Ipalco Enterprises 10-K 26 Feb 24 2023 FY Annual report Financial data

Cover Document

Cover Document $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($) shares
Entity Information [Line Items]
Entity Central Index Key	0000728391
Entity Filer Category	Non-accelerated Filer
Document Annual Report	true
Current Fiscal Year End Date	--12-31
Document Transition Report	false
Entity Registrant Name	IPALCO ENTERPRISES, INC.
Entity Incorporation, State or Country Code	IN
Entity File Number	1-8644
Entity Tax Identification Number	35-1575582
Entity Address, Address Line One	One Monument Circle
Entity Address, City or Town	Indianapolis
Entity Address, State or Province	IN
Entity Address, Postal Zip Code	46204
City Area Code	317
Local Phone Number	261-8261
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	Yes
Entity Current Reporting Status	No
Entity Interactive Data Current	Yes
Entity Small Business	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding	108,907,318
Document Fiscal Year Focus	2023
Document Fiscal Period Focus (i.e. Q1,Q2,Q3,FY)	FY
Amendment Flag	false
Entity Public Float | $	$ 0
ICFR Auditor Attestation Flag	false
ICFR Auditor Attestation Flag	false
Document Type	10-K
Document Period End Date	Dec. 31, 2023
AES U.S. Investments [Member]
Entity Information [Line Items]
Entity Common Stock, Shares Outstanding	89,685,177
CDPQ [Member]
Entity Information [Line Items]
Entity Common Stock, Shares Outstanding	19,222,141

Audit Information

Audit Information	12 Months Ended
	Dec. 31, 2023
Auditor [Line Items]
Auditor Name	Ernst & Young LLP
Auditor Firm ID	42
Auditor Location	Indianapolis, Indiana

Consolidated Statements Of Inco

Consolidated Statements Of Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
REVENUE	$ 1,649,917	$ 1,791,711	$ 1,426,132
OPERATING COSTS AND EXPENSES:
Fuel	494,000	568,676	255,817
Utilities Operating Expense, Purchased Power	159,908	199,860	175,025
Utilities Operating Expense, Maintenance and Operations	477,880	493,674	449,746
Depreciation and amortization	287,863	266,504	256,085
Taxes other than income taxes	24,864	33,048	44,419
Other Operating Income (Expense), Net	(361)	3,201	5,630
Operating Expenses	1,444,154	1,558,561	1,175,462
Operating Income (Loss)	205,763	233,150	250,670
OTHER (EXPENSE) / INCOME, NET:
Allowance for equity funds used during construction	9,315	4,784	5,412
Interest Expense	(142,926)	(131,232)	(125,626)
Other (expense) / income, net	(410)	11,783	17,667
Total other expense, net	(134,021)	(114,665)	(102,547)
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest	71,742	118,485	148,123
Income tax expense	14,715	21,859	28,941
NET INCOME	57,027	96,626	119,182
Dividends on and redemption of preferred stock	0	3,509	3,213
NET INCOME ATTRIBUTABLE TO COMMON STOCK	83,120	93,117	115,969
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Noncontrolling Interest	(26,093)	0	0
Net Income (Loss) Attributable to Noncontrolling Interest	(26,093)
Indianapolis Power And Light Company
REVENUE	1,649,917	1,791,711	1,426,132
OPERATING COSTS AND EXPENSES:
Fuel	494,000	568,676	255,817
Utilities Operating Expense, Purchased Power	159,908	199,860	175,025
Utilities Operating Expense, Maintenance and Operations	477,497	493,454	449,317
Depreciation and amortization	287,863	266,504	256,085
Taxes other than income taxes	24,865	33,048	44,419
Other Operating Income (Expense), Net	(361)	(3,201)	(5,630)
Operating Expenses	1,443,772	1,558,341	1,175,033
Operating Income (Loss)	206,145	233,370	251,099
OTHER (EXPENSE) / INCOME, NET:
Allowance for equity funds used during construction	9,315	4,784	5,412
Interest Expense	(99,051)	(87,428)	(84,257)
Other (expense) / income, net	(646)	12,136	17,294
Total other expense, net	(90,382)	(70,508)	(61,551)
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest	115,763	162,862	189,548
Income tax expense	25,666	32,887	39,305
NET INCOME	90,097	129,975	150,243
Dividends on and redemption of preferred stock	0	3,509	3,213
NET INCOME ATTRIBUTABLE TO COMMON STOCK	116,190	126,466	147,030
Net Income (Loss) Attributable to Noncontrolling Interest	(26,093)
Electricity [Member]
REVENUE	1,649,917	1,791,711	1,426,132
Electricity [Member] | Indianapolis Power And Light Company
REVENUE	$ 1,649,917	$ 1,791,711	$ 1,426,132

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
CURRENT ASSETS:
Cash and cash equivalents	$ 28,579	$ 201,548
Restricted Cash and Cash Equivalents	5	5
Accounts Receivable, after Allowance for Credit Loss, Current	233,921	216,523
Inventory, Net	143,590	123,608
Regulatory assets	89,419	119,723
Income Taxes Receivable, Current	36,481	18,000
Derivative Asset, Current	15,682	7,545
Other Assets, Current	26,358	19,882
Total current assets	574,030	706,829
NON-CURRENT ASSETS:
Property, plant and equipment	7,082,443	6,982,314
Less: Accumulated depreciation	2,954,555	3,243,968
	4,127,888	3,738,346
Construction work in progress	359,014	294,985
Property, Plant and Equipment, Net	4,486,902	4,033,331
OTHER NON-CURRENT ASSETS:
Intangible assets - net	235,656	138,978
Regulatory assets, non-current	541,784	593,939
Assets for Plan Benefits, Defined Benefit Plan	41,172	33,611
Derivative Asset, Noncurrent	0	12,172
Other non-current assets	301,979	70,354
Total other non-current assets	1,120,591	849,054
TOTAL ASSETS	6,181,523	5,589,214
CURRENT LIABILITIES:
Short-term debt	899,159	0
Accounts payable	292,851	189,845
Accrued taxes	22,580	22,474
Accrued interest	33,639	33,447
Customer deposits	29,308	35,097
Regulatory liabilities	23,371	23,348
Accrued and other current liabilities	27,547	19,014
Total current liabilities	1,328,455	323,225
Long-term Debt and Lease Obligation	2,576,798	3,016,810
Deferred Income Tax Liabilities, Net	361,488	312,641
NON-CURRENT LIABILITIES:
Regulatory liabilities	527,224	612,585
Accrued other postretirement benefits	2,776	3,085
Asset retirement obligations	249,930	218,729
Other non-current liabilities	5,130	11,621
Total non-current liabilities	3,723,346	4,175,471
Liabilities	$ 5,051,801	$ 4,498,696
Common Stock, Shares Authorized	290,000,000
Common Stock, Shares, Outstanding	108,907,318	108,907,000
Common shareholders' equity:
Additional Paid in Capital	$ 1,021,992	$ 1,068,357
Accumulated Other Comprehensive Income (Loss), Net of Tax	29,294	22,269
Accumulated deficit	25,182	(108)
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	1,129,722	1,090,518
Equity, Attributable to Noncontrolling Interest	53,254	0
Total common shareholders' equity	1,076,468	1,090,518
TOTAL LIABILITIES AND EQUITY	6,181,523	5,589,214
Accounts receivable and unbilled revenue, allowance for doubtful accounts	2,283	1,117
Indianapolis Power And Light Company
CURRENT ASSETS:
Cash and cash equivalents	25,767	199,103
Restricted Cash and Cash Equivalents	5	5
Accounts Receivable, after Allowance for Credit Loss, Current	233,970	216,572
Inventory, Net	143,590	123,608
Regulatory assets	89,419	119,723
Income Taxes Receivable, Current	5,140	6,682
Other Assets, Current	27,741	27,422
Total current assets	525,627	693,110
NON-CURRENT ASSETS:
Property, plant and equipment	7,082,443	6,982,314
Less: Accumulated depreciation	2,954,555	3,243,968
	4,127,888	3,738,346
Construction work in progress	359,014	294,985
Property, Plant and Equipment, Net	4,486,902	4,033,331
OTHER NON-CURRENT ASSETS:
Intangible assets - net	235,656	138,978
Regulatory assets, non-current	541,784	593,939
Assets for Plan Benefits, Defined Benefit Plan	41,172	33,611
Other non-current assets	298,439	67,008
Total other non-current assets	1,117,051	833,536
TOTAL ASSETS	6,129,580	5,559,977
CURRENT LIABILITIES:
Short-term debt	494,685	0
Accounts payable	292,835	189,806
Accrued taxes	22,580	22,474
Accrued interest	25,245	25,054
Customer deposits	29,308	35,097
Regulatory liabilities	23,371	23,348
Accrued and other current liabilities	34,748	26,214
Total current liabilities	922,772	321,993
Long-term Debt and Lease Obligation	2,106,146	2,143,147
Deferred Income Tax Liabilities, Net	342,557	305,107
NON-CURRENT LIABILITIES:
Regulatory liabilities	527,224	612,585
Accrued other postretirement benefits	2,776	3,085
Asset retirement obligations	249,930	218,729
Other non-current liabilities	5,129	11,621
Total non-current liabilities	3,233,762	3,294,274
Liabilities	$ 4,156,534	$ 3,616,267
Common Stock, Shares Authorized	20,000,000
Common Stock, Shares, Outstanding	17,206,630	17,207,000
Common shareholders' equity:
Common Stock, Value, Issued	$ 324,537	$ 324,537
Additional Paid in Capital	1,193,199	1,193,107
Accumulated deficit	402,056	426,066
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	1,973,046	1,943,710
Equity, Attributable to Noncontrolling Interest	53,254	0
Total common shareholders' equity	1,919,792	1,943,710
TOTAL LIABILITIES AND EQUITY	6,129,580	5,559,977
Accounts receivable and unbilled revenue, allowance for doubtful accounts	$ 2,283	$ 1,117

Consolidated Statements Of Cash

Consolidated Statements Of Cash Flows - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$ 57,027,000	$ 96,626,000	$ 119,182,000
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	287,863,000	266,504,000	256,085,000
Amortization of deferred financing costs and debt discounts	3,880,000	3,914,000	3,915,000
Deferred income taxes and investment tax credit adjustments - net	32,653,000	(6,706,000)	(7,378,000)
Allowance for equity funds used during construction	(9,315,000)	(4,784,000)	(5,412,000)
Cash Acquired from Acquisition	0	0	(5,630,000)
Change in certain assets and liabilities:
Accounts receivable	(17,398,000)	(37,387,000)	(13,943,000)
Inventories	(30,171,000)	(47,489,000)	(12,017,000)
Prepayments and other current assets	(6,476,000)	19,056,000	(4,593,000)
Accounts payable	(46,993,000)	(32,038,000)	(21,417,000)
Accrued and other current liabilities	2,790,000	6,532,000	(13,017,000)
Accrued taxes payable/receivable	(18,375,000)	(5,858,000)	638,000
Accrued interest	192,000	2,813,000	(1,099,000)
Pension and other postretirement benefit assets and liabilities	1,625,000	(8,727,000)	(16,592,000)
Current and non-current regulatory assets and liabilities	54,358,000	38,863,000	(104,759,000)
Other non-current liabilities	(9,445,000)	(14,384,000)	10,446,000
Other - net	(4,268,000)	5,335,000	(2,026,000)
Net Cash Provided by (Used in) Operating Activities	391,933,000	346,346,000	225,217,000
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(902,705,000)	(496,510,000)	(291,510,000)
Project development costs	(4,462,000)	(3,910,000)	(1,304,000)
Cost of removal payments	(45,595,000)	(23,948,000)	(35,260,000)
Proceeds from Insurance Settlement, Investing Activities	4,900,000	0	0
Purchase of intangibles	(44,650,000)	0	(26,261,000)
Other	(361,000)	(719,000)	(14,380,000)
Net cash used in investing activities	(992,873,000)	(525,087,000)	(368,715,000)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings from revolving credit facilities	435,000,000	300,000,000	320,000,000
Repayments from revolving credit facilities	280,000,000	360,000,000	335,000,000
Short-term borrowings	300,000,000	200,000,000	0
Repayments of short-term borrowings	0	(200,000,000)	0
Long-term borrowings	0	350,000,000	95,000,000
Retirement of long-term borrowings, including early payment premium	0	0	(95,000,000)
Distributions to shareholders	(104,287,000)	(101,986,000)	(131,476,000)
Equity contributions from shareholders	0	253,000,000	275,000,000
Proceeds from (Payments to) Noncontrolling Interests	77,921,000	0	0
Redemption of preferred stock	0	(60,080,000)	0
Preferred dividends of subsidiary	0	(3,213,000)	(3,213,000)
Contributions from shareholders		253,000,000	275,000,000
Payments of deferred financing costs and discounts	(350,000)	(4,309,000)	(1,387,000)
Other	(313,000)	(35,000)	(131,000)
Net cash provided by financing activities	427,971,000	373,377,000	123,793,000
Net change in cash, cash equivalents and restricted cash	(172,969,000)	194,636,000	(19,705,000)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	28,584,000	201,553,000	6,917,000
Cash and Cash Equivalents, at Carrying Value	28,579,000	201,548,000
Cash paid during the period for:
Interest (net of amount capitalized)	129,113,000	115,277,000	118,052,000
Income taxes	0	31,000,000	27,500,000
Non-cash investing activities:
Accruals for capital expenditures	124,626,000	66,949,000	81,325,000
Right-of-Use Asset Obtained in Exchange for Finance Lease Liability	983,000	(3,402,000)	19,763,000
Change in Right-of-Use Asset Lease Liability	(1,408,000)	(3,402,000)	19,763,000
Indianapolis Power And Light Company
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	90,097,000	129,975,000	150,243,000
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	287,863,000	266,504,000	256,085,000
Amortization of deferred financing costs and debt discounts	2,406,000	2,511,000	2,536,000
Deferred income taxes and investment tax credit adjustments - net	23,582,000	(6,584,000)	(7,373,000)
Allowance for equity funds used during construction	(9,315,000)	(4,784,000)	(5,412,000)
Cash Acquired from Acquisition	0	0	(5,630,000)
Change in certain assets and liabilities:
Accounts receivable	(17,398,000)	(37,391,000)	(13,746,000)
Inventories	(30,171,000)	(47,489,000)	(12,017,000)
Prepayments and other current assets	(6,476,000)	19,016,000	(4,556,000)
Accounts payable	(47,016,000)	(32,232,000)	(21,502,000)
Accrued and other current liabilities	2,790,000	6,532,000	(13,017,000)
Accrued taxes payable/receivable	1,647,000	(3,452,000)	(2,302,000)
Accrued interest	192,000	2,813,000	(1,099,000)
Pension and other postretirement benefit assets and liabilities	1,625,000	(8,727,000)	(16,592,000)
Current and non-current regulatory assets and liabilities	54,358,000	38,863,000	(104,759,000)
Other non-current liabilities	(16,663,000)	(21,717,000)	5,566,000
Other - net	(4,074,000)	4,967,000	(1,645,000)
Net Cash Provided by (Used in) Operating Activities	427,479,000	373,269,000	247,784,000
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(902,705,000)	(496,510,000)	(291,510,000)
Project development costs	(4,462,000)	(3,910,000)	(1,304,000)
Cost of removal payments	(45,595,000)	(23,948,000)	(35,260,000)
Proceeds from Insurance Settlement, Investing Activities	4,900,000	0	0
Loan repayments from parents	0	0	6,110,000
Purchase of intangibles	44,650,000	0	26,261,000
Other	(361,000)	(719,000)	(14,380,000)
Net cash used in investing activities	(992,873,000)	(525,087,000)	(362,605,000)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings from revolving credit facilities	435,000,000	300,000,000	320,000,000
Repayments from revolving credit facilities	280,000,000	360,000,000	335,000,000
Short-term borrowings	300,000,000	200,000,000	0
Repayments of short-term borrowings	0	200,000,000	0
Long-term borrowings	0	350,000,000	95,000,000
Retirement of long-term borrowings, including early payment premium	0	0	(95,000,000)
Distributions to shareholders	(140,200,000)	(127,200,000)	(155,700,000)
Proceeds from (Payments to) Noncontrolling Interests	77,921,000	0	0
Redemption of preferred stock	0	60,080,000	0
Preferred dividends of subsidiary	0	(3,213,000)	(3,213,000)
Contributions from shareholders	0	253,000,000	275,000,000
Payments of deferred financing costs and discounts	(350,000)	(4,309,000)	(1,325,000)
Other	(313,000)	(33,000)	(131,000)
Net cash provided by financing activities	392,058,000	348,165,000	99,631,000
Net change in cash, cash equivalents and restricted cash	(173,336,000)	196,347,000	(15,190,000)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	25,772,000	199,108,000	2,761,000
Cash and Cash Equivalents, at Carrying Value	25,767,000	199,103,000
Cash paid during the period for:
Interest (net of amount capitalized)	93,544,000	80,104,000	82,880,000
Income taxes	0	39,500,000	40,800,000
Non-cash investing activities:
Accruals for capital expenditures	124,626,000	66,949,000	81,325,000
Right-of-Use Asset Obtained in Exchange for Finance Lease Liability	983,000	(3,402,000)	19,763,000
Change in Right-of-Use Asset Lease Liability	$ (1,408,000)	$ (3,402,000)	$ 19,763,000

Consolidated Statements Of Comm

Consolidated Statements Of Common Shareholders' Equity (Deficit) And Noncontrolling Interest - USD ($) $ in Thousands	Total	Corporate Stocks - Common [Member]	Paid In Capital [Member]	AOCI Attributable to Parent [Member]	Accumulated Deficit [Member]	Cumulative Preferred Stock Of Subsidiary [Member]	Indianapolis Power And Light Company	Indianapolis Power And Light Company Corporate Stocks - Common [Member]	Indianapolis Power And Light Company Paid In Capital [Member]	Indianapolis Power And Light Company Accumulated Deficit [Member]	Indianapolis Power And Light Company Cumulative Preferred Stock Of Subsidiary [Member]
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common Stock, Shares, Outstanding	108,907,000						17,207,000
Stockholders' Equity Attributable to Parent	$ 520,988	$ 0	$ 588,966	$ (43,420)	$ (24,558)		$ 1,424,893	$ 324,537	$ 664,886	$ 435,470
Equity, Attributable to Noncontrolling Interest						$ 59,784
Other Comprehensive Income (Loss), Net of Tax	14,013			14,013	0
Net income / (loss)	115,969				119,182		147,030
Preferred Stock Dividends, Income Statement Impact	3,213						3,213				$ 3,213
Payments of Ordinary Dividends, Preferred Stock and Preference Stock	(3,213)				(3,213)	(3,213)	(3,213)				(3,213)
Distributions to AES	(131,476)				(115,969)
Contributions from shareholders	275,000		275,000				275,000		275,000
Beginning Balance at Dec. 31, 2020											59,784
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Partners' Capital Account, Return of Capital			(15,507)
Net income	119,182						150,243			150,243
Dividends, Preferred Stock										3,213
Return of Capital			(15,500)
Cash dividends declared on common stock							(155,700)			(155,700)
Equity contributions from shareholders	275,000
Other	106		106				$ 107		107
Ending Balance at Dec. 31, 2021											59,784
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Comprehensive Income (Loss), Net of Tax, Attributable to Noncontrolling Interest	$ 119,182
Common Stock, Shares, Outstanding	108,907,000						17,207,000
Stockholders' Equity Attributable to Parent	$ 794,600		848,565	(29,407)	(24,558)		$ 1,691,330	324,537	939,993	426,800
Equity, Attributable to Noncontrolling Interest						59,784
Other Comprehensive Income (Loss), Net of Tax	51,676			51,676	0
Net income / (loss)	93,117				96,626		126,466
Preferred Stock Dividends, Income Statement Impact	3,509						3,509				3,213
Payments of Ordinary Dividends, Preferred Stock and Preference Stock	(3,213)				(3,213)	(3,213)	(3,213)				(3,213)
Distributions to AES	(101,986)				(68,667)
Contributions from shareholders	253,000		253,000				253,000		253,000
Partners' Capital Account, Return of Capital			(33,319)
Net income	96,626						129,975			129,975
Dividends, Preferred Stock	3,213									3,213
Stock Redeemed or Called During Period, Value	(296)				(296)	(59,784)	(296)			(296)	(59,784)
Return of Capital			(33,300)
Cash dividends declared on common stock							(127,200)			(127,200)
Equity contributions from shareholders	253,000
Other	111		111				114		114
Ending Balance at Dec. 31, 2022	1,090,518						$ 1,943,710				0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Comprehensive Income (Loss), Net of Tax, Attributable to Noncontrolling Interest	$ 96,626
Common Stock, Shares, Outstanding	108,907,000						17,207,000
Stockholders' Equity Attributable to Parent	$ 1,090,518		1,068,357	22,269	(108)		$ 1,943,710	324,537	1,193,107	426,066
Equity, Attributable to Noncontrolling Interest	0					0	0
Other Comprehensive Income (Loss), Net of Tax	7,025			7,025	0
Net income / (loss)	83,120				83,120		116,190
Preferred Stock Dividends, Income Statement Impact	0						0				0
Payments of Ordinary Dividends, Preferred Stock and Preference Stock	0						0
Distributions to AES	(104,287)				(57,830)
Contributions from shareholders							0		0
Partners' Capital Account, Return of Capital			(46,457)
Net income	57,027						90,097
Dividends, Preferred Stock	0						3,200
Return of Capital			(46,500)
Cash dividends declared on common stock							(140,200)			(140,200)
Proceeds from Noncontrolling Interests	79,347						79,347
Equity contributions from shareholders	0
Other	92		92				92		92
Ending Balance at Dec. 31, 2023	1,129,722						1,973,046				$ 0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Income (Loss) from Continuing Operations, Net of Tax, Attributable to Parent							116,190			116,190
Net Income (Loss) Attributable to Noncontrolling Interest	(26,093)						$ (26,093)
Comprehensive Income (Loss), Net of Tax, Attributable to Noncontrolling Interest	$ 83,120
Common Stock, Shares, Outstanding	108,907,318						17,206,630
Stockholders' Equity Attributable to Parent	$ 1,076,468		$ 1,021,992	$ 29,294	$ 25,182		$ 1,919,792	$ 324,537	$ 1,193,199	$ 402,056
Equity, Attributable to Noncontrolling Interest	$ 53,254					$ 0	$ 53,254

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income Statement - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Net Income (Loss) Available to Common Stockholders, Basic	$ 83,120	$ 93,117	$ 115,969
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax	(528)	(15,309)	(3,441)
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	1,594	46,245	10,393
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Tax	(1,798)	(1,798)	(1,199)
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax	7,025	51,676	14,013
Other Comprehensive Income (Loss), Net of Tax	7,025	51,676	14,013
Other Comprehensive Income (Loss), before Tax	64,052	148,302	133,195
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Noncontrolling Interest	(26,093)	0	0
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	90,145	144,793	129,982
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	5,431	$ 5,431	$ 3,620
Net Income (Loss) Attributable to Noncontrolling Interest	$ (26,093)

