in 2022, $10.5 million in 2023, $10.5 million in 2024, $10.5 million in 2025 and $10.5 million in 2026). AES Indiana recorded project development intangible assets of $39.5 million during the year ended December 31, 2021. These project development intangible assets have a 30 year-weighted average amortization period and the estimated amortization expense is approximately $4.9 million over the next 5 years ($0.0 million in 2022, $1.0 million in 2023, $1.3 million in 2024, $1.3 million in 2025 and $1.3 million in 2026).
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 $9.1 million and $8.8 million as of December 31, 2021 and 2020, respectively, which are recorded within "Other non-current assets" on the accompanying Consolidated Balance Sheets.
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. As of December 31, 2021 and 2020, total loss contingencies accrued were $0.2 million and $15.4 million, respectively, which were included in “Accrued and Other Current Liabilities” and "Other Non-Current Liabilities", respectively, on the accompanying Consolidated Balance Sheets.
Concentrations of Risk
Substantially all of AES Indiana’s customers are located within the Indianapolis area. Approximately 69% 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 13, 2023. Additionally, AES Indiana has long-term coal contracts with three suppliers, and substantially all of AES Indiana's coal is currently mined in the state of Indiana.
Financial Derivatives
All derivatives are recognized as either assets or liabilities in the balance sheets and are measured at fair value. Changes in the fair value are recorded in earnings unless the derivative is designated as a cash flow hedge of a forecasted transaction or it qualifies for the normal purchases and sales exception.
AES Indiana has contracts involving the physical delivery of energy and fuel. 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'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 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.
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, 2021, the $5.6 million represents a gain on acquisition.
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 8, "Income Taxes" for additional information.
Pension and Postretirement Benefits
AES Indiana recognizes in its Consolidated Balance Sheets an asset or liability reflecting the funded status of pension and other postretirement plans with current-year changes in the funded status, that would otherwise be recognized in AOCI, recorded as a regulatory asset as this can be recovered through future rates. All plan assets are recorded at fair value. AES Indiana follows the measurement date provisions of the accounting guidance, which require a year-end measurement date of plan assets and obligations for all defined benefit plans.
AES Indiana accounts for and discloses pension and postretirement benefits in accordance with the provisions of GAAP relating to the accounting for pension and other postretirement plans. These GAAP provisions require the use of assumptions, such as the discount rate for liabilities and long-term rate of return on assets, in determining the obligations, annual cost and funding requirements of the plans. Consistent with the requirements of ASC 715, AES Indiana applies a disaggregated discount rate approach for determining service cost and interest cost for its defined benefit pension plans and postretirement plans.
See Note 9, "Benefit Plans" for more information.
Repair and Maintenance Costs
Repair and maintenance costs are expensed as incurred.
Per Share Data
IPALCO owns all of the outstanding common stock of AES Indiana. AES Indiana does not report earnings on a per-share basis.
New Accounting Pronouncements
The following table provides a brief description of recent accounting pronouncements that had an impact on the Company’s Financial Statements. Accounting pronouncements not listed below were assessed and determined to be either not applicable or did not have a material impact on the Company’s Financial Statements.
New Accounting Standards Adopted
ASU Number and Name Description Date of Adoption Effect on the Financial Statements upon adoption
2016-13, 2018-19, 2019-04, 2019-05, 2019-10, 2019-11, 2020-02, 2020-03, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments See discussion of the ASU below.
January 1, 2020 See impact upon adoption of the standard below.
ASC 326 - Financial Instruments - Credit Losses
On January 1, 2020, the Company adopted ASC 326 Financial Instruments - Credit Losses and its subsequent corresponding updates ("ASC 326"). The new standard updates the impairment model for financial assets measured at amortized cost, known as the Current Expected Credit Loss ("CECL") model. For trade and other receivables, held-to-maturity debt securities, loans and other instruments, entities are required to use a new forward-looking "expected loss" model that generally results in the earlier recognition of an allowance for credit losses. For available-for-sale debt securities with unrealized losses, entities measure credit losses as it was done under previous GAAP, except that unrealized losses due to credit-related factors are now recognized as an allowance on the balance sheet with a corresponding adjustment to earnings in the income statement.
The Company applied the modified retrospective method of adoption for ASC 326. Under this transition method, the Company applied the transition provisions starting at the date of adoption. The CECL model primarily impacts the calculation of the Company's expected credit losses in gross customer trade accounts receivable. The adoption of ASC 326 and the application of CECL on our trade accounts receivable did not have a material impact on our 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.
New Accounting Standards Issued But Not Yet Effective
ASU Number and Name Description Date of Adoption Effect on the Financial Statements upon adoption
2021-05, Leases (Topic 842), Lessors-Certain Leases with Variable Lease Payments The amendments in this update affect lessors with lease contracts that (1) have variable lease payments that do not depend on a reference index or a rate and (2) would have resulted in the recognition of a selling loss at lease commencement if classified as sales-type or direct financing. Lessors should classify and account for a lease with variable lease payments that do not depend on a reference index or a rate as an operating lease if both of the following criteria are met: (a) The lease would have been classified as a sales-type lease or a direct financing lease in accordance with the classification criteria in paragraphs 842-10-25-2 through 25-3, (b) The lessor would have otherwise recognized a day-one loss. This update could be applied either (1) retrospectively to leases that commenced or were modified on or after the adoption of Update 2016-02 or (2) prospectively to leases that commence or are modified on or after the date that an entity first applies the amendments. Earlier application is permitted. For fiscal years beginning after December 15, 2021, including interim periods within those fiscal years. The Company is currently evaluating the impact of adopting the standard on its consolidated financial statements.
2020-04 and 2021-01, Reference Rate Form (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting The amendments in these updates provide optional expedients and exceptions for applying GAAP to contracts, hedging relationships and other transactions that reference to LIBOR or another reference rate expected to be discontinued by reference rate reform, and clarify that certain optional expedients and exceptions in Topic 848 for contract modifications and hedge accounting apply to derivatives that are affected by the discounting transition. These amendments are effective for a limited period of time (March 12, 2020 - December 21, 2022).
March 12, 2020 - December 31, 2022
The Company is currently evaluating the impact of adopting the standard on the 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 revenues. 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.
Base Rate Orders
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 revenues (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 also provides customers approximately $50 million in benefits, which flowed to customers over the two-year period that began March 2019, via the ECCRA rate adjustment mechanism. As of December 31, 2021, these credits have been fully returned to customers. This liability, less amounts returned to AES Indiana's customers, is recorded primarily in "Regulatory liabilities, current" ($0.0 million and $4.7 million as of December 31, 2021 and 2020, respectively) on the accompanying Consolidated Balance Sheets. In addition, 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. Prior to the 2018 Base Rate Order, wholesale sales margins were shared with customers 50% above and below an established benchmark of $6.3 million. 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. The 2018 Base Rate Order also approved changes to AES Indiana's depreciation and amortization rates (including no longer deferring depreciation on the CCGT at Eagle Valley) which altogether represent a net expense increase of approximately $28.7 million annually.
Other
The DOE issued a Notice of Proposed Rule Making on September 29, 2017, which directed the FERC to exercise its authority to set just and reasonable rates that recognize the “resiliency” value provided by generation plants with certain characteristics, including having 90-days or more of on-site fuel and operating in markets where they do not receive rate base treatment through state ratemaking. Nuclear and coal-fired generation plants would have been most likely to be able to meet the requirements. As proposed, the DOE would value resiliency through rates that recover “compensable costs” that were defined to include the recovery of operating and fuel expenses, debt service and a fair return on equity. On January 8, 2018, the FERC issued an order terminating this docket stating that it
failed to satisfy the legal requirements of Section 206 of the Federal Power Act of 1935. The FERC initiated a new docket to take additional steps to explore resilience issues in RTOs/ISOs. The goal of this new proceeding is to: (1) develop a common understanding among the FERC, State Commissions, RTOs/ISOs, transmission owners, and others as to what resilience of the bulk power system means and requires; (2) understand how each RTO and ISO assesses resilience in its geographic footprint; and (3) use this information to evaluate whether additional action regarding resilience is appropriate at this time. It is not possible to predict the impact of this proceeding on our business, financial condition and results of operations.
