SEC Info - Ipalco Enterprises, Inc. - ‘10-K’ for 12/31/23

IPALCO ENTERPRISES, INC. and SUBSIDIARIES

Consolidated Statements of Operations

For the Years Ended December 31, 2023, 2022 and 2021

2023

2022

2021

(In Thousands)

REVENUE

i 1,649,917

i 1,791,711

i 1,426,132

OPERATING COSTS AND EXPENSES:

Fuel

i 494,000

i 568,676

i 255,817

Power purchased

i 159,908

i 199,860

i 175,025

Operation and maintenance

i 477,880

i 493,674

i 449,746

Depreciation and amortization

i 287,863

i 266,504

i 256,085

Taxes other than income taxes

i 24,864

i 33,048

i 44,419

Other, net

( i 361)

( i 3,201)

( i 5,630)

Total operating costs and expenses

i 1,444,154

i 1,558,561

i 1,175,462

OPERATING INCOME

i 205,763

i 233,150

i 250,670

OTHER (EXPENSE) / INCOME, NET:

Allowance for equity funds used during construction

i 9,315

i 4,784

i 5,412

Interest expense

( i 142,926)

( i 131,232)

( i 125,626)

Other (expense) / income, net

( i 410)

i 11,783

i 17,667

Total other expense, net

( i 134,021)

( i 114,665)

( i 102,547)

INCOME BEFORE INCOME TAX

i 71,742

i 118,485

i 148,123

Income tax expense

i 14,715

i 21,859

i 28,941

NET INCOME

i 57,027

i 96,626

i 119,182

Dividends on and redemption of preferred stock

i —

i 3,509

i 3,213

Net loss attributable to noncontrolling interests

( i 26,093)

i —

NET INCOME ATTRIBUTABLE TO COMMON STOCK

i 83,120

i 93,117

i 115,969

See Notes to Consolidated Financial Statements.

IPALCO ENTERPRISES, INC. and SUBSIDIARIES

Consolidated Statements of Comprehensive Income

For the Years Ended December 31, 2023, 2022 and 2021

2023

2022

2021

(In Thousands)

NET INCOME

i 57,027

i 96,626

i 119,182

Derivative activity:

Change in derivative fair value, net of income tax effect of $( i 528), $( i 15,309) and $( i 3,441), for each respective period

i 1,594

i 46,245

i 10,393

Reclassification to earnings, net of income tax effect of $( i 1,798), $( i 1,798) and $( i 1,199), for each respective period

i 5,431

i 3,620

Net change in fair value of derivatives

i 7,025

i 51,676

i 14,013

Other comprehensive income

i 7,025

i 51,676

i 14,013

Comprehensive income

i 64,052

i 148,302

i 133,195

Less: dividends on and redemption of preferred stock of subsidiary

i —

i 3,509

i 3,213

Less: comprehensive loss attributable to noncontrolling interests

( i 26,093)

—

COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON STOCK

i 90,145

i 144,793

i 129,982

See Notes to Consolidated Financial Statements.

IPALCO ENTERPRISES, INC. and SUBSIDIARIES

Consolidated Balance Sheets

(In Thousands)

ASSETS

CURRENT ASSETS:

Cash and cash equivalents

i 28,579

i 201,548

Accounts receivable, net of allowance for credit losses of $ i 2,283 and $ i 1,117, respectively

i 233,921

i 216,523

Inventories

i 143,590

i 123,608

Regulatory assets, current

i 89,419

i 119,723

Taxes receivable

i 36,481

i 18,000

Derivative assets, current

i 15,682

i 7,545

Prepayments and other current assets

i 26,358

i 19,882

Total current assets

i 574,030

i 706,829

NON-CURRENT ASSETS:

Property, plant and equipment

i 7,082,443

i 6,982,314

Less: Accumulated depreciation

i 2,954,555

i 3,243,968

i 4,127,888

i 3,738,346

Construction work in progress

i 359,014

i 294,985

Total net property, plant and equipment

i 4,486,902

i 4,033,331

OTHER NON-CURRENT ASSETS:

Intangible assets - net

i 235,656

i 138,978

Regulatory assets, non-current

i 541,784

i 593,939

Pension plan assets

i 41,172

i 33,611

Derivative assets, non-current

i —

i 12,172

Other non-current assets

i 301,979

i 70,354

Total other non-current assets

i 1,120,591

i 849,054

TOTAL ASSETS

i 6,181,523

i 5,589,214

LIABILITIES AND SHAREHOLDERS' EQUITY

CURRENT LIABILITIES:

Short-term debt and current portion of long-term debt (see Note 6)

i 899,159

i —

Accounts payable

i 292,851

i 189,845

Accrued taxes

i 22,580

i 22,474

Accrued interest

i 33,639

i 33,447

Customer deposits

i 29,308

i 35,097

Regulatory liabilities, current

i 23,371

i 23,348

Accrued and other current liabilities

i 27,547

i 19,014

Total current liabilities

i 1,328,455

i 323,225

NON-CURRENT LIABILITIES:

Long-term debt (see Notes 6 and 14)

i 2,576,798

i 3,016,810

Deferred income tax liabilities

i 361,488

i 312,641

Regulatory liabilities, non-current

i 527,224

i 612,585

Accrued other postretirement benefits

i 2,776

i 3,085

Asset retirement obligations

i 249,930

i 218,729

Other non-current liabilities

i 5,130

i 11,621

Total non-current liabilities

i 3,723,346

i 4,175,471

Total liabilities

i 5,051,801

i 4,498,696

COMMITMENTS AND CONTINGENCIES (see Note 10)

EQUITY:

Common shareholders' equity

Common stock (no par value, i 290,000,000 shares authorized; i 108,907,318 shares issued and outstanding at December 31, 2023 and 2022)

—

Paid in capital

i 1,021,992

i 1,068,357

Accumulated other comprehensive income

i 29,294

i 22,269

Retained earnings / (accumulated deficit)

i 25,182

( i 108)

Total common shareholders' equity

i 1,076,468

i 1,090,518

Noncontrolling interests

i 53,254

i —

Total equity

i 1,129,722

i 1,090,518

TOTAL LIABILITIES AND EQUITY

i 6,181,523

i 5,589,214

See Notes to Consolidated Financial Statements.

IPALCO ENTERPRISES, INC. and SUBSIDIARIES

Consolidated Statements of Cash Flows

For the Years Ended December 31, 2023, 2022 and 2021

2023

2022

2021

CASH FLOWS FROM OPERATING ACTIVITIES:

(In Thousands)

Net income

i 57,027

i 96,626

i 119,182

Adjustments to reconcile net income to net cash provided by operating activities:

Depreciation and amortization

i 287,863

i 266,504

i 256,085

Amortization of deferred financing costs and debt discounts

i 3,880

i 3,914

i 3,915

Deferred income taxes and investment tax credit adjustments - net

i 32,653

( i 6,706)

( i 7,378)

Allowance for equity funds used during construction

( i 9,315)

( i 4,784)

( i 5,412)

Gain on acquisition

i —

( i 5,630)

Change in certain assets and liabilities:

Accounts receivable

( i 17,398)

( i 37,387)

( i 13,943)

Inventories

( i 30,171)

( i 47,489)

( i 12,017)

Prepayments and other current assets

( i 6,476)

i 19,056

( i 4,593)

Accounts payable

i 46,993

i 32,038

i 21,417

Accrued and other current liabilities

i 2,790

i 6,532

( i 13,017)

Accrued taxes payable/receivable

( i 18,375)

( i 5,858)

i 638

Accrued interest

i 192

i 2,813

( i 1,099)

Pension and other postretirement benefit assets and liabilities

i 1,625

( i 8,727)

( i 16,592)

Current and non-current regulatory assets and liabilities

i 54,358

i 38,863

( i 104,759)

Other non-current liabilities

( i 9,445)

( i 14,384)

i 10,446

Other - net

( i 4,268)

i 5,335

( i 2,026)

Net cash provided by operating activities

i 391,933

i 346,346

i 225,217

CASH FLOWS FROM INVESTING ACTIVITIES:

Capital expenditures

( i 902,705)

( i 496,510)

( i 291,510)

Project development costs

( i 4,462)

( i 3,910)

( i 1,304)

Cost of removal payments

( i 45,595)

( i 23,948)

( i 35,260)

Insurance proceeds

i 4,900

i —

Purchase of intangibles

( i 44,650)

i —

( i 26,261)

Other

( i 361)

( i 719)

( i 14,380)

Net cash used in investing activities

( i 992,873)

( i 525,087)

( i 368,715)

CASH FLOWS FROM FINANCING ACTIVITIES:

Borrowings from revolving credit facilities

i 435,000

i 300,000

i 320,000

Repayments from revolving credit facilities

( i 280,000)

( i 360,000)

( i 335,000)

Short-term borrowings

i 300,000

i 200,000

i —

Repayments of short-term borrowings

i —

( i 200,000)

i —

Long-term borrowings

i —

i 350,000

i 95,000

Retirement of long-term borrowings, including early payment premium

i —

( i 95,000)

Distributions to shareholders

( i 104,287)

( i 101,986)

( i 131,476)

Equity contributions from shareholders

i —

i 253,000

i 275,000

Sales to noncontrolling interests

i 77,921

i —

Redemption of preferred stock

i —

( i 60,080)

i —

Preferred dividends of subsidiary

i —

( i 3,213)

Payments of deferred financing costs and discounts

( i 350)

( i 4,309)

( i 1,387)

Other

( i 313)

( i 35)

( i 131)

Net cash provided by financing activities

i 427,971

i 373,377

i 123,793

Net change in cash, cash equivalents and restricted cash

( i 172,969)

i 194,636

( i 19,705)

Cash, cash equivalents and restricted cash at beginning of year

i 201,553

i 6,917

i 26,622

Cash, cash equivalents and restricted cash at end of year

i 28,584

i 201,553

i 6,917

SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:

Cash paid during the period for:

Interest (net of amount capitalized)

i 129,113

i 115,277

i 118,052

Income taxes

i —

i 31,000

i 27,500

Non-cash investing activities:

Accruals for capital expenditures

i 124,626

i 66,949

i 81,325

Recognition and changes to right-of-use assets - finance leases

i 983

( i 3,402)

i 19,763

Non-cash financing activities:

Recognition and changes to financing lease liabilities

( i 1,408)

( i 3,402)

i 19,763

See Notes to Consolidated Financial Statements.

IPALCO ENTERPRISES, INC. and SUBSIDIARIES

Consolidated Statements of Changes in Equity

For the Years Ended December 31, 2023, 2022 and 2021

Common Shareholders' Equity

Common Stock

(in Thousands)

Outstanding Shares

Amount

Paid in
Capital

Accumulated Other Comprehensive Income (Loss)

Retained Earnings (Accumulated
Deficit)

Total Common Shareholders' Equity

Cumulative Preferred Stock of Subsidiary

Noncontrolling Interests

Balance at January 1, 2021

i 108,907

i —

i 588,966

( i 43,420)

( i 24,558)

i 520,988

i 59,784

—

Net income

—

i 119,182

i 3,213

—

Other comprehensive income

—

i 14,013

i —

i 14,013

Preferred stock dividends

—

( i 3,213)

—

Distributions to shareholders(1)

( i 15,507)

—

( i 115,969)

( i 131,476)

—

Contributions from shareholders

i 275,000

—

i 275,000

—

Other

i 106

—

i 106

—

Balance at December 31, 2021

i 108,907

i —

i 848,565

( i 29,407)

( i 24,558)

i 794,600

i 59,784

—

Net income

—

i 96,626

i 3,213

—

Other comprehensive income

—

i 51,676

i —

i 51,676

Preferred stock dividends

—

( i 3,213)

—

Redemption of preferred stock

—

( i 296)

( i 59,784)

—

Distributions to shareholders(1)

( i 33,319)

—

( i 68,667)

( i 101,986)

—

Contributions from shareholders

i 253,000

—

i 253,000

—

Other

i 111

—

i 111

—

Balance at December 31, 2022

i 108,907

i —

i 1,068,357

i 22,269

( i 108)

i 1,090,518

i —

—

Net income / (loss)

—

i 83,120

—

( i 26,093)

Other comprehensive income

—

i 7,025

i —

i 7,025

—

Distributions to shareholders(1)

( i 46,457)

—

( i 57,830)

( i 104,287)

—

Sales to noncontrolling interests

—

i 79,347

Other

i 92

—

i 92

—

Balance at December 31, 2023

i 108,907

i —

i 1,021,992

i 29,294

i 25,182

i 1,076,468

i —

i 53,254

(1) IPALCO made return of capital payments of $ i 46.5 million, $ i 33.3 million and $ i 15.5 million in 2023, 2022 and 2021, respectively, for the portion of current year distributions to shareholders in excess of current year net income at the time of distribution.

See Notes to Consolidated Financial Statements.

IPALCO ENTERPRISES, INC. and SUBSIDIARIES

Notes to Consolidated Financial Statements

For the Years Ended December 31, 2023, 2022 and 2021

1. i 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 ( i 82.35%) and CDPQ ( i 17.65%). AES U.S. Investments is owned by AES U.S. Holdings, LLC ( i 85%) and CDPQ ( i 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 i 523,000 retail customers in the city of Indianapolis and neighboring cities, towns and communities, and adjacent rural areas all within the state of Indiana. AES Indiana has an exclusive right to provide electric service to those customers.

AES Indiana owns and operates i four generating stations all within the state of Indiana. The first station, Petersburg, is coal-fired, and AES Indiana retired i 230 MW Petersburg Unit 1 in May 2021 and i 415 MW Petersburg Unit 2 in June 2023, which resulted in i 630 MW of total retired economic capacity at this station. AES Indiana plans to convert the remaining two coal units at Petersburg to natural gas (for further discussion, see Note 2, "Regulatory Matters - IRP Filings and Replacement Generation - 2022 IRP"). The second station, Harding Street, consists of three natural gas-fired boilers and steam turbines and uses natural gas and fuel oil to power five combustion turbines. In addition, AES Indiana operates a i 20 MW battery energy storage unit at this location, which provides frequency response. The third station, Eagle Valley, is a CCGT natural gas plant. The fourth station, Georgetown, is a peaking station that uses natural gas to power combustion turbines. As of December 31, 2023, AES Indiana’s net electric generation capacity for winter is i 3,070 MW and net summer capacity is i 2,925 MW.

In December 2021, AES Indiana, through a wholly-owned subsidiary, completed the acquisition of Hardy Hills Solar Energy LLC, including the development of a i 195 MW solar project (the "Hardy Hills Solar Project"). In December 2023, the first stage of construction for the Hardy Hills Solar Project was completed and placed in service, with initial operations for over half of the project commencing on December 28, 2023. The final stage for construction of the project is expected to be completed during the first half of 2024.

In August 2023, AES Indiana, through a wholly-owned subsidiary, completed the acquisition of Petersburg Energy Center, LLC, including the development of a i 250 MW solar and i 45 MW ( i 180 MWh) energy storage facility (the "Petersburg Energy Center Project"). The Petersburg Energy Center Project is expected to be completed in 2025.

In June 2023, AES Indiana, through a wholly-owned subsidiary, executed an agreement for the construction of the i 200 MW ( i 800 MWh) Pike County BESS Project to be developed at the AES Indiana Petersburg Plant site in Pike County, Indiana, subject to IURC approval, which was received in January 2024. The Pike County BESS Project is expected to be completed in 2024.

For further discussion about AES Indiana's plans for wind, solar, and battery energy storage projects, please see Note 2, "Regulatory Matters - IRP Filings and Replacement Generation."

IPALCO’s other direct subsidiary is Mid-America. Mid-America is the holding company for IPALCO’s unregulated activities, which have not been material to the financial statements in the periods covered by this report. IPALCO’s regulated business is conducted through AES Indiana. IPALCO has i two business segments: utility and nonutility. The utility segment consists of the operations of AES Indiana and everything else is included in the nonutility segment.

Principles of Consolidation

IPALCO’s consolidated financial statements are prepared in accordance with GAAP and in conjunction with the rules and regulations of the SEC. The consolidated financial statements include the accounts of IPALCO, its regulated utility subsidiary, AES Indiana, and its unregulated subsidiary, Mid-America. Furthermore, VIEs in which the Company has an ownership interest and is the primary beneficiary, thus controlling the VIE, as described below, have been consolidated. All intercompany items have been eliminated in consolidation. Certain costs for shared resources amongst AES Indiana and IPALCO, such as labor and benefits, are allocated to each entity based on

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

If IPALCO enters into transactions impacting equity interests in its affiliates, IPALCO must determine whether the transaction impacts the Company's consolidation conclusion by first determining whether the transaction should be evaluated under the variable interest model or the voting model. In determining which consolidation model applies to the transaction, IPALCO is required to make judgments about how the entity operates, the most significant of which are whether (i) the entity has sufficient equity to finance its activities, (ii) the equity holders, as a group, have the characteristics of a controlling financial interest, and (iii) whether the entity has non-substantive voting rights. If the entity is determined to be a variable interest entity and IPALCO is determined to have power and benefits, the entity will be consolidated by IPALCO.

Noncontrolling Interests

Noncontrolling interests are classified as a separate component of equity in the Consolidated Balance Sheets and Consolidated Statements of Changes in Equity. Additionally, net income attributable to noncontrolling interests is reflected separately from consolidated net income on the Consolidated Statements of Operations. Any change in ownership of a subsidiary while the controlling financial interest is retained is accounted for as an equity transaction between the controlling and noncontrolling interests. Losses continue to be attributed to the noncontrolling interests, even when the noncontrolling interests' basis has been reduced to zero.

Allocation of Earnings

Hardy Hills JV is subject to profit-sharing arrangements where the allocation of earnings, cash distributions, and tax benefits are not based on fixed ownership percentages. This arrangement exists to designate different allocations of value among the investors, where the allocations change in form or percentage over the life of the partnership. IPALCO uses the HLBV method when it is a reasonable approximation of the profit-sharing arrangement. The HLBV method calculates the proceeds that would be attributable to each partner based on the liquidation provisions of the respective operating partnership agreement if the partnership was to be liquidated at book value at the balance sheet date. Each partner’s share of income in the period is equal to the change in the amount of net equity they are legally able to claim based on a hypothetical liquidation of the entity at the end of a reporting period compared to the beginning of that period, adjusted for any capital transactions (for further discussion about the Equity Capital Contribution Agreement, see Note 2, "Regulatory Matters - IRP Filings and Replacement Generation").

The HLBV method is used to calculate the earnings attributable to noncontrolling interest when the business is consolidated by IPALCO. In the early months of operations of a renewable generation facility where HLBV results in a significant decrease in the hypothetical liquidation proceeds attributable to the tax equity investor due to the recognition of ITCs or other adjustments as required by the U.S. Internal Revenue Code, the Company records the impact (sometimes referred to as the ‘Day one gain’) to income in the same period.

Use of Management Estimates

The preparation of financial statements in conformity with GAAP requires that management make certain estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements. The reported amounts of revenue and expenses during the reporting period may also be affected by the estimates and assumptions management is required to make. Actual results may differ from those estimates. Significant items subject to such estimates and assumptions include: recognition of revenue including unbilled revenue; the carrying value of property, plant and equipment; the valuation of insurance and claims liabilities; the valuation of allowances for credit losses and deferred income taxes; regulatory assets and liabilities; liabilities recorded for income tax exposures; litigation; contingencies; and assets and liabilities related to AROs and employee benefits.

Reclassifications

Certain immaterial amounts from prior periods have been reclassified to conform to the current year presentation.

Cash and Cash Equivalents

Cash and cash equivalents are stated at cost, which approximates fair value. All highly liquid short-term investments with original maturities of three months or less are considered cash equivalents.

Restricted Cash

Restricted cash includes cash which is restricted as to withdrawal or usage. The nature of the restrictions includes restrictions imposed by agreements related to deposits held as collateral.

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

As of December 31,

2023

2022

(In Thousands)

Cash, cash equivalents and restricted cash

Cash and cash equivalents

i 28,579

i 201,548

Restricted cash (included in Prepayments and other current assets)

i 5

Total cash, cash equivalents and restricted cash

i 28,584

i 201,553

/ /

Accounts Receivable and Allowance for Credit Losses

The following table summarizes our accounts receivable balances at December 31:

As of December 31,

2023

2022

(In Thousands)

Accounts receivable, net

Customer receivables

i 125,715

i 125,540

Unbilled revenue

i 91,463

i 74,488

Amounts due from related parties

i 5,178

i 239

Other

i 13,848

i 17,373

Allowance for credit losses

( i 2,283)

( i 1,117)

Total accounts receivable, net

i 233,921

i 216,523

/ /

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

For the Years Ended December 31,

2023

2022

(In Thousands)

Allowance for credit losses:

Beginning balance

i 1,117

i 647

Current period provision

i 7,413

i 5,851

Write-offs charged against allowance

( i 7,764)

( i 7,008)

Recoveries collected

i 1,517

i 1,627

Ending Balance

i 2,283

i 1,117

characteristics and using historical credit loss experience. In addition, we also consider how current and future economic conditions are expected to impact collectability, as applicable, of our receivable balance. Amounts are written off when reasonable collections efforts have been exhausted.

Inventories

We maintain coal, fuel oil, natural gas, materials and supplies inventories for use in the production of electricity. These inventories are accounted for at the lower of cost or net realizable value, using the average cost. i The following table summarizes our inventories balances at December 31:

As of December 31,

2023

2022

(In Thousands)

Inventories

Fuel

i 77,198

i 60,497

Materials and supplies, net

i 66,392

i 63,111

Total inventories

i 143,590

i 123,608

Regulatory Accounting

The retail utility operations of AES Indiana are subject to the jurisdiction of the IURC. AES Indiana’s wholesale power transactions are subject to the jurisdiction of the FERC. These agencies regulate AES Indiana’s utility business operations, tariffs, accounting, depreciation allowances, services, issuances of securities and the sale and acquisition of utility properties. The financial statements of AES Indiana are based on GAAP, including the provisions of FASB ASC 980 “Regulated Operations,” which gives recognition to the ratemaking and accounting practices of these agencies. See also Note 2, “Regulatory Matters - Regulatory Assets and Liabilities” for a discussion of specific regulatory assets and liabilities.

Property, Plant and Equipment

Property, plant and equipment is stated at original cost as defined for regulatory purposes. The cost of additions to property, plant and equipment and replacements of retirement units of property are charged to plant accounts. Units of property replaced or abandoned in the ordinary course of business are retired from the plant accounts at cost; such amounts, less salvage, are charged to accumulated depreciation. Depreciation is computed by the straight-line method based on functional rates approved by the IURC and averaged i 3.7%, i 3.8% and i 3.7% during 2023, 2022 and 2021, respectively. Depreciation expense was $ i 244.8 million, $ i 247.5 million, and $ i 239.1 million for the years ended December 31, 2023, 2022 and 2021, respectively. "Depreciation and amortization" expense on the accompanying Consolidated Statements of Operations is presented net of regulatory deferrals of depreciation expense and also includes amortization of intangible assets and amortization of previously deferred regulatory costs.

AFUDC

In accordance with the Uniform System of Accounts prescribed by FERC, AES Indiana capitalizes an allowance for the net cost of funds (interest on borrowed funds and a reasonable rate of return on equity funds) used for construction purposes during the period of construction with a corresponding credit to income. AES Indiana capitalized amounts using pretax composite rates of i 7.1%, i 5.4% and i 5.7% during 2023, 2022 and 2021, respectively. AFUDC equity and AFUDC debt were as follows for the years ended December 31, 2023, 2022 and 2021:


	2023		2022		2021
	(In Thousands)
AFUDC equity	$	i 9,315	$	i 4,784	$	i 5,412
AFUDC debt	$	i 13,739	$	i 8,215	$	i 4,815

Impairment of Long-lived Assets

GAAP requires that we test long-lived assets for impairment when indicators of impairment exist. If an asset is deemed to be impaired, we are required to write down the asset to its fair value with a charge to current earnings. The net book value of our property, plant, and equipment was $ i 4.5 billion and $ i 4.0 billion as of December 31, 2023 and 2022, respectively. As of December 31, 2023 and 2022, AES Indiana had $ i 259.9 million and $ i 287.5 million, respectively, of long-term regulatory assets associated with Petersburg Unit 1 and 2 retirement costs (for further discussion, see Note 2, “Regulatory Matters - IRP Filings and Replacement Generation” and Note 3, "Property, Plant and Equipment"). We do not believe any of these assets are currently impaired. In making this assessment, we consider such factors as: the overall condition and generating and distribution capacity of the assets; the expected ability to recover additional expenditures in the assets; the anticipated demand and relative pricing of retail electricity in our service territory and wholesale electricity in the region; and the cost of fuel.

Intangible Assets

Finite-lived intangible assets primarily include capitalized software and project development intangible assets amortized on a straight-line basis over their useful lives. The following table presents information related to the Company's intangible assets, including the gross amount capitalized and related amortization:


			December 31,
$ in thousands	Weighted average amortization periods (in years)		2023		2022
Capitalized software	i 8		$	i 261,872	$	i 205,910
Project development intangible assets	i 28		i 84,097		i 39,455
Other	Various		i 797		i 797
Less: Accumulated amortization			( i 111,110)		( i 107,184)
Intangible assets - net			$	i 235,656	$	i 138,978

	For the Years Ended December 31,
	2023		2022		2021
Amortization expense	$	i 14,570	$	i 10,122	$	i 11,241

Estimated future amortization
Years ending December 31,
2024					$	i 20,764
2025					i 20,764
2026					i 22,550
2027					i 22,550
2028					i 22,550
Total					$	i 109,178

Implementation Costs Related to Software as a Service

IPALCO has recorded prepayments for implementation costs related to software as a service in support of utility customer services of $ i 7.1 million and $ i 8.2 million as of December 31, 2023 and 2022, respectively, which are recorded within "Other non-current assets" on the accompanying Consolidated Balance Sheets.

Debt Issuance Costs

Costs incurred in connection with the issuance of long-term debt are deferred and presented as a direct reduction from the face amount of that debt and amortized over the related financing period using the effective interest method. Debt issuance costs related to a line-of-credit or revolving credit facility are deferred and presented as an asset and amortized over the related financing period. Make-whole payments in connection with early debt retirements are classified as cash flows from financing activities.

Contingencies

IPALCO accrues for loss contingencies when the amount of the loss is probable and estimable. We are subject to various environmental regulations and are involved in certain legal proceedings. If IPALCO’s actual environmental and/or legal obligations are different from our estimates, the recognition of the actual amounts may have a material impact on our results of operations, financial condition and cash flows; although that has not been the case during the periods covered by this report. Accruals for loss contingencies were not material as of December 31, 2023 and 2022. See Note 10, "Commitments and Contingencies - Contingencies" for additional information.

Concentrations of Risk

Substantially all of AES Indiana’s customers are located within the Indianapolis area. Approximately i 68% of AES Indiana’s employees are covered by collective bargaining agreements in two bargaining units: a physical unit and a clerical-technical unit. AES Indiana’s contract with the physical unit expires on i December 4, 2024, and the contract with the clerical-technical unit expires i February 12, 2026. Additionally, AES Indiana has long-term coal contracts with i one supplier, and substantially all of AES Indiana's coal is currently mined in the state of Indiana.

Financial Derivatives

All derivatives are recognized as either assets or liabilities in the balance sheets and are measured at fair value. Changes in the fair value are recorded in earnings unless the derivative is designated as a cash flow hedge of a forecasted transaction or it qualifies for the normal purchases and sales exception.

AES Indiana has contracts involving the physical delivery of energy and fuel. Because some of these contracts qualify for the normal purchases and normal sales scope exception in ASC 815, AES Indiana has elected to account for them as accrual contracts, which are not adjusted for changes in fair value. AES Indiana has or previously had FTRs and forward power contracts that do not qualify for hedge accounting or the normal purchases and sales exceptions under ASC 815. Accordingly, FTRs are recorded at fair value when acquired and subsequently amortized over the annual period as they are used. FTRs are initially recorded at fair value using the income approach. The forward power contracts are recorded at fair value with changes in the fair value charged or credited to the Consolidated Statements of Operations in the period in which the change occurred. Forward power contracts are fair valued using the market approach.

Additionally, we use interest rate hedges to manage the interest rate risk associated with refinancing our long-term debt. We use cash flow hedge accounting when the hedge or a portion of the hedge is deemed to be highly effective, which results in changes in the fair value being recorded within accumulated other comprehensive income, a component of shareholders' equity. We have elected not to offset net derivative positions in the Financial Statements. Accordingly, we do not offset such derivative positions against the fair value of amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral under master netting agreements. See Note 5, “Derivative Instruments and Hedging Activities” for additional information.

Leases

The Company has finance leases primarily for land in which the Company is the lessee. Operating leases with an initial term of 12 months or less are not recorded on the balance sheet, but are expensed on a straight-line basis over the lease term. The Company’s leases do not contain any material residual value guarantees, restrictive covenants or subleases.

Right-of-use assets represent our right to use an underlying asset for the lease term while lease liabilities represent our obligation to make lease payments arising from the lease. Right-of-use assets and lease liabilities are recognized on commencement of the lease based on the present value of lease payments over the lease term. Generally, the rate implicit in the lease is not readily determinable; as such, we use the incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The Company determines discount rates based on its existing credit rates of its borrowings, which are then adjusted for the appropriate lease term. The right-of-use asset also includes any lease payments made and excludes lease incentives that are paid or payable to the lessee at commencement. The lease term includes periods covered by the option to extend if it is reasonably certain that the option will be exercised and periods covered by an option to terminate if it is reasonably certain that the option will not be exercised.

Accumulated Other Comprehensive Income / (Loss)

The amounts reclassified out of AOCI / (AOCL) by component during the years ended December 31, 2023, 2022 and 2021 are as follows (in thousands):

Details about AOCI / (AOCL) components

Affected line item in the Consolidated Statements of Operations

For the Years Ended December 31,

2023

2022

2021

Net losses on cash flow hedges (Note 5):

Interest expense

i 7,229

i 4,819

Income tax effect

( i 1,798)

( i 1,199)

Total reclassifications for the period, net of income taxes

i 5,431

i 3,620

See Note 5, "Derivative Instruments and Hedging Activities - Cash Flow Hedges" for further information on the changes in the components of AOCL.

Revenue Recognition

Revenue related to the sale of energy is generally recognized when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to certain customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is accrued. In making its estimates of unbilled revenue, AES Indiana uses models that consider various factors including daily generation volumes; known amounts of energy usage by nearly all residential, commercial and industrial customers; and estimated customer rates based on prior period billings. Given the use of these models, and that customers are billed on a monthly cycle, we believe it is unlikely that materially different results will occur in future periods when revenue is billed. An allowance for potential credit losses is maintained and amounts are written off when normal collection efforts have been exhausted. Our provision for expected credit losses included in “Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations was $ i 7.5 million, $ i 5.9 million and $ i 3.0 million for the years ended December 31, 2023, 2022 and 2021, respectively.