Overview and Summary of Signifi

Overview and Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2023
Entity Information [Line Items]
Overview and Summary of Significant Accounting Policies	OVERVIEW AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES IPALCO is a holding company incorporated under the laws of the state of Indiana. IPALCO, acquired by AES in March 2001, is owned by AES U.S. Investments (82.35%) and CDPQ (17.65%). AES U.S. Investments is owned by AES U.S. Holdings, LLC (85%) and CDPQ (15%). IPALCO owns all of the outstanding common stock of IPL, which does business as AES Indiana. Substantially all of IPALCO’s business consists of generating, transmitting, distributing and selling of electric energy conducted through its principal subsidiary, AES Indiana. AES Indiana was incorporated under the laws of the state of Indiana in 1926. AES Indiana has approximately 523,000 retail customers in the city of Indianapolis and neighboring cities, towns and communities, and adjacent rural areas all within the state of Indiana. AES Indiana has an exclusive right to provide electric service to those customers. AES Indiana owns and operates four generating stations all within the state of Indiana. The first station, Petersburg, is coal-fired, and AES Indiana retired 230 MW Petersburg Unit 1 in May 2021 and 415 MW Petersburg Unit 2 in June 2023, which resulted in 630 MW of total retired economic capacity at this station. AES Indiana plans to convert the remaining two coal units at Petersburg to natural gas (for further discussion, see Note 2, " Regulatory Matters - IRP Filings and Replacement Generation - 2022 IRP "). The second station, Harding Street, consists of three natural gas-fired boilers and steam turbines and uses natural gas and fuel oil to power five combustion turbines. In addition, AES Indiana operates a 20 MW battery energy storage unit at this location, which provides frequency response. The third station, Eagle Valley, is a CCGT natural gas plant. The fourth station, Georgetown, is a peaking station that uses natural gas to power combustion turbines. As of December 31, 2023, AES Indiana’s net electric generation capacity for winter is 3,070 MW and net summer capacity is 2,925 MW. In December 2021, AES Indiana, through a wholly-owned subsidiary, completed the acquisition of Hardy Hills Solar Energy LLC, including the development of a 195 MW solar project (the "Hardy Hills Solar Project"). In December 2023, the first stage of construction for the Hardy Hills Solar Project was completed and placed in service, with initial operations for over half of the project commencing on December 28, 2023. The final stage for construction of the project is expected to be completed during the first half of 2024. In August 2023, AES Indiana, through a wholly-owned subsidiary, completed the acquisition of Petersburg Energy Center, LLC, including the development of a 250 MW solar and 45 MW (180 MWh) energy storage facility (the "Petersburg Energy Center Project"). The Petersburg Energy Center Project is expected to be completed in 2025. In June 2023, AES Indiana, through a wholly-owned subsidiary, executed an agreement for the construction of the 200 MW (800 MWh) Pike County BESS Project to be developed at the AES Indiana Petersburg Plant site in Pike County, Indiana, subject to IURC approval, which was received in January 2024. The Pike County BESS Project is expected to be completed in 2024. For further discussion about AES Indiana's plans for wind, solar, and battery energy storage projects, please see Note 2, " Regulatory Matters - IRP Filings and Replacement Generation. " IPALCO’s other direct subsidiary is Mid-America. Mid-America is the holding company for IPALCO’s unregulated activities, which have not been material to the financial statements in the periods covered by this report. IPALCO’s regulated business is conducted through AES Indiana. IPALCO has two business segments: utility and nonutility. The utility segment consists of the operations of AES Indiana and everything else is included in the nonutility segment. Principles of Consolidation IPALCO’s consolidated financial statements are prepared in accordance with GAAP and in conjunction with the rules and regulations of the SEC. The consolidated financial statements include the accounts of IPALCO, its regulated utility subsidiary, AES Indiana, and its unregulated subsidiary, Mid-America. Furthermore, VIEs in which the Company has an ownership interest and is the primary beneficiary, thus controlling the VIE, as described below, have been consolidated. All intercompany items have been eliminated in consolidation. Certain costs for shared resources amongst AES Indiana and IPALCO, such as labor and benefits, are allocated to each entity based on allocation methodologies that management believes to be reasonable. We have evaluated subsequent events through the date this report is issued. If IPALCO enters into transactions impacting equity interests in its affiliates, IPALCO must determine whether the transaction impacts the Company's consolidation conclusion by first determining whether the transaction should be evaluated under the variable interest model or the voting model. In determining which consolidation model applies to the transaction, IPALCO is required to make judgments about how the entity operates, the most significant of which are whether (i) the entity has sufficient equity to finance its activities, (ii) the equity holders, as a group, have the characteristics of a controlling financial interest, and (iii) whether the entity has non-substantive voting rights. If the entity is determined to be a variable interest entity and IPALCO is determined to have power and benefits, the entity will be consolidated by IPALCO. Noncontrolling Interests Noncontrolling interests are classified as a separate component of equity in the Consolidated Balance Sheets and Consolidated Statements of Changes in Equity. Additionally, net income attributable to noncontrolling interests is reflected separately from consolidated net income on the Consolidated Statements of Operations. Any change in ownership of a subsidiary while the controlling financial interest is retained is accounted for as an equity transaction between the controlling and noncontrolling interests. Losses continue to be attributed to the noncontrolling interests, even when the noncontrolling interests' basis has been reduced to zero. Allocation of Earnings Hardy Hills JV is subject to profit-sharing arrangements where the allocation of earnings, cash distributions, and tax benefits are not based on fixed ownership percentages. This arrangement exists to designate different allocations of value among the investors, where the allocations change in form or percentage over the life of the partnership. IPALCO uses the HLBV method when it is a reasonable approximation of the profit-sharing arrangement. The HLBV method calculates the proceeds that would be attributable to each partner based on the liquidation provisions of the respective operating partnership agreement if the partnership was to be liquidated at book value at the balance sheet date. Each partner’s share of income in the period is equal to the change in the amount of net equity they are legally able to claim based on a hypothetical liquidation of the entity at the end of a reporting period compared to the beginning of that period, adjusted for any capital transactions (for further discussion about the Equity Capital Contribution Agreement, see Note 2, " Regulatory Matters - IRP Filings and Replacement Generation "). The HLBV method is used to calculate the earnings attributable to noncontrolling interest when the business is consolidated by IPALCO. In the early months of operations of a renewable generation facility where HLBV results in a significant decrease in the hypothetical liquidation proceeds attributable to the tax equity investor due to the recognition of ITCs or other adjustments as required by the U.S. Internal Revenue Code, the Company records the impact (sometimes referred to as the ‘Day one gain’) to income in the same period. Use of Management Estimates The preparation of financial statements in conformity with GAAP requires that management make certain estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements. The reported amounts of revenue and expenses during the reporting period may also be affected by the estimates and assumptions management is required to make. Actual results may differ from those estimates. Significant items subject to such estimates and assumptions include: recognition of revenue including unbilled revenue; the carrying value of property, plant and equipment; the valuation of insurance and claims liabilities; the valuation of allowances for credit losses and deferred income taxes; regulatory assets and liabilities; liabilities recorded for income tax exposures; litigation; contingencies; and assets and liabilities related to AROs and employee benefits. Reclassifications Certain immaterial amounts from prior periods have been reclassified to conform to the current year presentation. Cash and Cash Equivalents Cash and cash equivalents are stated at cost, which approximates fair value. All highly liquid short-term investments with original maturities of three months or less are considered cash equivalents. Restricted Cash Restricted cash includes cash which is restricted as to withdrawal or usage. The nature of the restrictions includes restrictions imposed by agreements related to deposits held as collateral. The following table provides a summary of cash, cash equivalents, and restricted cash amounts reported within the Consolidated Balance Sheets that reconcile to the total of such amounts as shown on the Consolidated Statements of Cash Flows: As of December 31, 2023 2022 (In Thousands) Cash, cash equivalents and restricted cash Cash and cash equivalents $ 28,579 $ 201,548 Restricted cash (included in Prepayments and other current assets) 5 5 Total cash, cash equivalents and restricted cash $ 28,584 $ 201,553 Accounts Receivable and Allowance for Credit Losses The following table summarizes our accounts receivable balances at December 31: As of December 31, 2023 2022 (In Thousands) Accounts receivable, net Customer receivables $ 125,715 $ 125,540 Unbilled revenue 91,463 74,488 Amounts due from related parties 5,178 239 Other 13,848 17,373 Allowance for credit losses (2,283) (1,117) Total accounts receivable, net $ 233,921 $ 216,523 The following table is a rollforward of our allowance for credit losses related to the accounts receivable balances for the periods indicated: For the Years Ended December 31, 2023 2022 (In Thousands) Allowance for credit losses: Beginning balance $ 1,117 $ 647 Current period provision 7,413 5,851 Write-offs charged against allowance (7,764) (7,008) Recoveries collected 1,517 1,627 Ending Balance $ 2,283 $ 1,117 The allowance for credit losses primarily relates to utility customer receivables, including unbilled amounts. Expected credit loss estimates are developed by disaggregating customers into those with similar credit risk characteristics and using historical credit loss experience. In addition, we also consider how current and future economic conditions are expected to impact collectability, as applicable, of our receivable balance. Amounts are written off when reasonable collections efforts have been exhausted. Inventories We maintain coal, fuel oil, natural gas, materials and supplies inventories for use in the production of electricity. These inventories are accounted for at the lower of cost or net realizable value, using the average cost. The following table summarizes our inventories balances at December 31: As of December 31, 2023 2022 (In Thousands) Inventories Fuel $ 77,198 $ 60,497 Materials and supplies, net 66,392 63,111 Total inventories $ 143,590 $ 123,608 Regulatory Accounting The retail utility operations of AES Indiana are subject to the jurisdiction of the IURC. AES Indiana’s wholesale power transactions are subject to the jurisdiction of the FERC. These agencies regulate AES Indiana’s utility business operations, tariffs, accounting, depreciation allowances, services, issuances of securities and the sale and acquisition of utility properties. The financial statements of AES Indiana are based on GAAP, including the provisions of FASB ASC 980 “Regulated Operations,” which gives recognition to the ratemaking and accounting practices of these agencies. See also Note 2, “Regulatory Matters - Regulatory Assets and Liabilities” for a discussion of specific regulatory assets and liabilities. Property, Plant and Equipment Property, plant and equipment is stated at original cost as defined for regulatory purposes. The cost of additions to property, plant and equipment and replacements of retirement units of property are charged to plant accounts. Units of property replaced or abandoned in the ordinary course of business are retired from the plant accounts at cost; such amounts, less salvage, are charged to accumulated depreciation. Depreciation is computed by the straight-line method based on functional rates approved by the IURC and averaged 3.7%, 3.8% and 3.7% during 2023, 2022 and 2021, respectively. Depreciation expense was $244.8 million, $247.5 million, and $239.1 million for the years ended December 31, 2023, 2022 and 2021, respectively. "Depreciation and amortization" expense on the accompanying Consolidated Statements of Operations is presented net of regulatory deferrals of depreciation expense and also includes amortization of intangible assets and amortization of previously deferred regulatory costs. AFUDC In accordance with the Uniform System of Accounts prescribed by FERC, AES Indiana capitalizes an allowance for the net cost of funds (interest on borrowed funds and a reasonable rate of return on equity funds) used for construction purposes during the period of construction with a corresponding credit to income. AES Indiana capitalized amounts using pretax composite rates of 7.1%, 5.4% and 5.7% during 2023, 2022 and 2021, respectively. AFUDC equity and AFUDC debt were as follows for the years ended December 31, 2023, 2022 and 2021: 2023 2022 2021 (In Thousands) AFUDC equity $ 9,315 $ 4,784 $ 5,412 AFUDC debt $ 13,739 $ 8,215 $ 4,815 Impairment of Long-lived Assets GAAP requires that we test long-lived assets for impairment when indicators of impairment exist. If an asset is deemed to be impaired, we are required to write down the asset to its fair value with a charge to current earnings. The net book value of our property, plant, and equipment was $4.5 billion and $4.0 billion as of December 31, 2023 and 2022, respectively. As of December 31, 2023 and 2022, AES Indiana had $259.9 million and $287.5 million, respectively, of long-term regulatory assets associated with Petersburg Unit 1 and 2 retirement costs (for further discussion, see Note 2, “Regulatory Matters - IRP Filings and Replacement Generation” and Note 3 , "Property, Plant and Equipment" ) . We do not believe any of these assets are currently impaired. In making this assessment, we consider such factors as: the overall condition and generating and distribution capacity of the assets; the expected ability to recover additional expenditures in the assets; the anticipated demand and relative pricing of retail electricity in our service territory and wholesale electricity in the region; and the cost of fuel. Intangible Assets Finite-lived intangible assets primarily include capitalized software and project development intangible assets amortized on a straight-line basis over their useful lives. The following table presents information related to the Company's intangible assets, including the gross amount capitalized and related amortization: December 31, $ in thousands Weighted average amortization periods (in years) 2023 2022 Capitalized software 8 $ 261,872 $ 205,910 Project development intangible assets 28 84,097 39,455 Other Various 797 797 Less: Accumulated amortization (111,110) (107,184) Intangible assets - net $ 235,656 $ 138,978 For the Years Ended December 31, 2023 2022 2021 Amortization expense $ 14,570 $ 10,122 $ 11,241 Estimated future amortization Years ending December 31, 2024 $ 20,764 2025 20,764 2026 22,550 2027 22,550 2028 22,550 Total $ 109,178 Implementation Costs Related to Software as a Service IPALCO has recorded prepayments for implementation costs related to software as a service in support of utility customer services of $7.1 million and $8.2 million as of December 31, 2023 and 2022, respectively, which are recorded within " Other non-current assets " on the accompanying Consolidated Balance Sheets. Debt Issuance Costs Costs incurred in connection with the issuance of long-term debt are deferred and presented as a direct reduction from the face amount of that debt and amortized over the related financing period using the effective interest method. Debt issuance costs related to a line-of-credit or revolving credit facility are deferred and presented as an asset and amortized over the related financing period. Make-whole payments in connection with early debt retirements are classified as cash flows from financing activities. Contingencies IPALCO accrues for loss contingencies when the amount of the loss is probable and estimable. We are subject to various environmental regulations and are involved in certain legal proceedings. If IPALCO’s actual environmental and/or legal obligations are different from our estimates, the recognition of the actual amounts may have a material impact on our results of operations, financial condition and cash flows; although that has not been the case during the periods covered by this report. Accruals for loss contingencies were not material as of December 31, 2023 and 2022. See Note 10, " Commitments and Contingencies - Contingencies " for additional information. Concentrations of Risk Substantially all of AES Indiana’s customers are located within the Indianapolis area. Approximately 68% of AES Indiana’s employees are covered by collective bargaining agreements in two bargaining units: a physical unit and a clerical-technical unit. AES Indiana’s contract with the physical unit expires on December 4, 2024, and the contract with the clerical-technical unit expires February 12, 2026. Additionally, AES Indiana has long-term coal contracts with one supplier, and substantially all of AES Indiana's coal is currently mined in the state of Indiana. Financial Derivatives All derivatives are recognized as either assets or liabilities in the balance sheets and are measured at fair value. Changes in the fair value are recorded in earnings unless the derivative is designated as a cash flow hedge of a forecasted transaction or it qualifies for the normal purchases and sales exception. AES Indiana has contracts involving the physical delivery of energy and fuel. Because some of these contracts qualify for the normal purchases and normal sales scope exception in ASC 815, AES Indiana has elected to account for them as accrual contracts, which are not adjusted for changes in fair value. AES Indiana has or previously had FTRs and forward power contracts that do not qualify for hedge accounting or the normal purchases and sales exceptions under ASC 815. Accordingly, FTRs are recorded at fair value when acquired and subsequently amortized over the annual period as they are used. FTRs are initially recorded at fair value using the income approach. The forward power contracts are recorded at fair value with changes in the fair value charged or credited to the Consolidated Statements of Operations in the period in which the change occurred. Forward power contracts are fair valued using the market approach. Additionally, we use interest rate hedges to manage the interest rate risk associated with refinancing our long-term debt. We use cash flow hedge accounting when the hedge or a portion of the hedge is deemed to be highly effective, which results in changes in the fair value being recorded within accumulated other comprehensive income, a component of shareholders' equity. We have elected not to offset net derivative positions in the Financial Statements. Accordingly, we do not offset such derivative positions against the fair value of amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral under master netting agreements. See Note 5, “Derivative Instruments and Hedging Activities” for additional information. Leases The Company has finance leases primarily for land in which the Company is the lessee. Operating leases with an initial term of 12 months or less are not recorded on the balance sheet, but are expensed on a straight-line basis over the lease term. The Company’s leases do not contain any material residual value guarantees, restrictive covenants or subleases. Right-of-use assets represent our right to use an underlying asset for the lease term while lease liabilities represent our obligation to make lease payments arising from the lease. Right-of-use assets and lease liabilities are recognized on commencement of the lease based on the present value of lease payments over the lease term. Generally, the rate implicit in the lease is not readily determinable; as such, we use the incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The Company determines discount rates based on its existing credit rates of its borrowings, which are then adjusted for the appropriate lease term. The right-of-use asset also includes any lease payments made and excludes lease incentives that are paid or payable to the lessee at commencement. The lease term includes periods covered by the option to extend if it is reasonably certain that the option will be exercised and periods covered by an option to terminate if it is reasonably certain that the option will not be exercised. Accumulated Other Comprehensive Income / (Loss) The amounts reclassified out of AOCI / (AOCL) by component during the years ended December 31, 2023, 2022 and 2021 are as follows (in thousands): Details about AOCI / (AOCL) components Affected line item in the Consolidated Statements of Operations For the Years Ended December 31, 2023 2022 2021 Net losses on cash flow hedges (Note 5): Interest expense $ 7,229 $ 7,229 $ 4,819 Income tax effect (1,798) (1,798) (1,199) Total reclassifications for the period, net of income taxes $ 5,431 $ 5,431 $ 3,620 See Note 5, " Derivative Instruments and Hedging Activities - Cash Flow Hedges " for further information on the changes in the components of AOCL. Revenue Recognition Revenue related to the sale of energy is generally recognized when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to certain customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is accrued. In making its estimates of unbilled revenue, AES Indiana uses models that consider various factors including daily generation volumes; known amounts of energy usage by nearly all residential, commercial and industrial customers; and estimated customer rates based on prior period billings. Given the use of these models, and that customers are billed on a monthly cycle, we believe it is unlikely that materially different results will occur in future periods when revenue is billed. An allowance for potential credit losses is maintained and amounts are written off when normal collection efforts have been exhausted. Our provision for expected credit losses included in “Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations was $7.5 million, $5.9 million and $3.0 million for the years ended December 31, 2023, 2022 and 2021, respectively. AES Indiana’s basic rates include a provision for fuel costs as established in AES Indiana’s most recent rate proceeding, which last adjusted AES Indiana’s rates in December 2018. AES Indiana is permitted to recover actual costs of purchased power and fuel consumed, subject to certain restrictions. This is accomplished through quarterly FAC proceedings, in which AES Indiana estimates the amount of fuel and purchased power costs in future periods. Through these proceedings, AES Indiana is also permitted to recover, in future rates, underestimated fuel and purchased power costs from prior periods, subject to certain restrictions, and therefore the over or underestimated costs are deferred or accrued and amortized into fuel expense in the same period that AES Indiana’s rates are adjusted. See also Note 2, “ Regulatory Matters ” for a discussion of other costs that AES Indiana is permitted to recover through periodic rate adjustment proceedings and the status of current rate adjustment proceedings. In addition, we are one of many transmission system owner members of MISO, a RTO which maintains functional control over the combined transmission systems of its members and manages one of the largest energy markets in the U.S. See Note 13, " Revenue " for additional information of MISO sales and other revenue streams. Operating Expenses – Other, Net Operating expenses – Other, net generally includes gains or losses on asset sales, dispositions or acquisitions, gains or losses on the sale or acquisition of businesses, and other expense or income from miscellaneous operating transactions. For the year ended December 31, 2022, the $3.2 million is primarily due to a gain on remeasurement of contingent consideration associated with the Hardy Hills Solar Project acquisition. For the year ended December 31, 2021, the $5.6 million represents a gain on acquisition. Pension and Postretirement Benefits We recognize in our Consolidated Balance Sheets an asset or liability reflecting the funded status of pension and other postretirement plans with current-year changes in the funded status, that would otherwise be recognized in AOCI, recorded as a regulatory asset as this can be recovered through future rates. All plan assets are recorded at fair value. We follow the measurement date provisions of the accounting guidance, which require a year-end measurement date of plan assets and obligations for all defined benefit plans. We account for and disclose pension and postretirement benefits in accordance with the provisions of GAAP relating to the accounting for pension and other postretirement plans. These GAAP provisions require the use of assumptions, such as the discount rate for liabilities and long-term rate of return on assets, in determining the obligations, annual cost and funding requirements of the plans. Consistent with the requirements of ASC 715, we apply a disaggregated discount rate approach for determining service cost and interest cost for our defined benefit pension plans and postretirement plans. See Note 8, " Benefit Plans " for more information. Income Taxes Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of the existing assets and liabilities, and their respective income tax bases. The Company establishes a valuation allowance when it is more likely than not that all or a portion of a deferred tax asset will not be realized. The Company’s tax positions are evaluated under a more likely than not recognition threshold and measurement analysis before they are recognized for financial statement reporting. Uncertain tax positions are classified as noncurrent income tax liabilities unless expected to be paid within one year. The Company’s policy for interest and penalties is to recognize interest and penalties as a component of the provision for income taxes in the Consolidated Statements of Operations. Income tax assets or liabilities, which are included in allowable costs for ratemaking purposes in future years, are recorded as regulatory assets or liabilities with a corresponding deferred tax liability or asset. Investment tax credits that reduced federal income taxes in the years they arose have been deferred and are being amortized to income over the useful lives of the properties in accordance with regulatory treatment. See Note 2, " Regulatory Matters " for additional information. IPALCO and its subsidiaries file U.S. federal income tax returns as part of the consolidated U.S. income tax return filed by AES. The consolidated tax liability is allocated to each subsidiary based on the separate return method which is specified in our tax allocation agreement and which provides a consistent, systematic and rational approach. See Note 7, " Income Taxes " for additional information. Repair and Maintenance Costs Repair and maintenance costs are expensed as incurred. Per Share Data IPALCO is owned by AES U.S. Investments and CDPQ. IPALCO does not report earnings on a per-share basis. New Accounting Pronouncements We have assessed and determined that the new accounting pronouncements adopted did not have a material impact on the Company's Financial Statements. New Accounting Pronouncements Issued But Not Yet Effective The following table provides a brief description of recent accounting pronouncements that could have a material impact on the Company's Financial Statements once adopted. Accounting pronouncements not listed below were assessed and determined to be either not applicable or are expected to have no material impact on the Company's Financial Statements. ASU Number and Name Description Date of Adoption Effect on the Financial Statements upon adoption 2023-06 Disclosure Improvements: Codification Amendments in Response to the SEC’s Disclosure Update and Simplification Initiative In U.S. Securities and Exchange Commission (SEC) Release No. 33-10532, Disclosure Update and Simplification, issued August 17, 2018, the SEC referred certain of its disclosure requirements that overlap with, but require incremental information to, generally accepted accounting principles (GAAP) to the FASB for potential incorporation into the Codification. The amendments in this Update are the result of the Board’s decision to incorporate into the Codification 14 of the 27 disclosures referred by the SEC. The amendments in this Update represent changes to clarify or improve disclosure and presentation requirements of a variety of Topics. Many of the amendments allow users to more easily compare entities subject to the SEC’s existing disclosures with those entities that were not previously subject to the SEC’s requirements. Also, the amendments align the requirements in the Codification with the SEC’s regulations. The effective date for each amendment will be the date on which the SEC's removal of that related disclosure becomes effective, with early adoption prohibited. The amendments in this Update should be applied prospectively. We will provide the required disclosures on a prospective basis on the date each amendment becomes effective. We do not expect ASU 2023-06 will have any impact to our consolidated financial statements. 2023-07 Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures The amendments in this section are designed to improve the disclosures related to Segment reporting on an interim and annual basis. Public companies must disclose significant segment expenses and an amount for other segment items. This will also require that a company disclose its annual disclosures under Topic 280 in each interim period. Furthermore, companies will need to disclose the Chief Operating Decision Maker (CODM) and how the CODM assesses the performance of a segment. Lastly, public companies that have a single reportable segment must report the required disclosures under topic 280. The amendments in this Update are effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. Early adoption is permitted. We are currently evaluating the impact of adopting the standard on our consolidated financial statements. 2023-09 Income Taxes (Topic 740): Improvements to Income Tax Disclosures The amendments in this Update require that public business entities on an annual basis (1) disclose specific categories in the rate reconciliation and (2) provide additional information for reconciling items that meet a quantitative threshold. Furthermore, companies are required to disclose a disaggregated amount of income taxes paid at a federal, state, and foreig