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 each of the last three calendar years, AES Indiana has reported earnings in excess of the authorized level for each of the four quarterly reporting periods in those years. AES Indiana was not required to reduce its fuel cost recovery in 2019 because of its Cumulative Deficiencies. During 2020, AES Indiana's Cumulative Deficiencies dropped to zero and thus AES Indiana recorded a reduction to revenue of $5.5 million and $10.0 million in 2021 and 2020, respectively. AES Indiana's regulatory liability attributed to the Cumulative Deficiencies calculation was $0.5 million and $7.7 million as of December 31, 2021 and 2020, respectively, which is recorded within "Regulatory liabilities, current" on the accompanying Consolidated Balance Sheets.
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. The total amount of AES Indiana’s equipment approved for ECCRA recovery as of December 31, 2021 was $23.4 million. The jurisdictional revenue requirement approved by the IURC to be included in AES Indiana’s rates for the twelve-month period ending February 2022 is a net cost to customers of $1.0 million. This amount is higher than the ECCRA periods in 2019 and 2020 due to AES Indiana fully crediting customers for the approximately $50 million of customer benefits that flowed through the ECCRA as a result of the 2018 Base Rate Order, as described above. The only equipment still remaining in the ECCRA as of December 31, 2021 are certain projects associated with NAAQS compliance.
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 2021, 2020 and 2019, AES Indiana also had the ability to receive performance incentives, dependent upon the level of success of the programs. Performance incentives included in revenues for the years ended December 31, 2021, 2020 and 2019 were $7.2 million, $6.0 million and $7.5 million, respectively.
On February 7, 2018, the IURC approved a settlement agreement approving a three year DSM plan for AES Indiana through 2020. 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 revenues, consistent with the provisions of the settlement agreement.
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 revenues, consistent with the provisions of the settlement agreement.
Wind and Solar Power Purchase Agreements
AES Indiana is committed under a power purchase agreement to purchase all wind-generated electricity through 2029 from a wind project in Indiana. 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, 2021. 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 revenues.
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 approved for TDSIC recovery as of December 31, 2021 was $159.5 million, The jurisdictional revenue requirement approved by the IURC to be included in AES Indiana’s rates for the twelve-month period ending October 2022 is a net cost to customers of $12.8 million.
IRP Filing and Replacement Generation
In December 2019, AES Indiana filed its IRP, 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. AES Indiana's Preferred Resource Portfolio is its reasonable least cost option and provides a cleaner and more diverse generation mix for customers. AES Indiana's Preferred Resource Portfolio includes 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 has determined that the cost of operating Petersburg Units 1 and 2 exceeds the value customers receive compared to alternative resources. Retirement of these units allows 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 is the first year AES Indiana is 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, but AES Indiana continues to assess the type, size, and location of resources in the bids we received. As a result of the plans to retire Petersburg Units 1 and 2, AES
Indiana recorded $0.8 million, $0.0 million and $6.2 million of obsolescence losses, during the periods ended December 31, 2021, 2020 and 2019, respectively, for materials and supplies inventory AES Indiana does 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.
On February 26, 2021, as a result of the plans to retire approximately 630 MW of coal-fired generation at Petersburg Units 1 and 2 in 2021 and 2023, respectively, AES Indiana filed a petition with the IURC 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 on May 31, 2021 and expects to retire Unit 2 in 2023. AES Indiana had recorded $74.5 million of net property, plant and equipment associated with the probable Petersburg Unit 1 retirement as a long-term regulatory assets as of December 31, 2020, and recorded $60.1 million and $239.9 million of Petersburg Units 1 and 2 retirement costs, respectively, net of accumulated amortization, as long-term regulatory assets as of December 31, 2021.
Hardy Hills Solar Project
In January 2021, AES Indiana, through its wholly-owned subsidiary AES Indiana Devco Holdings 1, LLC, executed an agreement for the acquisition and construction of the 195 MW Hardy Hills Solar Project to be developed in Clinton County, Indiana, which is expected to be completed in 2023. On February 12, 2021, AES Indiana filed a petition and case-in-chief with the IURC seeking a CPCN for this solar project and on June 16, 2021, AES Indiana received an order from the IURC approving the project, including a joint venture structure between an AES Indiana subsidiary and one or more tax equity partners upon completion. 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.
Petersburg Solar Project
In July 2021, AES Indiana, through its wholly-owned subsidiary AES Indiana Devco Holdings 2, LLC, executed an agreement for the acquisition and construction of a 250 MW solar and 180 MWh energy storage facility to be developed in Pike County, Indiana, which is expected to be completed in 2024. On July 30, 2021, AES Indiana filed a petition and case-in-chief with the IURC seeking a CPCN for this solar project and on November 24, 2021, AES Indiana received an order from the IURC approving the project, including a joint venture structure between an AES Indiana subsidiary and one or more tax equity partners upon completion.
In January 2022, AES Indiana held its first public advisory meeting for the 2022 IRP.
IURC COVID-19 Orders
In its June 29, 2020 order, the IURC extended the disconnection moratorium for IURC-jurisdictional utilities through August 14, 2020, which has lapsed. Additionally, the IURC authorized Indiana utilities to use regulatory accounting for any impacts associated with prohibiting utility disconnections, waiver or exclusion of certain utility fees (i.e., late fees, convenience fees, deposits, and reconnection fees), and also required utilities to use expanded payment arrangements to aid customers. The IURC also authorized regulatory accounting treatment for COVID-19 related uncollectible and incremental bad debt expense.
On August 12, 2020, the IURC required all jurisdictional utilities to continue offering extended payment arrangements for a minimum of six months to all customers for an additional 60 days, until October 12, 2020, which the IURC again extended through December 31, 2020 for residential customers on October 27, 2020. The IURC
also continued to suspend the collection of certain utility fees (late fees, deposits, and disconnection/reconnection fees) from residential customers for an additional 60 days, until October 12, 2020, after which utilities were allowed to resume charging convenience fees as set forth in the rate and charges established in their Commission-approved tariffs.
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 and $6.4 million as of December 31, 2021 and 2020, respectively. On August 25, 2021, the IURC closed the investigation to consider and address the impacts of the COVID-19 pandemic. For further discussion on the COVID-19 pandemic, see Note 15, "Risks and Uncertainties - COVID-19 Pandemic."
Excess Distributed Generation Rates
On March 1, 2021, AES Indiana filed a petition with the IURC for approval of its proposed rate for the procurement of excess distributed generation ("EDG") and related consumer EDG credit issues. The EDG rate will replace the current net metering program and will be offered beginning July 2022, when net metering is no longer available to new customers. The IURC approved the EDG rate by order dated January 26, 2022, and the case remains subject to a petition for reconsideration filed by the other parties on February 15, 2022 and a notice of appeal filed by the other parties on February 22, 2022.
Electric Vehicle Portfolio Program
On March 2, 2021, AES Indiana filed with the IURC a request to approve its Electric Vehicle (EV) portfolio and associated accounting and ratemaking treatment. The EV portfolio aims to accelerate electric car adoption by reducing friction in the car buying process, and by providing customers incentives to optimize electric car charging during off-peak periods. 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 $5.1 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. On August 26, 2021, AES Indiana’s request to vacate the procedural schedule and hold case in abeyance was granted. AES Indiana is required to update the IURC on the Company’s plans for this docket on or before February 12, 2022. On February 10, 2022, AES Indiana filed a notice of voluntary dismissal of this request without prejudice. The IURC dismissed the case on February 11, 2022.
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 44 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:
2021 2020 Recovery Period
(In Thousands)
Regulatory Assets
Current:
Undercollections of rate riders $ 49,998 $ 31,569 Approximately 1 year(1)
Costs being recovered through basic rates and charges 13,815 13,861 Approximately 1 year(1)
Total current regulatory assets 63,813 45,430
Long-term:
Unrecognized pension and other
postretirement benefit plan costs 114,887 149,374 Various(2)
Deferred MISO costs 47,875 61,267 Through 2026(1)
Unamortized Petersburg Unit 4 carrying
charges and certain other costs 4,921 5,975 Through 2026(1)(3)
Unamortized reacquisition premium on debt 15,703 17,018 Over remaining life of debt
Environmental projects 71,201 74,637 Through 2046(1)(3)
COVID-19 5,426 6,391 To be determined
TDSIC projects 8,540 2,747 36.3 years(1)(3)
Petersburg Unit 1 and 2 retirement costs 300,067 74,545 Through 2034(1)(3)
Hardy Hills Solar Project 2,907 - To be determined
Petersburg Solar Project 881 - To be determined
Fuel costs 83,513 - To be determined
Other miscellaneous 1,056 847 Various(4)
Total long-term regulatory assets 656,977 392,801
Total regulatory assets $ 720,790 $ 438,231
Regulatory Liabilities
Current:
Overcollections and other credits being passed
to customers through rate riders $ 3,006 $ 29,493 Approximately 1 year(1)
FTRs 1,235 543 Approximately 1 year(1)
Total current regulatory liabilities 4,241 30,036
Long-term:
ARO and accrued asset removal costs 722,774 723,897 Not applicable
Deferred income taxes payable to customers through rates 100,171 112,957 Various
Other miscellaneous 3,764 2,506 To be determined
Total long-term regulatory liabilities 826,709 839,360
Total regulatory liabilities $ 830,950 $ 869,396
(1)Recovered (credited) per specific rate orders
(2)AES Indiana receives a return on its discretionary funding
(3)Recovered with a current return
(4) The majority of these costs are being recovered in basic rates and charges through 2026. For the remainder, recovery is probable, but the
timing is not yet determined.