AES Indiana’s basic rates include a provision for fuel costs as established in AES Indiana’s most recent rate proceeding, which last adjusted AES Indiana’s rates in December 2018. AES Indiana is permitted to recover actual costs of purchased power and fuel consumed, subject to certain restrictions. This is accomplished through quarterly FAC proceedings, in which AES Indiana estimates the amount of fuel and purchased power costs in future periods. Through these proceedings, AES Indiana is also permitted to recover, in future rates, underestimated fuel and purchased power costs from prior periods, subject to certain restrictions, and therefore the over or underestimated costs are deferred or accrued and amortized into fuel expense in the same period that AES Indiana’s rates are adjusted. See also Note 2, “Regulatory Matters” for a discussion of other costs that AES Indiana is permitted to recover through periodic rate adjustment proceedings and the status of current rate adjustment proceedings.

In addition, we are one of many transmission system owner members of MISO, a RTO which maintains functional control over the combined transmission systems of its members and manages one of the largest energy markets in the U.S. See Note 13, "Revenue" for additional information of MISO sales and other revenue streams.

Operating Expenses – Other, Net

Operating expenses – Other, net generally includes gains or losses on asset sales, dispositions or acquisitions, gains or losses on the sale or acquisition of businesses, and other expense or income from miscellaneous operating transactions. For the year ended December 31, 2022, the $ i 3.2 million is primarily due to a gain on remeasurement of contingent consideration associated with the Hardy Hills Solar Project acquisition. For the year ended December 31, 2021, the $ i 5.6 million represents a gain on acquisition.

Pension and Postretirement Benefits

We recognize in our Consolidated Balance Sheets an asset or liability reflecting the funded status of pension and other postretirement plans with current-year changes in the funded status, that would otherwise be recognized in AOCI, recorded as a regulatory asset as this can be recovered through future rates. All plan assets are recorded at

fair value. We follow the measurement date provisions of the accounting guidance, which require a year-end measurement date of plan assets and obligations for all defined benefit plans.

We account for and disclose pension and postretirement benefits in accordance with the provisions of GAAP relating to the accounting for pension and other postretirement plans. These GAAP provisions require the use of assumptions, such as the discount rate for liabilities and long-term rate of return on assets, in determining the obligations, annual cost and funding requirements of the plans. Consistent with the requirements of ASC 715, we apply a disaggregated discount rate approach for determining service cost and interest cost for our defined benefit pension plans and postretirement plans.

See Note 8, "Benefit Plans" for more information.

Income Taxes

Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of the existing assets and liabilities, and their respective income tax bases. The Company establishes a valuation allowance when it is more likely than not that all or a portion of a deferred tax asset will not be realized. The Company’s tax positions are evaluated under a more likely than not recognition threshold and measurement analysis before they are recognized for financial statement reporting.

Uncertain tax positions are classified as noncurrent income tax liabilities unless expected to be paid within one year. The Company’s policy for interest and penalties is to recognize interest and penalties as a component of the provision for income taxes in the Consolidated Statements of Operations.

Income tax assets or liabilities, which are included in allowable costs for ratemaking purposes in future years, are recorded as regulatory assets or liabilities with a corresponding deferred tax liability or asset. Investment tax credits that reduced federal income taxes in the years they arose have been deferred and are being amortized to income over the useful lives of the properties in accordance with regulatory treatment. See Note 2, "Regulatory Matters" for additional information.

IPALCO and its subsidiaries file U.S. federal income tax returns as part of the consolidated U.S. income tax return filed by AES. The consolidated tax liability is allocated to each subsidiary based on the separate return method which is specified in our tax allocation agreement and which provides a consistent, systematic and rational approach. See Note 7, "Income Taxes" for additional information.

Repair and Maintenance Costs

Repair and maintenance costs are expensed as incurred.

Per Share Data

IPALCO is owned by AES U.S. Investments and CDPQ. IPALCO does not report earnings on a per-share basis.

New Accounting Pronouncements

We have assessed and determined that the new accounting pronouncements adopted did not have a material impact on the Company's Financial Statements.

New Accounting Pronouncements Issued But Not Yet Effective

The following table provides a brief description of recent accounting pronouncements that could have a material impact on the Company's Financial Statements once adopted. Accounting pronouncements not listed below were assessed and determined to be either not applicable or are expected to have no material impact on the Company's Financial Statements.


ASU Number and Name	Description	Date of Adoption	Effect on the Financial Statements upon adoption
2023-06 Disclosure Improvements: Codification Amendments in Response to the SEC’s Disclosure Update and Simplification Initiative	In U.S. Securities and Exchange Commission (SEC) Release No. 33-10532, Disclosure Update and Simplification, issued August 17, 2018, the SEC referred certain of its disclosure requirements that overlap with, but require incremental information to, generally accepted accounting principles (GAAP) to the FASB for potential incorporation into the Codification. The amendments in this Update are the result of the Board’s decision to incorporate into the Codification 14 of the 27 disclosures referred by the SEC. The amendments in this Update represent changes to clarify or improve disclosure and presentation requirements of a variety of Topics. Many of the amendments allow users to more easily compare entities subject to the SEC’s existing disclosures with those entities that were not previously subject to the SEC’s requirements. Also, the amendments align the requirements in the Codification with the SEC’s regulations.	The effective date for each amendment will be the date on which the SEC's removal of that related disclosure becomes effective, with early adoption prohibited. The amendments in this Update should be applied prospectively.	We will provide the required disclosures on a prospective basis on the date each amendment becomes effective. We do not expect ASU 2023-06 will have any impact to our consolidated financial statements.
2023-07 Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures	The amendments in this section are designed to improve the disclosures related to Segment reporting on an interim and annual basis. Public companies must disclose significant segment expenses and an amount for other segment items. This will also require that a company disclose its annual disclosures under Topic 280 in each interim period. Furthermore, companies will need to disclose the Chief Operating Decision Maker (CODM) and how the CODM assesses the performance of a segment. Lastly, public companies that have a single reportable segment must report the required disclosures under topic 280.	The amendments in this Update are effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
2023-09 Income Taxes (Topic 740): Improvements to Income Tax Disclosures	The amendments in this Update require that public business entities on an annual basis (1) disclose specific categories in the rate reconciliation and (2) provide additional information for reconciling items that meet a quantitative threshold. Furthermore, companies are required to disclose a disaggregated amount of income taxes paid at a federal, state, and foreign level as well as a break down of income taxes paid in a jurisdiction that comprises 5% of a company's total income taxes paid. Lastly, this ASU requires that companies disclose income (loss) from continuing operations before income tax at a domestic and foreign level and that companies disclose income tax expense from continuing operations on a federal, state, and foreign level.	The amendments in this Update are effective for fiscal years beginning after December 15, 2024.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.

2. REGULATORY MATTERS

General

AES Indiana is subject to regulation by the IURC as to its services and facilities, the valuation of property, the construction, purchase, or lease of electric generating facilities, the classification of accounts, rates of depreciation, retail rates and charges, the issuance of securities (other than evidences of indebtedness payable less than twelve months after the date of issue), the acquisition and sale of some public utility properties or securities and certain other matters.

In addition, AES Indiana is subject to the jurisdiction of the FERC with respect to, among other things, short-term borrowings not regulated by the IURC, the sale of electricity at wholesale, the transmission of electric energy in interstate commerce, the classification of accounts, reliability standards, and the acquisition and sale of utility property in certain circumstances as provided by the Federal Power Act. As a regulated entity, AES Indiana is required to use certain accounting methods prescribed by regulatory bodies which may differ from those accounting methods required to be used by unregulated entities.

AES Indiana is also affected by the regulatory jurisdiction of the EPA at the federal level, and the IDEM at the state level. Other significant regulatory agencies affecting AES Indiana include, but are not limited to, the NERC, the U.S. Department of Labor and the IOSHA.

Basic Rates and Charges

Our basic rates and charges represent the largest component of our annual revenue. Our basic rates and charges are determined after giving consideration, on a pro-forma basis, to all allowable costs for ratemaking purposes including a fair return on the fair value of the utility property used and useful in providing service to customers. These basic rates and charges are set and approved by the IURC after public hearings. Such proceedings, which have occurred at irregular intervals, involve AES Indiana, the IURC, the Indiana Office of Utility Consumer Counselor, and other interested stakeholders. Pursuant to statute, the IURC is to conduct a periodic review of the basic rates and charges of all Indiana utilities at least once every four years, but the IURC has the authority to review the rates of any Indiana utility at any time. Once set, the basic rates and charges authorized do not assure the realization of a fair return on the fair value of property.

Our declining block rate structure generally provides for residential and commercial customers to be charged a lower per kWh rate at higher consumption levels. Therefore, as volumes increase, the weighted average price per kWh decreases. Numerous factors including, but not limited to, weather, inflation, customer growth and usage, the level of actual operating and maintenance expenditures, fuel costs, generating unit availability, and capital expenditures including those required by environmental regulations can affect the return realized.

Regulatory Rate Review and Base Rate Orders

AES Indiana filed a petition with the IURC on June 28, 2023, for authority to increase its basic rates and charges to cover the rising operational costs and needs associated with continuing to serve its customers safely and reliably. The factors leading to AES Indiana's first base rate increase request in five years include inflationary impacts on operations and maintenance expenses, investments in the transmission and distribution systems, and modernization of its customer systems. AES Indiana is also seeking recovery of increased costs to support its vegetation management plan, which covers the removal of overhang and tree trimming in its service territory. AES Indiana also seeks to better align depreciation expense with the period in which the generation plants provide service to customers and remove operational costs of the retired Petersburg units from rates. On November 22, 2023, AES Indiana entered into a unanimous stipulation and settlement agreement (the "settlement") with the OUCC and the intervening parties which, if approved by the IURC, would increase its annual revenue requirement by $ i 73 million. AES Indiana expects to receive an order from the IURC and place new rates into effect by the end of the second quarter of 2024.

On October 31, 2018, the IURC issued an order approving an uncontested settlement agreement previously filed with the IURC by AES Indiana for a $ i 43.9 million, or i 3.2%, increase to annual revenue (the "2018 Base Rate Order"). The 2018 Base Rate Order includes recovery through rates of the CCGT at Eagle Valley completed in the first half of 2018, as well as other construction projects and changes to operating income since the 2016 Base Rate Order. New basic rates and charges became effective on December 5, 2018. The 2018 Base Rate Order provides that annual wholesale margins earned above (or below) the benchmark of $ i 16.3 million shall be passed back (or charged) to customer rates through a rate adjustment mechanism. Similarly, the 2018 Base Rate Order provides that all capacity sales above (or below) a benchmark of $ i 11.3 million shall be passed back (or charged) to customer rates through a rate adjustment mechanism.

FAC and Authorized Annual Jurisdictional Net Operating Income

AES Indiana may apply to the IURC for a change in AES Indiana’s fuel charge every three months to recover AES Indiana’s estimated fuel costs, including the energy portion of purchased power costs, which may be above or below the levels included in AES Indiana’s basic rates and charges. AES Indiana must present evidence in each

FAC proceeding that it has made every reasonable effort to acquire fuel and generate or purchase power or both so as to provide electricity to its retail customers at the lowest fuel cost reasonably possible.

Independent of the IURC’s ability to review basic rates and charges, Indiana law requires electric utilities under the jurisdiction of the IURC to meet operating expense and income test requirements as a condition for approval of requested changes in the FAC. A utility may be unable to recover all of its fuel costs if its rolling twelve-month operating income, determined at quarterly measurement dates, exceeds its authorized annual jurisdictional net operating income and there are not sufficient applicable cumulative net operating income deficiencies (“Cumulative Deficiencies”) to offset it. The Cumulative Deficiencies calculation provides that only five years’ worth of historical earnings deficiencies or surpluses are included, unless it has been greater than five years since the most recent rate case.

In calendar years 2021 and 2022, AES Indiana reported earnings in excess of the authorized level for certain quarterly reporting periods in those years. AES Indiana has not reported earnings in excess of the authorized level for any FAC periods in the calendar year 2023. Prior to 2020, AES Indiana was not required to reduce its fuel cost recovery because of its Cumulative Deficiencies. During 2020, AES Indiana's Cumulative Deficiencies dropped to zero. AES Indiana recorded a reduction to revenue of $ i 0.0 million, $ i 0.3 million and $ i 5.5 million in 2023, 2022 and 2021, respectively. As of the FAC period ending with the twelve months of October 31, 2023, AES Indiana has Cumulative Deficiencies; therefore, AES will not be required to reduce its fuel cost recovery for future earnings in excess of the authorized level until there are no longer Cumulative Deficiencies.

ECCRA

AES Indiana may apply to the IURC for approval of a rate adjustment known as the ECCRA periodically to recover costs (including a return) to comply with certain environmental regulations applicable to AES Indiana’s generating stations and to recover certain investments in renewable and battery storage projects. The total amount of AES Indiana’s environmental equipment and renewable projects approved for ECCRA recovery as of December 31, 2023 was $ i 129.7 million. The jurisdictional revenue requirement approved by the IURC to be included in AES Indiana’s rates for the twelve-month period ending February 2024 is a net cost to customers of $ i 8.9 million.

DSM

Through various rate orders from the IURC, AES Indiana has been able to recover its costs of implementing various DSM programs throughout the periods covered by this report. In 2023, 2022 and 2021, AES Indiana also had the ability to receive performance incentives, dependent upon the level of success of the programs. Performance incentives included in rates for the years ended December 31, 2023, 2022 and 2021 were $ i 2.7 million, $ i 8.3 million and $ i 7.2 million, respectively.

On December 29, 2020, the IURC approved a settlement agreement establishing a new three year DSM plan for AES Indiana through 2023. The approval included cost recovery of programs as well as performance incentives, depending on the level of success of the programs. The order also approved recovery of lost revenue, consistent with the provisions of the settlement agreement.

AES Indiana filed a petition with the IURC on May 26, 2023 asking for approval of a one year DSM interim plan. On December 27, 2023, the IURC approved a one-year DSM plan for AES Indiana through 2024. The approval included cost recovery of programs as well as performance incentives, depending on the level of success of the programs. The order also approved recovery of lost revenue, consistent with the provisions of the settlement agreement.

Wind and Solar Power Purchase Agreements

We are currently committed under a power purchase agreement to purchase all wind-generated electricity through 2029 from a wind project in Indiana ("Hoosier Wind Project"). On July 28, 2023, AES Indiana executed the Purchase Agreement and is currently in the process of acquiring this project. The existing power purchase agreement will be terminated upon closing (see "IRP Filings and Replacement Generation - Hoosier Wind Project" below for further information). We are also committed under another agreement to purchase all wind-generated electricity through 2031 from a project in Minnesota. The Indiana project has a maximum output capacity of approximately i 100 MW and the Minnesota project has a maximum output capacity of approximately i 200 MW. In addition, we have i 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 i 94.0 MW was in operation as of December 31, 2023. We have authority from the IURC to recover the costs for all of these agreements through an adjustment mechanism administered within the FAC. If and when AES Indiana sells the renewable energy attributes (in the form of renewable energy credits) generated from these facilities, the proceeds would pass back to benefit AES Indiana’s retail customers through the FAC.

TDSIC

In 2013, Senate Enrolled Act 560, the Transmission, Distribution, and Storage System Improvement Charge ("TDSIC") statute, was signed into law. The TDSIC statute was revised in 2019. Among other provisions, this legislation provides for cost recovery outside of a base rate proceeding for new or replacement electric and gas transmission, distribution, and storage projects that a public utility undertakes for the purposes of safety, reliability, system modernization, or economic development. Provisions of the TDSIC statute require that, among other things, requests for recovery include a plan of at least five years and not more than seven for eligible investments. The first i 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 i 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 i two percent of total retail revenue.

On March 4, 2020, the IURC issued an order approving the projects in a seven-year TDSIC Plan for eligible transmission, distribution and storage system improvements totaling $ i 1.2 billion from 2020 through 2026. Beginning in June 2020, AES Indiana files an annual TDSIC rate adjustment for a return on and of investments through March 31 with rates requested to be effective each November. Annual TDSIC plan update filings are required to be staggered by six months as ordered by the IURC and are filed each December. The total amount of AES Indiana’s equipment net of depreciation, including carrying costs, approved for TDSIC recovery as of December 31, 2023 was $ i 399.6 million. The jurisdictional revenue requirement approved by the IURC to be included in AES Indiana’s rates for the twelve-month period ending October 2024 is a net cost to customers of $ i 56.5 million.

IRP Filings and Replacement Generation

Electric utilities in Indiana are required to submit Integrated Resource Plans (IRPs) every three years. The IRPs are subject to a rigorous stakeholder process. IRPs describe how the utility plans to deliver safe, reliable, and efficient electricity at just and reasonable rates.

2022 IRP

AES Indiana held public advisory meetings for the 2022 IRP in January, April, June, September and October of 2022. Changes to our generation portfolio are evaluated and decided through the IRP. AES Indiana issued an all-source Request for Proposal on April 14, 2022, in order to competitively procure energy and capacity in the near term; such need was evaluated in AES Indiana's 2022 IRP.

In December 2022, AES Indiana filed its 2022 IRP with the IURC, which describes AES Indiana's Preferred Resource Portfolio for meeting generation capacity needs for serving AES Indiana's retail customers over the next several years. The Preferred Resource Portfolio is AES Indiana's reasonable least cost option and provides a cleaner and more diverse generation mix for customers. The 2022 IRP short-term action plan includes converting the two remaining coal units at Petersburg to natural gas. AES Indiana has not yet filed for the regulatory approvals from the IURC to convert Petersburg units 3 and 4; however, AES Indiana expects to do so in the first half of 2024. Construction is expected to begin in 2025 and be completed by the end of 2026. Additionally, AES Indiana plans to add up to 1,300 MW of wind, solar, and battery energy storage by 2027. As new technologies, such as green hydrogen, small modular reactors and carbon capture are developed and cost effective, AES Indiana will evaluate them in the future planning processes. As a result of the plan to convert Petersburg units 3 and 4 to natural gas, AES Indiana recorded a $ i 1.5 million write off of capital projects during the period ended December 31, 2022 to "Operating expenses - Operation and maintenance" on the accompanying Consolidated Statements of Operations.

2019 IRP

In December 2019, AES Indiana filed its 2019 IRP, which included the retirement of approximately i 630 MW of coal-fired generation at Petersburg Units 1 and 2 in 2021 and 2023, respectively. Based on extensive modeling, AES Indiana determined that the cost of operating Petersburg Units 1 and 2 exceeded the value customers received compared to alternative resources. Retirement of these units allowed the company to cost-effectively diversify the portfolio and transition to lower cost and cleaner resources while maintaining a reliable system.

AES Indiana issued an all-source Request for Proposal on December 20, 2019, in order to competitively procure replacement capacity by June 1, 2023, which was the first year AES Indiana was expected to have a capacity shortfall. Our modeling indicated that a combination of wind, solar, storage, and energy efficiency would be the lowest reasonable cost option for the replacement capacity. As a result of the plans to retire Petersburg Units 1 and 2, AES Indiana recorded $ i 0.7 million, $ i 2.1 million, and $ i 0.8 million of obsolescence losses, during the periods ended December 31, 2023, 2022, and 2021, respectively, for materials and supplies inventory AES Indiana did not believe will be utilized by the planned retirement dates, which is recorded in "Operating expenses - Operation and maintenance" on the accompanying Consolidated Statements of Operations.

As a result of the plans to retire Petersburg Units 1 and 2, AES Indiana filed a petition with the IURC on February 26, 2021 for approvals and cost recovery associated with these retirements. On August 6, 2021, AES Indiana filed an uncontested Stipulation and Settlement Agreement with the other parties in the case which includes: (1) AES Indiana's creation of regulatory assets for the net book value of Petersburg units 1 and 2 upon retirement; (2) a method for amortization of the regulatory assets; and (3) recovery of the regulatory assets through ongoing amortization in AES Indiana’s future rate cases. The Settlement Agreement also reserves all rights of all the parties with respect to the ratemaking treatment related to the regulatory assets, including the proper rate of return and mechanisms for recovery. On November 17, 2021, the IURC approved the Settlement Agreement without modification. AES Indiana retired i 230 MW Petersburg Unit 1 in May 2021 and i 415 MW Petersburg Unit 2 in June 2023.

AES Indiana had $ i 35.7 million and $ i 224.2 million of Petersburg Units 1 and 2 retirement costs, respectively, net of accumulated amortization, recorded as long-term regulatory assets as of December 31, 2023. AES Indiana had $47.6 million and $239.9 million of Petersburg Units 1 and 2 retirement costs, respectively, net of accumulated amortization, recorded as long-term regulatory assets as of December 31, 2022.

Hardy Hills Solar Project

In January 2021, AES Indiana, through a wholly-owned subsidiary, executed an agreement for the acquisition and construction of the i 195 MW Hardy Hills Solar Project to be developed in Clinton County, Indiana. In December 2022, the agreement was amended to revise the project schedule, including shifting the completion date to 2024, and adjusting for increased project costs. On January 13, 2023, AES Indiana filed a petition with the IURC for approval of these revisions, which was approved in August 2023.

On June 16, 2021, AES Indiana received an order from the IURC approving a petition and case-in-chief seeking a CPCN for this solar project, including a joint venture structure between an AES Indiana subsidiary and one or more tax equity partners upon completion and approval for recovery of project development costs and carrying costs on AES Indiana's investment in the project. The transaction closed in December 2021 and was accounted for as an asset acquisition of a variable interest entity that did not meet the definition of a business; therefore, the individual assets and liabilities were recorded at their fair values. Total net assets of $ i 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 $ i 3.2 million contingent liability was recorded in "Other Non-Current Liabilities" on the accompanying Consolidated Balance Sheets as of December 31, 2021. During 2022, this liability was remeasured due to updated cost estimates and was reduced to $ i 0.0 million.

On December 1, 2023, AES Indiana, through a wholly-owned subsidiary (the "Class B Member"), and a third-party investor (the "Class A Member"), entered into an Equity Capital Contribution Agreement, pursuant to which each member made certain capital contributions to Hardy Hills JV. The Class A member made total contributions of

$ i 79.3 million through December 31, 2023. Hardy Hills JV is consolidated by the Class B Member under the Variable Interest Model, and noncontrolling interest (“NCI”) was recorded by AES Indiana at the amount of cash contributed by the Class A Member. In December 2023, the first stage of the construction for the Hardy Hills Solar Project was completed and placed in service, with initial operations for over half of the project commencing on December 28, 2023. Upon the first stage of the project being placed in service, the Company recognized $ i 26.1 million of earnings from tax attributes using the HLBV method. The final stage for construction of the project is expected to be completed during the first half of 2024.

Petersburg Energy Center Project

In July 2021, AES Indiana, through a wholly-owned subsidiary, executed an agreement for the acquisition and construction of a i 250 MW solar and i 45MW ( i 180 MWh) energy storage facility to be developed in Pike County, Indiana. In October 2022, the agreement was amended to revise the project schedule, including shifting the completion date to 2025, and adjusting for increased project costs. On December 22, 2022, AES Indiana filed a petition with the IURC for approval of these revisions, which was approved in May 2023. On August 31, 2023, AES Indiana closed on the agreement for the acquisition and construction of the Petersburg Energy Center Project. This transaction was accounted for as an asset acquisition of a variable interest entity that did not meet the definition of a business; therefore, the individual assets were recorded at their fair values. Total net assets of $ i 48.7 million were recorded in the accompanying Consolidated Balance Sheets associated with the transaction, primarily consisting of project development intangible assets (see Note 1, "Overview and Summary of Significant Accounting Policies - Intangible Assets" for further information).

Pike County BESS Project

In June 2023, AES Indiana, through a wholly-owned subsidiary, executed an agreement for the construction of the i 200 MW ( i 800 MWh) Pike County BESS Project to be developed at the AES Indiana Petersburg Plant site in Pike County, Indiana. On July 19, 2023, AES Indiana filed a petition and case-in-chief with the IURC seeking approval for a Clean Energy Project and associated timely cost recovery under Indiana Code for this project. A hearing for this case was held in October 2023, and IURC approval was received on January 17, 2024. The Pike County BESS Project is expected to be completed in 2024.

Hoosier Wind Project

On July 5, 2023, AES Indiana filed a Notice of Intent with the IURC to request approval of a Clean Energy Project and for issuance of a CPCN for the Hoosier Wind Project acquisition. The proposed Project is the acquisition of the Hoosier Wind Project, which is an existing i 106 MW wind facility located in Benton County, Indiana. The Company executed the Purchase Agreement on July 28, 2023. A CPCN for this case was filed in early August 2023, and IURC approval was received on January 24, 2024. The acquisition of the Hoosier Wind Project is expected to be completed in the first quarter of 2024.

Incentives for Clean Energy Projects

Indiana Code 8-1-8 (the "clean energy statute") offers certain incentives for clean energy projects. Primarily, it allows for the timely recovery of costs and expenses incurred during construction and operation of eligible projects outside of a base rate proceeding. Clean energy projects eligible for incentives under this statute include renewable energy resources such as wind, photovoltaic cells and panels, solar energy, and energy storage systems or technologies, among others. AES Indiana filed for and received IURC approval of the Hoosier Wind Project and Pike County BESS Project under this statute. AES Indiana continues to evaluate projects which may also be filed under this statute.

IURC COVID-19 Orders

Due to the COVID-19 pandemic, there was a disconnection moratorium in 2020 for IURC-jurisdictional utilities, as well as suspension of certain utility fees (late fees, convenience fees, deposits, and disconnection/reconnection fees) from residential customers. The IURC authorized Indiana utilities to use regulatory accounting for any impacts associated with the moratorium and suspension. The IURC also authorized regulatory accounting treatment for COVID-19 related uncollectible and incremental bad debt expense. As a result of the IURC's COVID-19 related orders issued in 2020, AES Indiana has recorded a regulatory asset of $ i 5.4 million as of December 31, 2023 and

2022, which will be recovered through base rates under the stipulation and settlement agreement entered into on November 22, 2023, if approved by the IURC.

EDG Rates

On March 1, 2021, AES Indiana filed a petition with the IURC for approval of its proposed rate for the procurement of EDG and related consumer EDG credit issues. The EDG rate replaced the net metering program beginning in July 2022, when net metering was no longer available to new customers. The IURC approved the EDG rate by order dated January 26, 2022, On March 16, 2022, the IURC denied the petition for reconsideration filed by the other parties on February 15, 2022. The matter was subject to an appeal filed by the other parties on February 22, 2022, which was held in abeyance by the Indiana Court of Appeals pending resolution of a petition to transfer to the Indiana Supreme Court filed in a similar case involving a different and unaffiliated utility. The stay was extended by the Indiana Court of Appeals on July 11, 2022. On January 4, 2023, the Indiana Supreme Court issued a final decision in favor of the utility in the similar case that served as the basis of the stay in the AES Indiana case. On February 3, 2023, the OUCC moved to dismiss the appeal, which motion was granted on February 13, 2023.

EV Portfolio Program

On January 27, 2023, AES Indiana filed with the IURC a request to approve its EV Portfolio and associated accounting and ratemaking treatment. The EV Portfolio includes two separate parts: (1) a set of EV specific rates, tariffs, and alternative pricing structures, and (2) a set of Public Use EV Pilot Programs. The EV portfolio is designed to produce net benefits for all customers through new retail margins and grid optimization. The projected costs to successfully implement the services proposed in the EV Portfolio are estimated at $ i 16.2 million over the three-year period. AES Indiana requested approval to defer as a regulatory asset and recover in future base rates the cost necessary to implement the EV Portfolio, including carrying charges. A hearing on this request was held in July 2023. On November 22, 2023, the IURC issued an order approving AES Indiana's EV Portfolio filing with approval to defer as a regulatory asset and to seek recovery in future base rates the cost necessary to implement the EV Portfolio, including carrying charges with no other significant modifications.

Storm Outage Restoration Inquiry

On July 11, 2023, the OUCC and the Citizens Action Coalition (“CAC”) filed a Joint Petition through which they requested the IURC open an investigation into AES Indiana’s practices and procedures regarding storm outage restoration. A technical conference was held on October 2, 2023, to discuss AES Indiana’s response to outages and storm restoration; particularly the storms that occurred between June 29, 2023 and July 2, 2023.

House Bill 1002

In the first quarter of 2022, the 2022 Indiana General Assembly passed House Enrolled Act 1002, which includes language regarding the repeal of the URT. AES Indiana filed a rate adjustment with the IURC on April 29, 2022, which was approved by the IURC on June 28, 2022. AES Indiana began charging the new rates excluding URT in July 2022. Prior to the repeal, the URT was recoverable through a current charge to customer rates. After the repeal, the new rates approved by the IURC adjusted both revenue and tax expense. As a result, the repeal of the URT had no impact on the Company's net income.

Regulatory Assets and Liabilities

Regulatory assets represent deferred costs or credits that have been included as allowable costs or credits for ratemaking purposes. AES Indiana has recorded regulatory assets or liabilities relating to certain costs or credits as authorized by the IURC or established regulatory practices in accordance with ASC 980. AES Indiana is amortizing non tax-related regulatory assets to expense over periods ranging from i 1 to i 43 years. Tax-related regulatory assets represent the net income tax costs to be considered in future regulatory proceedings generally as the tax-related amounts are paid.