Indianapolis Power And Light Company
Entity Information [Line Items]
Overview and Summary of Significant Accounting Policies	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES IPL, which does business as AES Indiana, was incorporated under the laws of the state of Indiana in 1926. All of the outstanding common stock of AES Indiana is owned by IPALCO. IPALCO, acquired by AES in March 2001, is owned by AES U.S. Investments and CDPQ. AES U.S. Investments is owned by AES (85%) and CDPQ (15%). AES Indiana is engaged primarily in generating, transmitting, distributing and selling of electric energy to approximately 523,000 retail customers in the city of Indianapolis and neighboring cities, towns and communities, and adjacent rural areas all within the state of Indiana. AES Indiana has an exclusive right to provide electric service to those customers. AES Indiana owns and operates four generating stations all within the state of Indiana. The first station, Petersburg, is coal-fired, and AES Indiana retired 230 MW Petersburg Unit 1 in May 2021 and 415 MW Petersburg Unit 2 in June 2023, which resulted in 630 MW of total retired economic capacity at this station. AES Indiana plans to convert the remaining two coal units at Petersburg to natural gas (for further discussion, see Note 2, " Regulatory Matters - IRP Filings and Replacement Generation 2022 IRP "). The second station, Harding Street, consists of three natural gas-fired boilers and steam turbines and uses natural gas and fuel oil to power five combustion turbines. In addition, AES Indiana operates a 20 MW battery energy storage unit at this location, which provides frequency response. The third station, Eagle Valley, is a CCGT natural gas plant. The fourth station, Georgetown, is a peaking station that uses natural gas to power combustion turbines. As of December 31, 2023, AES Indiana’s net electric generation capacity for winter is 3,070 MW and net summer capacity is 2,925 MW. In December 2021, AES Indiana, through a wholly-owned subsidiary, completed the acquisition of Hardy Hills Solar Energy LLC, including the development of a 195 MW solar project (the "Hardy Hills Solar Project"). In December 2023, the first stage of construction for the Hardy Hills Solar Project was completed and placed in service, with initial operations for over half of the project commencing on December 28, 2023. The final stage for construction of the project is expected to be completed during the first half of 2024. In August 2023, AES Indiana, through a wholly-owned subsidiary, completed the acquisition of Petersburg Energy Center, LLC, including the development of a 250 MW solar and 45 MW (180 MWh) energy storage facility (the "Petersburg Energy Center Project"). The Petersburg Energy Center Project is expected to be completed in 2025. In June 2023, AES Indiana, through a wholly-owned subsidiary, executed an agreement for the construction of the 200 MW (800 MWh) Pike County BESS Project to be developed at the AES Indiana Petersburg Plant site in Pike County, Indiana, subject to IURC approval, which was received in January 2024. The Pike County BESS Project is expected to be completed in 2024. For further discussion about AES Indiana's plans for wind, solar, and battery energy storage projects, please see Note 2, " Regulatory Matters - IRP Filings and Replacement Generation. " Principles of Consolidation AES Indiana’s consolidated financial statements are prepared in accordance with GAAP and in conjunction with the rules and regulations of the SEC. The consolidated financial statements include the accounts of AES Indiana and its wholly owned subsidiaries . Furthermore, VIEs in which the Company has an ownership interest and is the primary beneficiary, thus controlling the VIE, as described below, have been consolidated. All intercompany items have been eliminated in consolidation. Certain costs for shared resources amongst AES Indiana and IPALCO, such as labor and benefits, are allocated to each entity based on allocation methodologies that management believes to be reasonable. We have evaluated subsequent events through the date this report is issued. If AES Indiana enters into transactions impacting equity interests in its affiliates, AES Indiana must determine whether the transaction impacts the Company's consolidation conclusion by first determining whether the transaction should be evaluated under the variable interest model or the voting model. In determining which consolidation model applies to the transaction, AES Indiana is required to make judgments about how the entity operates, the most significant of which are whether (i) the entity has sufficient equity to finance its activities, (ii) the equity holders, as a group, have the characteristics of a controlling financial interest, and (iii) whether the entity has non-substantive voting rights. If the entity is determined to be a variable interest entity and AES Indiana is determined to have power and benefits, the entity will be consolidated by AES Indiana. Noncontrolling Interests Noncontrolling interests are classified as a separate component of equity in the Consolidated Balance Sheets and Consolidated Statements of Changes in Equity. Additionally, net income attributable to noncontrolling interests is reflected separately from consolidated net income on the Consolidated Statements of Operations. Any change in ownership of a subsidiary while the controlling financial interest is retained is accounted for as an equity transaction between the controlling and noncontrolling interests. Losses continue to be attributed to the noncontrolling interests, even when the noncontrolling interests' basis has been reduced to zero. Allocation of Earnings Hardy Hills JV is subject to profit-sharing arrangements where the allocation of earnings, cash distributions, and tax benefits are not based on fixed ownership percentages. This arrangement exists to designate different allocations of value among the investors, where the allocations change in form or percentage over the life of the partnership. AES Indiana uses the HLBV method when it is a reasonable approximation of the profit-sharing arrangement. The HLBV method calculates the proceeds that would be attributable to each partner based on the liquidation provisions of the respective operating partnership agreement if the partnership was to be liquidated at book value at the balance sheet date. Each partner’s share of income in the period is equal to the change in the amount of net equity they are legally able to claim based on a hypothetical liquidation of the entity at the end of a reporting period compared to the beginning of that period, adjusted for any capital transactions (for further discussion about the Equity Capital Contribution Agreement, see Note 2, " Regulatory Matters - IRP Filings and Replacement Generation "). The HLBV method is used to calculate the earnings attributable to noncontrolling interest when the business is consolidated by AES Indiana. In the early months of operations of a renewable generation facility where HLBV results in a significant decrease in the hypothetical liquidation proceeds attributable to the tax equity investor due to the recognition of investment tax credits ("ITCs") or other adjustments as required by the U.S. Internal Revenue Code, the Company records the impact (sometimes referred to as the ‘Day one gain’) to income in the same period. Use of Management Estimates The preparation of financial statements in conformity with GAAP requires that management make certain estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements. The reported amounts of revenue and expenses during the reporting period may also be affected by the estimates and assumptions management is required to make. Actual results may differ from those estimates. Significant items subject to such estimates and assumptions include: recognition of revenue including unbilled revenue; the carrying value of property, plant and equipment; the valuation of insurance and claims liabilities; the valuation of allowances for credit losses and deferred income taxes; regulatory assets and liabilities; liabilities recorded for income tax exposures; litigation; contingencies; and assets and liabilities related to AROs and employee benefits. Reclassifications Certain immaterial amounts from prior periods have been reclassified to conform to the current year presentation. Cash and Cash Equivalents Cash and cash equivalents are stated at cost, which approximates fair value. All highly liquid short-term investments with original maturities of three months or less are considered cash equivalents. Restricted Cash Restricted cash includes cash which is restricted as to withdrawal or usage. The nature of the restrictions includes restrictions imposed by agreements related to deposits held as collateral. The following table provides a summary of cash, cash equivalents, and restricted cash amounts reported within the Consolidated Balance Sheets that reconcile to the total of such amounts as shown on the Consolidated Statements of Cash Flows: As of December 31, 2023 2022 (In Thousands) Cash, cash equivalents and restricted cash Cash and cash equivalents $ 25,767 $ 199,103 Restricted cash (included in Prepayments and other current assets) 5 5 Total cash, cash equivalents and restricted cash $ 25,772 $ 199,108 Accounts Receivable and Allowance for Credit Losses The following table summarizes our accounts receivable balances at December 31: As of December 31, 2023 2022 (In Thousands) Accounts receivable, net Customer receivables $ 125,715 $ 125,540 Unbilled revenue 91,463 74,488 Amounts due from related parties 5,227 288 Other 13,848 17,373 Allowance for credit losses (2,283) (1,117) Total accounts receivable, net $ 233,970 $ 216,572 The following table is a rollforward of our allowance for credit losses related to the accounts receivable balances for the periods indicated: For the Years Ended December 31, 2023 2022 (In Thousands) Allowance for credit losses: Beginning balance $ 1,117 $ 647 Current period provision 7,413 5,851 Write-offs charged against allowance (7,764) (7,008) Recoveries collected 1,517 1,627 Ending Balance $ 2,283 $ 1,117 The allowance for credit losses primarily relates to utility customer receivables, including unbilled amounts. Expected credit loss estimates are developed by disaggregating customers into those with similar credit risk characteristics and using historical credit loss experience. In addition, we also consider how current and future economic conditions are expected to impact collectability, as applicable, of our receivable balance. Amounts are written off when reasonable collections efforts have been exhausted. Inventories AES Indiana maintains coal, fuel oil, natural gas, materials and supplies inventories for use in the production of electricity. These inventories are accounted for at the lower of cost or net realizable value, using the average cost. The following table summarizes our inventories balances at December 31: As of December 31, 2023 2022 (In Thousands) Inventories Fuel $ 77,198 $ 60,497 Materials and supplies, net 66,392 63,111 Total inventories $ 143,590 $ 123,608 Regulatory Accounting The retail utility operations of AES Indiana are subject to the jurisdiction of the IURC. AES Indiana’s wholesale power transactions are subject to the jurisdiction of the FERC. These agencies regulate AES Indiana’s utility business operations, tariffs, accounting, depreciation allowances, services, issuances of securities and the sale and acquisition of utility properties. The financial statements of AES Indiana are based on GAAP, including the provisions of FASB ASC 980 “Regulated Operations,” which gives recognition to the ratemaking and accounting practices of these agencies. See also Note 2, “Regulatory Matters - Regulatory Assets and Liabilities” for a discussion of specific regulatory assets and liabilities. Property, Plant and Equipment Property, plant and equipment is stated at original cost as defined for regulatory purposes. The cost of additions to property, plant and equipment and replacements of retirement units of property are charged to plant accounts. Units of property replaced or abandoned in the ordinary course of business are retired from the plant accounts at cost; such amounts, less salvage, are charged to accumulated depreciation. Depreciation is computed by the straight-line method based on functional rates approved by the IURC and averaged 3.7%, 3.8% and 3.7% during 2023, 2022 and 2021, respectively. Depreciation expense was $244.8 million, $247.5 million, and $239.1 million for the years ended December 31, 2023, 2022 and 2021, respectively. "Depreciation and amortization" expense on the accompanying Consolidated Statements of Operations is presented net of regulatory deferrals of depreciation expense and also includes amortization of intangible assets and amortization of previously deferred regulatory costs. AFUDC In accordance with the Uniform System of Accounts prescribed by FERC, AES Indiana capitalizes an allowance for the net cost of funds (interest on borrowed funds and a reasonable rate of return on equity funds) used for construction purposes during the period of construction with a corresponding credit to income. AES Indiana capitalized amounts using pretax composite rates of 7.1%, 5.4% and 5.7% during 2023, 2022 and 2021, respectively. AFUDC equity and AFUDC debt were as follows for the years ended December 31, 2023, 2022 and 2021: 2023 2022 2021 (In Thousands) AFUDC equity $ 9,315 $ 4,784 $ 5,412 AFUDC debt $ 13,739 $ 8,215 $ 4,815 Impairment of Long-lived Assets GAAP requires that AES Indiana test long-lived assets for impairment when indicators of impairment exist. If an asset is deemed to be impaired, AES Indiana is required to write down the asset to its fair value with a charge to current earnings. The net book value of AES Indiana’s property, plant, and equipment was $4.5 billion and $4.0 billion as of December 31, 2023 and 2022, respectively. As of December 31, 2023 and 2022, AES Indiana had $259.9 million and $287.5 million, respectively, of long-term regulatory assets associated with Petersburg Unit 1 and 2 retirement costs (for further discussion, see Note 2, “Regulatory Matters - IRP Filings and Replacement Generation” and Note 3 , "Property, Plant and Equipment" ). AES Indiana does not believe any of these assets are currently impaired. In making this assessment, AES Indiana considers such factors as: the overall condition and generating and distribution capacity of the assets; the expected ability to recover additional expenditures in the assets; the anticipated demand and relative pricing of retail electricity in its service territory and wholesale electricity in the region; and the cost of fuel. Intangible Assets Finite-lived intangible assets primarily include capitalized software and project development intangible assets amortized on a straight-line basis over their useful lives. The following table presents information related to the Company's intangible assets, including the gross amount capitalized and related amortization: December 31, $ in thousands Weighted average amortization periods (in years) 2023 2022 Capitalized software 8 $ 261,872 $ 205,910 Project development intangible assets 28 84,097 39,455 Other Various 797 797 Less: Accumulated amortization (111,110) (107,184) Intangible assets - net $ 235,656 $ 138,978 For the Years Ended December 31, 2023 2022 2021 Amortization expense $ 14,570 $ 10,122 $ 11,241 Estimated future amortization Years ending December 31, 2024 $ 20,764 2025 20,764 2026 22,550 2027 22,550 2028 22,550 Total $ 109,178 Implementation Costs Related to Software as a Service AES Indiana has recorded prepayments for implementation costs related to software as a service in support of utility customer services of $7.1 million and $8.2 million as of December 31, 2023 and 2022, respectively, which are recorded within " Other non-current assets " on the accompanying Consolidated Balance Sheets. Debt Issuance Costs Costs incurred in connection with the issuance of long-term debt are deferred and presented as a direct reduction from the face amount of that debt and amortized over the related financing period using the effective interest method. Debt issuance costs related to a line-of-credit or revolving credit facility are deferred and presented as an asset and amortized over the related financing period. Make-whole payments in connection with early debt retirements are classified as cash flows from financing activities. Contingencies AES Indiana accrues for loss contingencies when the amount of the loss is probable and estimable. AES Indiana is subject to various environmental regulations and is involved in certain legal proceedings. If AES Indiana’s actual environmental and/or legal obligations are different from our estimates, the recognition of the actual amounts may have a material impact on our results of operations, financial condition and cash flows; although that has not been the case during the periods covered by this report. Accruals for loss contingencies were not material as of December 31, 2023 and 2022. See Note 10, " Commitments and Contingencies - Contingencies " for additional information. Concentrations of Risk Substantially all of AES Indiana’s customers are located within the Indianapolis area. Approximately 68% of AES Indiana’s employees are covered by collective bargaining agreements in two bargaining units: a physical unit and a clerical-technical unit. AES Indiana’s contract with the physical unit expires on December 4, 2024, and the contract with the clerical-technical unit expires February 12, 2026. Additionally, AES Indiana has long-term coal contracts with one supplier, and substantially all of AES Indiana's coal is currently mined in the state of Indiana. Financial Derivatives All derivatives are recognized as either assets or liabilities in the balance sheets and are measured at fair value. Changes in the fair value are recorded in earnings unless the derivative is designated as a cash flow hedge of a forecasted transaction or it qualifies for the normal purchases and sales exception. AES Indiana has contracts involving the physical delivery of energy and fuel. Because some of these contracts qualify for the normal purchases and normal sales scope exception in ASC 815, AES Indiana has elected to account for them as accrual contracts, which are not adjusted for changes in fair value. AES Indiana has or previously had FTRs and forward power contracts that do not qualify for hedge accounting or the normal purchases and sales exceptions under ASC 815. Accordingly, FTRs are recorded at fair value when acquired and subsequently amortized over the annual period as they are used. FTRs are initially recorded at fair value using the income approach. The forward power contracts are recorded at fair value with changes in the fair value charged or credited to the Consolidated Statements of Operations in the period in which the change occurred. Forward power contracts are fair valued using the market approach. Leases The Company has finance leases primarily for land in which the Company is the lessee. Operating leases with an initial term of 12 months or less are not recorded on the balance sheet, but are expensed on a straight-line basis over the lease term. The Company’s leases do not contain any material residual value guarantees, restrictive covenants or subleases. Right-of-use assets represent our right to use an underlying asset for the lease term while lease liabilities represent our obligation to make lease payments arising from the lease. Right-of-use assets and lease liabilities are recognized on commencement of the lease based on the present value of lease payments over the lease term. Generally, the rate implicit in the lease is not readily determinable; as such, we use the incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The Company determines discount rates based on its existing credit rates of its borrowings, which are then adjusted for the appropriate lease term. The right-of-use asset also includes any lease payments made and excludes lease incentives that are paid or payable to the lessee at commencement. The lease term includes periods covered by the option to extend if it is reasonably certain that the option will be exercised and periods covered by an option to terminate if it is reasonably certain that the option will not be exercised. Revenue Recognition Revenue related to the sale of energy is generally recognized when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to certain customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is accrued. In making its estimates of unbilled revenue, AES Indiana uses models that consider various factors including daily generation volumes; known amounts of energy usage by nearly all residential, commercial and industrial customers; and estimated customer rates based on prior period billings. Given the use of these models, and that customers are billed on a monthly cycle, we believe it is unlikely that materially different results will occur in future periods when revenue is billed. An allowance for potential credit losses is maintained and amounts are written off when normal collection efforts have been exhausted. AES Indiana’s provision for expected credit losses included in “ Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations was $7.5 million, $5.9 million and $3.0 million for the years ended December 31, 2023, 2022 and 2021, respectively. AES Indiana’s basic rates include a provision for fuel costs as established in AES Indiana’s most recent rate proceeding, which last adjusted AES Indiana’s rates in December 2018. AES Indiana is permitted to recover actual costs of purchased power and fuel consumed, subject to certain restrictions. This is accomplished through quarterly FAC proceedings, in which AES Indiana estimates the amount of fuel and purchased power costs in future periods. Through these proceedings, AES Indiana is also permitted to recover, in future rates, underestimated fuel and purchased power costs from prior periods, subject to certain restrictions, and therefore the over or underestimated costs are deferred or accrued and amortized into fuel expense in the same period that AES Indiana’s rates are adjusted. See also Note 2, “ Regulatory Matters ” for a discussion of other costs that AES Indiana is permitted to recover through periodic rate adjustment proceedings and the status of current rate adjustment proceedings. In addition, AES Indiana is one of many transmission system owner members of MISO, a RTO which maintains functional control over the combined transmission systems of its members and manages one of the largest energy markets in the U.S. See Note 13, " Revenue " for additional information of MISO sales and other revenue streams. Operating Expenses – Other, Net Operating expenses – Other, net generally includes gains or losses on asset sales, dispositions or acquisitions, gains or losses on the sale or acquisition of businesses, and other expense or income from miscellaneous operating transactions. For the year ended December 31, 2022, the $3.2 million is primarily due to a gain on remeasurement of contingent consideration associated with the Hardy Hills Solar Project acquisition. For the year ended December 31, 2021, the $5.6 million represents a gain on acquisition. Pension and Postretirement Benefits AES Indiana recognizes in its Consolidated Balance Sheets an asset or liability reflecting the funded status of pension and other postretirement plans with current-year changes in the funded status, that would otherwise be recognized in AOCI, recorded as a regulatory asset as this can be recovered through future rates. All plan assets are recorded at fair value. AES Indiana follows the measurement date provisions of the accounting guidance, which require a year-end measurement date of plan assets and obligations for all defined benefit plans. AES Indiana accounts for and discloses pension and postretirement benefits in accordance with the provisions of GAAP relating to the accounting for pension and other postretirement plans. These GAAP provisions require the use of assumptions, such as the discount rate for liabilities and long-term rate of return on assets, in determining the obligations, annual cost and funding requirements of the plans. Consistent with the requirements of ASC 715, AES Indiana applies a disaggregated discount rate approach for determining service cost and interest cost for its defined benefit pension plans and postretirement plans. See Note 8, " Benefit Plans " for more information. Income Taxes Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of the existing assets and liabilities, and their respective income tax bases. AES Indiana establishes a valuation allowance when it is more likely than not that all or a portion of a deferred tax asset will not be realized. AES Indiana’s tax positions are evaluated under a more likely than not recognition threshold and measurement analysis before they are recognized for financial statement reporting. Uncertain tax positions are classified as noncurrent income tax liabilities unless expected to be paid within one year. AES Indiana’s policy for interest and penalties is to recognize interest and penalties as a component of the provision for income taxes in the Consolidated Statements of Operations. Income tax assets or liabilities which are included in allowable costs for ratemaking purposes in future years are recorded as regulatory assets or liabilities with a corresponding deferred tax liability or asset. Investment tax credits that reduced federal income taxes in the years they arose have been deferred and are being amortized to income over the useful lives of the properties in accordance with regulatory treatment. See Note 2, " Regulatory Matters " for additional information. AES Indiana files U.S. federal income tax returns as part of the consolidated U.S. income tax return filed by AES. The consolidated tax liability is allocated to each subsidiary based on the separate return method which is specified in our tax allocation agreement and which provides a consistent, systematic and rational approach. See Note 7, " Income Taxes " for additional information. Repair and Maintenance Costs Repair and maintenance costs are expensed as incurred. Per Share Data IPALCO owns all of the outstanding common stock of AES Indiana. AES Indiana does not report earnings on a per-share basis. New Accounting Pronouncements We have assessed and determined that the new accounting pronouncements adopted did not have a material impact on AES Indiana's Financial Statements. New Accounting Pronouncements Issued But Not Yet Effective The following table provides a brief description of recent accounting pronouncements that could have a material impact on the AES Indiana's Financial Statements once adopted. Accounting pronouncements not listed below were assessed and determined to be either not applicable or are expected to have no material impact on AES Indiana's Financial Statements. ASU Number and Name Description Date of Adoption Effect on the Financial Statements upon adoption 2023-06 Disclosure Improvements: Codification Amendments in Response to the SEC’s Disclosure Update and Simplification Initiative In U.S. Securities and Exchange Commission (SEC) Release No. 33-10532, Disclosure Update and Simplification, issued August 17, 2018, the SEC referred certain of its disclosure requirements that overlap with, but require incremental information to, generally accepted accounting principles (GAAP) to the FASB for potential incorporation into the Codification. The amendments in this Update are the result of the Board’s decision to incorporate into the Codification 14 of the 27 disclosures referred by the SEC. The amendments in this Update represent changes to clarify or improve disclosure and presentation requirements of a variety of Topics. Many of the amendments allow users to more easily compare entities subject to the SEC’s existing disclosures with those entities that were not previously subject to the SEC’s requirements. Also, the amendments align the requirements in the Codification with the SEC’s regulations. The effective date for each amendment will be the date on which the SEC's removal of that related disclosure becomes effective, with early adoption prohibited. The amendments in this Update should be applied prospectively. AES Indiana will provide the required disclosures on a prospective basis on the date each amendment becomes effective. AES Indiana does not expect ASU 2023-06 will have any impact to its Financial Statements. 2023-07 Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures The amendments in this section are designed to improve the disclosures related to Segment reporting on an interim and annual basis. Public companies must disclose significant segment expenses and an amount for other segment items. This will also require that a company disclose its annual disclosures under Topic 280 in each interim period. Furthermore, companies will need to disclose the Chief Operating Decision Maker (CODM) and how the CODM assesses the performance of a segment. Lastly, public companies that have a single reportable segment must report the required disclosures under topic 280. The amendments in this Update are effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. Early adoption is permitted. AES Indiana is currently evaluating the impact of adopting the standard on its Financial Statements. 2023-09 Income Taxes (Topic 740): Improvements to Income Tax Disclosures The amendments in this Update require that public business entities on an annual basis (1) disclose specific categories in the rate reconciliation and (2) provide additional information for reconciling items that meet a quantitative threshold. Furthermore, companies are required to disclose a disaggregated amount of income taxes paid at a federal, state, and foreign level as well as a break down of income taxes paid in a jurisdiction that comprises 5% of a company's total income taxes paid. Lastly, this ASU requires that companies disclose income (loss) from continuing operations before income tax at a domestic and foreign level and that companies disclose income tax expense from continuing operations on a federal, state, and foreign level. The amendments in this Update are effective for fiscal years beginning after December 15, 2024. AES Indiana is currently evaluating the impact of adopting the standard on its Financial Statements.