(5) Recovered per regulatory precedent.
Current Regulatory Assets and Liabilities
Current regulatory assets and liabilities primarily represent costs that are being recovered per specific rate order; recovery for the remaining costs is probable, but not certain. As current assets, this includes undercollection of adjustment mechanisms for: (i) DSM, (ii) Off System Sales Margin Sharing, (iii) Capacity Cost Recovery, (iv) Green Power, (v) Deferred Fuel Costs and (vi) TDSIC. It also includes the current portion of deferred MISO costs and environmental costs collected through base rates which are described in greater detail below. As current liabilities, this includes overcollection of MISO rider costs, ECCRA costs, and the NOI liability that is credited to customers in the FAC filing.
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 FAC 133 IURC Order issued on November 24, 2021 approved the FAC 133 fuel cost factor on an interim basis subject to refund pending the outcome of a sub-docket created to examine the Eagle Valley CCGT extended outage. The FAC 134 IURC Order issued on February 23, 2022 approved a reduced FAC factor requested by AES Indiana in order to mitigate the rate impact on customers, primarily caused by rising commodity pricing and the Eagle Valley extended outage, that would defer the collection of variances until a future FAC filing or the resolution in the FAC sub-docket for the Eagle Valley outage. The order also approved deferral on an interim basis subject to refund pending the outcome of the sub-docket. Because the timing of collection is currently unknown, AES Indiana reclassified these variances to a long-term regulatory asset as of December 31, 2021 and will continue to record the FAC deferral as a long-term regulatory asset until AES Indiana seeks recovery.
Unrecognized Pension and Postretirement Benefit Plan Costs
In accordance with ASC 715 “Compensation - Retirement Benefits” and ASC 980, AES Indiana recognizes a regulatory asset equal to the unrecognized actuarial gains and losses and prior service costs. Pension expenses are recorded based on the benefit plan’s actuarially determined pension liability and associated level of annual expenses 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 Allowance for Funds Used During Construction ("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 44 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 31 years. See "TDSIC" above for additional discussion.
Petersburg Unit 1 and 2 Retirement Costs
These consist of the estimated remaining net book value of Petersburg Unit 1 and 2 at its anticipated date of retirement. 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 Filing and Replacement Generation" above for additional discussion.
Hardy Hills Solar Project
These consist of project development costs, mainly legal and consulting fees, incurred for the Hardy Hills Solar Project. These costs were approved for recovery through AES Indiana’s Hardy Hills Solar Project regulatory proceedings, but amortization will be determined in a future rate case filing.
Petersburg Solar Project
These consist of project development costs, mainly legal and consulting fees, incurred for the Petersburg Solar Project. These costs were approved for recovery through AES Indiana’s Petersburg Solar Project regulatory proceedings, but amortization 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 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 $100.2 million and $113.0 million as of December 31, 2021 and 2020, respectively.
3. PROPERTY, PLANT AND EQUIPMENT
The original cost of property, plant and equipment segregated by functional classifications follows:
As of December 31,
2021 2020
(In Thousands)
Production $ 4,099,110 $ 4,191,223
Transmission 436,257 408,380
Distribution 1,831,029 1,671,861
General plant 277,533 258,931
Total property, plant and equipment $ 6,643,929 $ 6,530,395
As of December 31, 2021 and 2020, AES Indiana had $300.1 million and $74.5 million, respectively, of net property, plant and equipment associated with the probable Petersburg Unit 1 and Unit 2 retirements recorded as long-term regulatory assets (for further discussion, see Note 2, “Regulatory Matters - IRP Filing”).
Substantially all of AES Indiana’s property is subject to a $1,803.8 million direct first mortgage lien, as of December 31, 2021, securing AES Indiana’s first mortgage bonds. Total non-contractually or legally required accrued removal costs of utility plant in service at December 31, 2021 and 2020 were $846.1 million and $818.0 million, respectively; and total contractually or legally required removal costs of property, plant and equipment at December 31, 2021 and 2020 were $189.5 million and $195.2 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:
2021 2020
(In Thousands)
Balance as of January 1 $ 195,236 $ 204,219
Liabilities settled (13,692) (18,302)
Revisions to cash flow and timing estimates - 1,120
Accretion expense 7,965 8,199
Balance as of December 31 $ 189,509 $ 195,236
AES Indiana recorded adjustments to its ARO liabilities of $0.0 million and $1.1 million in 2021 and 2020, respectively, primarily to reflect increases to estimated ash pond closure costs, including groundwater remediation. As of December 31, 2021 and 2020, AES Indiana did not have any assets that are legally restricted for settling its ARO liability.
4. FAIR VALUE
The fair value of 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. As 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, 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 revenues 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
In 2021, we entered into forward purchase power contracts. As of December 31, 2021, all outstanding forward power contracts had all 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 and liabilities at December 31, 2021 measured on a recurring basis and the respective category within the fair value hierarchy for AES Indiana was determined as follows:
Assets and Liabilities at Fair Value
Level 1 Level 2 Level 3
Fair value at December 31, 2021 Based on quoted market prices in active markets Other observable inputs Unobservable inputs
(In Thousands)
Financial assets:
Financial transmission rights $ 1,235 $ - $ - $ 1,235
Total financial assets measured at fair value $ 1,235 $ - $ - $ 1,235
The fair value of assets and liabilities at December 31, 2020 measured on a recurring basis and the respective category within the fair value hierarchy for AES Indiana was determined as follows:
Assets and Liabilities at Fair Value
Level 1 Level 2 Level 3
Fair value at December 31, 2020 Based on quoted market prices in active markets Other observable inputs Unobservable inputs
(In Thousands)
Financial assets:
Financial transmission rights $ 543 $ - $ - $ 543
Total financial assets measured at fair value $ 543 $ - $ - $ 543
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, 2020 $ 864
Issuances 1,889
Settlements (2,210)
Balance at December 31, 2020 $ 543
Issuances 2,971
Settlements (2,279)
Balance at December 31, 2021 $ 1,235
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, 2021 December 31, 2020
Face Value Fair Value Face Value Fair Value
(In Thousands)
Fixed-rate $ 1,803,800 $ 2,222,772 $ 1,803,800 $ 2,302,973
Variable-rate 60,000 60,000 75,000 75,000
Total indebtedness $ 1,863,800 $ 2,282,772 $ 1,878,800 $ 2,377,973
The difference between the face value and the carrying value of this indebtedness represents the following:
•unamortized deferred financing costs of $17.9 million and $17.4 million at December 31, 2021 and 2020, respectively; and
•unamortized discounts of $5.9 million and $6.0 million at December 31, 2021 and 2020, respectively.
5. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
We use derivatives principally to manage the risk of price changes for purchased power. The derivatives that we use to economically hedge this risk is 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, 2021, AES Indiana's outstanding derivative instruments were as follows:
Commodity Accounting Treatment (a)
Unit Purchases
(in thousands) Sales
(in thousands) Net Purchases/(Sales)
(in thousands)
FTRs Not Designated MWh 6,091 - 6,091
(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 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. 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 $6.0 million related to forward power contracts during the year ended December 31, 2021. The net gains resulting from these contracts have been deferred and included with deferred fuel costs in "Regulatory assets, non-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 mark to market 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, 2021 and 2020, 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 2021 2020
Financial transmission rights Not a Cash Flow Hedge Prepayments and other current assets $ 1,235 $ 543
6. EQUITY
Paid in Capital and Capital Stock
On December 13, 2021, AES Indiana received an equity capital contribution of $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, 2021.