The amounts of regulatory assets and regulatory liabilities at December 31 are as follows:

2023

2022

Recovery Period

(In Thousands)

Regulatory assets, current:

Undercollections of rate riders

i 75,416

i 26,047

Approximately 1 year(1)

Fuel costs

i —

i 79,861

Approximately 1 year(1)

Unamortized reacquisition premium on debt

i 188

i —

Approximately 1 year

Costs being recovered through basic rates and charges

i 13,815

Approximately 1 year(1)

Total regulatory assets, current

i 89,419

i 119,723

Regulatory assets, non-current:

Unrecognized pension and other

postretirement benefit plan costs

i 115,847

i 131,907

Various(2)

Deferred MISO costs

i 21,091

i 34,483

Through 2026(1)

Unamortized Petersburg Unit 4 carrying

charges and certain other costs

i 2,812

i 3,866

Through 2026(1)(3)

Unamortized reacquisition premium on debt

i 13,379

i 14,429

Over remaining life of debt

Environmental costs

i 66,837

i 68,947

Through 2046(1)(3)

COVID-19 costs

i 5,426

4 years(4)

Major storm damage

i 1,493

i —

To be determined

TDSIC costs

i 35,979

i 18,547

36.3 years(1)(3)

Petersburg Unit 1 and 2 retirement costs

i 259,892

i 287,463

Through 2034(1)(3)

Hardy Hills Solar Project development costs

i 6,774

i 5,744

30 years(3)

Petersburg Energy Center Project development costs

i 2,469

i 1,582

30 years(3)

Pike County BESS Project development costs

i 2,623

i —

20 years(3)

Fuel costs

i 4,275

i 20,518

Through 2025(1)

Other miscellaneous

i 2,887

i 1,027

Various(5)

Total regulatory assets, non-current

i 541,784

i 593,939

Total regulatory assets

i 631,203

i 713,662

Regulatory liabilities, current:

Overcollections and other credits being passed

to customers through rate riders

i 19,649

i 15,803

Approximately 1 year(1)

FTRs

i 3,722

i 7,545

Approximately 1 year(1)

Total regulatory liabilities, current

i 23,371

i 23,348

Regulatory liabilities, non-current:

ARO and accrued asset removal costs

i 451,886

i 518,797

Not applicable

Deferred income taxes payable to customers through rates

i 74,796

i 88,662

Various

Hardy Hills sponsor investment tax credit

i 542

i —

To be determined(6)

Major storm damage

i —

i 5,126

To be determined

Total regulatory liabilities, non-current

i 527,224

i 612,585

Total regulatory liabilities

i 550,595

i 635,933

(1)Recovered (credited) per specific rate orders

(2)AES Indiana receives a return on its discretionary funding

(3)Recovered with a current return

(4)Per the signed stipulation in the 2023 distribution rate case, Cause No. 45911

(5)Some of these costs are being recovered in basic rates and charges through 2026. For the remainder, recovery over four years was agreed to in the signed stipulation in the 2023 distribution rate case, Cause No. 45911. AES Indiana will include this credit in a future ECR filing.

(6)Will be included in a future ECR filing

Current Regulatory Assets and Liabilities

Current regulatory assets and liabilities primarily represent costs that are being recovered per specific rate orders; recovery for the remaining costs is probable, but not certain. As current assets, this includes undercollection of adjustment mechanisms for: (i) DSM, (ii) ECCRA costs, (iii) Off System Sales Margin Sharing, (iv) Capacity rider costs and (v) TDSIC. It also includes the current portion of deferred MISO costs and environmental costs collected through base rates which are described in greater detail below. With the exception of environmental costs, these costs do not earn a return on investment. As current liabilities, this includes (i) overcollection of MISO rider costs, (ii) Green Power, and (iii) deferred fuel costs.

Deferred Fuel

Deferred fuel costs are a component of current and long-term regulatory assets or liabilities (which is a result of AES Indiana charging either more or less for fuel than our actual costs to our jurisdictional customers) and are expected to be recovered through future FAC proceedings. AES Indiana records deferred fuel in accordance with standards prescribed by the FERC. The deferred fuel adjustment is the result of variances between estimated fuel and purchased power costs in AES Indiana’s FAC and actual fuel and purchased power costs. AES Indiana is generally permitted to recover underestimated fuel and purchased power costs in future rates through the FAC proceedings and therefore the costs are deferred when incurred and amortized into fuel expense in the same period that AES Indiana’s rates are adjusted to reflect these costs.

The Eagle Valley CCGT was on unplanned outage from late April 2021 until mid-March 2022, impacting several FAC periods. In November 2021, a sub-docket was created with the IURC to examine the unplanned outage. On October 25, 2022, AES Indiana and various intervening parties reached a unanimous settlement regarding the Eagle Valley CCGT unplanned outage, resolving all issues related to the FAC sub-docket and all outage related costs including energy purchases, Off-System Sales margins, Capacity trackers and base rate proceedings. As part of this comprehensive settlement, AES Indiana agreed not to recover $ i 21.0 million of previously deferred costs and to credit an additional $ i 6.8 million to customers in future rates. As such, AES Indiana recorded a $ i 27.8 million charge to "Power purchased" in the Consolidated Statements of Operations during the third quarter of 2022. On January 18, 2023, AES Indiana received an order from the IURC approving the settlement.

Unrecognized Pension and Postretirement Benefit Plan Costs

In accordance with ASC 715 “Compensation – Retirement Benefits” and ASC 980, we recognize a regulatory asset equal to the unrecognized actuarial gains and losses and prior service costs. Pension expenses or income are recorded based on the benefit plan’s actuarially determined pension liability or asset and associated level of annual expenses or income to be recognized. The other postretirement benefit plan’s deferred benefit cost is the excess of the other postretirement benefit liability over the amount previously recognized.

Deferred MISO Costs

These consist of administrative costs for transmission services, transmission expansion cost sharing, and certain other operational and administrative costs from the MISO market. These costs are being recovered per specific rate order.

Unamortized Petersburg Unit 4 Carrying Charges and Certain Other Costs

These consist of deferred debt carrying costs, depreciation, and post-in-service AFUDC on Petersburg Unit 4. These costs are being recovered per specific rate order.

Unamortized Reacquisition Premium on Debt

This regulatory asset represents losses on long-term debt reacquired or redeemed in prior periods that have been deferred. These deferred losses are being amortized over the lives of the original issues in accordance with the rules of the FERC and the IURC.

Environmental Costs

These consist of various costs incurred to comply with environmental regulations. These costs were approved for recovery either through AES Indiana's ECCRA proceedings or in the 2018 Base Rate Order. Amortization periods vary, ranging from i 3 to i 43 years.

COVID-19 Costs

These consist of deferred fees (foregone late fees, reconnection fees and disconnection fees), as well as deferred convenience payments and incremental bad debt expense as the result of COVID-19. See "IURC COVID-19 Orders" above for additional discussion.

TDSIC Costs

These consist of various costs incurred for AES Indiana's approved TDSIC Plan. These costs were approved for recovery through AES Indiana's TDSIC proceedings and amortization periods range from i 1 to i 36 years. See "TDSIC" above for additional discussion.

Petersburg Unit 1 and 2 Retirement Costs

These consist of the remaining unamortized net book value of Petersburg Unit 1 and 2. In accordance with ASC 980, it was determined that the Petersburg Unit 1 retirement became probable, in the fourth quarter of 2020, and the Petersburg Unit 2 retirement became probable in the fourth quarter of 2021. As the entire carrying value of these assets will be recoverable through future rates, no loss on abandonment was recorded and the asset was reclassified from net property, plant and equipment to a long-term regulatory asset. See "IRP Filings and Replacement Generation" above for additional discussion.

Hardy Hills Solar Project Development Costs

These consist of project development costs, mainly legal and consulting fees, incurred for the Hardy Hills Solar Project as well as carrying costs on AES Indiana's investment in the project. The investment costs were approved for recovery via the ECCRA rider through AES Indiana’s Hardy Hills Solar Project regulatory proceedings with an amortization period of 30 years. Amortization of the project development costs will be determined in a future rate case filing.

Petersburg Energy Center Project Development Costs

These consist of project development costs, mainly legal and consulting fees, incurred for the Petersburg Energy Center Project as well as carrying costs on AES Indiana's investment in the project. The investment costs were approved for recovery via the ECCRA rider through AES Indiana’s Petersburg Energy Center Project regulatory proceedings with an amortization period of i 30 years. Amortization of the project development costs will be determined in a future rate case filing.

Pike County BESS Project Development Costs

These consist of project development costs, mainly legal and consulting fees, incurred for the Pike County BESS Project as well as carrying costs on AES Indiana's investment in the project. The investment costs were approved for recovery via the ECCRA rider through AES Indiana’s Pike County BESS Project regulatory proceedings with an amortization period of i 20 years. Amortization of the project development costs will be determined in a future rate case filing.

FTRs

In connection with AES Indiana’s participation in MISO, in the second quarter of each year AES Indiana is granted financial instruments that can be converted into cash or FTRs based on AES Indiana’s forecasted peak load for the period. See Note 4, "Fair Value - Fair Value Hierarchy and Valuation Techniques - Financial Assets - FTRs" for additional information.

ARO and Accrued Asset Removal Costs

In accordance with ASC 410 and ASC 980, AES Indiana recognizes the amount collected in customer rates for costs of removal not yet incurred that do not have an associated legal retirement obligation as a deferred regulatory liability. This amount is net of the portion of legal ARO costs that are deferred that is also being recovered in rates.

Deferred Income Taxes Recoverable/Payable Through Rates

A deferred income tax asset or liability is created from a difference in timing of income recognition between tax laws and accounting methods. As a regulated utility, AES Indiana includes in ratemaking the impacts of current income taxes and changes in deferred income tax liabilities or assets.

On December 22, 2017, the U.S. federal government enacted the TCJA, which, among other things, reduced the federal corporate income tax rate from i 35% to i 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 $ i 74.8 million and $ i 88.7 million as of December 31, 2023 and 2022, respectively.

3. PROPERTY, PLANT AND EQUIPMENT

The original cost of property, plant and equipment segregated by functional classifications follows:

As of December 31,

2023

2022

(In Thousands)

Production

i 3,942,052

i 4,164,416

Transmission

i 487,527

i 461,245

Distribution

i 2,304,526

i 2,045,579

General plant

i 348,338

i 311,074

Total property, plant and equipment

i 7,082,443

i 6,982,314

As of December 31, 2023 and 2022, AES Indiana had $ i 259.9 million and $ i 287.5 million, respectively, of net property, plant and equipment associated with the Petersburg Unit 1 and Unit 2 retirements recorded as long-term regulatory assets (for further discussion, see Note 2, “Regulatory Matters - IRP Filings and Replacement Generation”).

Substantially all of AES Indiana’s property is subject to a $ i 2,153.8 million direct first mortgage lien, as of December 31, 2023, securing AES Indiana’s first mortgage bonds. Total non-contractually or legally required accrued removal costs of utility plant in service at December 31, 2023 and 2022 were $ i 680.9 million and $ i 694.0 million, respectively; and total contractually or legally required removal costs of property, plant and equipment at December 31, 2023 and 2022 were $ i 249.9 million and $ i 218.7 million, respectively. Please see “ARO” below for further information.

ARO

ASC 410 “Asset Retirement and Environmental Obligations” addresses financial accounting and reporting for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal operation. A legal obligation for purposes of ASC 410 is an obligation that a party is required to settle as a result of an existing law, statute, ordinance, written or oral contract or the doctrine of promissory estoppel.

AES Indiana’s ARO relates primarily to environmental issues involving asbestos-containing materials, ash ponds, landfills and miscellaneous contaminants associated with its generating plants, transmission system and distribution system. i The following is a roll forward of the ARO legal liability year end balances:

2023

2022

(In Thousands)

Balance as of January 1

i 218,729

i 189,509

Liabilities incurred

i 17,080

i 1,159

Liabilities settled

( i 11,902)

( i 24,699)

Revisions to cash flow and timing estimates

i 12,921

i 44,679

Accretion expense

i 13,102

i 8,081

Balance as of December 31

i 249,930

i 218,729

ARO liabilities incurred in 2023 and 2022 primarily relate to FGD residual water disposal and AES Indiana's solar projects. AES Indiana recorded revisions to its ARO liabilities in 2023 and 2022 primarily to reflect revisions to cash flow estimates and timing due to increases to estimated ash pond closure costs and changes to expected landfill closure dates. As of December 31, 2023 and 2022, AES Indiana did not have any assets that are legally restricted for settling its ARO liability.

4. i FAIR VALUE

The fair value of current financial assets and liabilities approximate their reported carrying amounts. The estimated fair values of the Company’s assets and liabilities have been determined using available market information. Because these amounts are estimates and based on hypothetical transactions to sell assets or transfer liabilities, the use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.

Fair Value Hierarchy and Valuation Techniques

ASC 820 defines and establishes a framework for measuring fair value and expands disclosures about fair value measurements for financial assets and liabilities that are adjusted to fair value on a recurring basis and/or financial assets and liabilities that are measured at fair value on a nonrecurring basis, which have been adjusted to fair value during the period. In accordance with ASC 820, we have categorized our financial assets and liabilities that are adjusted to fair value, based on the priority of the inputs to the valuation technique, following the three-level fair value hierarchy prescribed by ASC 820 as follows:

Level 1 - unadjusted quoted prices for identical assets or liabilities in an active market;

Level 2 - inputs from quoted prices in markets where trading occurs infrequently or quoted prices of instruments with similar attributes in active markets; and

Level 3 - unobservable inputs reflecting management’s own assumptions about the inputs used in pricing the asset or liability.

Whenever possible, quoted prices in active markets are used to determine the fair value of our financial instruments. Our financial instruments are not held for trading or other speculative purposes. The estimated fair value of financial instruments has been determined by using available market information and appropriate valuation methodologies. However, considerable judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we could realize in a current market exchange. The use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.

Financial Assets

VEBA Assets

IPALCO has VEBA investments that are to be used to fund certain employee postretirement health care benefit plans. These assets are primarily comprised of open-ended mutual funds, which are valued using the net assets value per unit. These investments are recorded at fair value within "Other non-current assets" on the accompanying Consolidated Balance Sheets and classified as equity securities. All changes to fair value on the VEBA investments are included in income in the period that the changes occur. These changes to fair value were not material for the years ended December 31, 2023, 2022, or 2021. Any unrealized gains or losses are recorded in "Other (expense) / income, net" on the accompanying Consolidated Statements of Operations and were not material to the consolidated financial statements in the periods covered by this report.

FTRs

In connection with AES Indiana’s participation in MISO, in the second quarter of each year AES Indiana is granted financial instruments that can be converted into cash or FTRs based on AES Indiana’s forecasted peak load for the period. FTRs are used in the MISO market to hedge AES Indiana’s exposure to congestion charges, which result from constraints on the transmission system. AES Indiana’s FTRs are valued at the cleared auction prices for FTRs in MISO’s annual auction. Because of the infrequent nature of this valuation, the fair value assigned to the FTRs is considered a Level 3 input under the fair value hierarchy required by ASC 820. An offsetting regulatory liability has been recorded as these revenue or costs will be flowed through to customers through the FAC. As such, there is no impact on our Consolidated Statements of Operations.

Forward Power Contracts

As of December 31, 2023 and 2022, all outstanding forward power contracts had settled and there was no notional amount outstanding. All changes in the market value of the forward power contracts were recorded in the Consolidated Statements of Operations in the period in which the change occurred. See also Note 5, "Derivative Instruments and Hedging Activities - Derivatives Not Designated as Hedge" for further information.

Interest Rate Hedges

IPALCO's interest rate hedges have a combined notional amount of $ i 400.0 million. All changes in the market value of the interest rate hedges are recorded in AOCI. See also Note 5, "Derivative Instruments and Hedging Activities - Cash Flow Hedges" for further information.

Recurring Fair Value Measurements

The fair value of assets at December 31, 2023 and 2022 measured on a recurring basis and the respective category within the fair value hierarchy for IPALCO was determined as follows:

Fair Value as of December 31, 2023

Fair Value as of December 31, 2022

Level 1

Level 2

Level 3

Total

Level 1

Level 2

Level 3

Total

(In Thousands)

Financial assets:

VEBA investments:

Money market funds

i 127

i —

i 127

i 5

i —

i 5

Mutual funds

i 3,425

i —

i 3,425

i 3,223

i —

i 3,223

Total VEBA investments

i 3,552

i —

i 3,552

i 3,228

i —

i 3,228

FTRs

i —

i 1,388

i —

i 7,545

Interest rate hedges

i —

i 14,294

i —

i 14,294

i —

i 12,172

i —

i 12,172

Total financial assets measured at fair value

i 3,552

i 14,294

i 1,388

i 19,234

i 3,228

i 12,172

i 7,545

i 22,945

The following table sets forth a roll forward of financial instruments, measured at fair value on a recurring basis, classified as Level 3 in the fair value hierarchy (note, amounts in this table indicate carrying values, which approximate fair values):


	Reconciliation of Financial Instruments Classified as Level 3
	(In Thousands)
Balance at January 1, 2022	$	i 1,235

Issuances	i 15,338
Settlements	( i 9,028)
Balance at December 31, 2022	i 7,545

Issuances	i 3,624
Settlements	( i 9,781)
Balance at December 31, 2023	$	i 1,388

Financial Instruments not Measured at Fair Value in the Consolidated Balance Sheets

Debt

The fair value of our outstanding fixed-rate debt has been determined on the basis of the quoted market prices of the specific securities issued and outstanding. In certain circumstances, the market for such securities was inactive and therefore the valuation was adjusted to consider changes in market spreads for similar securities. Accordingly, the purpose of this disclosure is not to approximate the value on the basis of how the debt might be refinanced.

The following table shows the face value and the fair value of fixed-rate and variable-rate indebtedness (Level 2) for the periods ending:

Face Value

Fair Value

Face Value

Fair Value

(In Thousands)

Fixed-rate

i 3,033,800

i 2,860,467

i 3,033,800

i 2,775,644

Variable-rate

i 455,000

i —

Total indebtedness

i 3,488,800

i 3,315,467

i 3,033,800

i 2,775,644

The difference between the face value and the carrying value of this indebtedness represents the following:

•unamortized deferred financing costs of $ i 24.8 million and $ i 26.3 million at December 31, 2023 and 2022, respectively; and

•unamortized discounts of $ i 6.8 million and $ i 7.1 million at December 31, 2023 and 2022, respectively.

5. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

We use derivatives principally to manage the interest rate risk associated with refinancing our long-term debt and the risk of price changes for purchased power. The derivatives that we use to economically hedge these risks are governed by our risk management policies for forward and futures contracts. Our net positions are continually assessed within our structured hedging programs to determine whether new or offsetting transactions are required. We monitor and value derivative positions monthly as part of our risk management processes. We use published sources for pricing, when possible, to mark positions to market. All of our derivative instruments are used for risk management purposes and are designated as cash flow hedges if they qualify under ASC 815 for accounting purposes.

At December 31, 2023, AES Indiana's outstanding derivative instruments were as follows:

Commodity

Accounting Treatment (a)

Unit

Notional
(in thousands)

Sales
(in thousands)

Net Notional
(in thousands)

Interest rate hedges

Designated

USD

i 400,000

i —

i 400,000

FTRs

Not Designated

MWh

i 3,919

i —

i 3,919

(a) Refers to whether the derivative instruments have been designated as a cash flow hedge.

Cash Flow Hedges

As part of our risk management processes, we identify the relationships between hedging instruments and hedged items, as well as the risk management objective and strategy for undertaking various hedge transactions. The fair values of cash flow hedges determined by current public market prices will continue to fluctuate with changes in market prices up to contract expiration. The change in the fair value of a hedging instrument is recorded in other comprehensive income and amounts deferred are reclassified to earnings in the same income statement line as the hedged item in the period in which it settles.

In March 2019, we entered into i three forward interest rate swaps to hedge the interest risk associated with refinancing the IPALCO 2020 maturities. The i three interest rate swaps had a combined notional amount of $ i 400.0 million. In April 2020, we de-designated the swaps as cash flow hedges and froze the AOCL of $ i 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 $ i 400.0 million and will be settled when the 2024 IPALCO Notes are refinanced. The $ i 72.3 million of AOCL associated with the interest rate swaps through the date of the amendment is being amortized out of AOCL into interest expense over the remaining life of the 2030 IPALCO Notes, while any changes in fair value associated with the amended interest rate swaps will be recognized in AOCL going forward.

The following tables provide information on gains or losses recognized in AOCI / (AOCL) for the cash flow hedges for the periods indicated:

Interest Rate Hedges for the Years Ended December 31,

$ in thousands (net of tax)

2023

2022

2021

Beginning accumulated derivative gain / (loss) in AOCI / (AOCL)

i 22,269

( i 29,407)

( i 43,420)

Net gains associated with current period hedging transactions

i 1,594

i 46,245

i 10,393

Net losses reclassified to interest expense

i 5,431

i 3,620

Ending accumulated derivative gain / (loss) in AOCI / (AOCL)

i 29,294

i 22,269

( i 29,407)

Loss expected to be reclassified to earnings in the next twelve months

( i 5,375)

Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)

i 9

Derivatives Not Designated as Hedge

acquired and subsequently amortized over the annual period as they are used. The forward power contracts are recorded at fair value using the market approach with changes in the fair value charged or credited to the Consolidated Statements of Operations in the period in which the change occurred. This is commonly referred to as "MTM accounting." Realized gains and losses on the forward power contracts are included in future FAC filings, therefore any realized and unrealized gains and losses are deferred as regulatory liabilities or regulatory assets. There were net realized gains of $ i 0.0 million and $ i 1.3 million related to forward power contracts during the years ended December 31, 2023 and 2022, respectively, related to the forward power contracts that were deferred and included with deferred fuel costs in "Regulatory assets, current" on the accompanying Consolidated Balance Sheets.

Certain qualifying derivative instruments have been designated as normal purchases or normal sales contracts, as provided under GAAP. Derivative contracts that have been designated as normal purchases or normal sales under GAAP are not subject to hedge or MTM accounting and are recognized in the Consolidated Statements of Operations on an accrual basis.

When applicable, IPALCO has elected not to offset derivative assets and liabilities and not to offset net derivative positions against the right to reclaim cash collateral pledged (an asset) or the obligation to return cash collateral received (a liability) under derivative agreements. As of December 31, 2023 and 2022, IPALCO did not have any offsetting positions.

The following table summarizes the fair value, balance sheet classification and hedging designation of IPALCO's derivative instruments (in thousands):

December 31,

Commodity

Hedging Designation

Balance sheet classification

2023

2022

FTRs

Not a Cash Flow Hedge

Derivative assets, current

i 1,388

i 7,545

Interest rate hedges

Cash Flow Hedge

Derivative assets, current

i 14,294

i —

Interest rate hedges

Cash Flow Hedge

Derivative assets, non-current

i —

i 12,172

6. i DEBT

The following table presents our long-term debt:

December 31,

Series

Due

2023

2022

(In Thousands)

AES Indiana first mortgage bonds:

i 3.125% (1)

December 2024

i 40,000

i 0.65% (1)

August 2025

i 40,000

i 0.75% (2)

April 2026

i 30,000

i 0.95% (2)

April 2026

i 60,000

i 1.40% (1)

August 2029

i 55,000

i 5.65%

December 2032

i 350,000

i 6.60%

January 2034

i 100,000

i 6.05%

October 2036

i 158,800

i 6.60%

June 2037

i 165,000

i 4.875%

November 2041

i 140,000

i 4.65%

June 2043

i 170,000

i 4.50%

June 2044

i 130,000

i 4.70%

September 2045

i 260,000

i 4.05%

May 2046

i 350,000

i 4.875%

November 2048

i 105,000

Unamortized discount – net

( i 6,449)

( i 6,651)

Deferred financing costs

( i 19,058)

( i 20,362)

Total AES Indiana first mortgage bonds

i 2,128,293

i 2,126,787

Total long-term debt – AES Indiana

i 2,128,293

i 2,126,787

Long-term debt – IPALCO:

i 3.70% Senior Secured Notes

September 2024

i 405,000

i 4.25% Senior Secured Notes

May 2030

i 475,000

Unamortized discount – net

( i 319)

( i 425)

Deferred financing costs

( i 4,554)

( i 5,912)

Total long-term debt – IPALCO

i 875,127

i 873,663

Total consolidated IPALCO long-term debt

i 3,003,420

i 3,000,450

Less: current portion of long-term debt

i 445,000

i —

Net consolidated IPALCO long-term debt

i 2,558,420

i 3,000,450

(1)First mortgage bonds issued to the Indiana Finance Authority, to secure the loan of proceeds from tax-exempt bonds issued by the Indiana Finance Authority.

(2)First mortgage bonds issued to the Indiana Finance Authority, to secure the loan of proceeds from tax-exempt bonds issued by the Indiana Finance Authority. The notes have a final maturity date of December 31, 2038, but are subject to a mandatory put in April 2026.

Line of Credit

AES Indiana entered into a second amendment and restatement of its $ i 350 million revolving Credit Agreement on December 22, 2022 with a syndication of bank lenders. This Credit Agreement is an unsecured committed line of credit to be used: (i) to finance capital expenditures; (ii) to refinance certain existing indebtedness, (iii) to support working capital; and (iv) for general corporate purposes. This agreement matures on December 22, 2027, and bears interest at variable rates as described in the Credit Agreement. It includes an uncommitted $ i 150 million accordion feature to provide AES Indiana with an option to request an increase in the size of the facility at any time prior to December 22, 2026, subject to approval by the lenders. The Credit Agreement also includes two one-year extension options, allowing AES Indiana to extend the maturity date subject to approval by the lenders. As of December 31,

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

Debt Maturities

Maturities on long-term indebtedness subsequent to December 31, 2023 are as follows:


Year	Amount
	(In Thousands)
2024	$	i 445,000
2025	i 40,000
2026	i 90,000
2027	i —
2028	i —
Thereafter	i 2,458,800
	i 3,033,800
Unamortized discounts	( i 6,768)
Deferred financing costs, net	( i 23,612)
Total long-term debt	$	i 3,003,420

Significant Transactions

AES Indiana Term Loans

In November 2023, AES Indiana entered into an unsecured $ i 300 million 364-day term loan agreement ("$ i 300 million Term Loan Agreement"). The $ i 300 million Term Loan Agreement was fully drawn at closing with the proceeds being used for general corporate purposes. This agreement matures on November 19, 2024, and bears interest at variable rates as described in the $ i 300 million Term Loan Agreement. The $ i 300 million Term Loan Agreement contains customary representations, warranties and covenants, including a leverage covenant consistent with the leverage covenant contained in AES Indiana's Credit Agreement. AES Indiana has classified this $ i 300 million Term Loan Agreement as short-term indebtedness as it matures November 2024. Although current liquid funds are not sufficient to repay the amount due at maturity, management plans to refinance this $ i 300 million Term Loan Agreement with new long-term debt.

In June 2022, AES Indiana entered into an unsecured $ i 200 million 364-day term loan agreement ("$ i 200 million Term Loan Agreement"). The $ i 200 million Term Loan Agreement was fully drawn at closing with the proceeds being used for general corporate purposes. This agreement was set to mature on June 22, 2023, but was fully repaid in November 2022.

AES Indiana First Mortgage Bonds and Recent Indiana Finance Authority Bond Issuances

In November 2022, AES Indiana issued $ i 350 million aggregate principal amount of first mortgage bonds, i 5.65% Series, due December 2032, pursuant to Rule 144A and Regulation S under the Securities Act. Net proceeds from this offering were approximately $ i 345.6 million, after deducting the initial purchasers’ discounts and fees and expenses for the offering. The net proceeds from this offering were used to repay amounts due under the Credit Agreement and the $ i 200 million Term Loan Agreement, and for general corporate purposes.

In July 2021, the Indiana Finance Authority issued at the request of AES Indiana an aggregate principal amount of $ i 95 million of Environmental Facilities Refunding Revenue Bonds, Series 2021A&B. AES Indiana issued $ i 95 million aggregate principal amount of first mortgage bonds to the Indiana Finance Authority in two series: $ i 55 million Series 2021A bonds at an interest rate of i 1.40% due August 1, 2029 and $ i 40 million Series 2021B notes at an interest rate of i 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 $ i 95 million of Indiana Finance Authority Environmental Facilities Refunding Revenue Bonds Series 2011A&B at a redemption price of i 100% of par.

IPALCO’s Senior Secured Notes and Term Loan

The 2024 IPALCO Notes are due September 1, 2024. Although current liquid funds are not sufficient to repay the collective amounts due under the 2024 IPALCO Notes at maturity, the Company believes it will be able to refinance the 2024 IPALCO Notes based on conversations with investment bankers, which currently indicate more than adequate demand for new IPALCO debt at its current credit ratings, and considering the Company's previous successful debt issuances.

Pursuant to a registration rights agreement dated April 14, 2020, IPALCO agreed to register the 2030 IPALCO Notes under the Securities Act by filing an exchange offer registration statement or, under specified circumstances, a shelf registration statement with the SEC. IPALCO filed a registration statement on Form S-4 with respect to the 2030 IPALCO Notes with the SEC on March 22, 2021 in respect of its obligations under such registration rights agreement, and this registration statement was declared effective on April 7, 2021. The exchange offer closed on May 11, 2021.

Restrictions on Issuance of Debt

All of AES Indiana’s long-term borrowings must first be approved by the IURC and the aggregate amount of AES Indiana’s short-term indebtedness must be approved by the FERC. AES Indiana has approval from FERC to borrow up to $ i 750 million of short-term indebtedness outstanding at any time through July 26, 2024. In November 2021, AES Indiana received an order from the IURC granting AES Indiana authority through December 31, 2024 to, among other things, issue up to $ i 740 million in aggregate principal amount of long-term debt, of which $ i 390 million remains available as of December 31, 2023. This order also grants AES Indiana authority to have up to $ i 750 million of long-term credit agreements and liquidity facilities outstanding at any one time, of which $ i 100.0 million remains available under the order as of December 31, 2023. As an alternative to the sale of all or a portion of $ i 65 million in principal of the long-term debt mentioned above, we have authority to issue up to $ i 65 million of new preferred stock, all of which authority remains available under the order as of December 31, 2023. AES Indiana also has restrictions on the amount of new debt that may be issued due to contractual obligations of AES and by financial covenant restrictions under our existing debt obligations. Under such restrictions, AES Indiana is generally allowed to fully draw the amounts available on its Credit Agreement, refinance existing debt and issue new debt approved by the IURC and issue certain other indebtedness. On September 29, 2023, AES Indiana filed a petition for approval of a financing program for the approximately three-year period ending December 31, 2026. The OUCC filed testimony on December 1, 2023 with certain recommended parameters for future debt issuances that AES Indiana accepted. A hearing was held January 10, 2024 and an agreed proposed order between AES Indiana and the OUCC was submitted on that date. AES Indiana awaits an IURC order in the matter and it remains pending.

The mortgage and deed of trust of AES Indiana, together with the supplemental indentures thereto, secure the first mortgage bonds issued by AES Indiana. Pursuant to the terms of the mortgage, substantially all property owned by AES Indiana is subject to a first mortgage lien securing indebtedness of $ i 2,153.8 million as of December 31, 2023. The AES Indiana first mortgage bonds require net income as calculated thereunder be at least two and one-half times the annual interest requirements before additional bonds can be authenticated on the basis of property additions. AES Indiana was in compliance with such requirements as of December 31, 2023.

Credit Ratings

Our ability to borrow money or to refinance existing indebtedness and the interest rates at which we can borrow money or refinance existing indebtedness are affected by our credit ratings. In addition, the applicable interest rates on AES Indiana’s Credit Agreement are dependent upon the credit ratings of AES Indiana. Downgrades in the credit ratings of AES could result in AES Indiana’s and/or IPALCO’s credit ratings being downgraded.