Regulatory Matters

Regulatory Matters	12 Months Ended
	Dec. 31, 2023
Indianapolis Power And Light Company
Entity Information [Line Items]
Regulatory Assets and Liabilities	. REGULATORY MATTERS General AES Indiana is subject to regulation by the IURC as to its services and facilities, the valuation of property, the construction, purchase, or lease of electric generating facilities, the classification of accounts, rates of depreciation, retail rates and charges, the issuance of securities (other than evidences of indebtedness payable less than twelve months after the date of issue), the acquisition and sale of some public utility properties or securities and certain other matters. In addition, AES Indiana is subject to the jurisdiction of the FERC with respect to, among other things, short-term borrowings not regulated by the IURC, the sale of electricity at wholesale, the transmission of electric energy in interstate commerce, the classification of accounts, reliability standards, and the acquisition and sale of utility property in certain circumstances as provided by the Federal Power Act. As a regulated entity, AES Indiana is required to use certain accounting methods prescribed by regulatory bodies which may differ from those accounting methods required to be used by unregulated entities. AES Indiana is also affected by the regulatory jurisdiction of the EPA at the federal level, and the IDEM at the state level. Other significant regulatory agencies affecting AES Indiana include, but are not limited to, the NERC, the U.S. Department of Labor and the IOSHA. Basic Rates and Charges AES Indiana’s basic rates and charges represent the largest component of its annual revenue. AES Indiana’s basic rates and charges are determined after giving consideration, on a pro-forma basis, to all allowable costs for ratemaking purposes including a fair return on the fair value of the utility property used and useful in providing service to customers. These basic rates and charges are set and approved by the IURC after public hearings. Such proceedings, which have occurred at irregular intervals, involve AES Indiana, the IURC, the Indiana Office of Utility Consumer Counselor, and other interested stakeholders. Pursuant to statute, the IURC is to conduct a periodic review of the basic rates and charges of all Indiana utilities at least once every four years, but the IURC has the authority to review the rates of any Indiana utility at any time. Once set, the basic rates and charges authorized do not assure the realization of a fair return on the fair value of property. AES Indiana’s declining block rate structure generally provides for residential and commercial customers to be charged a lower per kWh rate at higher consumption levels. Therefore, as volumes increase, the weighted average price per kWh decreases. Numerous factors including, but not limited to, weather, inflation, customer growth and usage, the level of actual operating and maintenance expenditures, fuel costs, generating unit availability, and capital expenditures including those required by environmental regulations can affect the return realized. Regulatory Rate Review and Base Rate Orders AES Indiana filed a petition with the IURC on June 28, 2023, for authority to increase its basic rates and charges to cover the rising operational costs and needs associated with continuing to serve its customers safely and reliably. The factors leading to AES Indiana's first base rate increase request in five years include inflationary impacts on operations and maintenance expenses, investments in the transmission and distribution systems, and modernization of its customer systems. AES Indiana is also seeking recovery of increased costs to support its vegetation management plan, which covers the removal of overhang and tree trimming in its service territory. AES Indiana also seeks to better align depreciation expense with the period in which the generation plants provide service to customers and remove operational costs of the retired Petersburg units from rates. On November 22, 2023, AES Indiana entered into a unanimous stipulation and settlement agreement (the "settlement") with the OUCC and the intervening parties which, if approved by the IURC, would increase its annual revenue requirement by $73 million. AES Indiana expects to receive an order from the IURC and place new rates into effect by the end of the second quarter of 2024. On October 31, 2018, the IURC issued an order approving an uncontested settlement agreement previously filed with the IURC by AES Indiana for a $43.9 million, or 3.2%, increase to annual revenue (the "2018 Base Rate Order"). The 2018 Base Rate Order includes recovery through rates of the CCGT at Eagle Valley completed in the first half of 2018, as well as other construction projects and changes to operating income since the 2016 Base Rate Order. New basic rates and charges became effective on December 5, 2018. The 2018 Base Rate Order provides that annual wholesale margins earned above (or below) the benchmark of $16.3 million shall be passed back (or charged) to customer rates through a rate adjustment mechanism. Similarly, the 2018 Base Rate Order provides that all capacity sales above (or below) a benchmark of $11.3 million shall be passed back (or charged) to customer rates through a rate adjustment mechanism. FAC and Authorized Annual Jurisdictional Net Operating Income AES Indiana may apply to the IURC for a change in AES Indiana’s fuel charge every three months to recover AES Indiana’s estimated fuel costs, including the energy portion of purchased power costs, which may be above or below the levels included in AES Indiana’s basic rates and charges. AES Indiana must present evidence in each FAC proceeding that it has made every reasonable effort to acquire fuel and generate or purchase power or both so as to provide electricity to its retail customers at the lowest fuel cost reasonably possible. Independent of the IURC’s ability to review basic rates and charges, Indiana law requires electric utilities under the jurisdiction of the IURC to meet operating expense and income test requirements as a condition for approval of requested changes in the FAC. A utility may be unable to recover all of its fuel costs if its rolling twelve-month operating income, determined at quarterly measurement dates, exceeds its authorized annual jurisdictional net operating income and there are not sufficient applicable cumulative net operating income deficiencies (“Cumulative Deficiencies”) to offset it. The Cumulative Deficiencies calculation provides that only five years’ worth of historical earnings deficiencies or surpluses are included, unless it has been greater than five years since the most recent rate case. In calendar years 2021 and 2022, AES Indiana reported earnings in excess of the authorized level for certain quarterly reporting periods in those years. AES Indiana has not reported earnings in excess of the authorized level for any FAC periods in the calendar year 2023. Prior to 2020, AES Indiana was not required to reduce its fuel cost recovery because of its Cumulative Deficiencies. During 2020, AES Indiana's Cumulative Deficiencies dropped to zero. AES Indiana recorded a reduction to revenue of $0.0 million, $0.3 million and $5.5 million in 2023, 2022 and 2021, respectively. As of the FAC period ending with the twelve months of October 31, 2023, AES Indiana has Cumulative Deficiencies; therefore, AES will not be required to reduce its fuel cost recovery for future earnings in excess of the authorized level until there are no longer Cumulative Deficiencies. ECCRA AES Indiana may apply to the IURC for approval of a rate adjustment known as the ECCRA periodically to recover costs (including a return) to comply with certain environmental regulations applicable to AES Indiana’s generating stations and to recover certain investments in renewable and battery storage projects. The total amount of AES Indiana’s environmental equipment and renewable projects approved for ECCRA recovery as of December 31, 2023 was $129.7 million. The jurisdictional revenue requirement approved by the IURC to be included in AES Indiana’s rates for the twelve-month period ending February 2024 is a net cost to customers of $8.9 million. DSM Through various rate orders from the IURC, AES Indiana has been able to recover its costs of implementing various DSM programs throughout the periods covered by this report. In 2023, 2022 and 2021, AES Indiana also had the ability to receive performance incentives, dependent upon the level of success of the programs. Performance incentives included in rates for the years ended December 31, 2023, 2022 and 2021 were $2.7 million, $8.3 million and $7.2 million, respectively. On December 29, 2020, the IURC approved a settlement agreement establishing a new three year DSM plan for AES Indiana through 2023. The approval included cost recovery of programs as well as performance incentives, depending on the level of success of the programs. The order also approved recovery of lost revenue, consistent with the provisions of the settlement agreement. AES Indiana filed a petition with the IURC on May 26, 2023 asking for approval of a one year DSM interim plan. On December 27, 2023, the IURC approved a one year DSM plan for AES Indiana through 2024. The approval included cost recovery of programs as well as performance incentives, depending on the level of success of the programs. The order also approved recovery of lost revenue, consistent with the provisions of the settlement agreement. Wind and Solar Power Purchase Agreements AES Indiana is currently committed under a power purchase agreement to purchase all wind-generated electricity through 2029 from a wind project in Indiana ("Hoosier Wind Project"). On July 28, 2023, AES Indiana executed the Purchase Agreement and is currently in the process of acquiring this project. The existing power purchase agreement will be terminated upon closing (see "IRP Filings and Replacement Generation - Hoosier Wind Project" below for further information). AES Indiana is also committed under another agreement to purchase all wind-generated electricity through 2031 from a project in Minnesota. The Indiana project has a maximum output capacity of approximately 100 MW and the Minnesota project has a maximum output capacity of approximately 200 MW. In addition, AES Indiana has 94.5 MW of solar-generated electricity in its service territory under long-term contracts (these long-term contracts have expiration dates ranging from 2026 to 2033), of which 94.0 MW was in operation as of December 31, 2023. AES Indiana has authority from the IURC to recover the costs for all of these agreements through an adjustment mechanism administered within the FAC. If and when AES Indiana sells the renewable energy attributes (in the form of renewable energy credits) generated from these facilities, the proceeds would pass back to benefit AES Indiana’s retail customers through the FAC. TDSIC In 2013, Senate Enrolled Act 560, the Transmission, Distribution, and Storage System Improvement Charge ("TDSIC") statute, was signed into law. The TDSIC statute was revised in 2019. Among other provisions, this legislation provides for cost recovery outside of a base rate proceeding for new or replacement electric and gas transmission, distribution, and storage projects that a public utility undertakes for the purposes of safety, reliability, system modernization, or economic development. Provisions of the TDSIC statute require that, among other things, requests for recovery include a plan of at least five years and not more than seven for eligible investments. The first eighty percent of eligible costs can be recovered using a periodic rate adjustment mechanism. The cost recovery mechanism is referred to as a TDSIC mechanism. Recoverable costs include a return on, and of, the investment, including AFUDC, post-in-service carrying charges, operation and maintenance expenses, depreciation and property taxes. The remaining twenty percent of recoverable costs are to be deferred for future recovery in the public utility’s next base rate case. The periodic rate adjustment mechanism is capped at an annual increase of no more than two percent of total retail revenue. On March 4, 2020, the IURC issued an order approving the projects in a seven-year TDSIC Plan for eligible transmission, distribution and storage system improvements totaling $1.2 billion from 2020 through 2026. Beginning in June 2020, AES Indiana files an annual TDSIC rate adjustment for a return on and of investments through March 31 with rates requested to be effective each November. Annual TDSIC plan update filings are required to be staggered by six months as ordered by the IURC and are filed each December. The total amount of AES Indiana’s equipment net of depreciation, including carrying costs, approved for TDSIC recovery as of December 31, 2023 was $399.6 million, The jurisdictional revenue requirement approved by the IURC to be included in AES Indiana’s rates for the twelve-month period ending October 2024 is a net cost to customers of $56.5 million. IRP Filings and Replacement Generation Electric utilities in Indiana are required to submit Integrated Resource Plans (IRPs) every three years. The IRPs are subject to a rigorous stakeholder process. IRPs describe how the utility plans to deliver safe, reliable, and efficient electricity at just and reasonable rates. 2022 IRP AES Indiana held public advisory meetings for the 2022 IRP in January, April, June, September and October of 2022. Changes to our generation portfolio are evaluated and decided through the IRP. AES Indiana issued an all-source Request for Proposal on April 14, 2022, in order to competitively procure energy and capacity in the near term; such need was evaluated in AES Indiana's 2022 IRP. In December 2022, AES Indiana filed its 2022 IRP with the IURC, which describes AES Indiana's Preferred Resource Portfolio for meeting generation capacity needs for serving AES Indiana's retail customers over the next several years. The Preferred Resource Portfolio is AES Indiana's reasonable least cost option and provides a cleaner and more diverse generation mix for customers. The 2022 IRP short-term action plan includes converting the two remaining coal units at Petersburg to natural gas. AES Indiana has not yet filed for the regulatory approvals from the IURC to convert Petersburg units 3 and 4; however, AES Indiana expects to do so in the first half of 2024. Construction is expected to begin in 2025 and be completed by the end of 2026. Additionally, AES Indiana plans to add up to 1,300 MW of wind, solar, and battery energy storage by 2027. As new technologies, such as green hydrogen, small modular reactors and carbon capture are developed and cost effective, AES Indiana will evaluate them in the future planning processes. As a result of the plan to convert Petersburg units 3 and 4 to natural gas, AES Indiana recorded a $1.5 million write off of capital projects during the period ended December 31, 2022 to " Operating expenses - Operation and maintenance " on the accompanying Consolidated Statements of Operations. 2019 IRP In December 2019, AES Indiana filed its 2019 IRP, which included the retirement of approximately 630 MW of coal-fired generation at Petersburg Units 1 and 2 in 2021 and 2023, respectively. Based on extensive modeling, AES Indiana determined that the cost of operating Petersburg Units 1 and 2 exceeded the value customers received compared to alternative resources. Retirement of these units allowed the company to cost-effectively diversify the portfolio and transition to lower cost and cleaner resources while maintaining a reliable system. AES Indiana issued an all-source Request for Proposal on December 20, 2019, in order to competitively procure replacement capacity by June 1, 2023, which was the first year AES Indiana was expected to have a capacity shortfall. AES Indiana's modeling indicated that a combination of wind, solar, storage, and energy efficiency would be the lowest reasonable cost option for the replacement capacity. As a result of the plans to retire Petersburg Units 1 and 2, AES Indiana recorded $0.7 million, $2.1 million, and $0.8 million of obsolescence losses, during the periods ended December 31, 2023, 2022, and 2021, respectively, for materials and supplies inventory AES Indiana did not believe will be utilized by the planned retirement dates, which is recorded in " Operating expenses - Operation and maintenance " on the accompanying Consolidated Statements of Operations. As a result of the plans to retire Petersburg Units 1 and 2, AES Indiana filed a petition with the IURC on February 26, 2021 for approvals and cost recovery associated with these retirements. On August 6, 2021, AES Indiana filed an uncontested Stipulation and Settlement Agreement with the other parties in the case which includes: (1) AES Indiana's creation of regulatory assets for the net book value of Petersburg units 1 and 2 upon retirement; (2) a method for amortization of the regulatory assets; and (3) recovery of the regulatory assets through ongoing amortization in AES Indiana’s future rate cases. The Settlement Agreement also reserves all rights of all the parties with respect to the ratemaking treatment related to the regulatory assets, including the proper rate of return and mechanisms for recovery. On November 17, 2021, the IURC approved the Settlement Agreement without modification. AES Indiana retired 230 MW Petersburg Unit 1 in May 2021 and 415 MW Petersburg Unit 2 in June 2023. AES Indiana had $35.7 million and $224.2 million of Petersburg Units 1 and 2 retirement costs, respectively, net of accumulated amortization, recorded as long-term regulatory assets as of December 31, 2023. AES Indiana had $47.6 million and $239.9 million of Petersburg Units 1 and 2 retirement costs, respectively, net of accumulated amortization, recorded as long-term regulatory assets as of December 31, 2022. Hardy Hills Solar Project In January 2021, AES Indiana, through a wholly-owned subsidiary, executed an agreement for the acquisition and construction of the 195 MW Hardy Hills Solar Project to be developed in Clinton County, Indiana. In December 2022, the agreement was amended to revise the project schedule, including shifting the completion date to 2024, and adjusting for increased project costs. On January 13, 2023, AES Indiana filed a petition with the IURC for approval of these revisions, which was approved in August 2023. On June 16, 2021, AES Indiana received an order from the IURC approving a petition and case-in-chief seeking a CPCN for this solar project, including a joint venture structure between an AES Indiana subsidiary and one or more tax equity partners upon completion and approval for recovery of project development costs and carrying costs on AES Indiana's investment in the project. The transaction closed in December 2021 and was accounted for as an asset acquisition of a variable interest entity that did not meet the definition of a business; therefore, the individual assets and liabilities were recorded at their fair values. Total net assets of $51.6 million were recorded in the accompanying Consolidated Balance Sheets associated with the transaction, primarily consisting of a development project intangible asset (see Note 1, "Overview and Summary of Significant Accounting Policies - Intangible Assets" ). A gain for the difference between the consideration transferred and the assets and liabilities recognized was recorded in “ Operating costs and expenses - Other, net” on the accompanying Consolidated Statements of Operations. Total consideration included a future payment contingent on certain future costs incurred by the project. As such, a $3.2 million contingent liability was recorded in " Other Non-Current Liabilities" on the accompanying Consolidated Balance Sheets as of December 31, 2021. During 2022, this liability was remeasured due to updated cost estimates and was reduced to $0.0 million. On December 1, 2023, AES Indiana, through a wholly-owned subsidiary (the "Class B Member"), and a third-party investor (the "Class A Member"), entered into an Equity Capital Contribution Agreement, pursuant to which each member made certain capital contributions to Hardy Hills JV. The Class A member made total contributions of $79.3 million through December 31, 2023. Hardy Hills JV is consolidated by the Class B Member under the Variable Interest Model, and noncontrolling interest (“NCI”) was recorded by AES Indiana at the amount of cash contributed by the Class A Member. In December 2023, the first stage of the construction for the Hardy Hills Solar Project was completed and placed in service, with initial operations for over half of the project commencing on December 28, 2023. Upon the first stage of the project being placed in service, the Company recognized $26.1 million of earnings from tax attributes using the HLBV method. The final stage for construction of the project is expected to be completed during the first half of 2024. Petersburg Energy Center Project In July 2021, AES Indiana, through a wholly-owned subsidiary, executed an agreement for the acquisition and construction of a 250 MW solar and 45MW (180 MWh) energy storage facility to be developed in Pike County, Indiana. In October 2022, the agreement was amended to revise the project schedule, including shifting the completion date to 2025, and adjusting for increased project costs. On December 22, 2022, AES Indiana filed a petition with the IURC for approval of these revisions, which was approved in May 2023. On August 31, 2023, AES Indiana closed on the agreement for the acquisition and construction of the Petersburg Energy Center Project. This transaction was accounted for as an asset acquisition of a variable interest entity that did not meet the definition of a business; therefore, the individual assets were recorded at their fair values. Total net assets of $48.7 million were recorded in the accompanying Consolidated Balance Sheets associated with the transaction, primarily consisting of project development intangible assets (see Note 1, "Overview and Summary of Significant Accounting Policies - Intangible Assets" for further information). Pike County BESS Project In June 2023, AES Indiana, through a wholly-owned subsidiary, executed an agreement for the construction of the 200 MW (800 MWh) Pike County BESS Project to be developed at the AES Indiana Petersburg Plant site in Pike County, Indiana. On July 19, 2023, AES Indiana filed a petition and case-in-chief with the IURC seeking approval for a Clean Energy Project and associated timely cost recovery under Indiana Code for this project. A hearing for this case was held in October 2023, and IURC approval was received on January 17, 2024. The Pike County BESS Project is expected to be completed in 2024. Hoosier Wind Project On July 5, 2023, AES Indiana filed a Notice of Intent with the IURC to request approval of a Clean Energy Project and for issuance of a CPCN for the Hoosier Wind Project acquisition. The proposed Project is the acquisition of the Hoosier Wind Project, which is an existing 106 MW wind facility located in Benton County, Indiana. The Company executed the Purchase Agreement on July 28, 2023. A CPCN for this case was filed in early August 2023, and IURC approval was received on January 24, 2024. The acquisition of the Hoosier Wind Project is expected to be completed in the first quarter of 2024. Incentives for Clean Energy Projects Indiana Code 8-1-8 (the "clean energy statute") offers certain incentives for clean energy projects. Primarily, it allows for the timely recovery of costs and expenses incurred during construction and operation of eligible projects outside of a base rate proceeding. Clean energy projects eligible for incentives under this statute include renewable energy resources such as wind, photovoltaic cells and panels, solar energy, and energy storage systems or technologies, among others. AES Indiana filed for and received IURC approval of the Hoosier Wind Project and Pike County BESS Project under this statute. AES Indiana continues to evaluate projects which may also be filed under this statute. IURC COVID-19 Orders Due to the COVID-19 pandemic, there was a disconnection moratorium in 2020 for IURC-jurisdictional utilities, as well as suspension of certain utility fees (late fees, convenience fees, deposits, and disconnection/reconnection fees) from residential customers. The IURC authorized Indiana utilities to use regulatory accounting for any impacts associated with the moratorium and suspension. The IURC also authorized regulatory accounting treatment for COVID-19 related uncollectible and incremental bad debt expense. As a result of the IURC's COVID-19 related orders issued in 2020, AES Indiana has recorded a regulatory asset of $5.4 million as of December 31, 2023 and 2022, which will be recovered through base rates under the stipulation and settlement agreement entered into on November 22, 2023, if approved by the IURC. EDG Rates On March 1, 2021, AES Indiana filed a petition with the IURC for approval of its proposed rate for the procurement of EDG and related consumer EDG credit issues. The EDG rate replaced the net metering program beginning in July 2022, when net metering was no longer available to new customers. The IURC approved the EDG rate by order dated January 26, 2022, On March 16, 2022, the IURC denied the petition for reconsideration filed by the other parties on February 15, 2022. The matter was subject to an appeal filed by the other parties on February 22, 2022, which was held in abeyance by the Indiana Court of Appeals pending resolution of a petition to transfer to the Indiana Supreme Court filed in a similar case involving a different and unaffiliated utility. The stay was extended by the Indiana Court of Appeals on July 11, 2022. On January 4, 2023, the Indiana Supreme Court issued a final decision in favor of the utility in the similar case that served as the basis of the stay in the AES Indiana case. On February 3, 2023, the OUCC moved to dismiss the appeal, which motion was granted on February 13, 2023. EV Portfolio Program On January 27, 2023, AES Indiana filed with the IURC a request to approve its EV Portfolio and associated accounting and ratemaking treatment. The EV Portfolio includes two separate parts: (1) a set of EV specific rates, tariffs, and alternative pricing structures, and (2) a set of Public Use EV Pilot Programs. The EV portfolio is designed to produce net benefits for all customers through new retail margins and grid optimization. The projected costs to successfully implement the services proposed in the EV Portfolio are estimated at $16.2 million over the three-year period. AES Indiana requested approval to defer as a regulatory asset and recover in future base rates the cost necessary to implement the EV Portfolio, including carrying charges. A hearing on this request was held in July 2023. On November 22, 2023, the IURC issued an order approving AES Indiana's EV Portfolio filing with approval to defer as a regulatory asset and to seek recovery in future base rates the cost necessary to implement the EV Portfolio, including carrying charges with no other significant modifications. Storm Outage Restoration Inquiry On July 11, 2023, the OUCC and the Citizens Action Coalition (“CAC”) filed a Joint Petition through which they requested the IURC open an investigation into AES Indiana’s practices and procedures regarding storm outage restoration. A technical conference was held on October 2, 2023, to discuss AES Indiana’s response to outages and storm restoration; particularly the storms that occurred between June 29, 2023 and July 2, 2023. House Bill 1002 In the first quarter of 2022, the 2022 Indiana General Assembly passed House Enrolled Act 1002, which includes language regarding the repeal of the URT. AES Indiana filed a rate adjustment with the IURC on April 29, 2022, which was approved by the IURC on June 28, 2022. AES Indiana began charging the new rates excluding URT in July 2022. Prior to the repeal, the URT was recoverable through a current charge to customer rates. After the repeal, the new rates approved by the IURC adjusted both revenue and tax expense. As a result, the repeal of the URT had no impact on AES Indiana's net income. Regulatory Assets and Liabilities Regulatory assets represent deferred costs or credits that have been included as allowable costs or credits for ratemaking purposes. AES Indiana has recorded regulatory assets or liabilities relating to certain costs or credits as authorized by the IURC or established regulatory practices in accordance with ASC 980. AES Indiana is amortizing non tax-related regulatory assets to expense over periods ranging from 1 to 43 years. Tax-related regulatory assets represent the net income tax costs to be considered in future regulatory proceedings generally as the tax-related amounts are paid. The amounts of regulatory assets and regulatory liabilities at December 31 are as follows: 2023 2022 Recovery Period (In Thousands) Regulatory assets, current: Undercollections of rate riders $ 75,416 $ 26,047 Approximately 1 year (1) Fuel costs — 79,861 Approximately 1 year (1) Unamortized reacquisition premium on debt 188 — Approximately 1 year Costs being recovered through basic rates and charges 13,815 13,815 Approximately 1 year (1) Total regulatory assets, current 89,419 119,723 Regulatory assets, non-current: Unrecognized pension and other postretirement benefit plan costs 115,847 131,907 Various (2) Deferred MISO costs 21,091 34,483 Through 2026 (1) Unamortized Petersburg Unit 4 carrying charges and certain other costs 2,812 3,866 Through 2026 (1)(3) Unamortized reacquisition premium on debt 13,379 14,429 Over remaining life of debt Environmental costs 66,837 68,947 Through 2046 (1)(3) COVID-19 costs 5,426 5,426 4 years (4) Major storm damage 1,493 — To be determined TDSIC costs 35,979 18,547 36.3 years (1)(3) Petersburg Unit 1 and 2 retirement costs 259,892 287,463 Through 2034 (1)(3) Hardy Hills Solar Project development costs 6,774 5,744 30 years (3) Petersburg Energy Center Project development costs 2,469 1,582 30 years (3) Pike County BESS Project development costs 2,623 — 20 years (3) Fuel costs 4,275 20,518 Through 2025 (1) Other miscellaneous 2,887 1,027 Various (5) Total regulatory assets, non-current 541,784 593,939 Total regulatory assets $ 631,203 $ 713,662 Regulatory liabilities, current: Overcollections and other credits being passed to customers through rate riders $ 19,649 $ 15,803 Approximately 1 year (1) FTRs 3,722 7,545 Approximately 1 year (1) Total regulatory liabilities, current 23,371 23,348 Regulatory liabilities, non-current: ARO and accrued asset removal costs 451,886 518,797 Not applicable Deferred income taxes payable to customers through rates 74,796 88,662 Various Hardy Hills sponsor investment tax credit 542 — To be determined (6) Major storm damage — 5,126 To be determined Total regulatory liabilities, non-current 527,224 612,585 Total regulatory liabilities $ 550,595 $ 635,933 (1) Recovered (credited) per specific rate orders (2) AES Indiana receives a return on its discretionary funding (3) Recovered with a current return (4) Per the signed stipulation in the 2023 distribution rate case, Cause No. 45911 (5) Some of these costs are being recovered in basic rates and charges through 2026. For the remainder, recovery over four years was agreed to in the signed stipulation in the 2023 distribution rate case, Cause No. 45911. AES Indiana will include this credit in a future ECR filing. (6) Will be included in a future ECR filing Current Regulatory Assets and Liabilities Current regulatory assets and liabilities primarily represent costs that are being recovered per specific rate orders; recovery for the remaining costs is probable, but not certain. As current assets, this includes undercollection of adjustment mechanisms for: (i) DSM, (ii) ECCRA costs, (iii) Off System Sales Margin Sharing, (iv) Capacity rider costs and (v) TDSIC. It also includes the current portion of deferred MISO costs and environmental costs collected through base rates which are described in greater detail below. With the exception of environmental costs, these costs do not earn a return on investment. As current liabilities, this includes (i) overcollection of MISO rider costs, (ii) Green Power, and (iii) deferred fuel costs. Deferred Fuel Deferred fuel costs are a component of current and long-term regulatory assets or liabilities (which is a result of AES Indiana charging either more or less for fuel than our actual costs to our jurisdictional c