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, 2021, 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, 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, 2021, 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, 2021, 2020 and 2019, AES Indiana declared dividends to its shareholder totaling $155.7 million, $140.6 million, and $159.0 million, respectively.
Cumulative Preferred Stock
AES Indiana has five separate series of cumulative preferred stock. Holders of preferred stock are entitled to receive dividends at rates per annum ranging from 4.0% to 5.65%. During each year ended December 31, 2021, 2020 and 2019, total preferred stock dividends declared were $3.2 million. Holders of preferred stock are 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 are 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 is 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. AES Indiana has issued and outstanding 500,000 shares of 5.65% preferred stock, which are redeemable at par value, subject to certain restrictions, in whole or in part. Additionally, AES Indiana has 91,353 shares of preferred stock which are redeemable at the option of AES Indiana and can be redeemed in whole or in part at any time at specific call prices.
At December 31, 2021, 2020 and 2019, preferred stock consisted of the following:
December 31, 2021 December 31,
Shares
Outstanding Call Price 2021 2020 2019
Par Value, plus premium, if applicable
(In Thousands)
Cumulative $100 par value,
authorized 2,000,000 shares
4% Series
47,611 $ 118.00 $ 5,410 $ 5,410 $ 5,410
4.2% Series
19,331 $ 103.00 1,933 1,933 1,933
4.6% Series
2,481 $ 103.00 248 248 248
4.8% Series
21,930 $ 101.00 2,193 2,193 2,193
5.65% Series
500,000 $ 100.00 50,000 50,000 50,000
Total cumulative preferred stock 591,353 $ 59,784 $ 59,784 $ 59,784
7. DEBT
Long-Term Debt
The following table presents AES Indiana’s long-term debt:
December 31,
Series Due 2021 2020
(In Thousands)
AES Indiana first mortgage bonds:
3.875% (1)
August 2021 $ - $ 55,000
3.875% (1)
August 2021 - 40,000
3.125% (1)
December 2024 40,000 40,000
0.65% (1)
August 2025 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 -
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 (5,855) (6,006)
Deferred financing costs (17,913) (17,384)
Total AES Indiana first mortgage bonds 1,780,032 1,780,410
Total consolidated AES Indiana long-term debt 1,780,032 1,780,410
Less: current portion of long-term debt - 94,907
Net consolidated AES Indiana long-term debt $ 1,780,032 $ 1,685,503
(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.
Debt Maturities
Maturities on long-term indebtedness subsequent to December 31, 2021, are as follows:
Year Amount
(In Thousands)
2022 $ -
2023 -
2024 40,000
2025 40,000
2026 90,000
Thereafter 1,633,800
Total $ 1,803,800
Significant Transactions
AES Indiana First Mortgage Bonds and Recent Indiana Finance Authority Bond Issuances
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 $1,803.8 million as of December 31, 2021. The AES Indiana first mortgage bonds require net earnings 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, 2021.
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.
In December 2020, the Indiana Finance Authority issued at the request of AES Indiana an aggregate principal amount of $90 million of Environmental Facilities Refunding Revenue Bonds, Series 2020A&B due December 2038. AES Indiana issued $90 million aggregate principal amount of first mortgage bonds to the Indiana Finance Authority in two series: $30 million Series 2020A notes at an interest rate of 0.75% and $60 million Series 2020B notes at an interest rate of 0.95% to secure the loan of proceeds from these bonds issued by the Indiana Finance Authority. These bonds are subject to a mandatory put date of April 1, 2026. Proceeds of the bond offering were used to refund $90 million of Indiana Finance Authority Environmental Facilities Refunding Revenue Bonds Series 2015A&B at a redemption price of 100% of par.
Line of Credit
AES Indiana entered into an amendment and restatement of its $250 million revolving Credit Agreement on June 19, 2019 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 June 19, 2024, 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 June 19, 2023, 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, 2021 and 2020, AES Indiana had $60.0 million and $75.0 million in outstanding borrowings on the committed Credit Agreement, respectively.
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 $500 million of short-term indebtedness outstanding at any time through July 26, 2022. 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, all of which authority remains available as of December 31, 2021. 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 $500.0 million remains available under the order as of December 31, 2021. 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, 2021. 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.
Credit Ratings
AES Indiana’s ability to borrow money or to refinance existing indebtedness and the interest rates at which AES Indiana can borrow money or refinance existing indebtedness are affected by AES Indiana’s credit ratings. In addition, the applicable interest rates on AES Indiana’s Credit Agreement are dependent upon the credit ratings of AES Indiana. Downgrades in the credit ratings of AES and/or IPALCO could result in AES Indiana’s credit ratings being downgraded.
8. INCOME TAXES
AES Indiana follows a policy of comprehensive interperiod income tax allocation. Investment tax credits related to utility property have been deferred and are being amortized over the estimated useful lives of the related property.
AES files federal and state income tax returns which consolidate IPALCO and AES Indiana. Under a tax sharing agreement with IPALCO, AES Indiana is responsible for the income taxes associated with its own taxable income and records the provision for income taxes as if AES Indiana filed separate income tax returns. AES Indiana is no longer subject to U.S. or state income tax examinations for tax years through March 27, 2001, but is open for all subsequent periods. AES Indiana made tax sharing payments to IPALCO of $40.8 million, $27.0 million and $37.4 million in 2021, 2020 and 2019, respectively.
On March 25, 2014, the state of Indiana amended Indiana Code 6-3-2-1 through Senate Bill 001, which phases in an additional 1.6% reduction to the state corporate income tax rate that was initially being reduced by 2%. While the statutory state income tax rate decreased to 5.075% for the calendar year 2021, the deferred tax balances were adjusted according to the anticipated reversal of temporary differences. The statutory state corporate income tax rate will be 4.9% for 2022 and beyond.
Income Tax Provision
Federal and state income taxes charged to income are as follows:
2021 2020 2019
(In Thousands)
Components of income tax expense:
Current income taxes:
Federal $ 36,353 $ 28,395 $ 23,941
State 10,325 8,661 4,370
Total current income taxes 46,678 37,056 28,311
Deferred income taxes:
Federal (7,283) 503 7,578
State (90) 2,576 7,556
Total deferred income taxes (7,373) 3,079 15,134
Net amortization of investment credit - - (15)
Total income tax expense $ 39,305 $ 40,135 $ 43,430
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:
2021 2020 2019
Federal statutory tax rate 21.0 % 21.0 % 21.0 %
State income tax, net of federal tax benefit 4.0 % 4.2 % 4.4 %
Depreciation flow through and amortization (4.9) % (5.1) % (4.7) %
Additional funds used during construction - equity 0.3 % 0.7 % 0.2 %
Other - net 0.3 % 1.0 % 0.8 %
Effective tax rate 20.7 % 21.8 % 21.7 %
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, 2021 and 2020 are as follows:
2021 2020
(In Thousands)
Deferred tax liabilities:
Relating to utility property, net $ 369,783 $ 408,291
Regulatory assets recoverable through future rates 126,531 82,783
Other 18,283 5,323
Total deferred tax liabilities 514,597 496,397
Deferred tax assets:
Investment tax credit 7 6
Regulatory liabilities including ARO 205,099 197,657
Employee benefit plans - 3,866
Other 9,313 5,069
Total deferred tax assets 214,419 206,598
Deferred income tax liability - net $ 300,178 $ 289,799
Uncertain Tax Positions
The following is a reconciliation of the beginning and ending amounts of unrecognized tax benefits for the years ended December 31, 2021, 2020 and 2019:
2021 2020 2019
(In Thousands)
Unrecognized tax benefits at January 1 $ 7,368 $ 7,056 $ 7,056
Gross increases - current period tax positions - 312 -
Gross decreases - prior period tax positions (7,368) - -
Unrecognized tax benefits at December 31 $ - $ 7,368 $ 7,056
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 March 27, 2001 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, 2021 is the appropriate accrual for our uncertain tax positions. However, audit outcomes and the timing of audit settlements and future events that would impact AES Indiana's previously recorded unrecognized tax benefits are subject to significant uncertainty. It is possible that the ultimate outcome of future examinations may exceed AES Indiana's provision for current unrecognized tax benefits.
Tax-related interest expense and income is reported as part of the provision for federal and state income taxes. Penalties, if incurred, would also be recognized as a component of tax expense. There are no interest or penalties applicable to the periods contained in this report.