7. i INCOME TAXES

IPALCO follows a policy of comprehensive interperiod income tax allocation. Investment tax credits related to utility property have been deferred and are being amortized over the estimated useful lives of the related property.

AES files federal and state income tax returns which consolidate IPALCO and its subsidiaries. Under a tax sharing agreement with AES, IPALCO is responsible for the income taxes associated with its own taxable income and records the provision for income taxes as if IPALCO and its subsidiaries each filed separate income tax returns. IPALCO is no longer subject to U.S. or state income tax examinations for tax years through 2016, but is open for all subsequent periods. IPALCO made tax sharing payments to AES of $ i 0.0 million, $ i 31.0 million and $ i 27.5 million in 2023, 2022 and 2021, respectively.

Income Tax Provision

Federal and state income taxes charged to income are as follows:

2023

2022

2021

(In Thousands)

Components of income tax expense:

Current income taxes:

Federal

( i 14,222)

i 22,539

i 28,100

State

( i 3,716)

i 6,026

i 8,218

Total current income taxes

( i 17,938)

i 28,565

i 36,318

Deferred income taxes:

Federal

i 24,885

( i 6,920)

( i 7,286)

State

i 7,768

i 214

( i 91)

Total deferred income taxes

i 32,653

( i 6,706)

( i 7,377)

Total income tax expense

i 14,715

i 21,859

i 28,941

Effective and Statutory Rate Reconciliation

The provision for income taxes (including net investment tax credit adjustments) is different than the amount computed by applying the statutory tax rate to pretax income. The reasons for the difference, stated as a percentage of pretax income, are as follows:


	2023		2022		2021
Federal statutory tax rate	i 21.0	%	i 21.0	%	i 21.0	%
State income tax, net of federal tax benefit	i 3.9	%	i 3.9	%	i 4.0	%



Depreciation flow through and amortization	( i 12.9)	%	( i 7.8)	%	( i 6.3)	%
AFUDC - equity	( i 0.3)	%	i 0.9	%	i 0.4	%

Noncontrolling interests in subsidiaries	i 9.0	%	i —	%	i —	%
Other – net	( i 0.2)	%	i 0.4	%	i 0.4	%
Effective tax rate	i 20.5	%	i 18.4	%	i 19.5	%

Deferred Income Taxes

The significant items comprising IPALCO’s net accumulated deferred tax liability recognized on the audited Consolidated Balance Sheets as of December 31, 2023 and 2022 are as follows:

2023

2022

(In Thousands)

Deferred tax liabilities:

Relating to utility property, net

i 409,675

i 341,473

Regulatory assets recoverable through future rates

i 108,823

i 123,669

Other

i 17,694

i 17,953

Total deferred tax liabilities

i 536,192

i 483,095

Deferred tax assets:

Investment tax credit

i 5

i 6

Regulatory liabilities including ARO

i 168,619

i 167,725

Investments in tax partnerships

i 2,501

i —

Other

i 3,579

i 2,723

Total deferred tax assets

i 174,704

i 170,454

Deferred income tax liability – net

i 361,488

i 312,641

Uncertain Tax Positions

The following is a reconciliation of the beginning and ending amounts of unrecognized tax benefits for the years ended December 31, 2023, 2022 and 2021:


	2023		2022		2021
	(In Thousands)
Unrecognized tax benefits at January 1	$	i —	$	i —	$	i 7,368

Gross decreases – prior period tax positions	i —		i —		( i 7,368)
Unrecognized tax benefits at December 31	$	i —	$	i —	$	i —

The prior period unrecognized tax benefits represent tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. As a result of the resolution of federal and state audits in 2021, IPALCO reviewed its uncertain positions and determined that they are more likely than not to be sustained upon examination by taxing authorities. Consequently, the uncertain tax positions were reversed; because of the impact of deferred tax accounting the reversal did not affect the annual effective tax rate but were reclassified to plant related deferred tax balances.

Tax years subsequent to 2016 remain open to examination by taxing authorities. While it is often difficult to predict the final outcome or the timing of resolution of any particular uncertain tax position, we believe unrecognized tax benefits of $ i 0 at December 31, 2023 and 2022, respectively, is the appropriate accrual for our uncertain tax positions. However, audit outcomes and the timing of audit settlements and future events that would impact our previously recorded unrecognized tax benefits are subject to significant uncertainty. It is possible that the ultimate outcome of future examinations may exceed our provision for current unrecognized tax benefits.

Tax-related interest expense and income is reported as part of the provision for federal and state income taxes. Penalties, if incurred, would also be recognized as a component of tax expense. There are no interest or penalties applicable to the periods contained in this report.

8. i 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 i 77% of AES Indiana’s active employees are covered by the Thrift Plan, a qualified defined contribution plan. All union new hires are covered under the Thrift Plan. Participants elect to make contributions to the Thrift Plan based on a percentage of their base compensation. Each participant’s contribution is matched up to certain thresholds of base compensation. The IBEW clerical-technical union new hires receive an annual lump sum company contribution into the Thrift Plan in addition to the company match. Employer contributions to the Thrift Plan were $ i 3.7 million, $ i 3.6 million and $ i 3.4 million for 2023, 2022 and 2021, respectively.

The RSP

Approximately i 23% of AES Indiana’s active employees are covered by the RSP, a qualified defined contribution plan containing both match and nondiscretionary components. All non-union new hires are covered under the RSP. Participants elect to make contributions to the RSP based on a percentage of their eligible compensation. Each participant’s contribution is matched in amounts up to, but not exceeding, i 5% of the participant’s eligible compensation. Starting in 2018, the RSP also includes a i 4% nondiscretionary contribution based as a percentage of each participant's eligible compensation. Employer contributions (by AES Indiana) relating to the RSP were $ i 2.5 million, $ i 2.1 million and $ i 1.9 million for 2023, 2022 and 2021, respectively.

Defined Benefit Plans

Approximately i 65% of AES Indiana’s active employees are covered by the qualified Defined Benefit Pension Plan; while approximately i 12% of active employees are IBEW clerical-technical unit employees who are only eligible for the Thrift Plan. The remaining i 23% of active employees are covered by the RSP. All non-union new hires are covered under the RSP, while IBEW physical unit union new hires are covered under the Defined Benefit Pension Plan and Thrift Plan. The IBEW clerical-technical unit new hires are no longer covered under the Defined Benefit Pension Plan but do receive an annual lump sum company contribution into the Thrift Plan, in addition to the company match. The Defined Benefit Pension Plan is noncontributory and is funded by AES Indiana through a trust. Benefits for non-union participants in the Defined Benefit Pension Plan are based on salary, years of service and accrued benefits at April 1, 2015. Benefits for eligible union participants are based on each individual employee's pension band and years of service as opposed to their compensation. Pension bands are based primarily on job duties and responsibilities.

Additionally, a small group of former officers and their surviving spouses are covered under a funded non-qualified Supplemental Retirement Plan. The total number of participants in the plan as of December 31, 2023 was i 19. The plan is closed to new participants.

AES Indiana also provides postretirement health care benefits to certain active or retired employees and the spouses of certain active or retired employees. Approximately i 123 active employees and i 26 retirees (including spouses) were receiving such benefits or entitled to future benefits as of January 1, 2023. The plan is unfunded. These postretirement health care benefits and the related unfunded obligation of $ i 3.0 million and $ i 3.2 million at December 31, 2023 and 2022, respectively, were not material to the consolidated financial statements in the periods covered by this report.

The following table presents information relating to the Pension Plans:

Pension benefits
as of December 31,

2023

2022

(In Thousands)

Change in benefit obligation:

Projected benefit obligation at January 1

i 577,530

i 772,040

Service cost

i 5,189

i 8,949

Interest cost

i 29,818

i 18,099

Actuarial loss (gain)

i 9,681

( i 182,590)

Amendments (primarily increases in pension bands)

i 653

i —

Settlements

i —

( i 394)

Benefits paid

( i 73,325)

( i 38,575)

Projected benefit obligation at December 31

i 549,546

i 577,529

Change in plan assets:

Fair value of plan assets at January 1

i 611,125

i 820,684

Actual return/(loss) on plan assets

i 52,905

( i 171,002)

Employer contributions

i 114

i 412

Settlements

i —

( i 394)

Benefits paid

( i 73,325)

( i 38,575)

Fair value of plan assets at December 31

i 590,819

i 611,125

Funded status

i 41,273

i 33,596

Amounts recognized in the statement of financial position:

Non-current assets

i 41,273

i 33,611

Non-current liabilities

i —

( i 15)

Net amount recognized at end of year

i 41,273

i 33,596

Sources of change in regulatory assets(1):

Prior service cost arising during period

i 653

i —

Net (gain)/loss arising during period

( i 10,117)

i 24,069

Amortization of prior service cost

( i 2,172)

( i 2,589)

Amortization of loss

( i 6,145)

( i 2,622)

Total recognized in regulatory assets

( i 17,781)

i 18,858

Amounts included in regulatory assets:

Net loss

i 115,297

i 131,559

Prior service cost

i 10,136

i 11,655

Total amounts included in regulatory assets

i 125,433

i 143,214

(1)Amounts that would otherwise be charged/credited to Accumulated Other Comprehensive Income or Loss upon application of ASC 715, “Compensation – Retirement Benefits,” are recorded as a regulatory asset or liability because AES Indiana has historically recovered and currently recovers pension and other postretirement benefit expenses in rates. These are unrecognized amounts not yet recognized as components of net periodic benefit costs.

Significant Loss / (Gain) Related to Changes in the Benefit Obligation for the Period

As shown in the table above, an actuarial loss of $ i 9.7 million and an actuarial gain of $ i 182.6 million for the year ended December 31, 2023 and December 31, 2022, respectively, were recognized in the benefit obligation, primarily due to changes in the discount rate.

Pension Benefits and Expense

Reported expenses relevant to the Defined Benefit Pension Plan are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience, including the performance of plan assets and actual benefits paid out in future years. Pension costs associated with the Defined Benefit Pension Plan are

impacted by the level of contributions made to the plan, income on plan assets, the adoption of new mortality tables, and employee demographics, including age, job responsibilities, salary and employment periods. Changes made to the provisions of the Defined Benefit Pension Plan may impact current and future pension costs. Pension costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the corporate bond discount rates, as well as, the adoption of a new mortality table used in determining the projected benefit obligation and pension costs.

The 2023 net actuarial gain of $ i 10.1 million recognized in regulatory assets is comprised of two parts: (1) a $ i 9.7 million pension liability actuarial loss primarily due to a decrease in the discount rate used to value pension liabilities; and (2) a $ i 19.8 million pension asset actuarial gain primarily due to higher than expected return on assets. The unrecognized net loss of $ i 115.3 million in the Pension Plans has accumulated over time primarily due to the long-term declining trend in corporate bond rates and the adoption of new mortality tables which have historically increased the expected benefit obligation due to the longer expected lives of plan participants. In 2023, the accumulated net loss decrease was primarily attributed to an annuity buyout involving a small portion of retirees, which was partially offset by factors such as a reduced discount rate utilized in valuing pension liabilities, along with the amortization of accumulated losses incurred during the year. The unrecognized net loss, to the extent that it exceeds i 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 i 11.66 years based on estimated demographic data as of December 31, 2023. The projected benefit obligation of $ i 549.5 million less the fair value of assets of $ i 590.8 million results in an overfunded status of $ i 41.3 million at December 31, 2023.

Pension benefits for
years ended December 31,

2023

2022

2021

(In Thousands)

Components of net periodic benefit cost / (credit):

Service cost

i 5,189

i 8,949

i 9,339

Interest cost

i 29,818

i 18,099

i 15,660

Expected return on plan assets

( i 33,107)

( i 35,656)

( i 41,815)

Amortization of prior service cost

i 2,172

i 2,589

i 2,944

Amortization of actuarial loss

i 6,145

i 2,424

i 5,529

Amortization of settlement loss

i —

i 199

i —

Net periodic benefit cost / (credit)

i 10,217

( i 3,396)

( i 8,343)

Less: amounts capitalized

i 1,689

( i 316)

( i 771)

Amount charged to expense

i 8,528

( i 3,080)

( i 7,572)

Rates relevant to each year’s expense calculations:

Discount rate – defined benefit pension plan

i 5.41

i 2.83

i 2.46

Discount rate – supplemental retirement plan

i 5.32

i 2.62

i 2.31

Expected return on defined benefit pension plan assets

i 5.60

i 4.45

i 5.05

Expected return on supplemental retirement plan assets

i 6.45

i 5.50

i 3.60

Pension expense / (income) for the following year is determined as of the December 31 measurement date based on the fair value of the Pension Plans’ assets, the expected long-term rate of return on plan assets, a mortality table assumption that reflects the life expectancy of plan participants, and a discount rate used to determine the projected benefit obligation. For 2023, pension expense / (income) was determined using an assumed long-term rate of return on plan assets of i 5.60% for the Defined Benefit Pension Plan and i 6.45% for the Supplemental Retirement Plan. As of the December 31, 2023 measurement date, AES Indiana decreased the discount rate from i 5.41% to i 5.15% for the Defined Benefit Pension Plan and increased the discount rate from i 5.32% to i 5.66% for the Supplemental Retirement Plan. The discount rate assumptions affect the pension expense / (income) determined for 2024. In addition, AES Indiana decreased the expected long-term rate of return on plan assets from i 5.60% to i 5.20% for the Defined Benefit Pension Plan and from i 6.45% to i 6.35% for the Supplemental Retirement Plan for 2024. The expected long-term rate of return assumptions affect the pension expense / (income) determined for 2024. The effect on 2024 total pension expense / (income) of a i 25 basis point increase and decrease in the assumed discount rate is $( i 0.8) million and $ i 0.8 million, respectively.

In determining the discount rate to use for valuing liabilities, we use the market yield curve on high-quality fixed income investments as of December 31, 2023. We project the expected benefit payments under the plan based on participant data and based on certain assumptions concerning mortality, retirement rates, termination rates, etc. The expected benefit payments for each year are discounted back to the measurement date using the appropriate spot rate for each half-year from the yield curve, thereby obtaining a present value of all expected future benefit payments using the yield curve. Finally, an equivalent single discount rate is determined which produces a present value equal to the present value determined using the full yield curve.

Pension Plan Assets and Fair Value Measurements

Pension plan assets consist of investments in cash and cash equivalents, government debt securities, and mutual funds (equity and debt). Differences between actual portfolio returns and expected returns may result in increased or reduced pension costs in future periods. Pension costs for 2024 are determined as of the plans' measurement date of December 31, 2023. Pension costs are determined for the following year based on the market value of pension plan assets, expected employer contributions, a discount rate used to determine the projected benefit obligation and the expected long-term rate of return on plan assets.

Fair value is defined under ASC 820 as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (i.e., an exit price). The fair value hierarchy prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets and liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).

Purchases and sales of securities are recorded on a trade-date basis. Interest income is recorded as earned. Dividends are recorded on the ex-dividend date. Net appreciation includes the Pension Plans’ gains and losses on investments bought and sold, as well as held, during the year.

A description of the valuation methodologies used for each major class of assets and liabilities measured at fair value follows:

•The non-qualified Supplemental Retirement Plan investments have quoted market prices and are categorized as Level 1 in the fair value hierarchy.

•The qualified Defined Benefit Pension Plan investments in common collective trusts are valued based on the daily net asset value and are categorized as Level 2 in the fair value hierarchy, except for cash and cash equivalents which are categorized as level 1.

The primary objective of the Pension Plans’ is to provide a source of retirement income for its participants and beneficiaries, while the primary financial objective is to improve the funded status of the Pension Plans. A secondary financial objective is, where possible, to minimize pension expense volatility. The objective is based on a long-term investment horizon, so that interim fluctuations should be viewed with appropriate perspective. There can be no assurance that these objectives will be met.

In establishing our expected long-term rate of return assumption, we utilize a methodology developed by the plan’s investment consultant who maintains a capital market assumption model that takes into consideration risk, return and correlation assumptions across asset classes. A combination of quantitative analysis of historical data and qualitative judgment is used to capture trends, structural changes and potential scenarios not reflected in historical data.

The result of the analyses is a series of inputs that produce a picture of how the plan consultant believes portfolios are likely to behave through time. Capital market assumptions are intended to reflect the behavior of asset classes observed over several market cycles. Stress assumptions are also examined, since the characteristics of asset classes are constantly changing. A dynamic model is employed to manage the numerous assumptions required to estimate portfolio characteristics under different base currencies, time horizons and inflation expectations.

The Pension Plans’ consultant develops forward-looking, long-term capital market assumptions for risk, return and correlations for a variety of global asset classes, interest rates and inflation. These assumptions are created using a combination of historical analysis, current market environment assessment and by applying the consultant’s own

100

judgment. The consultant then determines an equilibrium long-term rate of return. We then take into consideration the investment manager/consultant expenses, as well as any other expenses expected to be paid out of the Pension Plans’ trust. Finally, we have the Pension Plans’ actuary perform a tolerance test of the consultant’s equilibrium expected long-term rate of return. We use an expected long-term rate of return compatible with the actuary’s tolerance level.

The following table summarizes the Company’s target pension plan allocation for 2023:


Asset Category:			Target Allocations
Equity Securities			i 13.5%
Debt Securities			i 86.5%

Fair Value Measurements at

(in thousands)

Quoted Prices in Active Markets for Identical Assets

Significant Observable Inputs

Asset Category

Total

(Level 1)

(Level 2)

Common collective trusts:

Equities (a)

i 82,652

i 2,267

i 80,385

i 14

Debt securities (b)

i 387,979

i 1,168

i 386,811

i 66

Government debt securities (c)

i 117,397

i 178

i 117,219

i 20

Total common collective trusts

i 588,028

i 3,613

i 584,415

i 100

Cash and cash equivalents (d)

i 2,791

i —

Total pension plan assets

i 590,819

i 6,404

i 584,415

i 100

(a) This category represents investments that invest in equity securities of U.S. companies of any market capitalization and other investments (i.e.: futures, swaps, currency forwards) of foreign, emerging markets and seeks to provide long-term total return, which includes capital appreciation and income. The funds are valued using the net asset value method.

(b) This category represents investments that invest in high quality issues within the U.S. corporate bond markets and global high yield bonds and emerging markets debt denominated in local currency. The funds seek to provide current income and long-term capital preservation along with access to higher yielding, relatively liquid fixed income securities. The funds are valued using the net asset value method.

(c) This category represents investments that invest in U.S. treasury strips, U.S. government agency obligations, and U.S. treasury obligations. The funds seek investment returns over the long term and are valued using the net asset value method.

(d) This category represents an investment that seeks to maximize current income on cash reserves to the extent consistent with principal preservation and maintenance of liquidity from a portfolio of obligations of the U.S. Government, its agencies or municipalities, and related money market instruments. Principal preservation is a primary objective. The fund is valued at cost.

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Fair Value Measurements at

(in thousands)

Quoted Prices in Active Markets for Identical Assets

Significant Observable Inputs

Asset Category

Total

(Level 1)

(Level 2)

Common collective trusts:

Equities (a)

i 85,341

i 2,017

i 83,324

i 14

Debt securities (b)

i 400,291

i 1,254

i 399,037

i 66

Government debt securities (c)

i 122,704

i 420

i 122,284

i 20

Total common collective trusts

i 608,336

i 3,691

i 604,645

i 100

Cash and cash equivalents (d)

i 2,789

i —

Total pension plan assets

i 611,125

i 6,480

i 604,645

i 100

Pension Funding

We contributed $ i 0.1 million, $ i 0.4 million, and $ i 0.0 million to the Pension Plans in 2023, 2022 and 2021, respectively. Funding for the qualified Defined Benefit Pension Plan is based upon actuarially determined contributions that take into account the amount deductible for income tax purposes and the minimum contribution required under ERISA, as amended by the Pension Protection Act of 2006, as well as targeted funding levels necessary to meet certain thresholds.

From an ERISA funding perspective, AES Indiana’s funded target liability percentage was estimated to be i 98%. In general, AES Indiana must contribute the normal service cost earned by active participants during the plan year; however, this amount can be offset by any surplus or credit balance carried by the Pension Plan. The normal cost is expected to be approximately $ i 6.3 million in 2024 (including $ i 0.4 million for plan expenses), which is expected to be fully offset by the surplus amount. Each year thereafter, if the Pension Plans’ underfunding increases to more than the present value of the remaining annual installments, the excess is separately amortized over a seven-year period. AES Indiana does not expect to make an employer contribution for the calendar year 2024. AES Indiana’s funding policy for the Pension Plans is to contribute annually no less than the minimum required by applicable law, and no more than the maximum amount that can be deducted for federal income tax purposes.

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Benefit payments made from the Pension Plans for the years ended December 31, 2023, 2022 and 2021 were $ i 73.3 million, $ i 38.6 million and $ i 63.2 million, respectively. i Benefit payments, which reflect future service, are expected to be paid out of the Pension Plans as follows:


Year	Pension Benefits
	(In Thousands)
2024	$	i 37,997
2025	i 38,794
2026	i 39,665
2027	i 40,085
2028	i 41,477
2029 through 2033	i 200,574

9. i EQUITY AND CUMULATIVE PREFERRED STOCK

Cumulative Preferred Stock

On December 30, 2022 (the “Redemption Date”), AES Indiana redeemed all of its issued and outstanding preferred stock for $ i 60.1 million On the Redemption Date, the Preferred Stock of each series was redeemed with all applicable premiums, plus, in each case an amount equal to all accrued dividends payable with respect to such Preferred Stock to the Redemption Date. Dividends on the Preferred Stock ceased to accrue on the Redemption Date. Upon redemption, the Preferred Stock was no longer outstanding, and all rights of the holders thereof as shareholders of AES Indiana ceased to exist, except for the right to payment of the redemption price. AES Indiana recorded a charge of $ i 0.3 million on the redemption for the difference between the carrying value and redemption value of the preferred shares.

Prior to the redemption, AES Indiana had i five separate series of cumulative preferred stock. Holders of the preferred stock were entitled to receive dividends at rates per annum ranging from i 4.0% to i 5.65%. During the years ended December 31, 2023, 2022 and 2021, total preferred stock dividends declared were $ i 0.0 million, $ i 3.2 million, and $ i 3.2 million, respectively. Holders of preferred stock were entitled to i two votes per share for AES Indiana matters, and if four full quarterly dividends are in default on all shares of the preferred stock then outstanding, they were entitled to elect the smallest number of AES Indiana directors to constitute a majority of AES Indiana’s Board of Directors. Based on the preferred stockholders’ ability to elect a majority of AES Indiana’s Board of Directors in this circumstance, the redemption of the preferred shares was considered to be not solely within the control of the issuer and the preferred stock was considered temporary equity and presented in the mezzanine level of the audited consolidated balance sheets in accordance with the relevant accounting guidance for non-controlling interests and redeemable securities.

Paid In Capital

On December 12, 2022, AES U.S. Investments received equity capital contributions totaling $ i 208.3 million, of which $ i 177.0 million was contributed by AES U.S. Holdings, LLC and $ i 31.3 million was contributed by CDPQ. IPALCO then received equity capital contributions totaling $ i 253.0 million, of which $ i 208.3 million was contributed by AES U.S. Investments and $ i 44.7 million was contributed by CDPQ.

On December 13, 2021, AES U.S. Investments received equity capital contributions totaling $ i 226.5 million, of which $ i 192.5 million was contributed by AES U.S. Holdings, LLC and $ i 34.0 million was contributed by CDPQ. IPALCO then received equity capital contributions totaling $ i 275.0 million, of which $ i 226.5 million was contributed by AES U.S. Investments and $ i 48.5 million was contributed by CDPQ.

IPALCO then made the same investments in AES Indiana in 2021 and 2022. The proceeds are intended primarily for funding needs related to AES Indiana’s TDSIC and replacement generation projects. The capital contributions were made on a proportional share basis and, therefore, did not change CDPQ’s or AES’ ownership interests in IPALCO or AES U.S. Investments.

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Dividend Restrictions

AES Indiana’s mortgage and deed of trust and its amended articles of incorporation contain restrictions on AES Indiana’s ability to issue certain securities or pay cash dividends. So long as any of the several series of bonds of AES Indiana issued under its mortgage remains outstanding, and subject to certain exceptions, AES Indiana is restricted in the declaration and payment of dividends, or other distribution on shares of its capital stock of any class, or in the purchase or redemption of such shares, to the aggregate of its net income, as defined in the mortgage, after December 31, 1939. In addition, pursuant to AES Indiana’s articles, no dividends may be paid or accrued, and no other distribution may be made on AES Indiana’s common stock unless dividends on all outstanding shares of AES Indiana preferred stock have been paid or declared and set apart for payment. As of December 31, 2023, and as of the filing of this report, AES Indiana was in compliance with these restrictions. Additionally, all of AES Indiana's preferred stock was redeemed on December 30, 2022 (see "Cumulative Preferred Stock" above for further details).

AES Indiana is also restricted in its ability to pay dividends if it is in default under the terms of its Credit Agreement and $ i 300 million Term Loan Agreement, which could happen if AES Indiana fails to comply with certain covenants. These covenants, among other things, require AES Indiana to maintain a ratio of total debt to total capitalization not in excess of i 0.67 to i 1. As of December 31, 2023, and as of the filing of this report, AES Indiana was in compliance with all covenants and no event of default existed.

IPALCO’s Third Amended and Restated Articles of Incorporation contain provisions which state that IPALCO may not make a distribution to its shareholders or make a loan to any of its affiliates (other than its subsidiaries), unless: (a) there exists no event of default (as defined in the articles) and no such event of default would result from the making of the distribution or loan; and either (b)(i) at the time of, and/or as a result of, the distribution or loan, IPALCO’s leverage ratio does not exceed i 0.67 to i 1 and IPALCO’s interest coverage ratio is not less than i 2.50 to i 1 or, (b)(ii) if such ratios are not within the parameters, IPALCO’s senior long-term debt rating from one of the three major credit rating agencies is at least investment grade. As of December 31, 2023, and as of the filing of this report, IPALCO was in compliance with all covenants and no event of default existed.

During the years ended December 31, 2023, 2022 and 2021, IPALCO declared and paid distributions to its shareholders totaling $ i 104.3 million, $ i 102.0 million and $ i 131.5 million, respectively.

Equity Transactions with Noncontrolling Interests

The Hardy Hills Solar Project has been financed with a tax equity structure, in which a tax equity investor receives a portion of the economic attributes of the facility, including tax attributes, that vary over the life of the project. On December 1, 2023, the Class B Member and the Class A Member, entered into an Equity Capital Contribution Agreement, pursuant to which each member made certain capital contributions to Hardy Hills JV. The Class A member made total contributions of $ i 79.3 million through December 31, 2023. A noncontrolling interest was recorded by AES Indiana at the amount of cash contributed by the Class A Member.

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10. i COMMITMENTS AND CONTINGENCIES

Contractual Obligations and Commercial Commitments

We enter into various contractual obligations and other commercial commitments that may affect the liquidity of our operations. At December 31, 2023, these include:

Payments due in:

Total

Less Than 1 Year

1 – 3
Years

3 – 5
Years

More Than
5 Years

(In Millions)

Purchase obligations:

Coal, gas, purchased power and

related transportation

i 933.5

i 249.7

i 267.3

i 225.7

i 190.8

Other

i 409.1

i 355.0

i 32.8

i 20.2

i 1.1

Purchase obligations:

Purchase commitments for coal, gas, purchased power and related transportation:

Purchase orders and other contractual obligations:

Contingencies

Legal Matters

IPALCO and AES Indiana are involved in litigation arising in the normal course of business. We accrue for litigation and claims when it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. While the ultimate outcome of outstanding litigation cannot be predicted with certainty, management believes that final outcomes will not have a material adverse effect on IPALCO’s results of operations, financial condition and cash flows. Accruals for legal loss contingencies were not material as of December 31, 2023 and 2022.

Coal Ash Insurance Litigation

In August 2021, AES Indiana filed a civil action against various third-party insurance providers. The complaint seeks damages for breach of contract and a declaratory judgment declaring that such insurers must defend and indemnify AES Indiana under liability insurance policies issued between 1950 and the filing of the civil action against certain environmental liabilities arising from CCR at Harding Street, Petersburg and Eagle Valley. At this time, we cannot predict the outcome of this matter.

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Environmental Matters

We are subject to various federal, state, regional and local environmental protection and health and safety laws and regulations governing, among other things, the generation, storage, handling, use, disposal and transportation of regulated materials, including ash; the use and discharge of water used in generation boilers and for cooling purposes; the emission and discharge of hazardous and other materials, including GHGs, into the environment; climate change; and the health and safety of our employees. These laws and regulations often require a lengthy and complex process of obtaining and renewing permits and other governmental authorizations from federal, state and local agencies. Violation of these laws, regulations or permits can result in substantial fines, other sanctions, permit revocation and/or facility shutdowns. We cannot assure that we have been or will be at all times in full compliance with such laws, regulations and permits. Accruals for environmental contingencies were not material as of December 31, 2023 and 2022.

NSR and other CAA NOVs

In October 2009, AES Indiana received a NOV and Finding of Violation from the EPA pursuant to the CAA Section 113(a). The NOV alleged violations of the CAA at AES Indiana’s three primarily coal-fired electric generating facilities at the time, dating back to 1986. The alleged violations primarily pertain to the PSD and non-attainment NSR requirements under the CAA. In addition, on October 1, 2015, AES Indiana received a NOV from the EPA pursuant to CAA Section 113(a) alleging violations of the CAA, the Indiana SIP, and the Title V operating permit related to alleged particulate matter and opacity violations at AES Indiana Petersburg Unit 3. Also, on February 5, 2016, the EPA issued a NOV pursuant to CAA Section 113(a) alleging violations of PSD, non-attainment NSR and other CAA regulations, the Indiana SIP, and the Title V operating permit at Petersburg Generating Station. On August 31, 2020, AES Indiana reached a settlement with the EPA, the DOJ and IDEM resolving the purported violations of the CAA with respect to the coal-fired generation units at AES Indiana's Petersburg location. The settlement agreement, in the form of a proposed judicial consent decree was approved and entered by the U.S. District Court for the Southern District of Indiana on March 23, 2021, and includes, among other items, the following requirements: annual caps on NOx and SO2 emissions and more stringent emissions limits than AES Indiana's prior Title V air permit; payment of civil penalties totaling $ i 1.525 million (the payment of which was satisfied by AES Indiana in April 2021); a $ i 5 million environmental mitigation project consisting of the construction and operation of a new, non-emitting source of generation at the site; expenditure of $0.325 million on a state-only environmentally beneficial project to preserve local, ecologically-significant lands; and retirement of Units 1 and 2 prior to July 1, 2023 (which has occurred). AES Indiana previously had a contingent liability recorded related to these NSR and other CAA NOV matters.