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2019
Entity Information [Line Items]
Utility Plant In Service		The original cost of property, plant and equipment segregated by functional classifications follows: As of December 31, 2023 2022 (In Thousands) Production $ 3,942,052 $ 4,164,416 Transmission 487,527 461,245 Distribution 2,304,526 2,045,579 General plant 348,338 311,074 Total property, plant and equipment $ 7,082,443 $ 6,982,314 As of December 31, 2023 and 2022, AES Indiana had $259.9 million and $287.5 million, respectively, of net property, plant and equipment associated with the Petersburg Unit 1 and Unit 2 retirements recorded as long-term regulatory assets (for further discussion, see Note 2, “ Regulatory Matters - IRP Filings and Replacement Generation ”). Substantially all of AES Indiana’s property is subject to a $2,153.8 million direct first mortgage lien, as of December 31, 2023, securing AES Indiana’s first mortgage bonds. Total non-contractually or legally required accrued removal costs of utility plant in service at December 31, 2023 and 2022 were $680.9 million and $694.0 million, respectively; and total contractually or legally required removal costs of property, plant and equipment at December 31, 2023 and 2022 were $249.9 million and $218.7 million, respectively. Please see “ARO” below for further information. ARO ASC 410 “Asset Retirement and Environmental Obligations” addresses financial accounting and reporting for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal operation. A legal obligation for purposes of ASC 410 is an obligation that a party is required to settle as a result of an existing law, statute, ordinance, written or oral contract or the doctrine of promissory estoppel. AES Indiana’s ARO relates primarily to environmental issues involving asbestos-containing materials, ash ponds, landfills and miscellaneous contaminants associated with its generating plants, transmission system and distribution system. The following is a roll forward of the ARO legal liability year end balances: 2023 2022 (In Thousands) Balance as of January 1 $ 218,729 $ 189,509 Liabilities incurred 17,080 1,159 Liabilities settled (11,902) (24,699) Revisions to cash flow and timing estimates 12,921 44,679 Accretion expense 13,102 8,081 Balance as of December 31 $ 249,930 $ 218,729
Indianapolis Power And Light Company
Entity Information [Line Items]
Utility Plant In Service	. PROPERTY, PLANT AND EQUIPMENT The original cost of property, plant and equipment segregated by functional classifications follows: As of December 31, 2023 2022 (In Thousands) Production $ 3,942,052 $ 4,164,416 Transmission 487,527 461,245 Distribution 2,304,526 2,045,579 General plant 348,338 311,074 Total property, plant and equipment $ 7,082,443 $ 6,982,314 As of December 31, 2023 and 2022, AES Indiana had $259.9 million and $287.5 million, respectively, of net property, plant and equipment associated with the Petersburg Unit 1 and Unit 2 retirements recorded as long-term regulatory assets (for further discussion, see Note 2, “ Regulatory Matters - IRP Filings and Replacement Generation ”). Substantially all of AES Indiana’s property is subject to a $2,153.8 million direct first mortgage lien, as of December 31, 2023, securing AES Indiana’s first mortgage bonds. Total non-contractually or legally required accrued removal costs of utility plant in service at December 31, 2023 and 2022 were $680.9 million and $694.0 million, respectively; and total contractually or legally required removal costs of property, plant and equipment at December 31, 2023 and 2022 were $249.9 million and $218.7 million, respectively. Please see “ARO” below for further information. ARO ASC 410 “Asset Retirement and Environmental Obligations” addresses financial accounting and reporting for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal operation. A legal obligation for purposes of ASC 410 is an obligation that a party is required to settle as a result of an existing law, statute, ordinance, written or oral contract or the doctrine of promissory estoppel. AES Indiana’s ARO relates primarily to environmental issues involving asbestos-containing materials, ash ponds, landfills and miscellaneous contaminants associated with its generating plants, transmission system and distribution system. The following is a roll forward of the ARO legal liability year end balances: 2023 2022 (In Thousands) Balance as of January 1 $ 218,729 $ 189,509 Liabilities incurred 17,080 1,159 Liabilities settled (11,902) (24,699) Revisions to cash flow and timing estimates 12,921 44,679 Accretion expense 13,102 8,081 Balance as of December 31 $ 249,930 $ 218,729

Fair Value

Fair Value	12 Months Ended
	Dec. 31, 2023
Entity Information [Line Items]
Fair Value	FAIR VALUE The fair value of current financial assets and liabilities approximate their reported carrying amounts. The estimated fair values of the Company’s assets and liabilities have been determined using available market information. Because these amounts are estimates and based on hypothetical transactions to sell assets or transfer liabilities, the use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts. Fair Value Hierarchy and Valuation Techniques ASC 820 defines and establishes a framework for measuring fair value and expands disclosures about fair value measurements for financial assets and liabilities that are adjusted to fair value on a recurring basis and/or financial assets and liabilities that are measured at fair value on a nonrecurring basis, which have been adjusted to fair value during the period. In accordance with ASC 820, we have categorized our financial assets and liabilities that are adjusted to fair value, based on the priority of the inputs to the valuation technique, following the three-level fair value hierarchy prescribed by ASC 820 as follows: Level 1 - unadjusted quoted prices for identical assets or liabilities in an active market; Level 2 - inputs from quoted prices in markets where trading occurs infrequently or quoted prices of instruments with similar attributes in active markets; and Level 3 - unobservable inputs reflecting management’s own assumptions about the inputs used in pricing the asset or liability. Whenever possible, quoted prices in active markets are used to determine the fair value of our financial instruments. Our financial instruments are not held for trading or other speculative purposes. The estimated fair value of financial instruments has been determined by using available market information and appropriate valuation methodologies. However, considerable judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we could realize in a current market exchange. The use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts. Financial Assets VEBA Assets IPALCO has VEBA investments that are to be used to fund certain employee postretirement health care benefit plans. These assets are primarily comprised of open-ended mutual funds, which are valued using the net assets value per unit. These investments are recorded at fair value within " Other non-current assets " on the accompanying Consolidated Balance Sheets and classified as equity securities. All changes to fair value on the VEBA investments are included in income in the period that the changes occur. These changes to fair value were not material for the years ended December 31, 2023, 2022, or 2021. Any unrealized gains or losses are recorded in " Other (expense) / income, net " on the accompanying Consolidated Statements of Operations and were not material to the consolidated financial statements in the periods covered by this report. FTRs In connection with AES Indiana’s participation in MISO, in the second quarter of each year AES Indiana is granted financial instruments that can be converted into cash or FTRs based on AES Indiana’s forecasted peak load for the period. FTRs are used in the MISO market to hedge AES Indiana’s exposure to congestion charges, which result from constraints on the transmission system. AES Indiana’s FTRs are valued at the cleared auction prices for FTRs in MISO’s annual auction. Because of the infrequent nature of this valuation, the fair value assigned to the FTRs is considered a Level 3 input under the fair value hierarchy required by ASC 820. An offsetting regulatory liability has been recorded as these revenue or costs will be flowed through to customers through the FAC. As such, there is no impact on our Consolidated Statements of Operations. Forward Power Contracts As of December 31, 2023 and 2022, all outstanding forward power contracts had settled and there was no notional amount outstanding. All changes in the market value of the forward power contracts were recorded in the Consolidated Statements of Operations in the period in which the change occurred. See also Note 5, " Derivative Instruments and Hedging Activities - Derivatives Not Designated as Hedge" for further information. Interest Rate Hedges IPALCO's interest rate hedges have a combined notional amount of $400.0 million. All changes in the market value of the interest rate hedges are recorded in AOCI. See also Note 5, " Derivative Instruments and Hedging Activities - Cash Flow Hedges " for further information. Recurring Fair Value Measurements The fair value of assets at December 31, 2023 and 2022 measured on a recurring basis and the respective category within the fair value hierarchy for IPALCO was determined as follows: Fair Value as of December 31, 2023 Fair Value as of December 31, 2022 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total (In Thousands) Financial assets: VEBA investments: Money market funds $ 127 $ — $ — $ 127 $ 5 $ — $ — $ 5 Mutual funds 3,425 — — 3,425 3,223 — — 3,223 Total VEBA investments 3,552 — — 3,552 3,228 — — 3,228 FTRs — — 1,388 1,388 — — 7,545 7,545 Interest rate hedges — 14,294 — 14,294 — 12,172 — 12,172 Total financial assets measured at fair value $ 3,552 $ 14,294 $ 1,388 $ 19,234 $ 3,228 $ 12,172 $ 7,545 $ 22,945 The following table sets forth a roll forward of financial instruments, measured at fair value on a recurring basis, classified as Level 3 in the fair value hierarchy (note, amounts in this table indicate carrying values, which approximate fair values): Reconciliation of Financial Instruments Classified as Level 3 (In Thousands) Balance at January 1, 2022 $ 1,235 Issuances 15,338 Settlements (9,028) Balance at December 31, 2022 7,545 Issuances 3,624 Settlements (9,781) Balance at December 31, 2023 $ 1,388 Financial Instruments not Measured at Fair Value in the Consolidated Balance Sheets Debt The fair value of our outstanding fixed-rate debt has been determined on the basis of the quoted market prices of the specific securities issued and outstanding. In certain circumstances, the market for such securities was inactive and therefore the valuation was adjusted to consider changes in market spreads for similar securities. Accordingly, the purpose of this disclosure is not to approximate the value on the basis of how the debt might be refinanced. The following table shows the face value and the fair value of fixed-rate and variable-rate indebtedness (Level 2) for the periods ending: December 31, 2023 December 31, 2022 Face Value Fair Value Face Value Fair Value (In Thousands) Fixed-rate $ 3,033,800 $ 2,860,467 $ 3,033,800 $ 2,775,644 Variable-rate 455,000 455,000 — — Total indebtedness $ 3,488,800 $ 3,315,467 $ 3,033,800 $ 2,775,644 The difference between the face value and the carrying value of this indebtedness represents the following: • unamortized deferred financing costs of $24.8 million and $26.3 million at December 31, 2023 and 2022, respectively; and • unamortized discounts of $6.8 million and $7.1 million at December 31, 2023 and 2022, respectively.
Indianapolis Power And Light Company
Entity Information [Line Items]
Fair Value	FAIR VALUE The fair value of current financial assets and liabilities approximate their reported carrying amounts. The estimated fair values of AES Indiana’s assets and liabilities have been determined using available market information. Because these amounts are estimates and based on hypothetical transactions to sell assets or transfer liabilities, the use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts. Fair Value Hierarchy and Valuation Techniques ASC 820 defines and establishes a framework for measuring fair value and expands disclosures about fair value measurements for financial assets and liabilities that are adjusted to fair value on a recurring basis and/or financial assets and liabilities that are measured at fair value on a nonrecurring basis, which have been adjusted to fair value during the period. In accordance with ASC 820, AES Indiana has categorized its financial assets and liabilities that are adjusted to fair value, based on the priority of the inputs to the valuation technique, following the three-level fair value hierarchy prescribed by ASC 820 as follows: Level 1 - unadjusted quoted prices for identical assets or liabilities in an active market; Level 2 - inputs from quoted prices in markets where trading occurs infrequently or quoted prices of instruments with similar attributes in active markets; and Level 3 - unobservable inputs reflecting management’s own assumptions about the inputs used in pricing the asset or liability. Whenever possible, quoted prices in active markets are used to determine the fair value of AES Indiana’s financial instruments. AES Indiana’s financial instruments are not held for trading or other speculative purposes. The estimated fair value of financial instruments has been determined by using available market information and appropriate valuation methodologies. However, considerable judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that AES Indiana could realize in a current market exchange. The use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts. Financial Assets FTRs In connection with AES Indiana’s participation in MISO, in the second quarter of each year AES Indiana is granted financial instruments that can be converted into cash or FTRs based on AES Indiana’s forecasted peak load for the period. FTRs are used in the MISO market to hedge AES Indiana’s exposure to congestion charges, which result from constraints on the transmission system. AES Indiana’s FTRs are valued at the cleared auction prices for FTRs in MISO’s annual auction. Because of the infrequent nature of this valuation, the fair value assigned to the FTRs is considered a Level 3 input under the fair value hierarchy required by ASC 820. An offsetting regulatory liability has been recorded as these revenue or costs will be flowed through to customers through the FAC. As such, there is no impact on AES Indiana’s Consolidated Statements of Operations. Forward Power Contracts As of December 31, 2023 and 2022, all outstanding forward power contracts had settled and there was no notional amount outstanding. All changes in the market value of the forward power contracts were recorded in the Consolidated Statements of Operations in the period in which the change occurred. See also Note 5, " Derivative Instruments and Hedging Activities - Derivatives Not Designated as Hedge" for further information. Recurring Fair Value Measurements The fair value of assets at December 31, 2023 and 2022 measured on a recurring basis and the respective category within the fair value hierarchy for AES Indiana was determined as follows: Fair Value as of December 31, 2023 Fair Value as of December 31, 2022 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total (In Thousands) Financial assets: FTRs $ — $ — $ 1,388 $ 1,388 $ — $ — $ 7,545 $ 7,545 Total financial assets measured at fair value $ — $ — $ 1,388 $ 1,388 $ — $ — $ 7,545 $ 7,545 The following table sets forth a roll forward of financial instruments, measured at fair value on a recurring basis, classified as Level 3 in the fair value hierarchy (note, amounts in this table indicate carrying values, which approximate fair values): Reconciliation of Financial Instruments Classified as Level 3 (In Thousands) Balance at January 1, 2022 $ 1,235 Issuances 15,338 Settlements (9,028) Balance at December 31, 2022 7,545 Issuances 3,624 Settlements (9,781) Balance at December 31, 2023 $ 1,388 Financial Instruments not Measured at Fair Value in the Consolidated Balance Sheets Debt The fair value of AES Indiana’s outstanding fixed-rate debt has been determined on the basis of the quoted market prices of the specific securities issued and outstanding. In certain circumstances, the market for such securities was inactive and therefore the valuation was adjusted to consider changes in market spreads for similar securities. Accordingly, the purpose of this disclosure is not to approximate the value on the basis of how the debt might be refinanced. The following table shows the face value and the fair value of fixed-rate and variable-rate indebtedness (Level 2) for the periods ending: December 31, 2023 December 31, 2022 Face Value Fair Value Face Value Fair Value (In Thousands) Fixed-rate $ 2,153,800 $ 2,020,997 $ 2,153,800 $ 1,959,233 Variable-rate 455,000 455,000 — — Total indebtedness $ 2,608,800 $ 2,475,997 $ 2,153,800 $ 1,959,233 The difference between the face value and the carrying value of this indebtedness represents the following: • unamortized deferred financing costs of $20.2 million and $20.4 million at December 31, 2023 and 2022, respectively; and • unamortized discounts of $6.4 million and $6.7 million at December 31, 2023 and 2022, respectively.