9. BENEFIT PLANS
Defined Contribution Plans
All of AES Indiana’s employees are covered by one of two defined contribution plans, the Thrift Plan or the RSP:
The Thrift Plan
Approximately 79% 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 $3.4 million, $3.4 million and $3.3 million for 2021, 2020 and 2019, respectively.
The RSP
Approximately 21% 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 $1.9 million, $1.8 million and $1.6 million for 2021, 2020 and 2019, respectively.
Defined Benefit Plans
Approximately 70% of AES Indiana’s active employees are covered by the qualified Defined Benefit Pension Plan; while approximately 9% of active employees are IBEW clerical-technical unit employees who are only eligible for the Thrift Plan. The remaining 21% 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, 2021 was 21. 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 136 active employees and 19 retirees (including spouses) were receiving such benefits or entitled to future benefits as of January 1, 2021. The plan is unfunded. These postretirement health care benefits and the related unfunded obligation of $3.9 million and $4.3 million at December 31, 2021 and 2020, 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,
2021 2020
(In Thousands)
Change in benefit obligation:
Projected benefit obligation at January 1 $ 842,525 $ 782,795
Service cost 9,339 8,272
Interest cost 15,660 22,151
Actuarial (gain)/loss (37,858) 66,827
Amendments (primarily increases in pension bands) 5,575 967
Benefits paid (63,201) (38,487)
Projected benefit obligation at December 31 772,040 842,525
Change in plan assets:
Fair value of plan assets at January 1 850,020 769,704
Actual return on plan assets 33,841 118,716
Employer contributions 24 87
Benefits paid (63,201) (38,487)
Fair value of plan assets at December 31 820,684 850,020
Funded status $ 48,644 $ 7,495
Amounts recognized in the statement of financial position:
Non-current assets $ 49,182 $ 8,669
Non-current liabilities (538) (1,174)
Net amount recognized at end of year $ 48,644 $ 7,495
Sources of change in regulatory assets(1):
Prior service cost arising during period $ 5,575 $ 967
Net gain arising during period (29,884) (14,110)
Amortization of prior service cost (2,944) (3,677)
Amortization of loss (5,529) (8,115)
Total recognized in regulatory assets $ (32,782) $ (24,935)
Amounts included in regulatory assets:
Net loss $ 110,113 $ 145,526
Prior service cost 14,244 11,613
Total amounts included in regulatory assets $ 124,357 $ 157,139
(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 Gains and Losses Related to Changes in the Benefit Obligation for the Period
As shown in the table above, an actuarial gain of $37.9 million decreased the benefit obligation for the year ended December 31, 2021 and an actuarial loss of $66.8 million increased the benefit obligation for the year ended December 31, 2020. The actuarial gain in 2021 was primarily due to an increase in the discount rate. The actuarial loss in 2020 was primarily due to a decrease 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, earnings 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 2021 net actuarial gain of $29.9 million recognized in regulatory assets is comprised of two parts: (1) a $37.9 million pension liability actuarial loss primarily due to an increase in the discount rate used to value pension liabilities; partially offset by (2) a $8.0 million pension asset actuarial loss primarily due to lower than expected return on assets. The unrecognized net loss of $110.1 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 increased the expected benefit obligation due to the longer expected lives of plan participants. During 2021, the accumulated net gain decreased due to lower than expected return on pension assets, which was partially offset by a combination of higher discount rates used to value pension liabilities, as well as the year 2021 amortization of accumulated loss. 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 11.43 years based on estimated demographic data as of December 31, 2021. The projected benefit obligation of $772.0 million less the fair value of assets of $820.7 million results in an overfunded status of $48.6 million at December 31, 2021.
Pension benefits for
years ended December 31,
2021 2020 2019
(In Thousands)
Components of net periodic benefit (credit) / cost:
Service cost $ 9,339 $ 8,272 $ 7,412
Interest cost 15,660 22,151 27,343
Expected return on plan assets (41,815) (37,779) (29,907)
Amortization of prior service cost 2,944 3,677 3,823
Amortization of actuarial loss 5,529 8,115 11,084
Net periodic benefit (credit) / cost (8,343) 4,436 19,755
Less: amounts capitalized 771 372 1,237
Amount charged to expense $ (7,572) $ 4,064 $ 18,518
Rates relevant to each year’s expense calculations:
Discount rate - defined benefit pension plan 2.46 % 3.33 % 4.36 %
Discount rate - supplemental retirement plan 2.31 % 3.05 % 4.24 %
Expected return on defined benefit pension plan assets 5.05 % 5.05 % 4.50 %
Expected return on supplemental retirement plan assets 3.60 % 4.45 % 4.50 %
Pension expense / (income) for the following year is determined as of the December 31 measurement date based on the fair value of the Pension Plans’ assets, the expected long-term rate of return on plan assets, a mortality table assumption that reflects the life expectancy of plan participants, and a discount rate used to determine the projected benefit obligation. For 2021, pension expense / (income) was determined using an assumed long-term rate of return on plan assets of 5.05% for the Defined Benefit Pension Plan and 3.60% for the Supplemental Retirement Plan. As of the December 31, 2021 measurement date, AES Indiana increased the discount rate from 2.46% to 2.83% for the Defined Benefit Pension Plan and from 2.31% to 2.62% for the Supplemental Retirement Plan. The discount rate assumptions affect the pension expense / (income) determined for 2022. In addition, AES Indiana decreased the expected long-term rate of return on plan assets from 5.05% to 4.45% for the Defined Benefit Pension Plan and increased the expected long-term rate of return for the Supplemental Retirement Plan from 3.60% to 5.50% for 2022. The expected long-term rate of return assumption affects the pension expense / (income) determined for 2022. The effect on 2022 total pension expense / (income) of a 25 basis point increase and decrease in the assumed discount rate is $(1.3) million and $1.4 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, 2021. 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 are determined as of the plans' measurement date of December 31, 2021. 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 unfunded 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 2021:
Asset Category: Target Allocations
Equity Securities 22.5%
Debt Securities 77.5%
Fair Value Measurements at
December 31, 2021
(in thousands)
Quoted Prices in Active Markets for Identical Assets Significant Observable Inputs
Asset Category Total (Level 1) (Level 2) %
Cash and cash equivalents $ 2,353 $ 2,490 $ - - %
Government debt securities 154,051 324 153,727 19 %
Mutual fund - equities 183,203 2,778 180,425 22 %
Mutual fund - debt 481,077 1,637 479,440 59 %
Total $ 820,684 $ 7,229 $ 813,592 100 %
Fair Value Measurements at
December 31, 2020
(in thousands)
Quoted Prices in Active Markets for Identical Assets Significant Observable Inputs
Asset Category Total (Level 1) (Level 2) %
Cash and cash equivalents $ 2,221 $ 2,221 $ - - %
Government debt securities 118,255 131 118,124 14 %
Mutual fund - equities 323,253 2,839 320,414 38 %
Mutual fund - debt 406,291 1,578 404,713 48 %
Total(1)
$ 850,020 $ 6,769 $ 843,251 100 %
Pension Funding
AES Indiana contributed $0.0 million, $0.1 million, and $0.0 million to the Pension Plans in 2021, 2020 and 2019, 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 117%. In general, AES Indiana must contribute the normal service cost earned by active participants during the plan year; however, this amount can be offset by any surplus or credit balance carried by the Pension Plan. The normal cost is expected to be approximately $5.6 million in 2022 (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 2022. 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, 2021, 2020 and 2019 were $63.2 million, $38.5 million and $37.5 million, respectively. Expected benefit payments are expected to be paid out of the Pension Plans as follows:
Year Pension Benefits
(In Thousands)
2022 $ 39,994
2023 40,782
2024 41,509
2025 42,344
2026 42,893
2027 through 2031 216,332
10. COMMITMENTS AND CONTINGENCIES
Guarantees
We and certain of our subsidiaries enter into agreements from time to time providing financial or performance assurance to third parties for certain of our subsidiaries as part of our business, including guarantees and stand-by letters of credit. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to the subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiary's intended commercial purposes. At December 31, 2021, AES Indiana had issued $226.2 million of guarantees and no stand-by letters of credit.
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, 2021, 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 $ 1,241.8 $ 280.6 $ 310.3 $ 234.3 $ 416.6
Other $ 321.2 $ 241.6 $ 57.3 $ 14.6 $ 7.7
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, 2021, 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 and incentive compensation (see Note 5, "Derivative Instruments and Hedging Activities"), (iii) taxes (see Note 8, "Income Taxes"), (iv) pension and other postretirement employee benefit liabilities (see Note 9, "Benefit Plans") and (v) contingencies (see Note 10, "Commitments and Contingencies"). See the indicated notes to the Financial Statements for additional information on the items excluded.