11. i 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 $ i 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 $ i 11.7 million, $ i 9.5 million, and $ i 7.0 million in 2023, 2022 and 2021, respectively, and is recorded in “Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations. As of December 31, 2023 and 2022, we had prepaid approximately $ i 7.5 million and $ i 3.4 million, respectively, for coverage under these plans, which is recorded in "Prepayments and other current assets" on the accompanying Consolidated Balance Sheets.

AES Indiana participates in an agreement with Health and Welfare Benefit Plans LLC, an affiliate of AES, to participate in a group benefits program, including but not limited to, health, dental, vision and life benefits. Health and Welfare Benefit Plans LLC administers the financial aspects of the group insurance program, receives all premium payments from the participating affiliates, and makes all vendor payments. The cost of coverage under this program was approximately $ i 19.0 million, $ i 25.2 million, and $ i 23.7 million in 2023, 2022 and 2021, respectively, and

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is recorded in “Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations. We had no prepaids for coverage under this plan as of December 31, 2023 and 2022, respectively.

AES files federal and state income tax returns which consolidate IPALCO and its subsidiaries. Under a tax sharing agreement with AES, IPALCO is responsible for the income taxes associated with its own taxable income and records the provision for income taxes using a separate return method. IPALCO had a receivable balance under this agreement of $ i 36.5 million and $ i 18.0 million as of December 31, 2023 and 2022, respectively, which is recorded in “Taxes receivable” on the accompanying Consolidated Balance Sheets. See Note 7, "Income Taxes" for more information.

Long-term Compensation Plan

During 2023, 2022 and 2021, many of AES Indiana’s non-union employees received benefits under the AES Long-term Compensation Plan, a deferred compensation program. This type of plan is a common employee retention tool used in our industry. Benefits under this plan are granted in the form of performance units payable in cash and AES restricted stock units. Restricted stock units vest ratably over a three-year period. The performance units payable in cash vest at the end of the three-year performance period and are subject to certain AES performance criteria. Total deferred compensation expense recorded during 2023, 2022 and 2021 was $ i 0.3 million, $ i 0.2 million and $ i 0.2 million, respectively, and was included in “Operating expenses - Operation and maintenance” on IPALCO’s Consolidated Statements of Operations. The value of these benefits is being recognized over the 36 month vesting period and a portion is recorded as miscellaneous deferred credits with the remainder recorded as “Paid in capital” on IPALCO’s Consolidated Balance Sheets in accordance with ASC 718 “Compensation – Stock Compensation.”

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

Service Company

Total costs incurred by the Service Company on behalf of IPALCO were $ i 73.8 million, $ i 60.3 million and $ i 58.4 million during 2023, 2022 and 2021, respectively. Total costs incurred by IPALCO on behalf of the Service Company during 2023, 2022 and 2021 were $ i 11.9 million, $ i 10.0 million and $ i 10.4 million, respectively, which are included as a reduction to charges from the Service Company. These costs were included in “Operating expenses - Operation and maintenance” on IPALCO’s Consolidated Statements of Operations. IPALCO had a payable balance with the Service company of $ i 25.6 million and $ i 2.1 million as of December 31, 2023 and 2022, respectively, which is recorded in "Accounts payable" on the accompanying Consolidated Balance Sheets.

Other

In the second quarter of 2023, AES Indiana engaged a vendor that is a related party through a competitive RFP process as part of its replacement capacity resource construction projects. AES Indiana had payments of $ i 223.3 million to this vendor during the year ended December 31, 2023, which are included in "Other non-current assets" on the accompanying Consolidated Balance Sheets. Transactions with various other related parties were $ i 7.4 million, $ i 5.7 million and $ i 4.3 million during 2023, 2022 and 2021, respectively. These expenses were primarily recorded in “Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations.

12. i BUSINESS SEGMENTS

IPALCO manages its business through one reportable operating segment, the Utility segment. The primary segment performance measure is income / (loss) from continuing operations before income tax as management has concluded that this measure best reflects the underlying business performance of IPALCO and is the most relevant measure considered in IPALCO's internal evaluation of the financial performance of its segment. The Utility segment is comprised of AES Indiana, a vertically integrated electric utility, with all other nonutility business activities aggregated separately. See Note 1, "Overview and Summary of Significant Accounting Policies" for further information on AES Indiana. The “Other” nonutility category primarily includes the 2024 IPALCO Notes and 2030 IPALCO Notes and related interest expense, balance associated with IPALCO's interest rate hedges, cash and other immaterial balances. The accounting policies of the identified segment are consistent with those policies and procedures described in the summary of significant accounting policies.

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The following table provides information about IPALCO’s business segments (in thousands):


	2023						2022						2021
	Utility		Other		Total		Utility		Other		Total		Utility		Other		Total
Revenue	$	i 1,649,917	$	—	$	i 1,649,917	$	i 1,791,711	$	—	$	i 1,791,711	$	i 1,426,132	$	—	$	i 1,426,132
Depreciation and amortization	$	i 287,863	$	i —	$	i 287,863	$	i 266,504	$	i —	$	i 266,504	$	i 256,085	$	i —	$	i 256,085
Interest expense	$	i 99,051	$	i 43,875	$	i 142,926	$	i 87,428	$	i 43,804	$	i 131,232	$	i 84,256	$	i 41,370	$	i 125,626
Income/(loss) before income tax	$	i 115,763	$	( i 44,021)	$	i 71,742	$	i 162,862	$	( i 44,377)	$	i 118,485	$	i 189,548	$	( i 41,425)	$	i 148,123
Capital expenditures(1)	$	i 902,705	$	i —	$	i 902,705	$	i 496,510	$	i —	$	i 496,510	$	i 291,546	$	i —	$	i 291,546
(1) Capital expenditures includes $ i 0 thousand, $ i 0 thousand and $ i 36 thousand of payments for financed capital expenditures in 2023, 2022 and 2021, respectively.

	As of December 31, 2023						As of December 31, 2022						As of December 31, 2021
Total assets	$	i 6,129,581	$	i 51,942	$	i 6,181,523	$	i 5,559,977	$	i 29,237	$	i 5,589,214	$	i 5,222,987	$	i 16,780	$	i 5,239,767

13. i REVENUE

Revenue is primarily earned from retail and wholesale electricity sales and electricity transmission and distribution delivery services. Revenue is recognized upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Revenue is recorded net of any taxes assessed on and collected from customers, which are remitted to the governmental authorities.

Retail revenue - AES Indiana energy sales to utility customers are based on the reading of meters at the customer’s location that occurs on a systematic basis throughout the month. AES Indiana sells electricity directly to end-users, such as homes and businesses, and bills customers directly. Retail revenue have a single performance obligation, as the promise to transfer energy and other distribution and/or transmission services are not separately identifiable from other promises in the contracts and, therefore, are not distinct. Additionally, as the performance obligation is satisfied over time as energy is delivered, and the same method is used to measure progress, the performance obligation meets the criteria to be considered a series.

In exchange for the exclusive right to sell or distribute electricity in our service area, AES Indiana is subject to rate regulation by federal and state regulators. This regulation sets the framework for the prices (“tariffs”) that AES Indiana is allowed to charge customers for electric services. Since tariffs are approved by the regulator, the price that AES Indiana has the right to bill corresponds directly with the value to the customer of AES Indiana’s performance completed in each period. Therefore, revenue under these contracts is recognized using an output method measured by the MWhs delivered each month at the approved tariff. Customer payments are typically due on a monthly basis.

Wholesale revenue - Power produced at the generation stations in excess of our retail load is sold into the MISO market. Such sales are made at either the day-ahead or real-time hourly market price, and these sales are classified as wholesale revenue. We sell to and purchase power from MISO, and such sales and purchases are settled and accounted for on a net hourly basis.

In the MISO market, wholesale revenue is recorded at the spot price based on the quantities of MWh delivered in each hour during each month. As a member of MISO, we are obligated to declare the availability of our energy production into the wholesale energy market, but we are not obligated to commit our previously declared availability. As such, contract terms end as the energy for each day is delivered to the market in the case of the day-ahead market and for each hour in the case of the real-time market.

Miscellaneous revenue - Miscellaneous revenue is mainly comprised of MISO transmission revenue and capacity revenue. MISO transmission revenue is earned when AES Indiana’s power lines are used in transmission of energy by power producers other than AES Indiana. As AES Indiana owns and operates transmission lines in central and southern Indiana, demand charges collected from network customers by MISO are allocated to the appropriate transmission owners (including AES Indiana) and recognized as transmission revenue. Capacity revenue is also included in miscellaneous revenue, and represent compensation received from MISO for making installed generation capacity available to satisfy system integrity and reliability requirements through the annual MISO capacity auction. Capacity, which is a stand-ready obligation to deliver energy when called upon by the RTO, is measured using MWs.

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Transmission and capacity revenue each have a single performance obligation, as they each represent a distinct service or good. Additionally, as these performance obligations are satisfied over time and the same method is used to measure progress, the performance obligations meet the criteria to be considered a series. For transmission revenue, the price that the transmission operator has the right to bill corresponds directly with the value to the customer of AES Indiana’s performance completed in each period as the price paid is the transmission operator's allocation of the tariff rate (as approved by the regulator) charged to network participants. For capacity revenue, the capacity price that clears at the auction is fixed and AES Indiana is compensated based on the cleared MWs and cleared price.

AES Indiana i ’s revenue from contracts with customers was $ i 1,616.5 million, $ i 1,760.0 million and $ i 1,389.2 million for the years ended December 31, 2023 / , 2022 and 2021, respectively. The following table presents our revenue from contracts with customers and other revenue (in thousands):


	For the Years Ended December 31,
	2023		2022		2021
Retail Revenue
Retail revenue from contracts with customers:
Residential	$	i 660,559	$	i 688,487	$	i 595,692
Small commercial and industrial	i 241,800		i 247,655		i 211,997
Large commercial and industrial	i 619,899		i 625,351		i 518,069
Public lighting	i 9,767		i 9,832		i 8,888
Other (1)	i 14,016		i 17,845		i 16,785
Total retail revenue from contracts with customers	i 1,546,041		i 1,589,170		i 1,351,431
Alternative revenue programs	i 30,414		i 29,171		i 35,248
Wholesale Revenue
Wholesale revenue from contracts with customers	i 56,557		i 148,517		i 25,059
Miscellaneous Revenue
Capacity revenue	i 8,210		i 11,750		i 734
Transmission and other revenue	i 5,654		i 10,534		i 11,480
Total miscellaneous revenue from contracts with customers	i 13,864		i 22,284		i 12,214
Other miscellaneous revenue (2)	i 3,041		i 2,569		i 2,180
Total Revenue	$	i 1,649,917	$	i 1,791,711	$	i 1,426,132

(1) Other retail revenue from contracts with customers includes miscellaneous charges to customers, including reconnection and late fee charges.

(2) Other miscellaneous revenue includes lease and other miscellaneous revenue not accounted for under ASC 606.

The balances of receivables from contracts with customers were $ i 218.8 million and $ i 198.3 million as of December 31, 2023 and 2022, respectively. Payment terms for all receivables from contracts with customers typically do not extend beyond 30 days, unless a customer qualifies for payment extension.

The Company has elected to apply the optional disclosure exemptions under ASC 606. Therefore, the Company has not included disclosure pertaining to revenue expected to be recognized in any future year related to remaining performance obligations, as we exclude contracts with an original length of one year or less, contracts for which we recognize revenue based on the amount we have the right to invoice for services performed, and contracts with variable consideration allocated entirely to a wholly unsatisfied performance obligation when the consideration relates specifically to our efforts to satisfy the performance obligation and depicts the amount to which we expect to be entitled.

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14. i LEASES

LESSEE

The Company is the lessee under financing leases primarily for land. Right-of-use assets are long-term by nature. i 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

Assets

Right-of-use assets — finance leases

Other non-current assets

i 16,357

i 15,819

Liabilities

Finance lease liabilities (noncurrent)

Long-term debt

i 17,769

i 16,361

Total finance lease liabilities

i 17,769

i 16,361

The following table summarizes supplemental balance sheet information related to leases as of the periods indicated:

Lease Term and Discount Rate

Weighted-average remaining lease term — finance leases

i 35 years

i 36 years

Weighted-average discount rate — finance leases

i 5.30

i 5.650

The following table summarizes the components of lease expense recognized in "Operating Costs and Expenses" on the accompanying Consolidated Statements of Operations for the years ended December 31, 2023, 2022 and 2021, respectively (in thousands):


	For the Year Ended December 31,
Components of Lease Cost	2023		2022		2021

Finance lease cost:
Amortization of right-of-use assets	$	i 445	$	i 542	$	i —
Interest on lease liabilities	i 933		i 782		i —



Total lease cost	$	i 1,378	$	i 1,324	$	i —

Operating cash outflows from finance leases were $ i 0.6 million, $ i 0.3 million and $ i 0.0 million for the years ended December 31, 2023, 2022 and 2021, respectively.

The following table shows the future lease payments under finance leases together with the present value of the net lease payments as of December 31, 2023 for 2024 through 2028 and thereafter (in thousands):


	Finance Leases
2024	$	i 891
2025	i 909
2026	i 927
2027	i 945
2028	i 965
Thereafter	i 39,958
Total	$	i 44,595
Less: Imputed interest	( i 26,826)
Present value of lease payments	$	i 17,769

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LESSOR

The Company is the lessor under operating leases for land, office space and operating equipment. Lease receipts from such contracts are recognized as operating lease revenue on a straight-line basis over the lease term whereas contingent rentals are recognized when earned.

The following table presents lease revenue from operating leases in which the Company is the lessor for the periods indicated (in thousands):


	For the Year Ended December 31,
	2023		2022		2021
Total lease revenue	$	i 1,537	$	i 1,134	$	i 1,439

The following table presents the underlying gross assets and accumulated depreciation of operating leases included in Property, plant and equipment, net for the periods indicated (in thousands):

Property, Plant and Equipment, Net

Gross assets

i 4,341

i 4,334

Less: Accumulated depreciation

( i 1,222)

( i 1,060)

Net assets

i 3,119

i 3,274

The option to extend or terminate a lease is based on customary early termination provisions in the contract.

The following table shows the future minimum lease receipts through 2028 and thereafter (in thousands):


	Operating Leases
2024	$	i 544
2025	i 553
2026	i 554
2027	i 554
2028	i 354
Thereafter	i 891
Total	$	i 3,450

111

Report of Independent Registered Public Accounting Firm

To the Shareholders and the Board of Directors of Indianapolis Power & Light Company

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Indianapolis Power & Light Company and subsidiaries, d/b/a AES Indiana, (the Company) as of December 31, 2023 and 2022, the related consolidated statements of operations, changes in equity, and cash flows for each of the three years in the period ended December 31, 2023, and the related notes and financial statement schedule listed in the Index at Item 15 (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023 in conformity with U.S. generally accepted accounting principles.

Basis for Opinion

Critical Audit Matter

112


			Regulatory Accounting
			Regulatory Accounting
Description of the Matter			As described in Note 2 to the consolidated financial statements, the Company applies the provisions of FASB Accounting Standards Codification 980 “Regulated Operations”, which gives recognition to the ratemaking and accounting practices of the Indiana Utility Regulatory Commission and the Federal Energy Regulatory Commission. Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in customer rates. Regulatory assets can also represent performance incentives permitted by the regulator. Regulatory liabilities generally represent obligations to provide refunds or future rate reductions to customers for previous overcollections or the deferral of revenues collected for costs that the Company expects to incur in the future. Accounting for the economics of rate regulation affects multiple consolidated financial statement line items, including property, plant, and equipment; regulatory assets and liabilities; revenues; and depreciation expense, and related disclosures in the Company’s consolidated financial statements.
			Auditing the Company’s regulatory accounting was complex due to significant judgments made by management to support its assertions about the impact of future regulatory orders on the consolidated financial statements. In particular, there is subjectivity involved in assessing the impact of current and future regulatory orders on events that have occurred through December 31, 2023, judgment required to evaluate the relevance and reliability of audit evidence to support impacted account balances and disclosures, and judgments involved in assessing the probability of recovery in future rates of incurred costs or refunds to customers. These assumptions have a significant effect on the consolidated financial statements and related disclosures.
How We Addressed the Matter in Our Audit			To evaluate the Company’s significant judgments in accounting for regulatory assets and liabilities, our audit procedures included, among others, reviewing relevant regulatory orders, statutes and interpretations; filings made by intervening parties; and other publicly available information, to assess the likelihood of recovery of regulatory assets in future rates or of a refund or future reduction in rates for regulatory liabilities based on precedents for the treatment of similar costs under similar circumstances. We evaluated the Company’s assertions regarding the probability of recovery of regulatory assets or refund or future reduction in rates for regulatory liabilities, to assess the Company’s assertion that amounts are probable of recovery or of a refund or future reduction in rates.

113


			Asset Retirement Obligations
			Regulatory Accounting
Description of the Matter			At December 31, 2023, the Company’s asset retirement obligations (“ARO”) totaled $249.9 million. As described in Note 3 to the consolidated financial statements, the Company’s ARO liabilities relate primarily to environmental issues involving asbestos-containing materials, ash ponds, landfills and miscellaneous contaminants associated with its generating plants, transmission system and distribution system. The Company recorded adjustments to its ARO liabilities of $30.0 million during 2023. ARO liabilities incurred in 2023 primarily related to FGD residual water disposal. ARO liabilities were revised in 2023 primarily to reflect revisions to cash flow estimates due to increases to estimated ash pond closure costs.
			Auditing the Company’s ARO liabilities was complex and highly judgmental due to the significant estimation required by management to determine the estimated cost estimates of the legal obligations associated with the Company’s generating plants, transmission system and distribution system. In particular, the estimate was sensitive to significant assumptions including the scope and method of decommissioning and timing of related cash flows.
How We Addressed the Matter in Our Audit			To test the Company’s ARO liability estimates, our audit procedures included evaluating the appropriateness of the Company’s methodology, interviewing members of the Company’s environmental staff and testing significant assumptions and inputs including the timing of activities, projected closure dates and the method of decommissioning. We involved our specialists in our assessment of the Company’s ARO liabilities including reviewing the Company’s methodology, evaluating the reasonableness of the cost estimates and assumptions, and assessing completeness of the estimates with respect to regulatory requirements.

/s/ i Ernst & Young LLP

We have served as the Company’s auditor since 2008.

i Indianapolis, Indiana

114

AES INDIANA and SUBSIDIARIES

Consolidated Statements of Operations

For the Years Ended December 31, 2023, 2022 and 2021

2023

2022

2021

(In Thousands)

REVENUE

i 1,649,917

i 1,791,711

i 1,426,132

OPERATING COSTS AND EXPENSES:

Fuel

i 494,000

i 568,676

i 255,817

Power purchased

i 159,908

i 199,860

i 175,025

Operation and maintenance

i 477,497

i 493,454

i 449,317

Depreciation and amortization

i 287,863

i 266,504

i 256,085

Taxes other than income taxes

i 24,865

i 33,048

i 44,419

Other, net

( i 361)

( i 3,201)

( i 5,630)

Total operating costs and expenses

i 1,443,772

i 1,558,341

i 1,175,033

OPERATING INCOME

i 206,145

i 233,370

i 251,099

OTHER INCOME / (EXPENSE), NET:

Allowance for equity funds used during construction

i 9,315

i 4,784

i 5,412

Interest expense

( i 99,051)

( i 87,428)

( i 84,257)

Other income, net

( i 646)

i 12,136

i 17,294

Total other expense, net

( i 90,382)

( i 70,508)

( i 61,551)

INCOME BEFORE INCOME TAX

i 115,763

i 162,862

i 189,548

Income tax expense

i 25,666

i 32,887

i 39,305

NET INCOME

i 90,097

i 129,975

i 150,243

Dividends on and redemption of preferred stock

i —

i 3,509

i 3,213

Net loss attributable to noncontrolling interests

( i 26,093)

—

NET INCOME ATTRIBUTABLE TO COMMON STOCK

i 116,190

i 126,466

i 147,030

See Notes to Consolidated Financial Statements.

115

AES INDIANA and SUBSIDIARIES

Consolidated Balance Sheets

(In Thousands)

ASSETS

CURRENT ASSETS:

Cash and cash equivalents

i 25,767

i 199,103

Accounts receivable, net of allowance for credit losses of $ i 2,283 and $ i 1,117, respectively

i 233,970

i 216,572

Inventories

i 143,590

i 123,608

Regulatory assets, current

i 89,419

i 119,723

Taxes receivable

i 5,140

i 6,682

Prepayments and other current assets

i 27,741

i 27,422

Total current assets

i 525,627

i 693,110

NON-CURRENT ASSETS:

Property, plant and equipment

i 7,082,443

i 6,982,314

Less: Accumulated depreciation

i 2,954,555

i 3,243,968

i 4,127,888

i 3,738,346

Construction work in progress

i 359,014

i 294,985

Total net property, plant and equipment

i 4,486,902

i 4,033,331

OTHER NON-CURRENT ASSETS:

Intangible assets - net

i 235,656

i 138,978

Regulatory assets, non-current

i 541,784

i 593,939

Pension plan assets

i 41,172

i 33,611

Other non-current assets

i 298,439

i 67,008

Total other non-current assets

i 1,117,051

i 833,536

TOTAL ASSETS

i 6,129,580

i 5,559,977

LIABILITIES AND SHAREHOLDER'S EQUITY

CURRENT LIABILITIES:

Short-term debt and current portion of long-term debt (see Note 6)

i 494,685

i —

Accounts payable

i 292,835

i 189,806

Accrued taxes

i 22,580

i 22,474

Accrued interest

i 25,245

i 25,054

Customer deposits

i 29,308

i 35,097

Regulatory liabilities, current

i 23,371

i 23,348

Accrued and other current liabilities

i 34,748

i 26,214

Total current liabilities

i 922,772

i 321,993

NON-CURRENT LIABILITIES:

Long-term debt (see Notes 6 and 14)

i 2,106,146

i 2,143,147

Deferred income tax liabilities

i 342,557

i 305,107

Regulatory liabilities, non-current

i 527,224

i 612,585

Accrued other postretirement benefits

i 2,776

i 3,085

Asset retirement obligations

i 249,930

i 218,729

Other non-current liabilities

i 5,129

i 11,621

Total non-current liabilities

i 3,233,762

i 3,294,274

Total liabilities

i 4,156,534

i 3,616,267

COMMITMENTS AND CONTINGENCIES (see Note 10)

EQUITY:

Common shareholder's equity

Common stock (no par value, i 20,000,000 shares authorized; i 17,206,630 shares issued and outstanding at December 31, 2023 and 2022)

i 324,537

Paid in capital

i 1,193,199

i 1,193,107

Retained earnings

i 402,056

i 426,066

Total common shareholder's equity

i 1,919,792

i 1,943,710

Noncontrolling interests

i 53,254

i —

Total equity

i 1,973,046

i 1,943,710

TOTAL LIABILITIES AND EQUITY

i 6,129,580

i 5,559,977

See Notes to Consolidated Financial Statements.

116

AES INDIANA and SUBSIDIARIES

Consolidated Statements of Cash Flows

For the Years Ended December 31, 2023, 2022 and 2021

2023

2022

2021

(In Thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:

Net income

i 90,097

i 129,975

i 150,243

Adjustments to reconcile net income to net cash provided by operating activities:

Depreciation and amortization

i 287,863

i 266,504

i 256,085

Amortization of deferred financing costs and debt discounts

i 2,406

i 2,511

i 2,536

Deferred income taxes and investment tax credit adjustments - net

i 23,582

( i 6,584)

( i 7,373)

Allowance for equity funds used during construction

( i 9,315)

( i 4,784)

( i 5,412)

Gain on acquisition

i —

( i 5,630)

Change in certain assets and liabilities:

Accounts receivable

( i 17,398)

( i 37,391)

( i 13,746)

Inventories

( i 30,171)

( i 47,489)

( i 12,017)

Prepayments and other current assets

( i 6,476)

i 19,016

( i 4,556)

Accounts payable

i 47,016

i 32,232

i 21,502

Accrued and other current liabilities

i 2,790

i 6,532

( i 13,017)

Accrued taxes payable/receivable

i 1,647

( i 3,452)

( i 2,302)

Accrued interest

i 192

i 2,813

( i 1,099)

Pension and other postretirement benefit assets and liabilities

i 1,625

( i 8,727)

( i 16,592)

Current and non-current regulatory assets and liabilities

i 54,358

i 38,863

( i 104,759)

Other non-current liabilities

( i 16,663)

( i 21,717)

i 5,566

Other - net

( i 4,074)

i 4,967

( i 1,645)

Net cash provided by operating activities

i 427,479

i 373,269

i 247,784

CASH FLOWS FROM INVESTING ACTIVITIES:

Capital expenditures

( i 902,705)

( i 496,510)

( i 291,510)

Project development costs

( i 4,462)

( i 3,910)

( i 1,304)

Cost of removal payments

( i 45,595)

( i 23,948)

( i 35,260)

Insurance proceeds

i 4,900

i —

Loan repayments from parent

i —

i 6,110

Purchase of intangibles

( i 44,650)

i —

( i 26,261)

Other

( i 361)

( i 719)

( i 14,380)

Net cash used in investing activities

( i 992,873)

( i 525,087)

( i 362,605)

CASH FLOWS FROM FINANCING ACTIVITIES:

Borrowings from revolving credit facilities

i 435,000

i 300,000

i 320,000

Repayments from revolving credit facilities

( i 280,000)

( i 360,000)

( i 335,000)

Short-term borrowings

i 300,000

i 200,000

i —

Repayment of short-term borrowings

i —

( i 200,000)

i —

Long-term borrowings

i —

i 350,000

i 95,000

Retirement of long-term debt

i —

( i 95,000)

Dividends on common stock

( i 140,200)

( i 127,200)

( i 155,700)

Dividends on preferred stock

i —

( i 3,213)

Payments of deferred financings costs and discounts

( i 350)

( i 4,309)

( i 1,325)

Purchase of preferred stock

i —

( i 60,080)

i —

Equity contributions from IPALCO

i —

i 253,000

i 275,000

Sales to noncontrolling interests

i 77,921

i —

Other

( i 313)

( i 33)

( i 131)

Net cash provided by financing activities

i 392,058

i 348,165

i 99,631

Net change in cash, cash equivalents and restricted cash

( i 173,336)

i 196,347

( i 15,190)

Cash, cash equivalents and restricted cash at beginning of year

i 199,108

i 2,761

i 17,951

Cash, cash equivalents and restricted cash at end of year

i 25,772

i 199,108

i 2,761

SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:

Cash paid during the period for:

Interest (net of amount capitalized)

i 93,544

i 80,104

i 82,880

Income taxes

i —

i 39,500

i 40,800

Non-cash investing activities:

Accruals for capital expenditures

i 124,626

i 66,949

i 81,325

Recognition and changes to right-of-use assets - finance leases

i 983

( i 3,402)

i 19,763

Non-cash financing activities:

Recognition and changes to financing lease liabilities

( i 1,408)

( i 3,402)

i 19,763

See Notes to Consolidated Financial Statements.

117

AES INDIANA and SUBSIDIARIES

Consolidated Statements of Changes in Equity

For the Years Ended December 31, 2023, 2022 and 2021

Common Shareholder's Equity

Common Stock

(in Thousands)

Outstanding Shares

Amount

Paid in Capital

Retained Earnings

Total Common Shareholder's Equity

Cumulative Preferred Stock

Noncontrolling Interests

Balance at January 1, 2021

i 17,207

i 324,537

i 664,886

i 435,470

i 1,424,893

i 59,784

—

Net income

—

i 150,243

i 3,213

—

Preferred stock dividends

—

( i 3,213)

—

Cash dividends declared on common stock

—

( i 155,700)

—

Contributions from IPALCO

—

i 275,000

—

i 275,000

—

Other

—

i 107

—

i 107

—

Balance at December 31, 2021

i 17,207

i 324,537

i 939,993

i 426,800

i 1,691,330

i 59,784

—

Net income

—

i 129,975

i 3,213

—

Preferred stock dividends

—

( i 3,213)

—

Redemption of preferred stock

—

( i 296)

( i 59,784)

—

Cash dividends declared on common stock

—

( i 127,200)

—

Contributions from IPALCO

—

i 253,000

—

i 253,000

—

Other

—

i 114

—

i 114

—

Balance at December 31, 2022

i 17,207

i 324,537

i 1,193,107

i 426,066

i 1,943,710

i —

—

Net income / (loss)

—

i 116,190

i —

( i 26,093)

Cash dividends declared on common stock

—

( i 140,200)

—

Sales to noncontrolling interests

—

i —

—

i —

—

i 79,347

Other

—

i 92

—

i 92

—

Balance at December 31, 2023

i 17,207

i 324,537

i 1,193,199

i 402,056

i 1,919,792

i —

i 53,254

See Notes to Consolidated Financial Statements.

118

AES INDIANA and SUBSIDIARIES

Notes to Consolidated Financial Statements

For the Years Ended December 31, 2023, 2022 and 2021

1. OVERVIEW AND i 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 ( i 85%) and CDPQ ( i 15%). AES Indiana is engaged primarily in generating, transmitting, distributing and selling of electric energy to approximately i 523,000 retail customers in the city of Indianapolis and neighboring cities, towns and communities, and adjacent rural areas all within the state of Indiana. AES Indiana has an exclusive right to provide electric service to those customers.

AES Indiana owns and operates i four generating stations all within the state of Indiana. The first station, Petersburg, is coal-fired, and AES Indiana retired 230 MW Petersburg Unit 1 in May 2021 and 415 MW Petersburg Unit 2 in June 2023, which resulted in i 630 MW of total retired economic capacity at this station. AES Indiana plans to convert the remaining two coal units at Petersburg to natural gas (for further discussion, see Note 2, "Regulatory Matters - IRP Filings and Replacement Generation 2022 IRP"). The second station, Harding Street, consists of three natural gas-fired boilers and steam turbines and uses natural gas and fuel oil to power five combustion turbines. In addition, AES Indiana operates a i 20 MW battery energy storage unit at this location, which provides frequency response. The third station, Eagle Valley, is a CCGT natural gas plant. The fourth station, Georgetown, is a peaking station that uses natural gas to power combustion turbines. As of December 31, 2023, AES Indiana’s net electric generation capacity for winter is i 3,070 MW and net summer capacity is i 2,925 MW.

In June 2023, AES Indiana, through a wholly-owned subsidiary, executed an agreement for the construction of the i 200 MW ( i 800 MWh) Pike County BESS Project to be developed at the AES Indiana Petersburg Plant site in Pike County, Indiana, subject to IURC approval, which was received in January 2024. The Pike County BESS Project is expected to be completed in 2024.