Derivative Instruments and Hedg

Derivative Instruments and Hedging Activities	12 Months Ended
	Dec. 31, 2023
Derivative [Line Items]
Derivative Instruments and Hedging Activities Disclosure [Text Block]	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 Sales Net Notional Interest rate hedges Designated USD $ 400,000 $ — $ 400,000 FTRs Not Designated MWh 3,919 — 3,919 (a) Refers to whether the derivative instruments have been designated as a cash flow hedge. Cash Flow Hedges As part of our risk management processes, we identify the relationships between hedging instruments and hedged items, as well as the risk management objective and strategy for undertaking various hedge transactions. The fair values of cash flow hedges determined by current public market prices will continue to fluctuate with changes in market prices up to contract expiration. The change in the fair value of a hedging instrument is recorded in other comprehensive income and amounts deferred are reclassified to earnings in the same income statement line as the hedged item in the period in which it settles. In March 2019, we entered into three forward interest rate swaps to hedge the interest risk associated with refinancing the IPALCO 2020 maturities. The three interest rate swaps had a combined notional amount of $400.0 million. In April 2020, we de-designated the swaps as cash flow hedges and froze the AOCL of $72.3 million at the date of de-designation. The interest rate swaps were then amended and re-designated as cash flow hedges to hedge the interest rate risk associated with refinancing the 2024 IPALCO Notes. The amended interest rate swaps have a combined notional amount of $400.0 million and will be settled when the 2024 IPALCO Notes are refinanced. The $72.3 million of AOCL associated with the interest rate swaps through the date of the amendment is being amortized out of AOCL into interest expense over the remaining life of the 2030 IPALCO Notes, while any changes in fair value associated with the amended interest rate swaps will be recognized in AOCL going forward. The following tables provide information on gains or losses recognized in AOCI / (AOCL) for the cash flow hedges for the periods indicated: Interest Rate Hedges for the Years Ended December 31, $ in thousands (net of tax) 2023 2022 2021 Beginning accumulated derivative gain / (loss) in AOCI / (AOCL) $ 22,269 $ (29,407) $ (43,420) Net gains associated with current period hedging transactions 1,594 46,245 10,393 Net losses reclassified to interest expense 5,431 5,431 3,620 Ending accumulated derivative gain / (loss) in AOCI / (AOCL) $ 29,294 $ 22,269 $ (29,407) Loss expected to be reclassified to earnings in the next twelve months $ (5,375) Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months) 9 Derivatives Not Designated as Hedge AES Indiana's FTRs and forward power contracts do not qualify for hedge accounting or the normal purchases and sales exceptions under ASC 815. Accordingly, FTRs are recorded at fair value using the income approach when acquired and subsequently amortized over the annual period as they are used. The forward power contracts are recorded at fair value using the market approach with changes in the fair value charged or credited to the Consolidated Statements of Operations in the period in which the change occurred. This is commonly referred to as "MTM accounting." Realized gains and losses on the forward power contracts are included in future FAC filings, therefore any realized and unrealized gains and losses are deferred as regulatory liabilities or regulatory assets. There were net realized gains of $0.0 million and $1.3 million related to forward power contracts during the years ended December 31, 2023 and 2022, respectively, related to the forward power contracts that were deferred and included with deferred fuel costs in "Regulatory assets, current" on the accompanying Consolidated Balance Sheets. Certain qualifying derivative instruments have been designated as normal purchases or normal sales contracts, as provided under GAAP. Derivative contracts that have been designated as normal purchases or normal sales under GAAP are not subject to hedge or MTM accounting and are recognized in the Consolidated Statements of Operations on an accrual basis. When applicable, IPALCO has elected not to offset derivative assets and liabilities and not to offset net derivative positions against the right to reclaim cash collateral pledged (an asset) or the obligation to return cash collateral received (a liability) under derivative agreements. As of December 31, 2023 and 2022, IPALCO did not have any offsetting positions. The following table summarizes the fair value, balance sheet classification and hedging designation of IPALCO's derivative instruments (in thousands): December 31, Commodity Hedging Designation Balance sheet classification 2023 2022 FTRs Not a Cash Flow Hedge Derivative assets, current $ 1,388 $ 7,545 Interest rate hedges Cash Flow Hedge Derivative assets, current $ 14,294 $ — Interest rate hedges Cash Flow Hedge Derivative assets, non-current $ — $ 12,172
Subsidiaries [Member]
Derivative [Line Items]
Derivative Instruments and Hedging Activities Disclosure [Text Block]	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 Sales Net Notional FTRs Not Designated MWh 3,919 — 3,919 (a) Refers to whether the derivative instruments have been designated as a cash flow hedge. Derivatives Not Designated as Hedge AES Indiana's FTRs and forward power contracts do not qualify for hedge accounting or the normal purchases and sales exceptions under ASC 815. Accordingly, FTRs are recorded at fair value using the income approach when acquired and subsequently amortized over the annual period as they are used. The forward power contracts are recorded at fair value using the market approach with changes in the fair value charged or credited to the Consolidated Statements of Operations in the period in which the change occurred. This is commonly referred to as "MTM accounting." Realized gains and losses on the forward power contracts are included in future FAC filings, therefore any realized and unrealized gains and losses are deferred as regulatory liabilities or regulatory assets. There were net realized gains of $0.0 million and $1.3 million related to forward power contracts during the years ended December 31, 2023 and 2022, respectively, related to the forward power contracts that were deferred and included with deferred fuel costs in "Regulatory assets, current" on the accompanying Consolidated Balance Sheets. Certain qualifying derivative instruments have been designated as normal purchases or normal sales contracts, as provided under GAAP. Derivative contracts that have been designated as normal purchases or normal sales under GAAP are not subject to hedge or MTM accounting and are recognized in the Consolidated Statements of Operations on an accrual basis. When applicable, AES Indiana has elected not to offset derivative assets and liabilities and not to offset net derivative positions against the right to reclaim cash collateral pledged (an asset) or the obligation to return cash collateral received (a liability) under derivative agreements. As of December 31, 2023 and 2022, AES Indiana did not have any offsetting positions. The following table summarizes the fair value, balance sheet classification and hedging designation of AES Indiana's derivative instruments (in thousands): December 31, Commodity Hedging Designation Balance sheet classification 2023 2022 FTRs Not a Cash Flow Hedge Prepayments and other current assets $ 1,388 $ 7,545

Debt

Debt	12 Months Ended
	Dec. 31, 2023
Entity Information [Line Items]
Debt	DEBT The following table presents our long-term debt: December 31, Series Due 2023 2022 (In Thousands) AES Indiana first mortgage bonds: 3.125% (1) December 2024 $ 40,000 $ 40,000 0.65% (1) August 2025 40,000 40,000 0.75% (2) April 2026 30,000 30,000 0.95% (2) April 2026 60,000 60,000 1.40% (1) August 2029 55,000 55,000 5.65% December 2032 350,000 350,000 6.60% January 2034 100,000 100,000 6.05% October 2036 158,800 158,800 6.60% June 2037 165,000 165,000 4.875% November 2041 140,000 140,000 4.65% June 2043 170,000 170,000 4.50% June 2044 130,000 130,000 4.70% September 2045 260,000 260,000 4.05% May 2046 350,000 350,000 4.875% November 2048 105,000 105,000 Unamortized discount – net (6,449) (6,651) Deferred financing costs (19,058) (20,362) Total AES Indiana first mortgage bonds 2,128,293 2,126,787 Total long-term debt – AES Indiana 2,128,293 2,126,787 Long-term debt – IPALCO: 3.70% Senior Secured Notes September 2024 405,000 405,000 4.25% Senior Secured Notes May 2030 475,000 475,000 Unamortized discount – net (319) (425) Deferred financing costs (4,554) (5,912) Total long-term debt – IPALCO 875,127 873,663 Total consolidated IPALCO long-term debt 3,003,420 3,000,450 Less: current portion of long-term debt 445,000 — Net consolidated IPALCO long-term debt $ 2,558,420 $ 3,000,450 (1) First mortgage bonds issued to the Indiana Finance Authority, to secure the loan of proceeds from tax-exempt bonds issued by the Indiana Finance Authority. (2) First mortgage bonds issued to the Indiana Finance Authority, to secure the loan of proceeds from tax-exempt bonds issued by the Indiana Finance Authority. The notes have a final maturity date of December 31, 2038, but are subject to a mandatory put in April 2026. Line of Credit AES Indiana entered into a second amendment and restatement of its $350 million revolving Credit Agreement on December 22, 2022 with a syndication of bank lenders. This Credit Agreement is an unsecured committed line of credit to be used: (i) to finance capital expenditures; (ii) to refinance certain existing indebtedness, (iii) to support working capital; and (iv) for general corporate purposes. This agreement matures on December 22, 2027, and bears interest at variable rates as described in the Credit Agreement. It includes an uncommitted $150 million accordion feature to provide AES Indiana with an option to request an increase in the size of the facility at any time prior to December 22, 2026, subject to approval by the lenders. The Credit Agreement also includes two one-year extension options, allowing AES Indiana to extend the maturity date subject to approval by the lenders. As of December 31, 2023 and 2022, AES Indiana had $155.0 million and $0.0 million in outstanding borrowings on the committed Credit Agreement, respectively. Debt Maturities Maturities on long-term indebtedness subsequent to December 31, 2023 are as follows: Year Amount (In Thousands) 2024 $ 445,000 2025 40,000 2026 90,000 2027 — 2028 — Thereafter 2,458,800 3,033,800 Unamortized discounts (6,768) Deferred financing costs, net (23,612) Total long-term debt $ 3,003,420 Significant Transactions AES Indiana Term Loans In November 2023, AES Indiana entered into an unsecured $300 million 364-day term loan agreement ("$300 million Term Loan Agreement"). The $300 million Term Loan Agreement was fully drawn at closing with the proceeds being used for general corporate purposes. This agreement matures on November 19, 2024, and bears interest at variable rates as described in the $300 million Term Loan Agreement. The $300 million Term Loan Agreement contains customary representations, warranties and covenants, including a leverage covenant consistent with the leverage covenant contained in AES Indiana's Credit Agreement. AES Indiana has classified this $300 million Term Loan Agreement as short-term indebtedness as it matures November 2024. Although current liquid funds are not sufficient to repay the amount due at maturity, management plans to refinance this $300 million Term Loan Agreement with new long-term debt. In June 2022, AES Indiana entered into an unsecured $200 million 364-day term loan agreement ("$200 million Term Loan Agreement"). The $200 million Term Loan Agreement was fully drawn at closing with the proceeds being used for general corporate purposes. This agreement was set to mature on June 22, 2023, but was fully repaid in November 2022. AES Indiana First Mortgage Bonds and Recent Indiana Finance Authority Bond Issuances In November 2022, AES Indiana issued $350 million aggregate principal amount of first mortgage bonds, 5.65% Series, due December 2032, pursuant to Rule 144A and Regulation S under the Securities Act. Net proceeds from this offering were approximately $345.6 million, after deducting the initial purchasers’ discounts and fees and expenses for the offering. The net proceeds from this offering were used to repay amounts due under the Credit Agreement and the $200 million Term Loan Agreement, and for general corporate purposes. In July 2021, the Indiana Finance Authority issued at the request of AES Indiana an aggregate principal amount of $95 million of Environmental Facilities Refunding Revenue Bonds, Series 2021A&B. AES Indiana issued $95 million aggregate principal amount of first mortgage bonds to the Indiana Finance Authority in two series: $55 million Series 2021A bonds at an interest rate of 1.40% due August 1, 2029 and $40 million Series 2021B notes at an interest rate of 0.65% due August 1, 2025 to secure the loan of proceeds from these bonds issued by the Indiana Finance Authority. Proceeds of the bond offering were used to refund $95 million of Indiana Finance Authority Environmental Facilities Refunding Revenue Bonds Series 2011A&B at a redemption price of 100% of par. IPALCO’s Senior Secured Notes and Term Loan The 2024 IPALCO Notes are due September 1, 2024. Although current liquid funds are not sufficient to repay the collective amounts due under the 2024 IPALCO Notes at maturity, the Company believes it will be able to refinance the 2024 IPALCO Notes based on conversations with investment bankers, which currently indicate more than adequate demand for new IPALCO debt at its current credit ratings, and considering the Company's previous successful debt issuances. Pursuant to a registration rights agreement dated April 14, 2020, IPALCO agreed to register the 2030 IPALCO Notes under the Securities Act by filing an exchange offer registration statement or, under specified circumstances, a shelf registration statement with the SEC. IPALCO filed a registration statement on Form S-4 with respect to the 2030 IPALCO Notes with the SEC on March 22, 2021 in respect of its obligations under such registration rights agreement, and this registration statement was declared effective on April 7, 2021. The exchange offer closed on May 11, 2021. Restrictions on Issuance of Debt All of AES Indiana’s long-term borrowings must first be approved by the IURC and the aggregate amount of AES Indiana’s short-term indebtedness must be approved by the FERC. AES Indiana has approval from FERC to borrow up to $750 million of short-term indebtedness outstanding at any time through July 26, 2024. In November 2021, AES Indiana received an order from the IURC granting AES Indiana authority through December 31, 2024 to, among other things, issue up to $740 million in aggregate principal amount of long-term debt, of which $390 million remains available as of December 31, 2023. This order also grants AES Indiana authority to have up to $750 million of long-term credit agreements and liquidity facilities outstanding at any one time, of which $100.0 million remains available under the order as of December 31, 2023. As an alternative to the sale of all or a portion of $65 million in principal of the long-term debt mentioned above, we have authority to issue up to $65 million of new preferred stock, all of which authority remains available under the order as of December 31, 2023. AES Indiana also has restrictions on the amount of new debt that may be issued due to contractual obligations of AES and by financial covenant restrictions under our existing debt obligations. Under such restrictions, AES Indiana is generally allowed to fully draw the amounts available on its Credit Agreement, refinance existing debt and issue new debt approved by the IURC and issue certain other indebtedness. On September 29, 2023, AES Indiana filed a petition for approval of a financing program for the approximately three-year period ending December 31, 2026. The OUCC filed testimony on December 1, 2023 with certain recommended parameters for future debt issuances that AES Indiana accepted. A hearing was held January 10, 2024 and an agreed proposed order between AES Indiana and the OUCC was submitted on that date. AES Indiana awaits an IURC order in the matter and it remains pending. The mortgage and deed of trust of AES Indiana, together with the supplemental indentures thereto, secure the first mortgage bonds issued by AES Indiana. Pursuant to the terms of the mortgage, substantially all property owned by AES Indiana is subject to a first mortgage lien securing indebtedness of $2,153.8 million as of December 31, 2023. The AES Indiana first mortgage bonds require net income as calculated thereunder be at least two and one-half times the annual interest requirements before additional bonds can be authenticated on the basis of property additions. AES Indiana was in compliance with such requirements as of December 31, 2023. Credit Ratings Our ability to borrow money or to refinance existing indebtedness and the interest rates at which we can borrow money or refinance existing indebtedness are affected by our credit ratings. In addition, the applicable interest rates on AES Indiana’s Credit Agreement are dependent upon the credit ratings of AES Indiana. Downgrades in the credit ratings of AES could result in AES Indiana’s and/or IPALCO’s credit ratings being downgraded.
Indianapolis Power And Light Company
Entity Information [Line Items]
Debt	. DEBT The following table presents AES Indiana’s long-term debt: December 31, Series Due 2023 2022 (In Thousands) AES Indiana first mortgage bonds: 3.125% (1) December 2024 $ 40,000 $ 40,000 0.65% (1) August 2025 40,000 40,000 0.75% (2) April 2026 30,000 30,000 0.95% (2) April 2026 60,000 60,000 1.40% (1) August 2029 55,000 55,000 5.650% December 2032 350,000 350,000 6.60% January 2034 100,000 100,000 6.05% October 2036 158,800 158,800 6.60% June 2037 165,000 165,000 4.875% November 2041 140,000 140,000 4.65% June 2043 170,000 170,000 4.50% June 2044 130,000 130,000 4.70% September 2045 260,000 260,000 4.05% May 2046 350,000 350,000 4.875% November 2048 105,000 105,000 Unamortized discount – net (6,449) (6,651) Deferred financing costs (19,058) (20,362) Total AES Indiana first mortgage bonds 2,128,293 2,126,787 Total consolidated AES Indiana long-term debt 2,128,293 2,126,787 Less: current portion of long-term debt 40,000 — Net consolidated AES Indiana long-term debt $ 2,088,293 $ 2,126,787 (1) First mortgage bonds issued to the Indiana Finance Authority, to secure the loan of proceeds from tax-exempt bonds issued by the Indiana Finance Authority. (2) First mortgage bonds issued to the Indiana Finance Authority, to secure the loan of proceeds from tax-exempt bonds issued by the Indiana Finance Authority. The notes have a final maturity date of December 31, 2038, but are subject to a mandatory put in April 2026. Line of Credit AES Indiana entered into a second amendment and restatement of its $350 million revolving Credit Agreement on December 22, 2022 with a syndication of bank lenders. This Credit Agreement is an unsecured committed line of credit to be used: (i) to finance capital expenditures; (ii) to refinance certain existing indebtedness, (iii) to support working capital; and (iv) for general corporate purposes. This agreement matures on December 22, 2027, and bears interest at variable rates as described in the Credit Agreement. It includes an uncommitted $150 million accordion feature to provide AES Indiana with an option to request an increase in the size of the facility at any time prior to December 22, 2026, subject to approval by the lenders. The Credit Agreement also includes two one-year extension options, allowing AES Indiana to extend the maturity date subject to approval by the lenders. As of December 31, 2023 and 2022, AES Indiana had $155.0 million and $0.0 million in outstanding borrowings on the committed Credit Agreement, respectively. Debt Maturities Maturities on long-term indebtedness subsequent to December 31, 2023 are as follows: Year Amount (In Thousands) 2024 $ 40,000 2025 40,000 2026 90,000 2027 — 2028 — Thereafter 1,983,800 2,153,800 Unamortized discounts (6,449) Deferred financing costs, net (19,058) Total long-term debt $ 2,128,293 Significant Transactions AES Indiana Term Loans In November 2023, AES Indiana entered into an unsecured$300 million 364-day term loan agreement ("$300 million Term Loan Agreement"). The $300 million Term Loan Agreement was fully drawn at closing with the proceeds being used for general corporate purposes. This agreement matures on November 19, 2024, and bears interest at variable rates as described in the $300 million Term Loan Agreement. The $300 million Term Loan Agreement contains customary representations, warranties and covenants, including a leverage covenant consistent with the leverage covenant contained in AES Indiana's Credit Agreement. AES Indiana has classified this $300 million Term Loan Agreement as short-term indebtedness as it matures November 2024. Although current liquid funds are not sufficient to repay the amount due at maturity, management plans to refinance this $300 million Term Loan Agreement with new long-term debt. In June 2022, AES Indiana entered into an unsecured $200 million 364-day term loan agreement ("$200 million Term Loan Agreement"). The $200 million Term Loan Agreement was fully drawn at closing with the proceeds being used for general corporate purposes. This agreement was set to mature on June 22, 2023, but was fully repaid in November 2022. AES Indiana First Mortgage Bonds and Recent Indiana Finance Authority Bond Issuances In November 2022, AES Indiana issued $350 million aggregate principal amount of first mortgage bonds, 5.65% Series, due December 2032, pursuant to Rule 144A and Regulation S under the Securities Act. Net proceeds from this offering were approximately $345.6 million, after deducting the initial purchasers’ discounts and fees and expenses for the offering. The net proceeds from this offering were used to repay amounts due under the Credit Agreement and the $200 million Term Loan Agreement, and for general corporate purposes. In July 2021, the Indiana Finance Authority issued at the request of AES Indiana an aggregate principal amount of $95 million of Environmental Facilities Refunding Revenue Bonds, Series 2021A&B. AES Indiana issued $95 million aggregate principal amount of first mortgage bonds to the Indiana Finance Authority in two series: $55 million Series 2021A bonds at an interest rate of 1.40% due August 1, 2029 and $40 million Series 2021B notes at an interest rate of 0.65% due August 1, 2025 to secure the loan of proceeds from these bonds issued by the Indiana Finance Authority. Proceeds of the bond offering were used to refund $95 million of Indiana Finance Authority Environmental Facilities Refunding Revenue Bonds Series 2011A&B at a redemption price of 100% of par. Restrictions on Issuance of Debt All of AES Indiana’s long-term borrowings must first be approved by the IURC and the aggregate amount of AES Indiana’s short-term indebtedness must be approved by the FERC. AES Indiana has approval from FERC to borrow up to $750 million of short-term indebtedness outstanding at any time through July 26, 2024. In November 2021, AES Indiana received an order from the IURC granting AES Indiana authority through December 31, 2024 to, among other things, issue up to $740 million in aggregate principal amount of long-term debt, of which $390 million remains available as of December 31, 2023. This order also grants AES Indiana authority to have up to $750 million of long-term credit agreements and liquidity facilities outstanding at any one time, of which $100.0 million remains available under the order as of December 31, 2023. As an alternative to the sale of all or a portion of $65 million in principal of the long-term debt mentioned above, we have authority to issue up to $65 million of new preferred stock, all of which authority remains available under the order as of December 31, 2023. AES Indiana also has restrictions on the amount of new debt that may be issued due to contractual obligations of AES and by financial covenant restrictions under our existing debt obligations. Under such restrictions, AES Indiana is generally allowed to fully draw the amounts available on its Credit Agreement, refinance existing debt and issue new debt approved by the IURC and issue certain other indebtedness. On September 29, 2023, AES Indiana filed a petition for approval of a financing program for the approximately three-year period ending December 31, 2026. The OUCC filed testimony on December 1, 2023 with certain recommended parameters for future debt issuances that AES Indiana accepted. A hearing was held January 10, 2024 and an agreed proposed order between AES Indiana and the OUCC was submitted on that date. AES Indiana awaits an IURC order in the matter and it remains pending. The mortgage and deed of trust of AES Indiana, together with the supplemental indentures thereto, secure the first mortgage bonds issued by AES Indiana. Pursuant to the terms of the mortgage, substantially all property owned by AES Indiana is subject to a first mortgage lien securing indebtedness of $2,153.8 million as of December 31, 2023. The AES Indiana first mortgage bonds require net income as calculated thereunder be at least two and one-half times the annual interest requirements before additional bonds can be authenticated on the basis of property additions. AES Indiana was in compliance with such requirements as of December 31, 2023. Credit Ratings AES Indiana’s ability to borrow money or to refinance existing indebtedness and the interest rates at which AES Indiana can borrow money or refinance existing indebtedness are affected by AES Indiana’s credit ratings. In addition, the applicable interest rates on AES Indiana’s Credit Agreement are dependent upon the credit ratings of AES Indiana. Downgrades in the credit ratings of AES and/or IPALCO could result in AES Indiana’s credit ratings being downgraded.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2023
Entity Information [Line Items]
Income Taxes	INCOME TAXES IPALCO follows a policy of comprehensive interperiod income tax allocation. Investment tax credits related to utility property have been deferred and are being amortized over the estimated useful lives of the related property. AES files federal and state income tax returns which consolidate IPALCO and its subsidiaries. Under a tax sharing agreement with AES, IPALCO is responsible for the income taxes associated with its own taxable income and records the provision for income taxes as if IPALCO and its subsidiaries each filed separate income tax returns. IPALCO is no longer subject to U.S. or state income tax examinations for tax years through 2016, but is open for all subsequent periods. IPALCO made tax sharing payments to AES of $0.0 million, $31.0 million and $27.5 million in 2023, 2022 and 2021, respectively. Income Tax Provision Federal and state income taxes charged to income are as follows: 2023 2022 2021 (In Thousands) Components of income tax expense: Current income taxes: Federal $ (14,222) $ 22,539 $ 28,100 State (3,716) 6,026 8,218 Total current income taxes (17,938) 28,565 36,318 Deferred income taxes: Federal 24,885 (6,920) (7,286) State 7,768 214 (91) Total deferred income taxes 32,653 (6,706) (7,377) Total income tax expense $ 14,715 $ 21,859 $ 28,941 Effective and Statutory Rate Reconciliation The provision for income taxes (including net investment tax credit adjustments) is different than the amount computed by applying the statutory tax rate to pretax income. The reasons for the difference, stated as a percentage of pretax income, are as follows: 2023 2022 2021 Federal statutory tax rate 21.0 % 21.0 % 21.0 % State income tax, net of federal tax benefit 3.9 % 3.9 % 4.0 % Depreciation flow through and amortization (12.9) % (7.8) % (6.3) % AFUDC - equity (0.3) % 0.9 % 0.4 % Noncontrolling interests in subsidiaries 9.0 % — % — % Other – net (0.2) % 0.4 % 0.4 % Effective tax rate 20.5 % 18.4 % 19.5 % Deferred Income Taxes The significant items comprising IPALCO’s net accumulated deferred tax liability recognized on the audited Consolidated Balance Sheets as of December 31, 2023 and 2022 are as follows: 2023 2022 (In Thousands) Deferred tax liabilities: Relating to utility property, net $ 409,675 $ 341,473 Regulatory assets recoverable through future rates 108,823 123,669 Other 17,694 17,953 Total deferred tax liabilities 536,192 483,095 Deferred tax assets: Investment tax credit 5 6 Regulatory liabilities including ARO 168,619 167,725 Investments in tax partnerships 2,501 — Other 3,579 2,723 Total deferred tax assets 174,704 170,454 Deferred income tax liability – net $ 361,488 $ 312,641 Uncertain Tax Positions The following is a reconciliation of the beginning and ending amounts of unrecognized tax benefits for the years ended December 31, 2023, 2022 and 2021: 2023 2022 2021 (In Thousands) Unrecognized tax benefits at January 1 $ — $ — $ 7,368 Gross decreases – prior period tax positions — — (7,368) Unrecognized tax benefits at December 31 $ — $ — $ — The prior period unrecognized tax benefits represent tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. As a result of the resolution of federal and state audits in 2021, IPALCO reviewed its uncertain positions and determined that they are more likely than not to be sustained upon examination by taxing authorities. Consequently, the uncertain tax positions were reversed; because of the impact of deferred tax accounting the reversal did not affect the annual effective tax rate but were reclassified to plant related deferred tax balances. Tax years subsequent to 2016 remain open to examination by taxing authorities. While it is often difficult to predict the final outcome or the timing of resolution of any particular uncertain tax position, we believe unrecognized tax benefits of $0 at December 31, 2023 and 2022, respectively, is the appropriate accrual for our uncertain tax positions. However, audit outcomes and the timing of audit settlements and future events that would impact our previously recorded unrecognized tax benefits are subject to significant uncertainty. It is possible that the ultimate outcome of future examinations may exceed our provision for current unrecognized tax benefits. Tax-related interest expense and income is reported as part of the provision for federal and state income taxes. Penalties, if incurred, would also be recognized as a component of tax expense. There are no interest or penalties applicable to the periods contained in this report.
Indianapolis Power And Light Company
Entity Information [Line Items]
Income Taxes	INCOME TAXES AES Indiana follows a policy of comprehensive interperiod income tax allocation. Investment tax credits related to utility property have been deferred and are being amortized over the estimated useful lives of the related property. AES files federal and state income tax returns which consolidate IPALCO and AES Indiana. Under a tax sharing agreement with IPALCO, AES Indiana is responsible for the income taxes associated with its own taxable income and records the provision for income taxes as if AES Indiana filed separate income tax returns. AES Indiana is no longer subject to U.S. or state income tax examinations for tax years through 2016, but is open for all subsequent periods. AES Indiana made tax sharing payments to IPALCO of $0.0 million, $39.5 million and $40.8 million in 2023, 2022 and 2021, respectively. Income Tax Provision Federal and state income taxes charged to income are as follows: 2023 2022 2021 (In Thousands) Components of income tax expense: Current income taxes: Federal $ 1,816 $ 31,286 $ 36,353 State 268 8,185 10,325 Total current income taxes 2,084 39,471 46,678 Deferred income taxes: Federal 17,631 (6,822) (7,283) State 5,951 238 (90) Total deferred income taxes 23,582 (6,584) (7,373) Total income tax expense $ 25,666 $ 32,887 $ 39,305 Effective and Statutory Rate Reconciliation The provision for income taxes (including net investment tax credit adjustments) is different than the amount computed by applying the statutory tax rate to pretax income. The reasons for the difference, stated as a percentage of pretax income, are as follows: 2023 2022 2021 Federal statutory tax rate 21.0 % 21.0 % 21.0 % State income tax, net of federal tax benefit 3.9 % 3.9 % 4.0 % Depreciation flow through and amortization (8.0) % (5.7) % (4.9) % AFUDC - equity (0.2) % 0.7 % 0.3 % Noncontrolling interests in subsidiaries 5.6 % — % — % Other – net (0.1) % 0.3 % 0.3 % Effective tax rate 22.2 % 20.2 % 20.7 % Deferred Income Taxes The significant items comprising AES Indiana’s net accumulated deferred tax liability recognized on the audited Consolidated Balance Sheets as of December 31, 2023 and 2022 are as follows: 2023 2022 (In Thousands) Deferred tax liabilities: Relating to utility property, net $ 409,675 $ 341,473 Regulatory assets recoverable through future rates 108,823 123,669 Other 7,975 22,717 Total deferred tax liabilities 526,473 487,859 Deferred tax assets: Investment tax credit 5 6 Regulatory liabilities including ARO 168,619 167,726 Investments in tax partnerships 2,483 — Operating loss carryforwards 9,230 — Other 3,579 15,020 Total deferred tax assets 183,916 182,752 Deferred income tax liability – net $ 342,557 $ 305,107 Uncertain Tax Positions The following is a reconciliation of the beginning and ending amounts of unrecognized tax benefits for the years ended December 31, 2023, 2022 and 2021: 2023 2022 2021 (In Thousands) Unrecognized tax benefits at January 1 $ — $ — $ 7,368 Gross decreases – prior period tax positions — — (7,368) Unrecognized tax benefits at December 31 $ — $ — $ — The prior period unrecognized tax benefits represent tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. As a result of the resolution of federal and state audits in 2021, AES Indiana reviewed its uncertain positions and determined that they are more likely than not to be sustained upon examination by taxing authorities. Consequently, the uncertain tax positions were reversed; because of the impact of deferred tax accounting the reversal did not affect the annual effective tax rate but were reclassified to plant related deferred tax balances. Tax years subsequent to 2016 remain open to examination by taxing authorities. While it is often difficult to predict the final outcome or the timing of resolution of any particular uncertain tax position, AES Indiana believes unrecognized tax benefits of $0 at December 31, 2023 and 2022, respectively, is the appropriate accrual for our uncertain tax positions. However, audit outcomes and the timing of audit settlements and future events that would impact AES Indiana's previously recorded unrecognized tax benefits are subject to significant uncertainty. It is possible that the ultimate outcome of future examinations may exceed AES Indiana's provision for current unrecognized tax benefits. Tax-related interest expense and income is reported as part of the provision for federal and state income taxes. Penalties, if incurred, would also be recognized as a component of tax expense. There are no interest or penalties applicable to the periods contained in this report.