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. As of December 31, 2021 and 2020, total legal loss contingencies accrued were $0.2 million and $13.4 million, respectively, which primarily related to personal injury litigation. During 2021, AES Indiana entered into settlements resolving a significant portion of the legal loss contingencies previously accrued. The legal loss contingencies and settlement related accruals are included in "Accrued and other current liabilities" and "Other Non-Current Liabilities" on the accompanying Consolidated Balance Sheets. AES Indiana maintains an amount of insurance protection for such litigation that it believes is adequate. As of December 31, 2021 and 2020, AES Indiana has $12.5 million and $11.3 million, respectively, of receivables for insurance recoveries determined to be probable recorded in "Prepayments and other current assets" and "Other non-current assets" on the accompanying Consolidated Balance Sheets. 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.
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.
New Source Review 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 New Source Review (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 current 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. If AES Indiana does not meet this retirement obligation, it must install a Selective Non-Catalytic Reduction System (SNCR) on Unit 4. AES Indiana has a contingent liability recorded related to these New Source Review and other CAA NOV matters.
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.
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 $7.0 million, $5.6 million, and $4.3 million in 2021, 2020 and 2019, respectively, and is recorded in “Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations. As of December 31, 2021 and 2020, AES Indiana had prepaid approximately of $2.3 million and $2.3 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 $23.7 million, $21.0 million, and $20.2 million in 2021, 2020 and 2019, 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, 2021 and 2020, 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 $6.7 million and $12.5 million as of December 31, 2021 and 2020, respectively, which is recorded in “Taxes receivable” on the accompanying Consolidated Balance Sheets. See Note 8, "Income Taxes" for more information.
Long-term Compensation Plan
During 2021, 2020 and 2019, 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 2021, 2020 and 2019 was $0.2 million, $0.3 million and $0.3 million, respectively, and was included in “Operating expenses - Operation and maintenance” on AES Indiana’s Consolidated Statements of Operations. The value of these benefits is being recognized over the 36 month vesting period and a portion is recorded as miscellaneous deferred credits with the remainder recorded as “Paid in capital” on AES Indiana’s Consolidated Balance Sheets in accordance with ASC 718 “Compensation - Stock Compensation.”
See also Note 9, “Benefit Plans” 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 $58.2 million, $55.5 million and $41.8 million during 2021, 2020 and 2019, respectively. Total costs incurred by AES Indiana on behalf of the Service Company during 2021, 2020 and 2019 were $10.4 million, $10.6 million and $9.7 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 $5.9 million and $4.5 million as of December 31, 2021 and December 31, 2020, 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. During the year ended December 31, 2020, AES Indiana made loans to IPALCO, net of repayments, of $6.1 million. AES Indiana had a loan receivable in the same amount recorded in “Prepayments and other current assets” on the accompanying Consolidated Balance Sheets as of December 31, 2020.
Additionally, transactions with various other related parties were $4.3 million, $6.5 million and $3.0 million during 2021, 2020 and 2019, respectively. These expenses were primarily recorded in “Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations.
12. BUSINESS SEGMENT INFORMATION
Operating segments are components of an enterprise that engage in business activities from which it may earn revenues 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 revenues - 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 revenues 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, though see Note 2, "Regulatory Matters - IURC COVID-19 Orders" for a discussion of the orders requiring expanded payment arrangements for customers.
Wholesale revenues - 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 revenues. 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 revenues - Miscellaneous revenues are mainly comprised of MISO transmission revenues. MISO transmission revenues are 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 revenues. Capacity revenues are also included in miscellaneous revenues, but these were not material for the period presented.
Transmission revenues have a single performance obligation, as transmission services represent a distinct service. Additionally, as the performance obligation is satisfied over time and the same method is used to measure progress, the performance obligation meets the criteria to be considered a series. 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.
AES Indiana’s revenue from contracts with customers was $1,389.2 million, $1,326.6 million and $1,455.3 million for the years ended December 31, 2021, 2020 and 2019, respectively. The following table presents AES Indiana's revenue from contracts with customers and other revenue (in thousands):
For the Years Ended December 31,
2021 2020 2019
Retail Revenues
Retail revenue from contracts with customers:
Residential $ 595,692 $ 566,668 $ 589,719
Small commercial and industrial 211,997 194,904 215,878
Large commercial and industrial 518,069 484,230 548,551
Public lighting 8,888 9,115 7,249
Other (1)
16,785 14,402 14,136
Total retail revenue from contracts with customers 1,351,431 1,269,319 1,375,533
Alternative revenue programs 35,248 24,781 23,841
Wholesale Revenues
Wholesale revenues from contracts with customers 25,059 46,482 68,474
Miscellaneous Revenues
Transmission and other revenue from contracts with customers 12,671 10,794 11,335
Other miscellaneous revenues (2)
1,723 1,609 2,460
Total Revenues $ 1,426,132 $ 1,352,985 $ 1,481,643
(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 revenues not accounted for under ASC 606
The balances of receivables from contracts with customers are $163.0 million and $163.8 million as of December 31, 2021 and 2020, respectively. Payment terms for all receivables from contracts with customers typically do not extend beyond 30 days, though see Note 2, "Regulatory Matters - IURC COVID-19 Order" for a discussion of orders requiring expanded payment arrangements for customers.
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.
Contract Balances - The timing of revenue recognition, billings, and cash collections results in accounts receivable and contract liabilities. The contract liabilities from contracts with customers were $0.0 million and $0.5 million as of December 31, 2021 and 2020, respectively. During the years ended December 31, 2021 and 2020, we recognized revenue of $0.5 million and $1.3 million related to this contract liability balance, respectively.
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, 2021 December 31, 2020
Assets
Right-of-use assets - finance leases Other non-current assets $ 19,763 $ -
Liabilities
Finance lease liabilities (current) Short-term debt 294 -
Finance lease liabilities (noncurrent) Long-term debt 19,469 -
Total finance lease liabilities $ 19,763 $ -
The following table summarizes supplemental balance sheet information related to leases as of the periods indicated:
Lease Term and Discount Rate December 31, 2021 December 31, 2020
Weighted-average remaining lease term - finance leases 31 years
N/A
Weighted-average discount rate - finance leases 4.561%
N/A
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, 2021 for 2022 through 2026 and thereafter (in millions):
Finance Leases
2022 $ 298
2023 955
2024 975
2025 997
2026 1,019
Thereafter 35,274
Total $ 39,518
Less: Imputed interest (19,755)
Present value of lease payments $ 19,763
LESSOR
The Company is the lessor under operating leases for land, office space and operating equipment. Minimum lease payments 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. Lease revenue included in the Consolidated Statements of Operations was $1.4 million, $0.9 million and $1.0 million for the years ended December 31, 2021, 2020 and 2019, respectively. Underlying gross assets and accumulated depreciation of operating leases included in Total net property, plant and equipment on the Consolidated Balance Sheet were $4.4 million and $1.0 million, respectively, as of December 31, 2021 and $4.3 million and $0.8 million, respectively, as of December 31, 2020.
The option to extend or terminate a lease is based on customary early termination provisions in the contract. The Company has not recognized any early terminations as of December 31, 2021.
The following table shows the future minimum lease receipts through 2026 and thereafter (in thousands):
Operating Leases
2022 $ 903
2023 906
2024 786
2025 553
2026 554
Thereafter 1,559
Total $ 5,261
15. RISKS AND UNCERTAINTIES
COVID-19 Pandemic
The COVID-19 pandemic has impacted global economic activity, including electricity and energy consumption, and caused significant volatility in financial markets. Many countries, including the U.S., reacted to the pandemic by instituting quarantines and mandating business and school closures or limitations and other social distancing measures. Responses to the COVID-19 pandemic by the State of Indiana and its residents and businesses continue to evolve as virus variants emerge, vaccine availability and usage continues and the State and businesses review and adjust the scope and requirements of social distancing measures. Social distancing measures designed to slow the spread of the virus, such as business closures and operations limitations, impact energy demand within our service territory. We continue to take a variety of measures in response to the spread of COVID-19 to ensure our ability to generate, transmit, distribute and sell electric energy, ensure the health and safety of our employees, contractors, customers and communities and provide essential services to the communities in which we operate. In addition to the impacts to demand within our service territory, we also have incurred and expect to continue to incur expenses relating to COVID-19, including those that relate to events outside of our control. The magnitude and duration of the COVID-19 pandemic is unknown at this time and may have material and adverse effects on our results of operations, financial condition and cash flows in future periods.