For further discussion about AES Indiana's plans for wind, solar, and battery energy storage projects, please see Note 2, "Regulatory Matters - IRP Filings and Replacement Generation."

Principles of Consolidation

AES Indiana’s consolidated financial statements are prepared in accordance with GAAP and in conjunction with the rules and regulations of the SEC. The consolidated financial statements include the accounts of AES Indiana and its wholly owned subsidiaries. Furthermore, VIEs in which the Company has an ownership interest and is the primary beneficiary, thus controlling the VIE, as described below, have been consolidated. All intercompany items have been eliminated in consolidation. Certain costs for shared resources amongst AES Indiana and IPALCO, such as labor and benefits, are allocated to each entity based on allocation methodologies that management believes to be reasonable. We have evaluated subsequent events through the date this report is issued.

If AES Indiana enters into transactions impacting equity interests in its affiliates, AES Indiana must determine whether the transaction impacts the Company's consolidation conclusion by first determining whether the transaction should be evaluated under the variable interest model or the voting model. In determining which

119

consolidation model applies to the transaction, AES Indiana is required to make judgments about how the entity operates, the most significant of which are whether (i) the entity has sufficient equity to finance its activities, (ii) the equity holders, as a group, have the characteristics of a controlling financial interest, and (iii) whether the entity has non-substantive voting rights. If the entity is determined to be a variable interest entity and AES Indiana is determined to have power and benefits, the entity will be consolidated by AES Indiana.

Noncontrolling Interests

Allocation of Earnings

Hardy Hills JV is subject to profit-sharing arrangements where the allocation of earnings, cash distributions, and tax benefits are not based on fixed ownership percentages. This arrangement exists to designate different allocations of value among the investors, where the allocations change in form or percentage over the life of the partnership. AES Indiana uses the HLBV method when it is a reasonable approximation of the profit-sharing arrangement. The HLBV method calculates the proceeds that would be attributable to each partner based on the liquidation provisions of the respective operating partnership agreement if the partnership was to be liquidated at book value at the balance sheet date. Each partner’s share of income in the period is equal to the change in the amount of net equity they are legally able to claim based on a hypothetical liquidation of the entity at the end of a reporting period compared to the beginning of that period, adjusted for any capital transactions (for further discussion about the Equity Capital Contribution Agreement, see Note 2, "Regulatory Matters - IRP Filings and Replacement Generation").

The HLBV method is used to calculate the earnings attributable to noncontrolling interest when the business is consolidated by AES Indiana. In the early months of operations of a renewable generation facility where HLBV results in a significant decrease in the hypothetical liquidation proceeds attributable to the tax equity investor due to the recognition of investment tax credits ("ITCs") or other adjustments as required by the U.S. Internal Revenue Code, the Company records the impact (sometimes referred to as the ‘Day one gain’) to income in the same period.

Use of Management Estimates

Reclassifications

Certain immaterial amounts from prior periods have been reclassified to conform to the current year presentation.

Cash and Cash Equivalents

Cash and cash equivalents are stated at cost, which approximates fair value. All highly liquid short-term investments with original maturities of three months or less are considered cash equivalents.

Restricted Cash

Restricted cash includes cash which is restricted as to withdrawal or usage. The nature of the restrictions includes restrictions imposed by agreements related to deposits held as collateral.

120

As of December 31,

2023

2022

(In Thousands)

Cash, cash equivalents and restricted cash

Cash and cash equivalents

i 25,767

i 199,103

Restricted cash (included in Prepayments and other current assets)

i 5

Total cash, cash equivalents and restricted cash

i 25,772

i 199,108

Accounts Receivable and Allowance for Credit Losses

The following table summarizes our accounts receivable balances at December 31:

As of December 31,

2023

2022

(In Thousands)

Accounts receivable, net

Customer receivables

i 125,715

i 125,540

Unbilled revenue

i 91,463

i 74,488

Amounts due from related parties

i 5,227

i 288

Other

i 13,848

i 17,373

Allowance for credit losses

( i 2,283)

( i 1,117)

Total accounts receivable, net

i 233,970

i 216,572

/ /

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

For the Years Ended December 31,

2023

2022

(In Thousands)

Allowance for credit losses:

Beginning balance

i 1,117

i 647

Current period provision

i 7,413

i 5,851

Write-offs charged against allowance

( i 7,764)

( i 7,008)

Recoveries collected

i 1,517

i 1,627

Ending Balance

i 2,283

i 1,117

The allowance for credit losses primarily relates to utility customer receivables, including unbilled amounts. Expected credit loss estimates are developed by disaggregating customers into those with similar credit risk characteristics and using historical credit loss experience. In addition, we also consider how current and future economic conditions are expected to impact collectability, as applicable, of our receivable balance. Amounts are written off when reasonable collections efforts have been exhausted.

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Inventories

AES Indiana maintains coal, fuel oil, natural gas, materials and supplies inventories for use in the production of electricity. These inventories are accounted for at the lower of cost or net realizable value, using the average cost. i The following table summarizes our inventories balances at December 31:

As of December 31,

2023

2022

(In Thousands)

Inventories

Fuel

i 77,198

i 60,497

Materials and supplies, net

i 66,392

i 63,111

Total inventories

i 143,590

i 123,608

Regulatory Accounting

Property, Plant and Equipment

AFUDC


	2023		2022		2021
	(In Thousands)
AFUDC equity	$	i 9,315	$	i 4,784	$	i 5,412
AFUDC debt	$	i 13,739	$	i 8,215	$	i 4,815

Impairment of Long-lived Assets

GAAP requires that AES Indiana test long-lived assets for impairment when indicators of impairment exist. If an asset is deemed to be impaired, AES Indiana is required to write down the asset to its fair value with a charge to

122

current earnings. The net book value of AES Indiana’s property, plant, and equipment was $ i 4.5 billion and $ i 4.0 billion as of December 31, 2023 and 2022, respectively. As of December 31, 2023 and 2022, AES Indiana had $ i 259.9 million and $ i 287.5 million, respectively, of long-term regulatory assets associated with Petersburg Unit 1 and 2 retirement costs (for further discussion, see Note 2, “Regulatory Matters - IRP Filings and Replacement Generation” and Note 3, "Property, Plant and Equipment"). AES Indiana does not believe any of these assets are currently impaired. In making this assessment, AES Indiana considers such factors as: the overall condition and generating and distribution capacity of the assets; the expected ability to recover additional expenditures in the assets; the anticipated demand and relative pricing of retail electricity in its service territory and wholesale electricity in the region; and the cost of fuel.

Intangible Assets


			December 31,
$ in thousands	Weighted average amortization periods (in years)		2023		2022
Capitalized software	i 8		$	i 261,872	$	i 205,910
Project development intangible assets	i 28		i 84,097		i 39,455
Other	Various		i 797		i 797
Less: Accumulated amortization			( i 111,110)		( i 107,184)
Intangible assets - net			$	i 235,656	$	i 138,978

	For the Years Ended December 31,
	2023		2022		2021
Amortization expense	$	i 14,570	$	i 10,122	$	i 11,241

Estimated future amortization
Years ending December 31,
2024					$	i 20,764
2025					i 20,764
2026					i 22,550
2027					i 22,550
2028					i 22,550
Total					$	i 109,178

Implementation Costs Related to Software as a Service

AES Indiana has recorded prepayments for implementation costs related to software as a service in support of utility customer services of $ i 7.1 million and $ i 8.2 million as of December 31, 2023 and 2022, respectively, which are recorded within "Other non-current assets" on the accompanying Consolidated Balance Sheets.

Debt Issuance Costs

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

123

the case during the periods covered by this report. Accruals for loss contingencies were not material as of December 31, 2023 and 2022. See Note 10, "Commitments and Contingencies - Contingencies" for additional information.

Concentrations of Risk

Substantially all of AES Indiana’s customers are located within the Indianapolis area. Approximately i 68% of AES Indiana’s employees are covered by collective bargaining agreements in two bargaining units: a physical unit and a clerical-technical unit. AES Indiana’s contract with the physical unit expires on December 4, 2024, and the contract with the clerical-technical unit expires February 12, 2026. Additionally, AES Indiana has long-term coal contracts with one supplier, and substantially all of AES Indiana's coal is currently mined in the state of Indiana.

Financial Derivatives

Leases

Revenue Recognition

Revenue related to the sale of energy is generally recognized when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to certain customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is accrued. In making its estimates of unbilled revenue, AES Indiana uses models that consider various factors including daily generation volumes; known amounts of energy usage by nearly all residential, commercial and industrial customers; and estimated customer rates based on prior period billings. Given the use of these models, and that customers are billed on a monthly cycle, we believe it is unlikely that materially different results will occur in future periods when revenue is billed. An allowance for potential credit losses is maintained and amounts are written off when normal collection efforts have been exhausted. AES Indiana’s provision for expected credit losses included in “Operating expenses - Operation and maintenance” on the accompanying Consolidated

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Statements of Operations was $ i 7.5 million, $ i 5.9 million and $ i 3.0 million for the years ended December 31, 2023, 2022 and 2021, respectively.

In addition, AES Indiana is one of many transmission system owner members of MISO, a RTO which maintains functional control over the combined transmission systems of its members and manages one of the largest energy markets in the U.S. See Note 13, "Revenue" for additional information of MISO sales and other revenue streams.

Operating Expenses – Other, Net

Pension and Postretirement Benefits

AES Indiana recognizes in its Consolidated Balance Sheets an asset or liability reflecting the funded status of pension and other postretirement plans with current-year changes in the funded status, that would otherwise be recognized in AOCI, recorded as a regulatory asset as this can be recovered through future rates. All plan assets are recorded at fair value. AES Indiana follows the measurement date provisions of the accounting guidance, which require a year-end measurement date of plan assets and obligations for all defined benefit plans.

AES Indiana accounts for and discloses pension and postretirement benefits in accordance with the provisions of GAAP relating to the accounting for pension and other postretirement plans. These GAAP provisions require the use of assumptions, such as the discount rate for liabilities and long-term rate of return on assets, in determining the obligations, annual cost and funding requirements of the plans. Consistent with the requirements of ASC 715, AES Indiana applies a disaggregated discount rate approach for determining service cost and interest cost for its defined benefit pension plans and postretirement plans.

See Note 8, "Benefit Plans" for more information.

Income Taxes

Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of the existing assets and liabilities, and their respective income tax bases. AES Indiana establishes a valuation allowance when it is more likely than not that all or a portion of a deferred tax asset will not be realized. AES Indiana’s tax positions are evaluated under a more likely than not recognition threshold and measurement analysis before they are recognized for financial statement reporting.

Uncertain tax positions are classified as noncurrent income tax liabilities unless expected to be paid within one year. AES Indiana’s policy for interest and penalties is to recognize interest and penalties as a component of the provision for income taxes in the Consolidated Statements of Operations.

Income tax assets or liabilities which are included in allowable costs for ratemaking purposes in future years are recorded as regulatory assets or liabilities with a corresponding deferred tax liability or asset. Investment tax credits that reduced federal income taxes in the years they arose have been deferred and are being amortized to income over the useful lives of the properties in accordance with regulatory treatment. See Note 2, "Regulatory Matters" for additional information.

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AES Indiana files U.S. federal income tax returns as part of the consolidated U.S. income tax return filed by AES. The consolidated tax liability is allocated to each subsidiary based on the separate return method which is specified in our tax allocation agreement and which provides a consistent, systematic and rational approach. See Note 7, "Income Taxes" for additional information.

Repair and Maintenance Costs

Repair and maintenance costs are expensed as incurred.

Per Share Data

IPALCO owns all of the outstanding common stock of AES Indiana. AES Indiana does not report earnings on a per-share basis.

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New Accounting Pronouncements

We have assessed and determined that the new accounting pronouncements adopted did not have a material impact on AES Indiana's Financial Statements.

New Accounting Pronouncements Issued But Not Yet Effective

The following table provides a brief description of recent accounting pronouncements that could have a material impact on the AES Indiana's Financial Statements once adopted. Accounting pronouncements not listed below were assessed and determined to be either not applicable or are expected to have no material impact on AES Indiana's Financial Statements.


ASU Number and Name	Description	Date of Adoption	Effect on the Financial Statements upon adoption
2023-06 Disclosure Improvements: Codification Amendments in Response to the SEC’s Disclosure Update and Simplification Initiative	In U.S. Securities and Exchange Commission (SEC) Release No. 33-10532, Disclosure Update and Simplification, issued August 17, 2018, the SEC referred certain of its disclosure requirements that overlap with, but require incremental information to, generally accepted accounting principles (GAAP) to the FASB for potential incorporation into the Codification. The amendments in this Update are the result of the Board’s decision to incorporate into the Codification 14 of the 27 disclosures referred by the SEC. The amendments in this Update represent changes to clarify or improve disclosure and presentation requirements of a variety of Topics. Many of the amendments allow users to more easily compare entities subject to the SEC’s existing disclosures with those entities that were not previously subject to the SEC’s requirements. Also, the amendments align the requirements in the Codification with the SEC’s regulations.	The effective date for each amendment will be the date on which the SEC's removal of that related disclosure becomes effective, with early adoption prohibited. The amendments in this Update should be applied prospectively.	AES Indiana will provide the required disclosures on a prospective basis on the date each amendment becomes effective. AES Indiana does not expect ASU 2023-06 will have any impact to its Financial Statements.
2023-07 Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures	The amendments in this section are designed to improve the disclosures related to Segment reporting on an interim and annual basis. Public companies must disclose significant segment expenses and an amount for other segment items. This will also require that a company disclose its annual disclosures under Topic 280 in each interim period. Furthermore, companies will need to disclose the Chief Operating Decision Maker (CODM) and how the CODM assesses the performance of a segment. Lastly, public companies that have a single reportable segment must report the required disclosures under topic 280.	The amendments in this Update are effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. Early adoption is permitted.	AES Indiana is currently evaluating the impact of adopting the standard on its Financial Statements.
2023-09 Income Taxes (Topic 740): Improvements to Income Tax Disclosures	The amendments in this Update require that public business entities on an annual basis (1) disclose specific categories in the rate reconciliation and (2) provide additional information for reconciling items that meet a quantitative threshold. Furthermore, companies are required to disclose a disaggregated amount of income taxes paid at a federal, state, and foreign level as well as a break down of income taxes paid in a jurisdiction that comprises 5% of a company's total income taxes paid. Lastly, this ASU requires that companies disclose income (loss) from continuing operations before income tax at a domestic and foreign level and that companies disclose income tax expense from continuing operations on a federal, state, and foreign level.	The amendments in this Update are effective for fiscal years beginning after December 15, 2024.	AES Indiana is currently evaluating the impact of adopting the standard on its Financial Statements.

2 i . REGULATORY MATTERS

General

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Basic Rates and Charges

AES Indiana’s basic rates and charges represent the largest component of its annual revenue. AES Indiana’s basic rates and charges are determined after giving consideration, on a pro-forma basis, to all allowable costs for ratemaking purposes including a fair return on the fair value of the utility property used and useful in providing service to customers. These basic rates and charges are set and approved by the IURC after public hearings. Such proceedings, which have occurred at irregular intervals, involve AES Indiana, the IURC, the Indiana Office of Utility Consumer Counselor, and other interested stakeholders. Pursuant to statute, the IURC is to conduct a periodic review of the basic rates and charges of all Indiana utilities at least once every four years, but the IURC has the authority to review the rates of any Indiana utility at any time. Once set, the basic rates and charges authorized do not assure the realization of a fair return on the fair value of property.

AES Indiana’s declining block rate structure generally provides for residential and commercial customers to be charged a lower per kWh rate at higher consumption levels. Therefore, as volumes increase, the weighted average price per kWh decreases. Numerous factors including, but not limited to, weather, inflation, customer growth and usage, the level of actual operating and maintenance expenditures, fuel costs, generating unit availability, and capital expenditures including those required by environmental regulations can affect the return realized.

Regulatory Rate Review and Base Rate Orders

FAC and Authorized Annual Jurisdictional Net Operating Income

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Independent of the IURC’s ability to review basic rates and charges, Indiana law requires electric utilities under the jurisdiction of the IURC to meet operating expense and income test requirements as a condition for approval of requested changes in the FAC. 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.

ECCRA

DSM

AES Indiana filed a petition with the IURC on May 26, 2023 asking for approval of a one year DSM interim plan. On December 27, 2023, the IURC approved a one year DSM plan for AES Indiana through 2024. The approval included cost recovery of programs as well as performance incentives, depending on the level of success of the programs. The order also approved recovery of lost revenue, consistent with the provisions of the settlement agreement.

Wind and Solar Power Purchase Agreements

AES Indiana is currently committed under a power purchase agreement to purchase all wind-generated electricity through 2029 from a wind project in Indiana ("Hoosier Wind Project"). On July 28, 2023, AES Indiana executed the Purchase Agreement and is currently in the process of acquiring this project. The existing power purchase agreement will be terminated upon closing (see "IRP Filings and Replacement Generation - Hoosier Wind Project" below for further information). AES Indiana is also committed under another agreement to purchase all wind-generated electricity through 2031 from a project in Minnesota. The Indiana project has a maximum output capacity of approximately i 100 MW and the Minnesota project has a maximum output capacity of approximately i 200 MW. In addition, AES Indiana has i 94.5 MW of solar-generated electricity in its service territory under long-term contracts

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(these long-term contracts have expiration dates ranging from 2026 to 2033), of which i 94.0 MW was in operation as of December 31, 2023. AES Indiana has authority from the IURC to recover the costs for all of these agreements through an adjustment mechanism administered within the FAC. If and when AES Indiana sells the renewable energy attributes (in the form of renewable energy credits) generated from these facilities, the proceeds would pass back to benefit AES Indiana’s retail customers through the FAC.

TDSIC

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 $ i 1.2 billion from 2020 through 2026. Beginning in June 2020, AES Indiana files an annual TDSIC rate adjustment for a return on and of investments through March 31 with rates requested to be effective each November. Annual TDSIC plan update filings are required to be staggered by six months as ordered by the IURC and are filed each December. The total amount of AES Indiana’s equipment net of depreciation, including carrying costs, approved for TDSIC recovery as of December 31, 2023 was $ i 399.6 million, The jurisdictional revenue requirement approved by the IURC to be included in AES Indiana’s rates for the twelve-month period ending October 2024 is a net cost to customers of $ i 56.5 million.

IRP Filings and Replacement Generation

2022 IRP

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2019 IRP

AES Indiana issued an all-source Request for Proposal on December 20, 2019, in order to competitively procure replacement capacity by June 1, 2023, which was the first year AES Indiana was expected to have a capacity shortfall. AES Indiana's modeling indicated that a combination of wind, solar, storage, and energy efficiency would be the lowest reasonable cost option for the replacement capacity. As a result of the plans to retire Petersburg Units 1 and 2, AES Indiana recorded $ i 0.7 million, $ i 2.1 million, and $ i 0.8 million of obsolescence losses, during the periods ended December 31, 2023, 2022, and 2021, respectively, for materials and supplies inventory AES Indiana did not believe will be utilized by the planned retirement dates, which is recorded in "Operating expenses - Operation and maintenance" on the accompanying Consolidated Statements of Operations.

Hardy Hills Solar Project

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Petersburg Energy Center Project

Pike County BESS Project

In June 2023, AES Indiana, through a wholly-owned subsidiary, executed an agreement for the construction of the i 200 MW ( i 800 MWh) Pike County BESS Project to be developed at the AES Indiana Petersburg Plant site in Pike County, Indiana. On July 19, 2023, AES Indiana filed a petition and case-in-chief with the IURC seeking approval for a Clean Energy Project and associated timely cost recovery under Indiana Code for this project. A hearing for this case was held in October 2023, and IURC approval was received on January 17, 2024. The Pike County BESS Project is expected to be completed in 2024.

Hoosier Wind Project

Incentives for Clean Energy Projects

IURC COVID-19 Orders

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2022, which will be recovered through base rates under the stipulation and settlement agreement entered into on November 22, 2023, if approved by the IURC.

EDG Rates

EV Portfolio Program

Storm Outage Restoration Inquiry

House Bill 1002

Regulatory Assets and Liabilities

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The amounts of regulatory assets and regulatory liabilities at December 31 are as follows:

2023

2022

Recovery Period

(In Thousands)

Regulatory assets, current:

Undercollections of rate riders

i 75,416

i 26,047

Approximately 1 year(1)

Fuel costs

i —

i 79,861

Approximately 1 year(1)

Unamortized reacquisition premium on debt

i 188

i —

Approximately 1 year

Costs being recovered through basic rates and charges

i 13,815

Approximately 1 year(1)

Total regulatory assets, current

i 89,419

i 119,723

Regulatory assets, non-current:

Unrecognized pension and other

postretirement benefit plan costs

i 115,847

i 131,907

Various(2)

Deferred MISO costs

i 21,091

i 34,483

Through 2026(1)

Unamortized Petersburg Unit 4 carrying

charges and certain other costs

i 2,812

i 3,866

Through 2026(1)(3)

Unamortized reacquisition premium on debt

i 13,379

i 14,429

Over remaining life of debt

Environmental costs

i 66,837

i 68,947

Through 2046(1)(3)

COVID-19 costs

i 5,426

4 years(4)

Major storm damage

i 1,493

i —

To be determined

TDSIC costs

i 35,979

i 18,547

36.3 years(1)(3)

Petersburg Unit 1 and 2 retirement costs

i 259,892

i 287,463

Through 2034(1)(3)

Hardy Hills Solar Project development costs

i 6,774

i 5,744

30 years(3)

Petersburg Energy Center Project development costs

i 2,469

i 1,582

30 years(3)

Pike County BESS Project development costs

i 2,623

i —

20 years(3)

Fuel costs

i 4,275

i 20,518

Through 2025(1)

Other miscellaneous

i 2,887

i 1,027

Various(5)

Total regulatory assets, non-current

i 541,784

i 593,939

Total regulatory assets

i 631,203

i 713,662

Regulatory liabilities, current:

Overcollections and other credits being passed

to customers through rate riders

i 19,649

i 15,803

Approximately 1 year(1)

FTRs

i 3,722

i 7,545

Approximately 1 year(1)

Total regulatory liabilities, current

i 23,371

i 23,348

Regulatory liabilities, non-current:

ARO and accrued asset removal costs

i 451,886

i 518,797

Not applicable

Deferred income taxes payable to customers through rates

i 74,796

i 88,662

Various

Hardy Hills sponsor investment tax credit

i 542

i —

To be determined(6)

Major storm damage

i —

i 5,126

To be determined

Total regulatory liabilities, non-current

i 527,224

i 612,585

Total regulatory liabilities

i 550,595

i 635,933

(1)Recovered (credited) per specific rate orders

(2)AES Indiana receives a return on its discretionary funding

(3)Recovered with a current return

(4)Per the signed stipulation in the 2023 distribution rate case, Cause No. 45911

(6)Will be included in a future ECR filing

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Current Regulatory Assets and Liabilities

Deferred Fuel

Unrecognized Pension and Postretirement Benefit Plan Costs

Deferred MISO Costs

Unamortized Petersburg Unit 4 Carrying Charges and Certain Other Costs

These consist of deferred debt carrying costs, depreciation, and post-in-service AFUDC on Petersburg Unit 4. These costs are being recovered per specific rate order.

Unamortized Reacquisition Premium on Debt

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Environmental Costs

COVID-19 Costs

TDSIC Costs

Petersburg Unit 1 and 2 Retirement Costs

Hardy Hills Solar Project Development Costs

Petersburg Energy Center Project Development Costs

These consist of project development costs, mainly legal and consulting fees, incurred for the Petersburg Energy Center Project as well as carrying costs on AES Indiana's investment in the project. The investment costs were approved for recovery via the ECCRA rider through AES Indiana’s Petersburg Energy Center Project regulatory proceedings with an amortization period of 30 years. Amortization of the project development costs will be determined in a future rate case filing.

Pike County BESS Project Development Costs

These consist of project development costs, mainly legal and consulting fees, incurred for the Pike County BESS Project as well as carrying costs on AES Indiana's investment in the project. The investment costs were approved for recovery via the ECCRA rider through AES Indiana’s Pike County BESS Project regulatory proceedings with an amortization period of 20 years. Amortization of the project development costs will be determined in a future rate case filing.

FTRs

In connection with AES Indiana’s participation in MISO, in the second quarter of each year AES Indiana is granted financial instruments that can be converted into cash or FTRs based on AES Indiana’s forecasted peak load for the period. See Note 4, "Fair Value - Fair Value Hierarchy and Valuation Techniques - Financial Assets - FTRs" for additional information.

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ARO and Accrued Asset Removal Costs

Deferred Income Taxes Recoverable/Payable Through Rates

On December 22, 2017, the U.S. federal government enacted the TCJA, which, among other things, reduced the federal corporate income tax rate from i 35% to i 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 $ i 74.8 million and $ i 88.7 million as of December 31, 2023 and 2022, respectively.

3 i . PROPERTY, PLANT AND EQUIPMENT

The original cost of property, plant and equipment segregated by functional classifications follows:

As of December 31,

2023

2022

(In Thousands)

Production

i 3,942,052

i 4,164,416

Transmission

i 487,527

i 461,245

Distribution

i 2,304,526

i 2,045,579

General plant

i 348,338

i 311,074

Total property, plant and equipment

i 7,082,443

i 6,982,314

ARO

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2023

2022

(In Thousands)

Balance as of January 1

i 218,729

i 189,509

Liabilities incurred

i 17,080

i 1,159

Liabilities settled

( i 11,902)

( i 24,699)

Revisions to cash flow and timing estimates

i 12,921

i 44,679

Accretion expense

i 13,102

i 8,081

Balance as of December 31

i 249,930

i 218,729

4. i FAIR VALUE

The fair value of current financial assets and liabilities approximate their reported carrying amounts. The estimated fair values of AES Indiana’s assets and liabilities have been determined using available market information. Because these amounts are estimates and based on hypothetical transactions to sell assets or transfer liabilities, the use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.

Fair Value Hierarchy and Valuation Techniques

ASC 820 defines and establishes a framework for measuring fair value and expands disclosures about fair value measurements for financial assets and liabilities that are adjusted to fair value on a recurring basis and/or financial assets and liabilities that are measured at fair value on a nonrecurring basis, which have been adjusted to fair value during the period. In accordance with ASC 820, AES Indiana has categorized its financial assets and liabilities that are adjusted to fair value, based on the priority of the inputs to the valuation technique, following the three-level fair value hierarchy prescribed by ASC 820 as follows:

Level 1 - unadjusted quoted prices for identical assets or liabilities in an active market;

Level 2 - inputs from quoted prices in markets where trading occurs infrequently or quoted prices of instruments with similar attributes in active markets; and

Level 3 - unobservable inputs reflecting management’s own assumptions about the inputs used in pricing the asset or liability.

Whenever possible, quoted prices in active markets are used to determine the fair value of AES Indiana’s financial instruments. AES Indiana’s financial instruments are not held for trading or other speculative purposes. The estimated fair value of financial instruments has been determined by using available market information and appropriate valuation methodologies. However, considerable judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that AES Indiana could realize in a current market exchange. The use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.

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Financial Assets

FTRs

In connection with AES Indiana’s participation in MISO, in the second quarter of each year AES Indiana is granted financial instruments that can be converted into cash or FTRs based on AES Indiana’s forecasted peak load for the period. FTRs are used in the MISO market to hedge AES Indiana’s exposure to congestion charges, which result from constraints on the transmission system. AES Indiana’s FTRs are valued at the cleared auction prices for FTRs in MISO’s annual auction. Because of the infrequent nature of this valuation, the fair value assigned to the FTRs is considered a Level 3 input under the fair value hierarchy required by ASC 820. An offsetting regulatory liability has been recorded as these revenue or costs will be flowed through to customers through the FAC. As such, there is no impact on AES Indiana’s Consolidated Statements of Operations.

Forward Power Contracts

Recurring Fair Value Measurements

The fair value of assets at December 31, 2023 and 2022 measured on a recurring basis and the respective category within the fair value hierarchy for AES Indiana was determined as follows:

Fair Value as of December 31, 2023

Fair Value as of December 31, 2022

Level 1

Level 2

Level 3

Total

Level 1

Level 2

Level 3

Total

(In Thousands)

Financial assets:

FTRs

i —

i 1,388

i —

i 7,545

Total financial assets measured at fair value

i —

i 1,388

i —

i 7,545


	Reconciliation of Financial Instruments Classified as Level 3
	(In Thousands)
Balance at January 1, 2022	$	i 1,235

Issuances	i 15,338
Settlements	( i 9,028)
Balance at December 31, 2022	i 7,545

Issuances	i 3,624
Settlements	( i 9,781)
Balance at December 31, 2023	$	i 1,388

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Financial Instruments not Measured at Fair Value in the Consolidated Balance Sheets

Debt

The fair value of AES Indiana’s outstanding fixed-rate debt has been determined on the basis of the quoted market prices of the specific securities issued and outstanding. In certain circumstances, the market for such securities was inactive and therefore the valuation was adjusted to consider changes in market spreads for similar securities. Accordingly, the purpose of this disclosure is not to approximate the value on the basis of how the debt might be refinanced.

The following table shows the face value and the fair value of fixed-rate and variable-rate indebtedness (Level 2) for the periods ending:

Face Value

Fair Value

Face Value

Fair Value

(In Thousands)

Fixed-rate

i 2,153,800

i 2,020,997

i 2,153,800

i 1,959,233

Variable-rate

i 455,000

i —

Total indebtedness

i 2,608,800

i 2,475,997

i 2,153,800

i 1,959,233

The difference between the face value and the carrying value of this indebtedness represents the following:

•unamortized deferred financing costs of $ i 20.2 million and $ i 20.4 million at December 31, 2023 and 2022, respectively; and

•unamortized discounts of $ i 6.4 million and $ i 6.7 million at December 31, 2023 and 2022, respectively.

5. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

AES Indiana uses derivatives principally to manage the risk of price changes for purchased power. The derivatives that AES Indiana uses to economically hedge this risk is governed by our risk management policies for forward and futures contracts. AES Indiana's net positions are continually assessed within its structured hedging programs to determine whether new or offsetting transactions are required. AES Indiana monitors and values derivative positions monthly as part of its risk management processes. AES Indiana uses published sources for pricing, when possible, to mark positions to market. All of AES Indiana's derivative instruments are used for risk management purposes and are designated as cash flow hedges if they qualify under ASC 815 for accounting purposes.

At December 31, 2023, AES Indiana's outstanding derivative instruments were as follows:

Commodity

Accounting Treatment (a)

Unit

Notional
(in thousands)

Sales
(in thousands)

Net Notional
(in thousands)

FTRs

Not Designated

MWh

i 3,919

i —

i 3,919

(a) Refers to whether the derivative instruments have been designated as a cash flow hedge.