Benefit Plans

Benefit Plans	12 Months Ended
	Dec. 31, 2023
Entity Information [Line Items]
Benefit Plans	BENEFIT PLANS Defined Contribution Plans All of AES Indiana’s employees are covered by one of two defined contribution plans, the Thrift Plan or the RSP: The Thrift Plan Approximately 77% of AES Indiana’s active employees are covered by the Thrift Plan, a qualified defined contribution plan. All union new hires are covered under the Thrift Plan. Participants elect to make contributions to the Thrift Plan based on a percentage of their base compensation. Each participant’s contribution is matched up to certain thresholds of base compensation. The IBEW clerical-technical union new hires receive an annual lump sum company contribution into the Thrift Plan in addition to the company match. Employer contributions to the Thrift Plan were $3.7 million, $3.6 million and $3.4 million for 2023, 2022 and 2021, respectively. The RSP Approximately 23% of AES Indiana’s active employees are covered by the RSP, a qualified defined contribution plan containing both match and nondiscretionary components. All non-union new hires are covered under the RSP. Participants elect to make contributions to the RSP based on a percentage of their eligible compensation. Each participant’s contribution is matched in amounts up to, but not exceeding, 5% of the participant’s eligible compensation. Starting in 2018, the RSP also includes a 4% nondiscretionary contribution based as a percentage of each participant's eligible compensation. Employer contributions (by AES Indiana) relating to the RSP were $2.5 million, $2.1 million and $1.9 million for 2023, 2022 and 2021, respectively. Defined Benefit Plans Approximately 65% of AES Indiana’s active employees are covered by the qualified Defined Benefit Pension Plan; while approximately 12% of active employees are IBEW clerical-technical unit employees who are only eligible for the Thrift Plan. The remaining 23% of active employees are covered by the RSP. All non-union new hires are covered under the RSP, while IBEW physical unit union new hires are covered under the Defined Benefit Pension Plan and Thrift Plan. The IBEW clerical-technical unit new hires are no longer covered under the Defined Benefit Pension Plan but do receive an annual lump sum company contribution into the Thrift Plan, in addition to the company match. The Defined Benefit Pension Plan is noncontributory and is funded by AES Indiana through a trust. Benefits for non-union participants in the Defined Benefit Pension Plan are based on salary, years of service and accrued benefits at April 1, 2015. Benefits for eligible union participants are based on each individual employee's pension band and years of service as opposed to their compensation. Pension bands are based primarily on job duties and responsibilities. Additionally, a small group of former officers and their surviving spouses are covered under a funded non-qualified Supplemental Retirement Plan. The total number of participants in the plan as of December 31, 2023 was 19. The plan is closed to new participants. AES Indiana also provides postretirement health care benefits to certain active or retired employees and the spouses of certain active or retired employees. Approximately 123 active employees and 26 retirees (including spouses) were receiving such benefits or entitled to future benefits as of January 1, 2023. The plan is unfunded. These postretirement health care benefits and the related unfunded obligation of $3.0 million and $3.2 million at December 31, 2023 and 2022, respectively, were not material to the consolidated financial statements in the periods covered by this report. The following table presents information relating to the Pension Plans: Pension benefits 2023 2022 (In Thousands) Change in benefit obligation: Projected benefit obligation at January 1 $ 577,530 $ 772,040 Service cost 5,189 8,949 Interest cost 29,818 18,099 Actuarial loss (gain) 9,681 (182,590) Amendments (primarily increases in pension bands) 653 — Settlements — (394) Benefits paid (73,325) (38,575) Projected benefit obligation at December 31 549,546 577,529 Change in plan assets: Fair value of plan assets at January 1 611,125 820,684 Actual return/(loss) on plan assets 52,905 (171,002) Employer contributions 114 412 Settlements — (394) Benefits paid (73,325) (38,575) Fair value of plan assets at December 31 590,819 611,125 Funded status $ 41,273 $ 33,596 Amounts recognized in the statement of financial position: Non-current assets $ 41,273 $ 33,611 Non-current liabilities — (15) Net amount recognized at end of year $ 41,273 $ 33,596 Sources of change in regulatory assets (1) : Prior service cost arising during period $ 653 $ — Net (gain)/loss arising during period (10,117) 24,069 Amortization of prior service cost (2,172) (2,589) Amortization of loss (6,145) (2,622) Total recognized in regulatory assets $ (17,781) $ 18,858 Amounts included in regulatory assets: Net loss $ 115,297 $ 131,559 Prior service cost 10,136 11,655 Total amounts included in regulatory assets $ 125,433 $ 143,214 (1) Amounts that would otherwise be charged/credited to Accumulated Other Comprehensive Income or Loss upon application of ASC 715, “Compensation – Retirement Benefits,” are recorded as a regulatory asset or liability because AES Indiana has historically recovered and currently recovers pension and other postretirement benefit expenses in rates. These are unrecognized amounts not yet recognized as components of net periodic benefit costs. Significant Loss / (Gain) Related to Changes in the Benefit Obligation for the Period As shown in the table above, an actuarial loss of $9.7 million and an actuarial gain of $182.6 million for the year ended December 31, 2023 and December 31, 2022, respectively, were recognized in the benefit obligation, primarily due to changes in the discount rate. Pension Benefits and Expense Reported expenses relevant to the Defined Benefit Pension Plan are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience, including the performance of plan assets and actual benefits paid out in future years. Pension costs associated with the Defined Benefit Pension Plan are impacted by the level of contributions made to the plan, income on plan assets, the adoption of new mortality tables, and employee demographics, including age, job responsibilities, salary and employment periods. Changes made to the provisions of the Defined Benefit Pension Plan may impact current and future pension costs. Pension costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the corporate bond discount rates, as well as, the adoption of a new mortality table used in determining the projected benefit obligation and pension costs. The 2023 net actuarial gain of $10.1 million recognized in regulatory assets is comprised of two parts: (1) a $9.7 million pension liability actuarial loss primarily due to a decrease in the discount rate used to value pension liabilities; and (2) a $19.8 million pension asset actuarial gain primarily due to higher than expected return on assets. The unrecognized net loss of $115.3 million in the Pension Plans has accumulated over time primarily due to the long-term declining trend in corporate bond rates and the adoption of new mortality tables which have historically increased the expected benefit obligation due to the longer expected lives of plan participants. In 2023, the accumulated net loss decrease was primarily attributed to an annuity buyout involving a small portion of retirees, which was partially offset by factors such as a reduced discount rate utilized in valuing pension liabilities, along with the amortization of accumulated losses incurred during the year. The unrecognized net loss, to the extent that it exceeds 10% of the greater of the benefit obligation or the assets, will be amortized and included as a component of net periodic benefit cost in future years. The amortization period is approximately 11.66 years based on estimated demographic data as of December 31, 2023. The projected benefit obligation of $549.5 million less the fair value of assets of $590.8 million results in an overfunded status of $41.3 million at December 31, 2023. Pension benefits for 2023 2022 2021 (In Thousands) Components of net periodic benefit cost / (credit): Service cost $ 5,189 $ 8,949 $ 9,339 Interest cost 29,818 18,099 15,660 Expected return on plan assets (33,107) (35,656) (41,815) Amortization of prior service cost 2,172 2,589 2,944 Amortization of actuarial loss 6,145 2,424 5,529 Amortization of settlement loss — 199 — Net periodic benefit cost / (credit) 10,217 (3,396) (8,343) Less: amounts capitalized 1,689 (316) (771) Amount charged to expense $ 8,528 $ (3,080) $ (7,572) Rates relevant to each year’s expense calculations: Discount rate – defined benefit pension plan 5.41 % 2.83 % 2.46 % Discount rate – supplemental retirement plan 5.32 % 2.62 % 2.31 % Expected return on defined benefit pension plan assets 5.60 % 4.45 % 5.05 % Expected return on supplemental retirement plan assets 6.45 % 5.50 % 3.60 % Pension expense / (income) for the following year is determined as of the December 31 measurement date based on the fair value of the Pension Plans’ assets, the expected long-term rate of return on plan assets, a mortality table assumption that reflects the life expectancy of plan participants, and a discount rate used to determine the projected benefit obligation. For 2023, pension expense / (income) was determined using an assumed long-term rate of return on plan assets of 5.60% for the Defined Benefit Pension Plan and 6.45% for the Supplemental Retirement Plan. As of the December 31, 2023 measurement date, AES Indiana decreased the discount rate from 5.41% to 5.15% for the Defined Benefit Pension Plan and increased the discount rate from 5.32% to 5.66% for the Supplemental Retirement Plan. The discount rate assumptions affect the pension expense / (income) determined for 2024. In addition, AES Indiana decreased the expected long-term rate of return on plan assets from 5.60% to 5.20% for the Defined Benefit Pension Plan and from 6.45% to 6.35% for the Supplemental Retirement Plan for 2024. The expected long-term rate of return assumptions affect the pension expense / (income) determined for 2024. The effect on 2024 total pension expense / (income) of a 25 basis point increase and decrease in the assumed discount rate is $(0.8) million and $0.8 million, respectively. In determining the discount rate to use for valuing liabilities, we use the market yield curve on high-quality fixed income investments as of December 31, 2023. We project the expected benefit payments under the plan based on participant data and based on certain assumptions concerning mortality, retirement rates, termination rates, etc. The expected benefit payments for each year are discounted back to the measurement date using the appropriate spot rate for each half-year from the yield curve, thereby obtaining a present value of all expected future benefit payments using the yield curve. Finally, an equivalent single discount rate is determined which produces a present value equal to the present value determined using the full yield curve. Pension Plan Assets and Fair Value Measurements Pension plan assets consist of investments in cash and cash equivalents, government debt securities, and mutual funds (equity and debt). Differences between actual portfolio returns and expected returns may result in increased or reduced pension costs in future periods. Pension costs for 2024 are determined as of the plans' measurement date of December 31, 2023. Pension costs are determined for the following year based on the market value of pension plan assets, expected employer contributions, a discount rate used to determine the projected benefit obligation and the expected long-term rate of return on plan assets. Fair value is defined under ASC 820 as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (i.e., an exit price). The fair value hierarchy prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets and liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Purchases and sales of securities are recorded on a trade-date basis. Interest income is recorded as earned. Dividends are recorded on the ex-dividend date. Net appreciation includes the Pension Plans’ gains and losses on investments bought and sold, as well as held, during the year. A description of the valuation methodologies used for each major class of assets and liabilities measured at fair value follows: • The non-qualified Supplemental Retirement Plan investments have quoted market prices and are categorized as Level 1 in the fair value hierarchy. • The qualified Defined Benefit Pension Plan investments in common collective trusts are valued based on the daily net asset value and are categorized as Level 2 in the fair value hierarchy, except for cash and cash equivalents which are categorized as level 1. The primary objective of the Pension Plans’ is to provide a source of retirement income for its participants and beneficiaries, while the primary financial objective is to improve the funded status of the Pension Plans. A secondary financial objective is, where possible, to minimize pension expense volatility. The objective is based on a long-term investment horizon, so that interim fluctuations should be viewed with appropriate perspective. There can be no assurance that these objectives will be met. In establishing our expected long-term rate of return assumption, we utilize a methodology developed by the plan’s investment consultant who maintains a capital market assumption model that takes into consideration risk, return and correlation assumptions across asset classes. A combination of quantitative analysis of historical data and qualitative judgment is used to capture trends, structural changes and potential scenarios not reflected in historical data. The result of the analyses is a series of inputs that produce a picture of how the plan consultant believes portfolios are likely to behave through time. Capital market assumptions are intended to reflect the behavior of asset classes observed over several market cycles. Stress assumptions are also examined, since the characteristics of asset classes are constantly changing. A dynamic model is employed to manage the numerous assumptions required to estimate portfolio characteristics under different base currencies, time horizons and inflation expectations. The Pension Plans’ consultant develops forward-looking, long-term capital market assumptions for risk, return and correlations for a variety of global asset classes, interest rates and inflation. These assumptions are created using a combination of historical analysis, current market environment assessment and by applying the consultant’s own judgment. The consultant then determines an equilibrium long-term rate of return. We then take into consideration the investment manager/consultant expenses, as well as any other expenses expected to be paid out of the Pension Plans’ trust. Finally, we have the Pension Plans’ actuary perform a tolerance test of the consultant’s equilibrium expected long-term rate of return. We use an expected long-term rate of return compatible with the actuary’s tolerance level. The following table summarizes the Company’s target pension plan allocation for 2023: Asset Category: Target Allocations Equity Securities 13.5% Debt Securities 86.5% Fair Value Measurements at December 31, 2023 (in thousands) Quoted Prices in Active Markets for Identical Assets Significant Observable Inputs Asset Category Total (Level 1) (Level 2) % Common collective trusts: Equities (a) $ 82,652 $ 2,267 $ 80,385 14 % Debt securities (b) 387,979 1,168 386,811 66 % Government debt securities (c) 117,397 178 117,219 20 % Total common collective trusts 588,028 3,613 584,415 100 % Cash and cash equivalents (d) 2,791 2,791 — — % Total pension plan assets $ 590,819 $ 6,404 $ 584,415 100 % (a) This category represents investments that invest in equity securities of U.S. companies of any market capitalization and other investments (i.e.: futures, swaps, currency forwards) of foreign, emerging markets and seeks to provide long-term total return, which includes capital appreciation and income. The funds are valued using the net asset value method. (b) This category represents investments that invest in high quality issues within the U.S. corporate bond markets and global high yield bonds and emerging markets debt denominated in local currency. The funds seek to provide current income and long-term capital preservation along with access to higher yielding, relatively liquid fixed income securities. The funds are valued using the net asset value method. (c) This category represents investments that invest in U.S. treasury strips, U.S. government agency obligations, and U.S. treasury obligations. The funds seek investment returns over the long term and are valued using the net asset value method. (d) This category represents an investment that seeks to maximize current income on cash reserves to the extent consistent with principal preservation and maintenance of liquidity from a portfolio of obligations of the U.S. Government, its agencies or municipalities, and related money market instruments. Principal preservation is a primary objective. The fund is valued at cost. Fair Value Measurements at December 31, 2022 (in thousands) Quoted Prices in Active Markets for Identical Assets Significant Observable Inputs Asset Category Total (Level 1) (Level 2) % Common collective trusts: Equities (a) $ 85,341 $ 2,017 $ 83,324 14 % Debt securities (b) 400,291 1,254 399,037 66 % Government debt securities (c) 122,704 420 122,284 20 % Total common collective trusts 608,336 3,691 604,645 100 % Cash and cash equivalents (d) 2,789 2,789 — — % Total pension plan assets $ 611,125 $ 6,480 $ 604,645 100 % (a) This category represents investments that invest in equity securities of U.S. companies of any market capitalization and other investments (i.e.: futures, swaps, currency forwards) of foreign, emerging markets and seeks to provide long-term total return, which includes capital appreciation and income. The funds are valued using the net asset value method. (b) This category represents investments that invest in high quality issues within the U.S. corporate bond markets and global high yield bonds and emerging markets debt denominated in local currency. The funds seek to provide current income and long-term capital preservation along with access to higher yielding, relatively liquid fixed income securities. The funds are valued using the net asset value method. (c) This category represents investments that invest in U.S. treasury strips, U.S. government agency obligations, and U.S. treasury obligations. The funds seek investment returns over the long term and are valued using the net asset value method. (d) This category represents an investment that seeks to maximize current income on cash reserves to the extent consistent with principal preservation and maintenance of liquidity from a portfolio of obligations of the U.S. Government, its agencies or municipalities, and related money market instruments. Principal preservation is a primary objective. The fund is valued at cost. Pension Funding We contributed $0.1 million, $0.4 million, and $0.0 million to the Pension Plans in 2023, 2022 and 2021, respectively. Funding for the qualified Defined Benefit Pension Plan is based upon actuarially determined contributions that take into account the amount deductible for income tax purposes and the minimum contribution required under ERISA, as amended by the Pension Protection Act of 2006, as well as targeted funding levels necessary to meet certain thresholds. From an ERISA funding perspective, AES Indiana’s funded target liability percentage was estimated to be 98%. In general, AES Indiana must contribute the normal service cost earned by active participants during the plan year; however, this amount can be offset by any surplus or credit balance carried by the Pension Plan. The normal cost is expected to be approximately $6.3 million in 2024 (including $0.4 million for plan expenses), which is expected to be fully offset by the surplus amount. Each year thereafter, if the Pension Plans’ underfunding increases to more than the present value of the remaining annual installments, the excess is separately amortized over a seven-year period. AES Indiana does not expect to make an employer contribution for the calendar year 2024. AES Indiana’s funding policy for the Pension Plans is to contribute annually no less than the minimum required by applicable law, and no more than the maximum amount that can be deducted for federal income tax purposes. Benefit payments made from the Pension Plans for the years ended December 31, 2023, 2022 and 2021 were $73.3 million, $38.6 million and $63.2 million, respectively. Benefit payments, which reflect future service, are expected to be paid out of the Pension Plans as follows: Year Pension Benefits (In Thousands) 2024 $ 37,997 2025 38,794 2026 39,665 2027 40,085 2028 41,477 2029 through 2033 200,574
Indianapolis Power And Light Company
Entity Information [Line Items]