16. SUBSEQUENT EVENT
In February 2022, AES announced its intent to exit coal generation by year-end 2025 versus prior expectation of a reduction to below 10% by year-end 2025, subject to necessary approvals. Changes to AES Indiana's generation portfolio are evaluated and decided through the IRP. The impact that this new goal may have on AES Indiana's financial statements will be evaluated as part of the 2022 IRP.

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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, 2021, our disclosure controls and procedures were effective.
Management’s Report on Internal Control over Financial Reporting
Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rule 13a-15(f) under the Exchange Act. The Company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP and includes those policies and procedures that:
•pertain to the maintenance of records that in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;
•provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and
•provide reasonable assurance that unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements are prevented or detected timely.
Management, including our CEO and CFO, does not expect that our internal controls will prevent or detect all errors and all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. In addition, any evaluation of the effectiveness of controls is subject to risks that those internal controls may become inadequate in future periods because of changes in business conditions, or that the degree of compliance with the policies or procedures deteriorates.
Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2021. In
making this assessment, management used the criteria established in Internal Control - Integrated Framework issued by the COSO in 2013. Based on this assessment, management believes that the Company maintained effective internal control over financial reporting as of December 31, 2021.
Changes in Internal Control Over Financial Reporting:
There were no changes that occurred during the quarter ended December 31, 2021 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

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ITEM 9B. OTHER INFORMATION
ITEM 9B. OTHER INFORMATION
Not applicable.

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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 ACCOUNTING 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,
2021 2020
Audit Fees $ 916,333 $ 855,233
Audit Related Fees:
Fees for the audit of AES Indiana’s employee benefit plans 61,200 61,200
Assurance services for debt offering documents 108,000 116,525
Fees for tax services - -
Other 8,500 8,500
Total Principal Accounting Fees and Services $ 1,094,033 $ 1,041,458
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 - 2021, 2020 and 2019 (PCAOB ID: 42)
Consolidated Statements of Operations for the Years Ended December 31, 2021, 2020 and 2019 59
Consolidated Statements of Comprehensive Income/(Loss) for the Years Ended December 31, 2020, 2019, and 2018
Consolidated Balance Sheets as of December 31, 2021 and 2020 61
Consolidated Statements of Cash Flows for the Years Ended December 31, 2021, 2020 and 2019 62
Consolidated Statements of Common Shareholders’ Equity and Cumulative Preferred Stock of Subsidiary
for the Years Ended December 31, 2021, 2020 and 2019 63
Notes to Consolidated Financial Statements 64
Schedule I - Condensed Financial Information of Registrant 156
Schedule II - Valuation and Qualifying Accounts and Reserves 166
AES Indiana - Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm - 2021, 2020 and 2019 106
Consolidated Statements of Operations for the Years Ended December 31, 2021, 2020 and 2019 108
Consolidated Balance Sheets as of December 31, 2021 and 2020 109
Consolidated Statements of Cash Flows for the Years Ended December 31, 2021, 2020 and 2019 110
Consolidated Statements of Common Shareholder’s Equity and Cumulative Preferred Stock
for the Years Ended December 31, 2021, 2020 and 2019 111
Notes to Consolidated Financial Statements 111
Schedule II - Valuation and Qualifying Accounts and Reserves 166
(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)
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 $250,000,000 Revolving Credit Facility Amended and Restated Credit Agreement, dated June 19, 2019, 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 BMO Harris Bank, N.A. and Fifth Third Bank, as Co-Documentation Agents (Incorporated by reference to Exhibit 10.1 to IPALCO's Current Report on Form 8-K filed on June 21, 2019)
10.6 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)
10.7 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)
10.8 The AES Corporation 2003 Long Term Compensation Plan, as amended and restated, dated April 23, 2015 (Incorporated by reference to Exhibit 99.1 of The AES Corporation’s Form 8-K filed on April 23, 2015)
10.9 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)
10.10 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)
10.11 The AES Corporation Restoration Supplemental Retirement Plan, as amended and restated, effective January 1, 2017 (Incorporated by reference to Exhibit 4.1 of The AES Corporation’s Form S-8 filed on August 6, 2019)
10.12 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)
10.13 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)
10.14 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)
10.15 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)
10.16 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)
10.17 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)
10.18 Separation Agreement by and between The AES Corporation and Lisa Krueger dated January 25, 2022 (Incorporated by reference to Exhibit 10.26 of the AES Corporation's Form 10-K for the year ended December 31, 2021)
10.19 Consultation Agreement by and between The AES Corporation and Lisa Krueger dated January 25, 2022 (Incorporated by reference to Exhibit 10.27 of the AES Corporation's Form 10-K for the year ended December 31, 2021)
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 Balance Sheets
(In Thousands)
December 31,
2021 2020
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 1,902 $ 302
Restricted cash - 6,115
Taxes receivable 8,912 11,862
Prepayments and other current assets 7,551 7,508
Total current assets 18,365 25,787
OTHER NON-CURRENT ASSETS:
Investment in subsidiaries 1,693,176 1,426,739
Deferred tax asset - long term 9,655 14,289
Other non-current assets 3,577 3,194
Total other non-current assets 1,706,408 1,444,222
TOTAL ASSETS
$ 1,724,773 $ 1,470,009
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Loans payable to subsidiary $ - $ 6,110
Accounts payable 277 365
Accrued interest 8,360 8,556
Total current liabilities 8,637 15,031
NON-CURRENT LIABILITIES:
Long-term debt 872,154 870,775
Derivative liabilities, non-current 49,382 63,215
Total non-current liabilities 921,536 933,990
Total liabilities 930,173 949,021
SHAREHOLDERS' EQUITY
Paid in capital 848,565 588,966
Accumulated other comprehensive loss (29,407) (43,420)
Accumulated deficit (24,558) (24,558)
Total shareholders' equity 794,600 520,988
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 1,724,773 $ 1,470,009
See notes to Schedule I.
IPALCO ENTERPRISES, INC.
Schedule I - Condensed Financial Information of Registrant
Unconsolidated Statements of Operations
(In Thousands)
2021 2020 2019
OTHER INCOME / (EXPENSE), NET:
Equity in earnings of subsidiaries $ 147,030 $ 140,030 $ 154,078
Interest expense (41,380) (42,212) (32,761)
Loss on early extinguishment of debt - (2,415) -
Other income / (expense), net (45) 73 (46)
Total other income / (expense), net 105,605 95,476 121,271
EARNINGS FROM OPERATIONS BEFORE INCOME TAX 105,605 95,476 121,271
Less: income tax expense / (benefit) (10,364) (11,278) (7,909)
NET INCOME $ 115,969 $ 106,754 $ 129,180
See notes to Schedule I.
IPALCO ENTERPRISES, INC.
Schedule I - Condensed Financial Information of Registrant
Unconsolidated Statements of Comprehensive Income/(Loss)
(In Thousands)
2021 2020 2019
Net income $ 115,969 $ 106,754 $ 129,180
Derivative activity:
Change in derivative fair value, net of income tax benefit/(expense) of $(3,441), $8,876 and $6,810, for each respective period
10,393 (27,779) (19,750)
Reclassification to earnings, net of income tax benefit of $1,199, $1,313 and $0, for each respective period
3,620 4,109 -
Net change in fair value of derivatives 14,013 (23,670) (19,750)
Other comprehensive income/(loss) 14,013 (23,670) (19,750)
Net comprehensive income $ 129,982 $ 83,084 $ 109,430
See notes to Schedule I.
IPALCO ENTERPRISES, INC.