Derivatives Not Designated as Hedge

AES Indiana's FTRs and forward power contracts do not qualify for hedge accounting or the normal purchases and sales exceptions under ASC 815. Accordingly, FTRs are recorded at fair value using the income approach when acquired and subsequently amortized over the annual period as they are used. The forward power contracts are recorded at fair value using the market approach with changes in the fair value charged or credited to the Consolidated Statements of Operations in the period in which the change occurred. This is commonly referred to as "MTM accounting." Realized gains and losses on the forward power contracts are included in future FAC filings, therefore any realized and unrealized gains and losses are deferred as regulatory liabilities or regulatory assets. There were net realized gains of $ i 0.0 million and $ i 1.3 million related to forward power contracts during the years ended December 31, 2023 and 2022, respectively, related to the forward power contracts that were deferred and included with deferred fuel costs in "Regulatory assets, current" on the accompanying Consolidated Balance Sheets.

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When applicable, AES Indiana has elected not to offset derivative assets and liabilities and not to offset net derivative positions against the right to reclaim cash collateral pledged (an asset) or the obligation to return cash collateral received (a liability) under derivative agreements. As of December 31, 2023 and 2022, AES Indiana did not have any offsetting positions.

The following table summarizes the fair value, balance sheet classification and hedging designation of AES Indiana's derivative instruments (in thousands):

December 31,

Commodity

Hedging Designation

Balance sheet classification

2023

2022

FTRs

Not a Cash Flow Hedge

Prepayments and other current assets

i 1,388

i 7,545

6 i . DEBT

The following table presents AES Indiana’s long-term debt:

December 31,

Series

Due

2023

2022

(In Thousands)

AES Indiana first mortgage bonds:

i 3.125% (1)

December 2024

i 40,000

i 0.65% (1)

August 2025

i 40,000

i 0.75% (2)

April 2026

i 30,000

i 0.95% (2)

April 2026

i 60,000

i 1.40% (1)

August 2029

i 55,000

i 5.650%

December 2032

i 350,000

i 6.60%

January 2034

i 100,000

i 6.05%

October 2036

i 158,800

i 6.60%

June 2037

i 165,000

i 4.875%

November 2041

i 140,000

i 4.65%

June 2043

i 170,000

i 4.50%

June 2044

i 130,000

i 4.70%

September 2045

i 260,000

i 4.05%

May 2046

i 350,000

i 4.875%

November 2048

i 105,000

Unamortized discount – net

( i 6,449)

( i 6,651)

Deferred financing costs

( i 19,058)

( i 20,362)

Total AES Indiana first mortgage bonds

i 2,128,293

i 2,126,787

Total consolidated AES Indiana long-term debt

i 2,128,293

i 2,126,787

Less: current portion of long-term debt

i 40,000

i —

Net consolidated AES Indiana long-term debt

i 2,088,293

i 2,126,787

(1)First mortgage bonds issued to the Indiana Finance Authority, to secure the loan of proceeds from tax-exempt bonds issued by the Indiana Finance Authority.

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Line of Credit

Debt Maturities

Maturities on long-term indebtedness subsequent to December 31, 2023 are as follows:


Year	Amount
	(In Thousands)
2024	$	i 40,000
2025	i 40,000
2026	i 90,000
2027	i —
2028	i —
Thereafter	i 1,983,800
	i 2,153,800
Unamortized discounts	( i 6,449)
Deferred financing costs, net	( i 19,058)
Total long-term debt	$	i 2,128,293

Significant Transactions

AES Indiana Term Loans

In November 2023, AES Indiana entered into an unsecured$ i 300 million 364-day term loan agreement ("$ i 300 million Term Loan Agreement"). The $ i 300 million Term Loan Agreement was fully drawn at closing with the proceeds being used for general corporate purposes. This agreement matures on November 19, 2024, and bears interest at variable rates as described in the $ i 300 million Term Loan Agreement. The $ i 300 million Term Loan Agreement contains customary representations, warranties and covenants, including a leverage covenant consistent with the leverage covenant contained in AES Indiana's Credit Agreement. AES Indiana has classified this $ i 300 million Term Loan Agreement as short-term indebtedness as it matures November 2024. Although current liquid funds are not sufficient to repay the amount due at maturity, management plans to refinance this $ i 300 million Term Loan Agreement with new long-term debt.

AES Indiana First Mortgage Bonds and Recent Indiana Finance Authority Bond Issuances

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Restrictions on Issuance of Debt

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.

143

7. i INCOME TAXES

AES Indiana follows a policy of comprehensive interperiod income tax allocation. Investment tax credits related to utility property have been deferred and are being amortized over the estimated useful lives of the related property.

AES files federal and state income tax returns which consolidate IPALCO and AES Indiana. Under a tax sharing agreement with IPALCO, AES Indiana is responsible for the income taxes associated with its own taxable income and records the provision for income taxes as if AES Indiana filed separate income tax returns. AES Indiana is no longer subject to U.S. or state income tax examinations for tax years through 2016, but is open for all subsequent periods. AES Indiana made tax sharing payments to IPALCO of $ i 0.0 million, $ i 39.5 million and $ i 40.8 million in 2023, 2022 and 2021, respectively.

Income Tax Provision

Federal and state income taxes charged to income are as follows:

2023

2022

2021

(In Thousands)

Components of income tax expense:

Current income taxes:

Federal

i 1,816

i 31,286

i 36,353

State

i 268

i 8,185

i 10,325

Total current income taxes

i 2,084

i 39,471

i 46,678

Deferred income taxes:

Federal

i 17,631

( i 6,822)

( i 7,283)

State

i 5,951

i 238

( i 90)

Total deferred income taxes

i 23,582

( i 6,584)

( i 7,373)

Total income tax expense

i 25,666

i 32,887

i 39,305

Effective and Statutory Rate Reconciliation

The provision for income taxes (including net investment tax credit adjustments) is different than the amount computed by applying the statutory tax rate to pretax income. i The reasons for the difference, stated as a percentage of pretax income, are as follows:


	2023		2022		2021
Federal statutory tax rate	i 21.0	%	i 21.0	%	i 21.0	%
State income tax, net of federal tax benefit	i 3.9	%	i 3.9	%	i 4.0	%


Depreciation flow through and amortization	( i 8.0)	%	( i 5.7)	%	( i 4.9)	%
AFUDC - equity	( i 0.2)	%	i 0.7	%	i 0.3	%

Noncontrolling interests in subsidiaries	i 5.6	%	i —	%	i —	%
Other – net	( i 0.1)	%	i 0.3	%	i 0.3	%
Effective tax rate	i 22.2	%	i 20.2	%	i 20.7	%

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Deferred Income Taxes

The significant items comprising AES Indiana’s net accumulated deferred tax liability recognized on the audited Consolidated Balance Sheets as of December 31, 2023 and 2022 are as follows:

2023

2022

(In Thousands)

Deferred tax liabilities:

Relating to utility property, net

i 409,675

i 341,473

Regulatory assets recoverable through future rates

i 108,823

i 123,669

Other

i 7,975

i 22,717

Total deferred tax liabilities

i 526,473

i 487,859

Deferred tax assets:

Investment tax credit

i 5

i 6

Regulatory liabilities including ARO

i 168,619

i 167,726

Investments in tax partnerships

i 2,483

i —

Operating loss carryforwards

i 9,230

i —

Other

i 3,579

i 15,020

Total deferred tax assets

i 183,916

i 182,752

Deferred income tax liability – net

i 342,557

i 305,107

Uncertain Tax Positions

The following is a reconciliation of the beginning and ending amounts of unrecognized tax benefits for the years ended December 31, 2023, 2022 and 2021:


	2023		2022		2021
	(In Thousands)
Unrecognized tax benefits at January 1	$	i —	$	i —	$	i 7,368

Gross decreases – prior period tax positions	i —		i —		( i 7,368)
Unrecognized tax benefits at December 31	$	i —	$	i —	$	i —

The prior period unrecognized tax benefits represent tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. As a result of the resolution of federal and state audits in 2021, AES Indiana reviewed its uncertain positions and determined that they are more likely than not to be sustained upon examination by taxing authorities. Consequently, the uncertain tax positions were reversed; because of the impact of deferred tax accounting the reversal did not affect the annual effective tax rate but were reclassified to plant related deferred tax balances.

Tax years subsequent to 2016 remain open to examination by taxing authorities. While it is often difficult

to predict the final outcome or the timing of resolution of any particular uncertain tax position, AES Indiana believes

unrecognized tax benefits of $ i 0 at December 31, 2023 and 2022, respectively, is the appropriate accrual for our uncertain tax positions. However, audit outcomes and the timing of audit settlements and future events that would impact AES Indiana's previously recorded unrecognized tax benefits are subject to significant uncertainty. It is possible that the ultimate outcome of future examinations may exceed AES Indiana's provision for current unrecognized tax benefits.

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8. i 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

The RSP

Defined Benefit Plans

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The following table presents information relating to the Pension Plans:

Pension benefits
as of December 31,

2023

2022

(In Thousands)

Change in benefit obligation:

Projected benefit obligation at January 1

i 577,530

i 772,040

Service cost

i 5,189

i 8,949

Interest cost

i 29,818

i 18,099

Actuarial loss (gain)

i 9,681

( i 182,590)

Amendments (primarily increases in pension bands)

i 653

i —

Settlements

i —

( i 394)

Benefits paid

( i 73,325)

( i 38,575)

Projected benefit obligation at December 31

i 549,546

i 577,529

Change in plan assets:

Fair value of plan assets at January 1

i 611,125

i 820,684

Actual return/(loss) on plan assets

i 52,905

( i 171,002)

Employer contributions

i 114

i 412

Settlements

i —

( i 394)

Benefits paid

( i 73,325)

( i 38,575)

Fair value of plan assets at December 31

i 590,819

i 611,125

Funded status

i 41,273

i 33,596

Amounts recognized in the statement of financial position:

Non-current assets

i 41,273

i 33,611

Non-current liabilities

i —

( i 15)

Net amount recognized at end of year

i 41,273

i 33,596

Sources of change in regulatory assets(1):

Prior service cost arising during period

i 653

i —

Net (gain)/loss arising during period

( i 10,117)

i 24,069

Amortization of prior service cost

( i 2,172)

( i 2,589)

Amortization of loss

( i 6,145)

( i 2,622)

Total recognized in regulatory assets

( i 17,781)

i 18,858

Amounts included in regulatory assets:

Net loss

i 115,297

i 131,559

Prior service cost

i 10,136

i 11,655

Total amounts included in regulatory assets

i 125,433

i 143,214

Significant Loss / (Gain) Related to Changes in the Benefit Obligation for the Period

Pension Benefits and Expense

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Pension benefits for
years ended December 31,

2023

2022

2021

(In Thousands)

Components of net periodic benefit cost / (credit):

Service cost

i 5,189

i 8,949

i 9,339

Interest cost

i 29,818

i 18,099

i 15,660

Expected return on plan assets

( i 33,107)

( i 35,656)

( i 41,815)

Amortization of prior service cost

i 2,172

i 2,589

i 2,944

Amortization of actuarial loss

i 6,145

i 2,424

i 5,529

Amortization of settlement loss

i —

i 199

i —

Net periodic benefit cost / (credit)

i 10,217

( i 3,396)

( i 8,343)

Less: amounts capitalized

i 1,689

( i 316)

( i 771)

Amount charged to expense

i 8,528

( i 3,080)

( i 7,572)

Rates relevant to each year’s expense calculations:

Discount rate – defined benefit pension plan

i 5.41

i 2.83

i 2.46

Discount rate – supplemental retirement plan

i 5.32

i 2.62

i 2.31

Expected return on defined benefit pension plan assets

i 5.60

i 4.45

i 5.05

Expected return on supplemental retirement plan assets

i 6.45

i 5.50

i 3.60

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Pension Plan Assets and Fair Value Measurements

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.

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.

149

combination of historical analysis, current market environment assessment and by applying the consultant’s own judgment. The consultant then determines an equilibrium long-term rate of return. AES Indiana then takes into consideration the investment manager/consultant expenses, as well as any other expenses expected to be paid out of the Pension Plans’ trust. Finally, AES Indiana has the Pension Plans’ actuary perform a tolerance test of the consultant’s equilibrium expected long-term rate of return. AES Indiana uses an expected long-term rate of return compatible with the actuary’s tolerance level.

The following table summarizes AES Indiana’s target pension plan allocation for 2023:


Asset Category:			Target Allocations
Equity Securities			i 13.5%
Debt Securities			i 86.5%

Fair Value Measurements at

(in thousands)

Quoted Prices in Active Markets for Identical Assets

Significant Observable Inputs

Asset Category

Total

(Level 1)

(Level 2)

Common collective trusts:

Equities (a)

i 82,652

i 2,267

i 80,385

i 14

Debt securities (b)

i 387,979

i 1,168

i 386,811

i 66

Government debt securities (c)

i 117,397

i 178

i 117,219

i 20

Total common collective trusts

i 588,028

i 3,613

i 584,415

i 100

Cash and cash equivalents (d)

i 2,791

—

i —

Total pension plan assets

i 590,819

i 6,404

i 584,415

i 100

150

Fair Value Measurements at

(in thousands)

Quoted Prices in Active Markets for Identical Assets

Significant Observable Inputs

Asset Category

Total

(Level 1)

(Level 2)

Common collective trusts:

Equities (a)

i 85,341

i 2,017

i 83,324

i 14

Debt securities (b)

i 400,291

i 1,254

i 399,037

i 66

Government debt securities (c)

i 122,704

i 420

i 122,284

i 20

Total common collective trusts

i 608,336

i 3,691

i 604,645

i 100

Cash and cash equivalents (d)

i 2,789

—

i —

Total pension plan assets

i 611,125

i 6,480

i 604,645

i 100

Pension Funding

AES Indiana contributed $ i 0.1 million, $ i 0.4 million, and $ i 0.0 million to the Pension Plans in 2023, 2022 and 2021, respectively. Funding for the qualified Defined Benefit Pension Plan is based upon actuarially determined contributions that take into account the amount deductible for income tax purposes and the minimum contribution required under ERISA, as amended by the Pension Protection Act of 2006, as well as targeted funding levels necessary to meet certain thresholds.

From an ERISA funding perspective, AES Indiana’s funded target liability percentage was estimated to be i 98%. In general, AES Indiana must contribute the normal service cost earned by active participants during the plan year; however, this amount can be offset by any surplus or credit balance carried by the Pension Plan. The normal cost is expected to be approximately $ i 6.3 million in 2024 (including $ i 0.4 million for plan expenses), which is expected to be fully offset by the surplus amount. Each year thereafter, if the Pension Plans' underfunding increases to more than the present value of the remaining annual installments, the excess is separately amortized over a seven-year period. AES Indiana does not expect to make an employer contribution for the calendar year 2024. AES Indiana’s funding policy for the Pension Plans is to contribute annually no less than the minimum required by applicable law, and no more than the maximum amount that can be deducted for federal income tax purposes.

151

Benefit payments made from the Pension Plans for the years ended December 31, 2023, 2022 and 2021 were $ i 73.3 million, $ i 38.6 million and $ i 63.2 million, respectively. Benefit payments, which reflect future service, are expected to be paid out of the Pension Plans as follows:


Year	Pension Benefits
	(In Thousands)
2024	$	i 37,997
2025	i 38,794
2026	i 39,665
2027	i 40,085
2028	i 41,477
2029 through 2033	i 200,574

9. EQUITY AND CUMULATIVE PREFERRED STOCK

Cumulative Preferred Stock

On December 30, 2022 (the “Redemption Date”), AES Indiana redeemed all of its issued and outstanding preferred stock for $ i 60.1 million. On the Redemption Date, the Preferred Stock of each series was redeemed with all applicable premiums, plus, in each case an amount equal to all accrued dividends payable with respect to such Preferred Stock to the Redemption Date. Dividends on the Preferred Stock ceased to accrue on the Redemption Date. Upon redemption, the Preferred Stock was no longer outstanding, and all rights of the holders thereof as shareholders of AES Indiana ceased to exist, except for the right to payment of the redemption price. AES Indiana recorded a charge of $ i 0.3 million on the redemption for the difference between the carrying value and redemption value of the preferred shares.

Paid in Capital and Capital Stock

On December 12, 2022 and December 13, 2021, respectively, AES Indiana received equity capital contributions of $ i 253.0 million and $ i 275.0 million from IPALCO. The proceeds are intended primarily for funding needs related to AES Indiana’s TDSIC and replacement generation projects.

All of the outstanding common stock of AES Indiana is owned by IPALCO. AES Indiana’s common stock is pledged under the 2024 IPALCO Notes and 2030 IPALCO Notes. There have been no changes in the capital stock of AES Indiana during the three years ended December 31, 2023.

Dividend Restrictions

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accrued, and no other distribution may be made on AES Indiana’s common stock unless dividends on all outstanding shares of AES Indiana preferred stock have been paid or declared and set apart for payment. As of December 31, 2023, and as of the filing of this report, AES Indiana was in compliance with these restrictions.

Additionally, all of AES Indiana's preferred stock was redeemed on December 30, 2022 (see "Cumulative Preferred Stock" above for further details).

During the years ended December 31, 2023, 2022 and 2021, AES Indiana declared dividends to its shareholder totaling $ i 140.2 million, $ i 127.2 million, and $ i 155.7 million, respectively.

Equity Transactions with Noncontrolling Interests

10. i COMMITMENTS AND CONTINGENCIES

Contractual Obligations and Commercial Commitments

We enter into various contractual obligations and other commercial commitments that may affect the liquidity of our operations. At December 31, 2023, these include:

Payments due in:

Total

Less Than 1 Year

1 – 3
Years

3 – 5
Years

More Than
5 Years

(In Millions)

Purchase obligations:

Coal, gas, purchased power and

related transportation

i 933.5

i 249.7

i 267.3

i 225.7

i 190.8

Other

i 409.1

i 355.0

i 32.8

i 20.2

i 1.1

Purchase obligations:

Purchase commitments for coal, gas, purchased power and related transportation:

Purchase orders and other contractual obligations:

153

(see Note 10, "Commitments and Contingencies"). See the indicated notes to the Financial Statements for additional information on the items excluded.

Contingencies

Legal Matters

AES Indiana is involved in litigation arising in the normal course of business. AES Indiana accrues for litigation and claims when it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. While the ultimate outcome of outstanding litigation cannot be predicted with certainty, management believes that final outcomes will not have a material adverse effect on AES Indiana’s results of operations, financial condition and cash flows. Accruals for legal loss contingencies were not material as of December 31, 2023 and 2022.

Coal Ash Insurance Litigation

Environmental Matters

AES Indiana is subject to various federal, state, regional and local environmental protection and health and safety laws and regulations governing, among other things, the generation, storage, handling, use, disposal and transportation of regulated materials, including ash; the use and discharge of water used in generation boilers and for cooling purposes; the emission and discharge of hazardous and other materials, including GHGs, into the environment; climate change; and the health and safety of AES Indiana's employees. These laws and regulations often require a lengthy and complex process of obtaining and renewing permits and other governmental authorizations from federal, state and local agencies. Violation of these laws, regulations or permits can result in substantial fines, other sanctions, permit revocation and/or facility shutdowns. AES Indiana cannot assure that it has been or will be at all times in full compliance with such laws, regulations and permits. Accruals for environmental contingencies were not material as of December 31, 2023 and 2022.

NSR and other CAA NOVs

154

11. i 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 $ i 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 $ i 11.7 million, $ i 9.5 million, and $ i 7.0 million in 2023, 2022 and 2021, respectively, and is recorded in “Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations. As of December 31, 2023 and 2022, AES Indiana had prepaid approximately $ i 7.5 million and $ i 3.4 million, respectively, for coverage under these plans, which is recorded in "Prepayments and other current assets" on the accompanying Consolidated Balance Sheets.

AES 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 $ i 5.1 million and $ i 6.7 million as of December 31, 2023 and 2022, respectively, which is recorded in “Taxes receivable” on the accompanying Consolidated Balance Sheets. See Note 7, "Income Taxes" for more information.

Long-term Compensation Plan

During 2023, 2022 and 2021, many of AES Indiana’s non-union employees received benefits under the AES Long-term Compensation Plan, a deferred compensation program. This type of plan is a common employee retention tool used in our industry. Benefits under this plan are granted in the form of performance units payable in cash and AES restricted stock units. Restricted stock units vest ratably over a three-year period. The performance units payable in cash vest at the end of the three-year performance period and are subject to certain AES performance criteria. Total deferred compensation expense recorded during 2023, 2022 and 2021 was $ i 0.3 million, $ i 0.2 million and $ i 0.2 million, respectively, and was included in “Operating expenses - Operation and maintenance” on AES Indiana’s Consolidated Statements of Operations. The value of these benefits is being recognized over the 36 month vesting period and a portion is recorded as miscellaneous deferred credits with the remainder recorded as “Paid in capital” on AES Indiana’s Consolidated Balance Sheets in accordance with ASC 718 “Compensation – Stock Compensation.”

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

Service Company

Total costs incurred by the Service Company on behalf of AES Indiana were $ i 73.6 million, $ i 60.1 million and $ i 58.2 million during 2023, 2022 and 2021, respectively. Total costs incurred by AES Indiana on behalf of the Service Company during 2023, 2022 and 2021 were $ i 11.9 million, $ i 10.0 million and $ i 10.4 million, respectively, which are included as a reduction to charges from the Service Company. These costs were included in “Operating expenses -

155

Operation and maintenance” on AES Indiana’s Consolidated Statements of Operations. AES Indiana had a payable balance with the Service company of $ i 25.6 million and $ i 2.1 million as of December 31, 2023 and 2022, respectively, which is recorded in "Accounts payable" on the accompanying Consolidated Balance Sheets.

Other

During the year ended December 31, 2021, AES Indiana received loan repayments of $ i 6.1 million from IPALCO.

In the second quarter of 2023, AES Indiana engaged a vendor that is a related party through a competitive RFP process as part of its replacement capacity resource construction projects. AES Indiana had payments of $ i 223.3 million to this vendor during the year ended December 31, 2023, which are included in "Other non-current assets" on the accompanying Consolidated Balance Sheets. Additionally, transactions with various other related parties were $ i 7.4 million, $ i 5.7 million and $ i 4.3 million during 2023, 2022 and 2021, respectively. These expenses were primarily recorded in “Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations.

12. i BUSINESS SEGMENTS

Operating segments are components of an enterprise that engage in business activities from which it may earn revenue and incur expenses, for which separate financial information is available, and is evaluated regularly by the chief operating decision maker in assessing performance and deciding how to allocate resources. All of AES Indiana’s current business consists of the generation, transmission, distribution and sale of electric energy, and therefore AES Indiana had only i one reportable segment.

13. REVENUE

156

AES Indiana’s revenue from contracts with customers was $ i 1,616.5 million, $ i 1,760.0 million and $ i 1,389.2 million for the years ended December 31, 2023, 2022 and 2021, respectively. T i he following table presents AES Indiana's revenue from contracts with customers and other revenue (in thousands):


	For the Years Ended December 31,
	2023		2022		2021
Retail Revenue
Retail revenue from contracts with customers:
Residential	$	i 660,559	$	i 688,487	$	i 595,692
Small commercial and industrial	i 241,800		i 247,655		i 211,997
Large commercial and industrial	i 619,899		i 625,351		i 518,069
Public lighting	i 9,767		i 9,832		i 8,888
Other (1)	i 14,016		i 17,845		i 16,785
Total retail revenue from contracts with customers	i 1,546,041		i 1,589,170		i 1,351,431
Alternative revenue programs	i 30,414		i 29,171		i 35,248
Wholesale Revenue
Wholesale revenue from contracts with customers	i 56,557		i 148,517		i 25,059
Miscellaneous Revenue
Capacity revenue	i 8,210		i 11,750		i 734
Transmission and other revenue	i 5,654		i 10,534		i 11,480
Total miscellaneous revenue from contracts with customers	i 13,864		i 22,284		i 12,214
Other miscellaneous revenue (2)	i 3,041		i 2,569		i 2,180
Total Revenue	$	i 1,649,917	$	i 1,791,711	$	i 1,426,132

(1) Other retail revenue from contracts with customers includes miscellaneous charges to customers, including reconnection and late fee charges.

(2) Other miscellaneous revenue includes lease and other miscellaneous revenue not accounted for under ASC 606.

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

157

relates specifically to our efforts to satisfy the performance obligation and depicts the amount to which AES Indiana expects to be entitled.

14. i 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

Assets

Right-of-use assets — finance leases

Other non-current assets

i 16,357

i 15,819

Liabilities

Finance lease liabilities (noncurrent)

Long-term debt

i 17,769

i 16,361

Total finance lease liabilities

i 17,769

i 16,361

The following table summarizes supplemental balance sheet information related to leases as of the periods indicated:

Lease Term and Discount Rate

Weighted-average remaining lease term — finance leases

i 35 years

i 36 years

Weighted-average discount rate — finance leases

i 5.30%

i 5.650%


	For the Year Ended December 31,
Components of Lease Cost	2023		2022		2021

Finance lease cost:
Amortization of right- of-use assets	$	i 445	$	i 542	$	i —
Interest on lease liabilities	i 933		i 782		i —



Total lease cost	$	i 1,378	$	i 1,324	$	i —

Operating cash outflows from finance leases were $ i 0.6 million, $ i 0.3 million and $ i 0.0 million for the years ended December 31, 2023, 2022 and 2021, respectively.


	Finance Leases
2024	$	i 891
2025	i 909
2026	i 927
2027	i 945
2028	i 965
Thereafter	i 39,958
Total	$	i 44,595
Less: Imputed interest	( i 26,826)
Present value of lease payments	$	i 17,769

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LESSOR

The following table presents lease revenue from operating leases in which the Company is the lessor for the periods indicated (in thousands):


	For the Year Ended December 31,
	2023		2022		2021
Total lease revenue	$	i 1,537	$	i 1,134	$	i 1,439

The following table presents the underlying gross assets and accumulated depreciation of operating leases included in Property, plant and equipment, net for the periods indicated (in thousands):

Property, Plant and Equipment, Net

Gross assets

i 4,341

i 4,334

Less: Accumulated depreciation

( i 1,222)

( i 1,060)

Net assets

i 3,119

i 3,274

The option to extend or terminate a lease is based on customary early termination provisions in the contract.

The following table shows the future minimum lease receipts through 2028 and thereafter (in thousands):


	Operating Leases
2024	$	i 544
2025	i 553
2026	i 554
2027	i 554
2028	i 354
Thereafter	i 891
Total	$	i 3,450

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

The Company maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed in the reports that the Company files or submits under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to the CEO and CFO, as appropriate, to allow timely decisions regarding required disclosures.

The Company carried out the evaluation required by Rules 13a-15(b) and 15d-15(b), under the supervision and with the participation of our management, including the CEO and CFO, of the effectiveness of our “disclosure controls and procedures” (as defined in the Exchange Act Rules 13a-15(e) and 15d-15(e)). Based upon this evaluation, the CEO and CFO concluded that as of December 31, 2023, our disclosure controls and procedures were not effective due to a material weakness in our internal control over financial reporting described below.

Management’s Report on Internal Control over Financial Reporting

Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rule 13a-15(f) under the Exchange Act. The Company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP and includes those policies and procedures that:

•pertain to the maintenance of records that in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;

•provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and

•provide reasonable assurance that unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements are prevented or detected timely.

A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be prevented or detected on a timely basis.

The Company conducted an assessment of the effectiveness of its internal control over financial reporting as of December 31, 2023 based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework). As of December 31, 2023, we have identified material weaknesses in internal controls related to the fourth quarter implementation of SAP IS-U, a software solution that SAP developed for businesses operating in the utility industries. We identified control deficiencies that aggregated to a material weakness in the design and operation of information technology general controls (“ITGCs”) which support the Company’s internal control processes for revenue recognition and related accounts and disclosures impacted by revenue recognition. The design deficiencies relate to user access and program change-management controls. Business process controls (automated and manual) and management review controls reliant on SAP IS-U were deemed ineffective as they were adversely impacted by the ineffective information technology general controls.

Management has implemented and continues to implement measures designed to ensure that control deficiencies contributing to the material weakness are remediated. The remediation actions include: (i) changes to our ITGC attributes in the areas of user access and program change-management for systems supporting the Company’s

160

revenue internal control processes to ensure that internal controls are designed and operating effectively; and (ii) training and educating the control owners on ITGC policies concerning the requirements of each control, with a focus on those related to user access and change-management over IT systems impacting our revenue process. Management has performed a lookback analysis to determine if any unauthorized activity occurred related to the control deficiencies; none was identified.

We believe that these actions will remediate the foregoing material weakness. The material weakness will not be considered remediated, however, until the applicable controls operate for a sufficient period of time, and management has concluded, through testing, that these controls are operating effectively.

Management, including our CEO and CFO, does not expect that our internal controls will prevent or detect all misstatements and all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. In addition, any evaluation of the effectiveness of controls is subject to risks that those internal controls may become inadequate in future periods because of changes in business conditions, or that the degree of compliance with the policies or procedures deteriorates.

Changes in Internal Control Over Financial Reporting

Except for the implementation of the SAP IS-U system discussed above, there has been no change in the Company’s internal control over financial reporting during the quarter ended December 31, 2023, that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

Notwithstanding the existence of the material weaknesses as described above, we believe that the consolidated financial statements in this Annual Report present fairly, in all material respects, our financial position, results of operations and cash flows as of the dates, and for the periods presented, in conformity with U.S. GAAP.

ITEM 9B. OTHER INFORMATION

None.

ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

Not applicable.

PART III

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.

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.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

161

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.

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.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The Financial Audit Committee of AES pre-approves the audit and non-audit services provided by the independent auditors for itself and its subsidiaries, including IPALCO and its subsidiaries. The AES Financial Audit Committee maintained its policy established in 2002 within which to judge if the independent auditor may be eligible to provide certain services outside of its main role as outside auditor. Services within the established framework include audit and related services and certain tax services. Services outside of the framework require AES Financial Audit Committee approval prior to the performance of the service. The Sarbanes-Oxley Act of 2002 addresses auditor independence and this framework is consistent with the provisions of the Act. No services performed by the independent auditor with respect to IPALCO and its subsidiaries were approved after the fact by the AES Financial Audit Committee other than those that were considered to be de minimis and approved in accordance with Regulation 2-01(c)(7)(i)(C) to Regulation S-X of the Exchange Act.

