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’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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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 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.

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."

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.

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 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.


	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

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 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.

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.

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.