Schedule I - Condensed Financial Information of Registrant
Unconsolidated Statements of Cash Flows
(In Thousands)
2021 2020 2019
CASH FLOWS FROM OPERATIONS:
Net income $ 115,969 $ 106,754 $ 129,180
Adjustments to reconcile net income to net cash
provided by operating activities:
Equity in earnings of subsidiaries (147,030) (140,030) (154,078)
Cash dividends received from subsidiary companies 155,700 147,600 159,000
Amortization of deferred financing costs and debt premium 1,379 1,607 1,847
Deferred income taxes - net (5) (224) 157
Charges related to early extinguishment of debt - 2,415 -
Change in certain assets and liabilities:
Accounts payable (85) 299 231
Accrued and other current liabilities - - (3)
Accrued taxes payable/receivable 2,940 (11,317) (261)
Accrued interest - (3,083) (2)
Other - net 4,265 5,005 (623)
Net cash provided by operating activities 133,133 109,026 135,448
CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in subsidiaries (275,000) - -
Other - - 278
Net cash provided by (used in) investing activities (275,000) - 278
CASH FLOWS FROM FINANCING ACTIVITIES:
Long-term borrowings, net of discount - 474,568 -
Retirement of long-term debt and early tender premium - (472,135) -
Loans from subsidiary - 26,110 -
Repayments of loans to subsidiary (6,110) (20,000) -
Distributions to shareholders (131,476) (108,739) (136,426)
Equity contributions from shareholders 275,000 - -
Deferred financing costs paid (62) (6,122) -
Net cash used in financing activities 137,352 (106,318) (136,426)
Net change in cash and cash equivalents (4,515) 2,708 (700)
Cash, cash equivalents and restricted cash at beginning of period 6,417 3,709 4,409
Cash, cash equivalents and restricted cash at end of period $ 1,902 $ 6,417 $ 3,709
Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest (net of amount capitalized) $ 35,172 $ 38,069 $ 28,911
Income taxes 27,500 27,000 29,600
See notes to Schedule I.
IPALCO ENTERPRISES, INC.
Schedule I - Condensed Financial Information of Registrant
Unconsolidated Statements of Common Shareholders' Equity (Deficit)
(In Thousands)
Paid in Capital Accumulated Other Comprehensive Income (Loss) Accumulated Deficit Total
Balance at January 1, 2019 $ 597,824 $ - $ (24,558) $ 573,266
Net comprehensive income - (19,750) 129,180 109,430
Distributions to shareholders(1)
(7,246) - (129,180) (136,426)
Other 206 - - 206
Balance at December 31, 2019 590,784 (19,750) (24,558) 546,476
Net comprehensive income - (23,670) 106,754 83,084
Distributions to shareholders(1)
(1,985) - (106,754) (108,739)
Other 167 - - 167
Balance at December 31, 2020 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
1) IPALCO made return of capital payments of $15.5 million, $2.0 million and $7.2 million in 2021, 2020 and 2019, respectively, for the portion of current year distributions to shareholders in excess of current year net income.
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 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. As 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 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, 2021, 2020, or 2019. Any unrealized gains or losses are recorded in "Other income / (expense), net" on the accompanying Unconsolidated Statements of Operations.
Financial Liabilities
Interest Rate Hedges
In March 2019, we entered into forward interest rate hedges, which were amended in April 2020. The 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 AOCL. See also Note 3, "Derivative Instruments and Hedging Activities - Cash Flow Hedges" for further information.
Summary
The fair value of assets and liabilities at December 31, 2021 measured on a recurring basis and the respective category within the fair value hierarchy for IPALCO was determined as follows:
Assets and Liabilities at Fair Value
Level 1 Level 2 Level 3
Fair value at December 31, 2021 Based on quoted market prices in active markets Other observable inputs Unobservable inputs
(In Thousands)
Financial assets:
VEBA investments:
Money market funds $ 11 $ 11 $ - $ -
Mutual funds 3,594 - 3,594 -
Total VEBA investments 3,605 11 3,594 -
Total financial assets measured at fair value $ 3,605 $ 11 $ 3,594 $ -
Financial liabilities:
Interest rate hedges $ 49,382 $ - $ 49,382 $ -
Total financial liabilities measured at fair value $ 49,382 $ - $ 49,382 $ -
The fair value of assets and liabilities at December 31, 2020 measured on a recurring basis and the respective category within the fair value hierarchy for IPALCO was determined as follows:
Assets and Liabilities at Fair Value
Level 1 Level 2 Level 3
Fair value at December 31, 2020 Based on quoted market prices in active markets Other observable inputs Unobservable inputs
(In Thousands)
Financial assets:
VEBA investments:
Money market funds $ 16 $ 16 $ - $ -
Mutual funds 3,209 - 3,209 -
Total VEBA investments 3,225 16 3,209 -
Total financial assets measured at fair value $ 3,225 $ 16 $ 3,209 $ -
Financial liabilities:
Interest rate hedges $ 63,215 $ - $ 63,215 $ -
Total financial liabilities measured at fair value $ 63,215 $ - $ 63,215 $ -
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, 2021 December 31, 2020
Face Value Fair Value Face Value Fair Value
(In Thousands)
Fixed-rate $ 880,000 $ 946,346 $ 880,000 $ 992,615
Variable-rate - - - -
Total indebtedness $ 880,000 $ 946,346 $ 880,000 $ 992,615
The difference between the face value and the carrying value of this indebtedness represents the following:
•unamortized deferred financing costs of $7.3 million and $8.6 million at December 31, 2021 and 2020, respectively; and
•unamortized discounts of $0.5 million and $0.6 million at December 31, 2021 and 2020, 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, 2021, IPALCO's outstanding derivative instruments were as follows:
Commodity Accounting Treatment (a)
Unit Purchases
(in thousands) Sales
(in thousands) Net Purchases/(Sales)
(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. With the adoption of ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted improvements to Accounting for Hedging Activities effective January 1, 2019, we are no longer required to calculate effectiveness and thus the entire change in the fair value of a hedging instrument is now 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 future debt. The three interest rate swaps have 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) 2021 2020 2019
Beginning accumulated derivative gain / (loss) in AOCL $ (43,420) $ (19,750) $ -
Net gains / (losses) associated with current period hedging transactions 10,378 (27,779) (19,750)
Net losses reclassified to interest expense, net of tax 3,636 4,109 -
Ending accumulated derivative loss in AOCL $ (29,406) $ (43,420) $ (19,750)
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) 33
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, 2021 and 2020, IPALCO had $0.0 million and $6.1 million, respectively, of collateral in a broker margin account which offsets our loss positions on the interest rate hedges.
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 2021 2020
Interest rate hedges Cash Flow Hedge Derivative liabilities, non-current $ 49,382 $ 63,215
4. DEBT
The following table presents IPALCO’s long-term indebtedness:
December 31,
Series Due 2021 2020
(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 (527) (625)
Deferred financing costs - net (7,319) (8,600)
Total long-term debt 872,154 870,775
Less: current portion of long-term debt - -
Net long-term debt $ 872,154 $ 870,775
IPALCO’s Senior Secured Notes and Term Loan
In April 2020, IPALCO completed the sale of $475 million aggregate principal amount of 4.25% 2030 IPALCO Notes pursuant to Rule 144A and Regulation S under the Securities Act of 1933, as amended. We used the net proceeds from this offering to retire the $65 million Term Loan on April 14, 2020. The remaining net proceeds, together with cash on hand, were used to redeem the 2020 IPALCO Notes on May 14, 2020, and to pay certain related fees, expenses and make-whole premiums. A loss on early extinguishment of debt of $2.4 million for the 2020 IPALCO Notes is included as a separate line item within "Other Income/(Expense), Net" in the accompanying Unconsolidated Statements of Operations.
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, 2021, 2020 and 2019
(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, 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
Year ended December 31, 2020
Accumulated Provisions Deducted from
Assets - Doubtful Accounts $ 2,053 $ 5,861 $ (1,132) $ 3,627 $ 3,155
Deducted from Inventories
Valuation Allowance for Materials and Supplies $ 6,204 $ - $ - $ 71 $ 6,133
Year ended December 31, 2019
Accumulated Provisions Deducted from
Assets - Doubtful Accounts $ 2,821 $ 4,760 $ - $ 5,528 $ 2,053
Deducted from Inventories
Valuation Allowance for Materials and Supplies $ - $ 6,204 $ - $ - $ 6,204
AES INDIANA and SUBSIDIARIES
Valuation and Qualifying Accounts and Reserves
For the Years Ended December 31, 2021, 2020 and 2019
(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, 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
Year ended December 31, 2020
Accumulated Provisions Deducted from
Assets - Doubtful Accounts $ 2,053 $ 5,861 $ (1,132) $ 3,627 $ 3,155
Deducted from Inventories
Valuation Allowance for Materials and Supplies $ 6,204 $ - $ - $ 71 $ 6,133
Year ended December 31, 2019
Accumulated Provisions Deducted from
Assets - Doubtful Accounts $ 2,821 $ 4,760 $ - $ 5,528 $ 2,053
Deducted from Inventories
Valuation Allowance for Materials and Supplies $ - $ 6,204 $ - $ - $ 6,204