In addition to the pre-approval policies of the AES Financial Audit Committee, the IPALCO Board of Directors has established a pre-approval policy for audit, audit related, and certain tax and other non-audit services. The Board of Directors will specifically approve the annual audit services engagement letter, including terms and fees, with the independent auditor. Other audit, audit related and tax consultation services are specifically identified in the pre-approval policy and the policy is subject to review at least annually. This pre-approval allows management to request the specified services on an as-needed basis during the year. Any such services are reviewed with the Board of Directors on a timely basis. Any audit or non-audit services that involve a service not listed on the pre-approval list must be specifically approved by the Board of Directors prior to commencement of such work. No services were approved after the fact by the IPALCO Board of Directors other than those that were considered to be de minimis and approved in accordance with Regulation 2-01 (c)(7)(i)(c) to Regulation S-X of the Exchange Act.

Audit fees are fees billed or expected to be billed by our principal accountant for professional services for the audit of the Financial Statements, included in this Annual Report on Form 10-K and review of financial statements included in IPALCO’s quarterly reports on Form 10-Q, services that are normally provided by our principal accountants in connection with statutory, regulatory or other filings or engagements or any other service performed to comply with generally accepted auditing standards and include comfort and consent letters in connection with SEC filings and financing transactions.

The following table lists fees billed to IPALCO for products and services provided by our principal accountants:


	Years Ended December 31,
	2023		2022
Audit Fees	$	1,442,837	$	945,033
Audit Related Fees:
Fees for the audit of AES Indiana’s employee benefit plans	70,000		68,096


Other	10,000		8,500
Total Principal Accountant Fees and Services	$	1,522,837	$	1,021,629

162

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES

(a) Index to the financial statements, supplementary data and financial statement schedules


IPALCO Enterprises, Inc. and Subsidiaries – Consolidated Financial Statements			Page
Report of Independent Registered Public Accounting Firm – 2023, 2022 and 2021 (PCAOB ID: i 42)			60
Consolidated Statements of Operations for the Years Ended December 31, 2023, 2022 and 2021			63
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2023, 2022, and 2021			64
Consolidated Balance Sheets as of December 31, 2023 and 2022			65
Consolidated Statements of Cash Flows for the Years Ended December 31, 2023, 2022 and 2021			66
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2023, 2022 and 2021			67
Notes to Consolidated Financial Statements			68
Schedule I – Condensed Financial Information of Registrant			166
Schedule II – Valuation and Qualifying Accounts and Reserves			175

AES Indiana – Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm – 2023, 2022 and 2021 (PCAOB ID: i 42)			112
Consolidated Statements of Operations for the Years Ended December 31, 2023, 2022 and 2021			115
Consolidated Balance Sheets as of December 31, 2023 and 2022			116
Consolidated Statements of Cash Flows for the Years Ended December 31, 2023, 2022 and 2021			117
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2023, 2022 and 2021			118
Notes to Consolidated Financial Statements			119
Schedule II – Valuation and Qualifying Accounts and Reserves			175

163


(b) Exhibits

Exhibit No.			Document
3.1			Third Amended and Restated Articles of Incorporation of IPALCO Enterprises, Inc. (Incorporated by reference to Exhibit No. 3.1 to IPALCO’s Form 8-K dated as of February 18, 2015)
3.2			Amended and Restated By-Laws of IPALCO Enterprises, Inc. (Incorporated by reference to Exhibit No. 3.2 to IPALCO’s Form 8-K dated as of February 18, 2015)
4.1			Pledge Agreement between IPALCO Enterprises, Inc. and The Bank of New York Mellon Trust Company, N.A. dated as of November 14, 2001 (Incorporated by reference to Exhibit No 4.1 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
4.2			Mortgage and Deed of Trust, dated as of May 1, 1940, between IPL and the Bank of New York Mellon Trust Company, NA, as successor in interest to American National Bank & Trust Company of Chicago, Trustee (Incorporated by reference to Exhibit No. 4.2 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
4.3			The following supplemental indentures to the Mortgage and Deed of Trust referenced in 4.2 above:
			Third Supplemental Indenture, dated as of April 1, 1949 (Incorporated by reference to Exhibit No. 4.3 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
			Tenth Supplemental Indenture, dated as of October 1, 1960 (Incorporated by reference to Exhibit No. 4.3 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
			Eighteenth Supplemental Indenture, dated as of February 15, 1974 (Incorporated by reference to Exhibit No. 4.3 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
			Forty-Eighth Supplemental Indenture, dated as of January 1, 2004 (Incorporated by reference to Exhibit No. 4.3 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
			Fifty-Third Supplemental Indenture, dated as of October 1, 2006 (Incorporated by reference to Exhibit No. 4.3 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
			Fifty-Fourth Supplemental Indenture, dated as of June 1, 2007 (Incorporated by reference to Exhibit No. 4.3 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
			Sixtieth Supplemental Indenture, dated as of November 1, 2011 (Incorporated by reference to Exhibit No. 4.3 to IPALCO’s December 31, 2011 Form 10-K)
			Sixty-First Supplemental Indenture, dated as of June 1, 2013 (Incorporated by reference to Exhibit No. 4.1 to IPALCO’s June 30, 2013 Form 10-Q)
			Sixty-Second Supplemental Indenture, dated as of June 1, 2014 (Incorporated by reference to Exhibit No. 4.1 to IPALCO’s June 30, 2014 Form 10-Q)
			Sixty-Third Supplemental Indenture, dated as of September 1, 2015 (Incorporated by reference to Exhibit No. 4.3 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on September 28, 2015)
			Sixty-Fourth Supplemental Indenture, dated as of May 1, 2016 (Incorporated by reference to Exhibit No. 4.1 to IPALCO’s June 30, 2016 Form 10-Q)
			Sixty-Fifth Supplemental Indenture, dated as of December 1, 2016 (Incorporated by reference to Exhibit No. 4.3 to IPALCO’s December 31, 2016 Form 10-K)
			Sixty-Sixth Supplemental Indenture, dated as of November 1, 2018 (Incorporated by reference to Exhibit No. 4.3 to IPALCO's December 31, 2018 Form 10-K)
			Sixty-Seventh Supplemental Indenture, dated as of December 1, 2020 (Incorporated by reference to Exhibit No. 4.3A to IPALCO's December 31, 2020 Form 10-K)
			Sixty-Eighth Supplemental Indenture, dated as of December 1, 2020 (Incorporated by reference to Exhibit No. 4.3B to IPALCO's December 31, 2020 Form 10-K)
			Sixty-Ninth Supplemental Indenture, dated as of July 1, 2021 (Incorporated by reference to Exhibit No. 4.1 to IPALCO's June 30, 2021 Form 10-Q)
			Seventieth Supplemental Indenture, dated as of July 1, 2021 (Incorporated by reference to Exhibit No. 4.2 to IPALCO's June 30, 2021 Form 10-Q)
			Seventy-First Supplemental Indenture, dated as of November 15, 2022 (Incorporated by reference to Exhibit No. 4.3 to IPALCO's December 31, 2022 Form 10-K)
4.4			Indenture between IPALCO Enterprises, Inc. and U.S. Bank, National Association, as Trustee, dated August 22, 2017 for IPALCO’s 3.70% Senior Secured Notes due 2024 (Incorporated by reference to Exhibit No. 4.1 to IPALCO’s August 22, 2017 Form 8-K)
4.5			Pledge Agreement Supplement between IPALCO Enterprises, Inc. and The Bank of New York Mellon trust Company, N.A., as Collateral Agent, dated August 22, 2017 to the Pledge Agreement between IPALCO Enterprises, Inc. and The Bank of New York Mellon Trust Company dated November 14, 2001, as amended (Incorporated by reference to Exhibit No. 4.2 to IPALCO’s August 22, 2017 Form 8-K)
4.6			Indenture between IPALCO Enterprises, Inc. and U.S. Bank National Association, as Trustee, dated April 14, 2020 for the 4.250% Senior Secured Notes due 2030 (Incorporated by reference to Exhibit No. 4.1 to IPALCO's April 14, 2020 Form 8-K)
4.7			Pledge Agreement Supplement between IPALCO Enterprises, Inc. and The Bank of New York Mellon Trust Company, N.A., as Collateral Agent, dated April 14, 2020 to the Pledge Agreement between IPALCO Enterprises, Inc. and The Bank of New York Mellon Trust Company dated November 14, 2001, as amended and supplemented (Incorporated by reference to Exhibit No. 4.2 to IPALCO's April 14, 2020 Form 8-K)
10.1			Interconnection Agreement, dated April 1, 2008, between American Electric Power Service Corporation, as agent for Indiana Michigan Power Company, and IPL (Incorporated by reference to Exhibit No. 10.1 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)

164


10.2			Interconnection Agreement, dated December 2, 1968, between IPL and Southern Indiana Gas and Electric Company as modified through Modification Number 11 (Incorporated by reference to Exhibit No. 10.2 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
10.3			Interconnection Agreement dated December 1, 1981, between IPL and Hoosier Energy Rural Electric Cooperative, Inc., as modified through Modification 6 (Incorporated by reference to Exhibit No. 10.3 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
10.4			Tenth Supplemental Agreement to the Interconnection Agreement between IPL and PSI Energy, Inc., dated as of June 26, 2002, amending and completely restating prior agreements (Incorporated by reference to Exhibit No. 10.4 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
10.5			$350,000,000 Revolving Credit Facility Amended and Restated Credit Agreement, dated December 22, 2022, among Indianapolis Power & Light Company, each lender from time to time party thereto, PNC Bank, National Association, as Administrative Agent, PNC Capital Markets LLC, as Joint Bookrunner and Joint Lead Arranger, U.S. Bank, National Association, as Syndication Agent, Joint Bookrunner and Joint Lead Arranger and The Huntington National Bank, as Documentation Agent (Incorporated by reference to Exhibit 10.1 to IPALCO's Current Report on Form 8-K filed on December 23, 2022)
10.6			$300,00 0,000 Term Loan Agreement by and among Indianapolis Power & Light Company, d/b/a AES Indiana the Le nders Party Hereto, PNC Bank, Na tional Association, as Administrative Agent, PNC Capital Markets LLC, as Bookrunn er and Joint Lead Arranger, U.S. Bank Nati onal Association, as Syndication Agent and Joint Lead Arranger, and The Huntington National Bank, as Documentation Agent and Joint Lead Arranger, dated as of November 21, 2023
10.7			Subscription Agreement by and between IPALCO and CDP Infrastructures Fund G.P., a wholly owned subsidiary of La Caisse de dépȏt et placement du Québec dated December 14, 2014 (Incorporated by reference to Exhibit 10.10 to IPALCO’s December 31, 2014 10-K/A)
10.8			IPALCO’s Shareholders’ Agreement by and among AES U.S. Investments, Inc., IPALCO Enterprises, Inc. and CDP Infrastructures Fund G.P. dated as of February 11, 2015 (Incorporated by reference to Exhibit No. 10.1 to IPALCO’s March 31, 2015 10-Q)
10.9			The AES Corporation 2023 Long Term Compensation Plan , as amended and restated, dated October 1 1 , 2023 (Incorporated by reference to Exhibit 10.5 of The AES Corporation’s Form 10-K for the year ended December 31, 2023)
10.10			The AES Corporation Performance Incentive Plan, as amended and restated on April 23, 2015 (Incorporated by reference to Exhibit 99.2 of The AES Corporation’s Form 8-K filed on April 23, 2015)
10.11			The AES Corporation Severance Plan, as amended and restated on August 4, 2017 (Incorporated by reference to Exhibit 10.1 of The AES Corporation’s Form 10-Q for the quarter ended June 30, 2017)
10.12			The AES Corporation Restoration Supplemental Retirement Plan, as amended and restated, effective October 1 0 , 20 23 (Incorporated by reference to Exhibit 10.1 2 of The AES Corporation’s Form 10-K for the year ended December 31, 2023 )
10.13			Form of AES Performance Stock Unit Award Agreement under The AES Corporation 2003 Long Term Compensation Plan (Incorporated by reference to Exhibit 10.13 of The AES Corporation’s Form 10-K for the year ended December 31, 2015)
10.14			Form of AES Restricted Stock Unit Award Agreement under The AES Corporation 2003 Long Term Compensation Plan (Incorporated by reference to Exhibit 10.14 of The AES Corporation’s Form 10-K for the year ended December 31, 2019)
10.15			Form of AES Performance Unit Award Agreement under The AES Corporation 2003 Long Term Compensation Plan (Incorporated by reference to Exhibit 10.15 of The AES Corporation’s Form 10-K for the year ended December 31, 2015)
10.16			Form of AES Nonqualified Stock Option Award Agreement under The AES Corporation 2003 Long Term Compensation Plan (Incorporated by reference to Exhibit 10.4 of The AES Corporation’s Form 10-Q for the quarter ended June 30, 2015)
10.17			Form of AES Performance Cash Unit Award Agreement under The AES Corporation 2003 Long Term Compensation Plan (Incorporated by reference to Exhibit 10.17 of The AES Corporation’s Form 10-K for the year ended December 31, 2019)
10.18			The AES Corporation Amended and Restated Executive Severance Plan dated October 5, 2018 is incorporated by reference to Exhibit 10.1 of the AES Corporation's Form 10-Q for the quarter ended September 30, 2018)
21			Subsidiaries of IPALCO Enterprises, Inc.
31.1			Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2			Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1			Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2			Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS			XBRL Instance Document (furnished herewith as provided in Rule 406T of Regulation S-T)
101.SCH			XBRL Taxonomy Extension Schema Document (furnished herewith as provided in Rule 406T of Regulation S-T)
101.CAL			XBRL Taxonomy Extension Calculation Linkbase Document (furnished herewith as provided in Rule 406T of Regulation S-T)
101.DEF			XBRL Taxonomy Extension Definition Linkbase Document (furnished herewith as provided in Rule 406T of Regulation S-T)
101.LAB			XBRL Taxonomy Extension Label Linkbase Document (furnished herewith as provided in Rule 406T of Regulation S-T)
101.PRE			XBRL Taxonomy Extension Presentation Linkbase Document (furnished herewith as provided in Rule 406T of Regulation S-T)

165

Schedules other than those listed below are omitted as the information is either not applicable, not required, or has been furnished in the financial statements or notes thereto included in Item 8 hereof.

SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF REGISTRANT

IPALCO ENTERPRISES, INC.

Schedule I – Condensed Financial Information of Registrant

Unconsolidated Statements of Operations

2023

2022

2021

(In Thousands)

OTHER INCOME / (EXPENSE), NET:

Equity in income of subsidiaries

i 116,190

i 126,466

i 147,030

Interest expense

( i 43,877)

( i 43,805)

( i 41,380)

Other expense, net

( i 121)

( i 571)

( i 45)

Total other income, net

i 72,192

i 82,090

i 105,605

INCOME FROM OPERATIONS BEFORE INCOME TAX

i 72,192

i 82,090

i 105,605

Income tax benefit

( i 10,928)

( i 11,027)

( i 10,364)

NET INCOME

i 83,120

i 93,117

i 115,969

See Notes to Schedule I.

166

IPALCO ENTERPRISES, INC.

Schedule I - Condensed Financial Information of Registrant

Unconsolidated Statements of Comprehensive Income

2023

2022

2021

(In Thousands)

NET INCOME

i 83,120

i 93,117

i 115,969

Derivative activity:

Change in derivative fair value, net of income tax effect of $( i 528), $( i 15,309) and $( i 3,441), for each respective period

i 1,594

i 46,245

i 10,393

Reclassification to earnings, net of income tax effect of $( i 1,798), $( i 1,798) and $( i 1,199), for each respective period

i 5,431

i 3,620

Net change in fair value of derivatives

i 7,025

i 51,676

i 14,013

Other comprehensive income

i 7,025

i 51,676

i 14,013

COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON STOCK

i 90,145

i 144,793

i 129,982

See Notes to Schedule I.

167

IPALCO ENTERPRISES, INC.

Schedule I – Condensed Financial Information of Registrant

Unconsolidated Balance Sheets

(In Thousands)

ASSETS

CURRENT ASSETS:

Cash and cash equivalents

i 537

i 191

Taxes receivable

31,341

11,318

Derivative assets, current

i 14,294

i —

Prepayments and other current assets

i 7,626

i 7,509

Total current assets

i 53,798

i 19,018

OTHER NON-CURRENT ASSETS:

Investment in subsidiaries

i 1,921,548

i 1,945,556

Derivative assets, non-current

i —

i 12,172

Other non-current assets

i 3,540

i 3,211

Total other non-current assets

i 1,925,088

i 1,960,939

TOTAL ASSETS

i 1,978,886

i 1,979,957

LIABILITIES AND SHAREHOLDERS' EQUITY

CURRENT LIABILITIES:

Short-term and current portion of long-term debt

i 404,474

i —

Accounts payable

i —

i 87

Accrued interest

i 8,360

Total current liabilities

i 412,834

i 8,447

NON-CURRENT LIABILITIES:

Long-term debt

i 470,653

i 873,663

Deferred tax liability - long-term

i 18,931

i 7,329

Total non-current liabilities

i 489,584

i 880,992

Total liabilities

i 902,418

i 889,439

SHAREHOLDERS' EQUITY

Paid in capital

i 1,021,992

i 1,068,357

Accumulated other comprehensive income

i 29,294

i 22,269

Retained earnings / (accumulated deficit)

i 25,182

( i 108)

Total shareholders' equity

i 1,076,468

i 1,090,518

TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY

i 1,978,886

i 1,979,957

See Notes to Schedule I.

168

IPALCO ENTERPRISES, INC.

Schedule I – Condensed Financial Information of Registrant

Unconsolidated Statements of Cash Flows

2023

2022

2021

(In Thousands)

CASH FLOWS FROM OPERATIONS:

Net income

i 83,120

i 93,117

i 115,969

Adjustments to reconcile net income to net cash

provided by operating activities:

Equity in earnings of subsidiaries

( i 116,190)

( i 126,466)

( i 147,030)

Cash dividends received from subsidiary companies

i 140,200

i 127,200

i 155,700

Amortization of deferred financing costs and debt premium

i 1,474

i 1,403

i 1,379

Deferred income taxes – net

i 9,276

( i 121)

( i 5)

Change in certain assets and liabilities:

Accounts payable

( i 23)

( i 194)

( i 85)

Accrued taxes payable/receivable

( i 20,022)

( i 2,406)

i 2,940

Other – net

i 6,798

i 7,744

i 4,265

Net cash provided by operating activities

i 104,633

i 100,277

i 133,133

CASH FLOWS FROM INVESTING ACTIVITIES:

Investment in subsidiaries

i —

( i 253,000)

( i 275,000)

Net cash used in investing activities

i —

( i 253,000)

( i 275,000)

CASH FLOWS FROM FINANCING ACTIVITIES:

Repayments of loans to subsidiary

i —

( i 6,110)

Distributions to shareholders

( i 104,287)

( i 101,986)

( i 131,476)

Equity contributions from shareholders

i —

i 253,000

i 275,000

Deferred financing costs paid and other

i —

( i 2)

( i 62)

Net cash (used in) provided by financing activities

( i 104,287)

i 151,012

i 137,352

Net change in cash, cash equivalents and restricted cash

i 346

( i 1,711)

( i 4,515)

Cash, cash equivalents and restricted cash at beginning of period

i 191

i 1,902

i 6,417

Cash, cash equivalents and restricted cash at end of period

i 537

i 191

i 1,902

Supplemental disclosures of cash flow information:

Cash paid during the period for:

Interest (net of amount capitalized)

i 35,569

i 35,173

i 35,172

Income taxes

i —

i 31,000

i 27,500

See Notes to Schedule I.

169

IPALCO ENTERPRISES, INC.

Schedule I - Condensed Financial Information of Registrant

Unconsolidated Statements of Changes in Equity (Deficit)

Paid in Capital

Accumulated Other Comprehensive Income (Loss)

Retained Earnings (Accumulated
Deficit)

Total Shareholders' Equity

(In Thousands)

Balance at January 1, 2021

i 588,966

( i 43,420)

( i 24,558)

i 520,988

Net comprehensive income

—

i 14,013

i 115,969

i 129,982

Distributions to shareholders(1)

( i 15,507)

—

( i 115,969)

( i 131,476)

Contributions from shareholders

275,000

—

275,000

Other

i 106

—

i 106

Balance at December 31, 2021

i 848,565

( i 29,407)

( i 24,558)

i 794,600

Net comprehensive income

—

i 51,676

i 93,117

i 144,793

Distributions to shareholders(1)

( i 33,319)

—

( i 68,667)

( i 101,986)

Contributions from shareholders

i 253,000

—

i 253,000

Other

i 111

—

i 111

Balance at December 31, 2022

i 1,068,357

i 22,269

( i 108)

i 1,090,518

Net comprehensive income

—

i 7,025

i 83,120

i 90,145

Distributions to shareholders(1)

( i 46,457)

—

( i 57,830)

( i 104,287)

Other

i 92

—

i 92

Balance at December 31, 2023

i 1,021,992

i 29,294

i 25,182

i 1,076,468

1) IPALCO made return of capital payments of $ i 46.5 million, $ i 33.3 million and $ i 15.5 million in 2023, 2022 and 2021, respectively, for the portion of current year distributions to shareholders in excess of current year net income at the time of distribution.

See Notes to Schedule I.

170

IPALCO ENTERPRISES, INC.

Schedule I – Condensed Financial Information of Registrant

Notes to Schedule I

1. i 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

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.

Financial Assets

VEBA Assets

IPALCO has VEBA investments that are to be used to fund certain employee postretirement health care benefit plans. These assets are primarily comprised of open-ended mutual funds, which are valued using the net assets value per unit. These investments are recorded at fair value within "Other non-current assets" on the accompanying Unconsolidated Balance Sheets and classified as equity securities. All changes to fair value on the VEBA investments are included in income in the period that the changes occur. These changes to fair value were not material for the years ended December 31, 2023, 2022, or 2021. Any unrealized gains or losses are recorded in "Other income / (expense), net" on the accompanying Unconsolidated Statements of Operations.

171

Financial Assets

Interest Rate Hedges

IPALCO's interest rate hedges have a combined notional amount of $ i 400.0 million. All changes in the market value of the interest rate hedges are recorded in AOCI. See also Note 3, "Derivative Instruments and Hedging Activities - Cash Flow Hedges" for further information.

Summary

The fair value of assets at December 31, 2023 and 2022 measured on a recurring basis and the respective category within the fair value hierarchy for IPALCO was determined as follows:

Fair Value as of December 31, 2023

Fair Value as of December 31, 2022

Level 1

Level 2

Level 3

Total

Level 1

Level 2

Level 3

Total

(In Thousands)

Financial assets:

VEBA investments:

Money market funds

i 127

i —

i 127

i 5

i —

i 5

Mutual funds

i 3,425

i —

i 3,425

i 3,223

i —

i 3,223

Total VEBA investments

i 3,552

i —

i 3,552

i 3,228

i —

i 3,228

Interest rate hedges

i —

i 14,294

i —

i 14,294

i —

i 12,172

i —

i 12,172

Total financial assets measured at fair value

i 3,552

i 14,294

i —

i 17,846

i 3,228

i 12,172

i —

i 15,400

Financial Instruments not Measured at Fair Value in the Unconsolidated Balance Sheets

Debt

The following table shows the face value and the fair value of fixed-rate indebtedness (Level 2) for the periods ending:

Face Value

Fair Value

Face Value

Fair Value

(In Thousands)

Fixed-rate

i 880,000

i 839,471

i 880,000

i 816,411

Total indebtedness

i 880,000

i 839,471

i 880,000

i 816,411

The difference between the face value and the carrying value of this indebtedness represents the following:

•unamortized deferred financing costs of $ i 4.6 million and $ i 5.9 million at December 31, 2023 and 2022, respectively; and

•unamortized discounts of $ i 0.3 million and $ i 0.4 million at December 31, 2023 and 2022, respectively.

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3. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

We use derivatives principally to manage the interest rate risk associated with refinancing our long-term debt. The derivatives that we use to economically hedge these risks are governed by our risk management policies for forward and futures contracts. Our net positions are continually assessed within our structured hedging programs to determine whether new or offsetting transactions are required. We monitor and value derivative positions monthly as part of our risk management processes. We use published sources for pricing, when possible, to mark positions to market. All of our derivative instruments are used for risk management purposes and are designated as cash flow hedges if they qualify under ASC 815 for accounting purposes.

At December 31, 2023, IPALCO's outstanding derivative instruments were as follows:

Commodity

Accounting Treatment (a)

Unit

Notional
(in thousands)

Sales
(in thousands)

Net Notional
(in thousands)

Interest rate hedges

Designated

USD

i 400,000

i —

i 400,000

(a) Refers to whether the derivative instruments have been designated as a cash flow hedge.

Cash Flow Hedges

In March 2019, we entered into i three forward interest rate swaps to hedge the interest risk associated with refinancing the IPALCO 2020 maturities. The i three interest rate swaps had a combined notional amount of $ i 400.0 million. In April 2020, we de-designated the swaps as cash flow hedges and froze the AOCL of $ i 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 $ i 400.0 million and will be settled when the 2024 IPALCO Notes are refinanced. The $ i 72.3 million of AOCL associated with the interest rate swaps through the date of the amendment will be amortized out of AOCL into interest expense over the remaining life of the 2030 IPALCO Notes, while any changes in fair value associated with the amended interest rate swaps will be recognized in AOCL going forward.

The following tables provide information on gains or losses recognized in AOCL for the cash flow hedges for the period indicated:

Interest Rate Hedges for the Year Ended December 31,

$ in thousands (net of tax)

2023

2022

2021

Beginning accumulated derivative gain / (loss) in AOCL

i 22,269

( i 29,407)

( i 43,420)

Net gains associated with current period hedging transactions

i 1,594

i 46,245

i 10,393

Net losses reclassified to interest expense

i 5,431

i 3,620

Ending accumulated derivative gain / (loss) in AOCI / (AOCL)

i 29,294

i 22,269

( i 29,407)

Loss expected to be reclassified to earnings in the next twelve months

( i 5,375)

Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)

i 9

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The following table summarizes the fair value, balance sheet classification and hedging designation of IPALCO's derivative instruments:


			December 31,
Commodity	Hedging Designation	Balance sheet classification	2023		2022
Interest rate hedges	Cash Flow Hedge	Derivative assets, current	$	14,294	$	—
Interest rate hedges	Cash Flow Hedge	Derivative assets, non-current	$	i —	$	i 12,172

4. DEBT

The following table presents IPALCO’s long-term indebtedness:

December 31,

Series

Due

2023

2022

(In Thousands)

Long-Term Debt

i 3.70% Senior Secured Notes

September 2024

i 405,000

i 4.25% Senior Secured Notes

May 2030

i 475,000

Unamortized discount – net

( i 319)

( i 425)

Deferred financing costs – net

( i 4,554)

( i 5,912)

Total long-term debt

i 875,127

i 873,663

Less: current portion of long-term debt

i 405,000

i —

Net long-term debt

i 470,127

i 873,663

IPALCO’s Senior Secured Notes and Term Loan

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SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

IPALCO ENTERPRISES, INC. and SUBSIDIARIES

Valuation and Qualifying Accounts and Reserves

For the Years Ended December 31, 2023, 2022 and 2021

(In Thousands)

Column A – Description

Column B

Column C – Additions

Column D – Deductions

Column E

Balance at Beginning
of Period

Charged to
Income

Charged to Other
Accounts

Net
Write-offs

Balance at
End of Period

Year ended December 31, 2023

Accumulated Provisions Deducted from

Assets – Doubtful Accounts

i 1,117

i 8,930

i —

i 7,764

i 2,283

Deducted from Inventories

Valuation Allowance for Materials and Supplies

i 5,160

i 736

i —

i 2,456

i 3,440

Year ended December 31, 2022

Accumulated Provisions Deducted from

Assets – Doubtful Accounts

i 647

i 7,478

i —

i 7,008

i 1,117

Deducted from Inventories

Valuation Allowance for Materials and Supplies

i 3,107

i 2,053

i —

i 5,160

Year ended December 31, 2021

Accumulated Provisions Deducted from

Assets – Doubtful Accounts

i 3,155

i 3,940

i —

i 6,448

i 647

Deducted from Inventories

Valuation Allowance for Materials and Supplies

i 6,133

i 758

i —

i 3,784

i 3,107

AES INDIANA and SUBSIDIARIES

Valuation and Qualifying Accounts and Reserves

For the Years Ended December 31, 2023, 2022 and 2021

(In Thousands)

Column A – Description

Column B

Column C – Additions

Column D – Deductions

Column E

Balance at Beginning
of Period

Charged to
Income

Charged to Other
Accounts

Net
Write-offs

Balance at
End of Period

Year ended December 31, 2023

Accumulated Provisions Deducted from

Assets – Doubtful Accounts

i 1,117

i 8,930

i —

i 7,764

i 2,283

Deducted from Inventories

Valuation Allowance for Materials and Supplies

i 5,160

i 736

i —

i 2,456

i 3,440

Year ended December 31, 2022

Accumulated Provisions Deducted from

Assets – Doubtful Accounts

i 647

i 7,478

i —

i 7,008

i 1,117

Deducted from Inventories

Valuation Allowance for Materials and Supplies

i 3,107

i 2,053

i —

i 5,160

Year ended December 31, 2021

Accumulated Provisions Deducted from

Assets – Doubtful Accounts

i 3,155

i 3,940

i —

i 6,448

i 647

Deducted from Inventories

Valuation Allowance for Materials and Supplies

i 6,133

i 758

i —

i 3,784

i 3,107

ITEM 16. FORM 10-K SUMMARY

None.

175

SIGNATURES

Pursuant to the requirements of Section 13 or 15 (d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

IPALCO ENTERPRISES, INC.

(Registrant)

Date: February 26, 2024 /s/ Kenneth J. Zagzebski

Kenneth J. Zagzebski

President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature

Capacity

Date

/s/ Kenneth J. Zagzebski

President, Chief Executive Officer, Director and Chairman (Principal Executive Officer)

Kenneth J. Zagzebski

/s/ Ricardo Manuel Falú

Director

Ricardo Manuel Falú

/s/ Bernerd Da Santos

Director

Bernerd Da Santos

/s/ Paul L. Freedman

Director

Paul L. Freedman

/s/ Susan Harcourt

Director

Susan Harcourt

/s/ Marc Michael

Director

Marc Michael

/s/ Stephen Coughlin

Director

Stephen Coughlin

/s/ Tish Mendoza

Director

Tish Mendoza

/s/ Frédéric Lesage

Director

Frédéric Lesage

/s/ Olivier Roy Durocher

Director

Olivier Roy Durocher

/s/ Sherry Kohan

Interim Vice President and Chief Financial Officer (Principal Financial Officer)

Sherry Kohan

/s/ Karin M. Mehringer

Controller (Principal Accounting Officer)