Benefit Plans	BENEFIT PLANS Defined Contribution Plans All of AES Indiana’s employees are covered by one of two defined contribution plans, the Thrift Plan or the RSP: The Thrift Plan Approximately 77% of AES Indiana’s active employees are covered by the Thrift Plan, a qualified defined contribution plan. All union new hires are covered under the Thrift Plan. Participants elect to make contributions to the Thrift Plan based on a percentage of their base compensation. Each participant’s contribution is matched up to certain thresholds of base compensation. The IBEW clerical-technical union new hires receive an annual lump sum company contribution into the Thrift Plan in addition to the company match. Employer contributions to the Thrift Plan were $3.7 million, $3.6 million and $3.4 million for 2023, 2022 and 2021, respectively. The RSP Approximately 23% of AES Indiana’s active employees are covered by the RSP, a qualified defined contribution plan containing both match and nondiscretionary components. All non-union new hires are covered under the RSP. Participants elect to make contributions to the RSP based on a percentage of their eligible compensation. Each participant’s contribution is matched in amounts up to, but not exceeding, 5% of the participant’s eligible compensation. Starting in 2018, the RSP also includes a 4% nondiscretionary contribution based as a percentage of each participant's eligible compensation. Employer contributions (by AES Indiana) relating to the RSP were $2.5 million, $2.1 million and $1.9 million for 2023, 2022 and 2021, respectively. Defined Benefit Plans Approximately 65% of AES Indiana’s active employees are covered by the qualified Defined Benefit Pension Plan; while approximately 12% of active employees are IBEW clerical-technical unit employees who are only eligible for the Thrift Plan. The remaining 23% of active employees are covered by the RSP. All non-union new hires are covered under the RSP, while IBEW physical unit union new hires are covered under the Defined Benefit Pension Plan and Thrift Plan. The IBEW clerical-technical unit new hires are no longer covered under the Defined Benefit Pension Plan but do receive an annual lump sum company contribution into the Thrift Plan, in addition to the company match. The Defined Benefit Pension Plan is noncontributory and is funded by AES Indiana through a trust. Benefits for non-union participants in the Defined Benefit Pension Plan are based on salary, years of service and accrued benefits at April 1, 2015. Benefits for eligible union participants are based on each individual employee's pension band and years of service as opposed to their compensation. Pension bands are based primarily on job duties and responsibilities. Additionally, a small group of former officers and their surviving spouses are covered under a funded non-qualified Supplemental Retirement Plan. The total number of participants in the plan as of December 31, 2023 was 19. The plan is closed to new participants. AES Indiana also provides postretirement health care benefits to certain active or retired employees and the spouses of certain active or retired employees. Approximately 123 active employees and 26 retirees (including spouses) were receiving such benefits or entitled to future benefits as of January 1, 2023. The plan is unfunded. These postretirement health care benefits and the related unfunded obligation of $3.0 million and $3.2 million at December 31, 2023 and 2022, respectively, were not material to the consolidated financial statements in the periods covered by this report. The following table presents information relating to the Pension Plans: Pension benefits 2023 2022 (In Thousands) Change in benefit obligation: Projected benefit obligation at January 1 $ 577,530 $ 772,040 Service cost 5,189 8,949 Interest cost 29,818 18,099 Actuarial loss (gain) 9,681 (182,590) Amendments (primarily increases in pension bands) 653 — Settlements — (394) Benefits paid (73,325) (38,575) Projected benefit obligation at December 31 549,546 577,529 Change in plan assets: Fair value of plan assets at January 1 611,125 820,684 Actual return/(loss) on plan assets 52,905 (171,002) Employer contributions 114 412 Settlements — (394) Benefits paid (73,325) (38,575) Fair value of plan assets at December 31 590,819 611,125 Funded status $ 41,273 $ 33,596 Amounts recognized in the statement of financial position: Non-current assets $ 41,273 $ 33,611 Non-current liabilities — (15) Net amount recognized at end of year $ 41,273 $ 33,596 Sources of change in regulatory assets (1) : Prior service cost arising during period $ 653 $ — Net (gain)/loss arising during period (10,117) 24,069 Amortization of prior service cost (2,172) (2,589) Amortization of loss (6,145) (2,622) Total recognized in regulatory assets $ (17,781) $ 18,858 Amounts included in regulatory assets: Net loss $ 115,297 $ 131,559 Prior service cost 10,136 11,655 Total amounts included in regulatory assets $ 125,433 $ 143,214 (1) Amounts that would otherwise be charged/credited to Accumulated Other Comprehensive Income or Loss upon application of ASC 715, “Compensation – Retirement Benefits,” are recorded as a regulatory asset or liability because AES Indiana has historically recovered and currently recovers pension and other postretirement benefit expenses in rates. These are unrecognized amounts not yet recognized as components of net periodic benefit costs. Significant Loss / (Gain) Related to Changes in the Benefit Obligation for the Period As shown in the table above, an actuarial loss of $9.7 million and an actuarial gain of $182.6 million for the year ended December 31, 2023 and December 31, 2022, respectively, were recognized in the benefit obligation, primarily due to changes in the discount rate. Pension Benefits and Expense Reported expenses relevant to the Defined Benefit Pension Plan are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience, including the performance of plan assets and actual benefits paid out in future years. Pension costs associated with the Defined Benefit Pension Plan are impacted by the level of contributions made to the plan, income on plan assets, the adoption of new mortality tables, and employee demographics, including age, job responsibilities, salary and employment periods. Changes made to the provisions of the Defined Benefit Pension Plan may impact current and future pension costs. Pension costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the corporate bond discount rates, as well as, the adoption of a new mortality table used in determining the projected benefit obligation and pension costs. The 2023 net actuarial gain of $10.1 million recognized in regulatory assets is comprised of two parts: (1) a $9.7 million pension liability actuarial loss primarily due to a decrease in the discount rate used to value pension liabilities; and (2) a $19.8 million pension asset actuarial gain primarily due to higher than expected return on assets. The unrecognized net loss of $115.3 million in the Pension Plans has accumulated over time primarily due to the long-term declining trend in corporate bond rates and the adoption of new mortality tables which have historically increased the expected benefit obligation due to the longer expected lives of plan participants. In 2023, the accumulated net loss decrease was primarily attributed to an annuity buyout involving a small portion of retirees, which was partially offset by factors such as a reduced discount rate utilized in valuing pension liabilities, along with the amortization of accumulated losses incurred during the year. The unrecognized net loss, to the extent that it exceeds 10% of the greater of the benefit obligation or the assets, will be amortized and included as a component of net periodic benefit cost in future years. The amortization period is approximately 11.66 years based on estimated demographic data as of December 31, 2023. The projected benefit obligation of $549.5 million less the fair value of assets of $590.8 million results in an overfunded status of $41.3 million at December 31, 2023. Pension benefits for 2023 2022 2021 (In Thousands) Components of net periodic benefit cost / (credit): Service cost $ 5,189 $ 8,949 $ 9,339 Interest cost 29,818 18,099 15,660 Expected return on plan assets (33,107) (35,656) (41,815) Amortization of prior service cost 2,172 2,589 2,944 Amortization of actuarial loss 6,145 2,424 5,529 Amortization of settlement loss — 199 — Net periodic benefit cost / (credit) 10,217 (3,396) (8,343) Less: amounts capitalized 1,689 (316) (771) Amount charged to expense $ 8,528 $ (3,080) $ (7,572) Rates relevant to each year’s expense calculations: Discount rate – defined benefit pension plan 5.41 % 2.83 % 2.46 % Discount rate – supplemental retirement plan 5.32 % 2.62 % 2.31 % Expected return on defined benefit pension plan assets 5.60 % 4.45 % 5.05 % Expected return on supplemental retirement plan assets 6.45 % 5.50 % 3.60 % Pension expense / (income) for the following year is determined as of the December 31 measurement date based on the fair value of the Pension Plans’ assets, the expected long-term rate of return on plan assets, a mortality table assumption that reflects the life expectancy of plan participants, and a discount rate used to determine the projected benefit obligation. For 2023, pension expense / (income) was determined using an assumed long-term rate of return on plan assets of 5.60% for the Defined Benefit Pension Plan and 6.45% for the Supplemental Retirement Plan. As of the December 31, 2023 measurement date, AES Indiana decreased the discount rate from 5.41% to 5.15% for the Defined Benefit Pension Plan and increased the discount rate from 5.32% to 5.66% for the Supplemental Retirement Plan. The discount rate assumptions affect the pension expense / (income) determined for 2024. In addition, AES Indiana decreased the expected long-term rate of return on plan assets from 5.60% to 5.20% for the Defined Benefit Pension Plan and from 6.45% to 6.35% for the Supplemental Retirement Plan for 2024. The expected long-term rate of return assumptions affect the pension expense / (income) determined for 2024. The effect on 2024 total pension expense / (income) of a 25 basis point increase and decrease in the assumed discount rate is $(0.8) million and $0.8 million, respectively. In determining the discount rate to use for valuing liabilities, we use the market yield curve on high-quality fixed income investments as of December 31, 2023. We project the expected benefit payments under the plan based on participant data and based on certain assumptions concerning mortality, retirement rates, termination rates, etc. The expected benefit payments for each year are discounted back to the measurement date using the appropriate spot rate for each half-year from the yield curve, thereby obtaining a present value of all expected future benefit payments using the yield curve. Finally, an equivalent single discount rate is determined which produces a present value equal to the present value determined using the full yield curve. Pension Plan Assets and Fair Value Measurements Pension plan assets consist of investments in cash and cash equivalents, government debt securities, and mutual funds (equity and debt). Differences between actual portfolio returns and expected returns may result in increased or reduced pension costs in future periods. Pension costs for 2024 are determined as of the plans' measurement date of December 31, 2023. Pension costs are determined for the following year based on the market value of pension plan assets, expected employer contributions, a discount rate used to determine the projected benefit obligation and the expected long-term rate of return on plan assets. Fair value is defined under ASC 820 as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (i.e., an exit price). The fair value hierarchy prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets and liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Purchases and sales of securities are recorded on a trade-date basis. Interest income is recorded as earned. Dividends are recorded on the ex-dividend date. Net appreciation includes the Pension Plans’ gains and losses on investments bought and sold, as well as held, during the year. A description of the valuation methodologies used for each major class of assets and liabilities measured at fair value follows: • The non-qualified Supplemental Retirement Plan investments have quoted market prices and are categorized as Level 1 in the fair value hierarchy. • The qualified Defined Benefit Pension Plan investments in common collective trusts are valued based on the daily net asset value and are categorized as Level 2 in the fair value hierarchy, except for cash and cash equivalents which are categorized as level 1. The primary objective of the Pension Plans’ is to provide a source of retirement income for its participants and beneficiaries, while the primary financial objective is to improve the funded status of the Pension Plans. A secondary financial objective is, where possible, to minimize pension expense volatility. The objective is based on a long-term investment horizon, so that interim fluctuations should be viewed with appropriate perspective. There can be no assurance that these objectives will be met. In establishing AES Indiana’s expected long-term rate of return assumption, we utilize a methodology developed by the plan’s investment consultant who maintains a capital market assumption model that takes into consideration risk, return and correlation assumptions across asset classes. A combination of quantitative analysis of historical data and qualitative judgment is used to capture trends, structural changes and potential scenarios not reflected in historical data. The result of the analyses is a series of inputs that produce a picture of how the plan consultant believes portfolios are likely to behave through time. Capital market assumptions are intended to reflect the behavior of asset classes observed over several market cycles. Stress assumptions are also examined, since the characteristics of asset classes are constantly changing. A dynamic model is employed to manage the numerous assumptions required to estimate portfolio characteristics under different base currencies, time horizons and inflation expectations. The Pension Plans’ consultant develops forward-looking, long-term capital market assumptions for risk, return and correlations for a variety of global asset classes, interest rates and inflation. These assumptions are created using a combination of historical analysis, current market environment assessment and by applying the consultant’s own judgment. The consultant then determines an equilibrium long-term rate of return. AES Indiana then takes into consideration the investment manager/consultant expenses, as well as any other expenses expected to be paid out of the Pension Plans’ trust. Finally, AES Indiana has the Pension Plans’ actuary perform a tolerance test of the consultant’s equilibrium expected long-term rate of return. AES Indiana uses an expected long-term rate of return compatible with the actuary’s tolerance level. The following table summarizes AES Indiana’s target pension plan allocation for 2023: Asset Category: Target Allocations Equity Securities 13.5% Debt Securities 86.5% Fair Value Measurements at December 31, 2023 (in thousands) Quoted Prices in Active Markets for Identical Assets Significant Observable Inputs Asset Category Total (Level 1) (Level 2) % Common collective trusts: Equities (a) $ 82,652 $ 2,267 $ 80,385 14 % Debt securities (b) 387,979 1,168 386,811 66 % Government debt securities (c) 117,397 178 117,219 20 % Total common collective trusts 588,028 3,613 584,415 100 % Cash and cash equivalents (d) 2,791 2,791 — — % Total pension plan assets $ 590,819 $ 6,404 $ 584,415 100 % (a) This category represents investments that invest in equity securities of U.S. companies of any market capitalization and other investments (i.e.: futures, swaps, currency forwards) of foreign, emerging markets and seeks to provide long-term total return, which includes capital appreciation and income. The funds are valued using the net asset value method. (b) This category represents investments that invest in high quality issues within the U.S. corporate bond markets and global high yield bonds and emerging markets debt denominated in local currency. The funds seek to provide current income and long-term capital preservation along with access to higher yielding, relatively liquid fixed income securities. The funds are valued using the net asset value method. (c) This category represents investments that invest in U.S. treasury strips, U.S. government agency obligations, and U.S. treasury obligations. The funds seek investment returns over the long term and are valued using the net asset value method. (d) This category represents an investment that seeks to maximize current income on cash reserves to the extent consistent with principal preservation and maintenance of liquidity from a portfolio of obligations of the U.S. Government, its agencies or municipalities, and related money market instruments. Principal preservation is a primary objective. The fund is valued at cost. Fair Value Measurements at December 31, 2022 (in thousands) Quoted Prices in Active Markets for Identical Assets Significant Observable Inputs Asset Category Total (Level 1) (Level 2) % Common collective trusts: Equities (a) $ 85,341 $ 2,017 $ 83,324 14 % Debt securities (b) 400,291 1,254 399,037 66 % Government debt securities (c) 122,704 420 122,284 20 % Total common collective trusts 608,336 3,691 604,645 100 % Cash and cash equivalents (d) 2,789 2,789 — — % Total pension plan assets $ 611,125 $ 6,480 $ 604,645 100 % (a) This category represents investments that invest in equity securities of U.S. companies of any market capitalization and other investments (i.e.: futures, swaps, currency forwards) of foreign, emerging markets and seeks to provide long-term total return, which includes capital appreciation and income. The funds are valued using the net asset value method. (b) This category represents investments that invest in high quality issues within the U.S. corporate bond markets and global high yield bonds and emerging markets debt denominated in local currency. The funds seek to provide current income and long-term capital preservation along with access to higher yielding, relatively liquid fixed income securities. The funds are valued using the net asset value method. (c) This category represents investments that invest in U.S. treasury strips, U.S. government agency obligations, and U.S. treasury obligations. The funds seek investment returns over the long term and are valued using the net asset value method. (d) This category represents an investment that seeks to maximize current income on cash reserves to the extent consistent with principal preservation and maintenance of liquidity from a portfolio of obligations of the U.S. Government, its agencies or municipalities, and related money market instruments. Principal preservation is a primary objective. The fund is valued at cost. Pension Funding AES Indiana contributed $0.1 million, $0.4 million, and $0.0 million to the Pension Plans in 2023, 2022 and 2021, respectively. Funding for the qualified Defined Benefit Pension Plan is based upon actuarially determined contributions that take into account the amount deductible for income tax purposes and the minimum contribution required under ERISA, as amended by the Pension Protection Act of 2006, as well as targeted funding levels necessary to meet certain thresholds. From an ERISA funding perspective, AES Indiana’s funded target liability percentage was estimated to be 98%. In general, AES Indiana must contribute the normal service cost earned by active participants during the plan year; however, this amount can be offset by any surplus or credit balance carried by the Pension Plan. The normal cost is expected to be approximately $6.3 million in 2024 (including $0.4 million for plan expenses), which is expected to be fully offset by the surplus amount. Each year thereafter, if the Pension Plans' underfunding increases to more than the present value of the remaining annual installments, the excess is separately amortized over a seven-year period. AES Indiana does not expect to make an employer contribution for the calendar year 2024. AES Indiana’s funding policy for the Pension Plans is to contribute annually no less than the minimum required by applicable law, and no more than the maximum amount that can be deducted for federal income tax purposes. Benefit payments made from the Pension Plans for the years ended December 31, 2023, 2022 and 2021 were $73.3 million, $38.6 million and $63.2 million, respectively. Benefit payments, which reflect future service, are expected to be paid out of the Pension Plans as follows: Year Pension Benefits (In Thousands) 2024 $ 37,997 2025 38,794 2026 39,665 2027 40,085 2028 41,477 2029 through 2033 200,574

Equity

Equity	12 Months Ended
	Dec. 31, 2023
Entity Information [Line Items]
Equity	EQUITY AND CUMULATIVE PREFERRED STOCK Cumulative Preferred Stock On December 30, 2022 (the “Redemption Date”), AES Indiana redeemed all of its issued and outstanding preferred stock for $60.1 million On the Redemption Date, the Preferred Stock of each series was redeemed with all applicable premiums, plus, in each case an amount equal to all accrued dividends payable with respect to such Preferred Stock to the Redemption Date. Dividends on the Preferred Stock ceased to accrue on the Redemption Date. Upon redemption, the Preferred Stock was no longer outstanding, and all rights of the holders thereof as shareholders of AES Indiana ceased to exist, except for the right to payment of the redemption price. AES Indiana recorded a charge of $0.3 million on the redemption for the difference between the carrying value and redemption value of the preferred shares. Prior to the redemption, AES Indiana had five separate series of cumulative preferred stock. Holders of the preferred stock were entitled to receive dividends at rates per annum ranging from 4.0% to 5.65%. During the years ended December 31, 2023, 2022 and 2021, total preferred stock dividends declared were $0.0 million, $3.2 million, and $3.2 million, respectively. Holders of preferred stock were entitled to two votes per share for AES Indiana matters, and if four full quarterly dividends are in default on all shares of the preferred stock then outstanding, they were entitled to elect the smallest number of AES Indiana directors to constitute a majority of AES Indiana’s Board of Directors. Based on the preferred stockholders’ ability to elect a majority of AES Indiana’s Board of Directors in this circumstance, the redemption of the preferred shares was considered to be not solely within the control of the issuer and the preferred stock was considered temporary equity and presented in the mezzanine level of the audited consolidated balance sheets in accordance with the relevant accounting guidance for non-controlling interests and redeemable securities. Paid In Capital On December 12, 2022, AES U.S. Investments received equity capital contributions totaling $208.3 million, of which $177.0 million was contributed by AES U.S. Holdings, LLC and $31.3 million was contributed by CDPQ. IPALCO then received equity capital contributions totaling $253.0 million, of which $208.3 million was contributed by AES U.S. Investments and $44.7 million was contributed by CDPQ. On December 13, 2021, AES U.S. Investments received equity capital contributions totaling $226.5 million, of which $192.5 million was contributed by AES U.S. Holdings, LLC and $34.0 million was contributed by CDPQ. IPALCO then received equity capital contributions totaling $275.0 million, of which $226.5 million was contributed by AES U.S. Investments and $48.5 million was contributed by CDPQ. IPALCO then made the same investments in AES Indiana in 2021 and 2022. The proceeds are intended primarily for funding needs related to AES Indiana’s TDSIC and replacement generation projects. The capital contributions were made on a proportional share basis and, therefore, did not change CDPQ’s or AES’ ownership interests in IPALCO or AES U.S. Investments. Dividend Restrictions AES Indiana’s mortgage and deed of trust and its amended articles of incorporation contain restrictions on AES Indiana’s ability to issue certain securities or pay cash dividends. So long as any of the several series of bonds of AES Indiana issued under its mortgage remains outstanding, and subject to certain exceptions, AES Indiana is restricted in the declaration and payment of dividends, or other distribution on shares of its capital stock of any class, or in the purchase or redemption of such shares, to the aggregate of its net income, as defined in the mortgage, after December 31, 1939. In addition, pursuant to AES Indiana’s articles, no dividends may be paid or accrued, and no other distribution may be made on AES Indiana’s common stock unless dividends on all outstanding shares of AES Indiana preferred stock have been paid or declared and set apart for payment. As of December 31, 2023, and as of the filing of this report, AES Indiana was in compliance with these restrictions. Additionally, all of AES Indiana's preferred stock was redeemed on December 30, 2022 (see " Cumulative Preferred Stock " above for further details). AES Indiana is also restricted in its ability to pay dividends if it is in default under the terms of its Credit Agreement and $300 million Term Loan Agreement, which could happen if AES Indiana fails to comply with certain covenants. These covenants, among other things, require AES Indiana to maintain a ratio of total debt to total capitalization not in excess of 0.67 to 1. As of December 31, 2023, and as of the filing of this report, AES Indiana was in compliance with all covenants and no event of default existed. IPALCO’s Third Amended and Restated Articles of Incorporation contain provisions which state that IPALCO may not make a distribution to its shareholders or make a loan to any of its affiliates (other than its subsidiaries), unless: (a) there exists no event of default (as defined in the articles) and no such event of default would result from the making of the distribution or loan; and either (b)(i) at the time of, and/or as a result of, the distribution or loan, IPALCO’s leverage ratio does not exceed 0.67 to 1 and IPALCO’s interest coverage ratio is not less than 2.50 to 1 or, (b)(ii) if such ratios are not within the parameters, IPALCO’s senior long-term debt rating from one of the three major credit rating agencies is at least investment grade. As of December 31, 2023, and as of the filing of this report, IPALCO was in compliance with all covenants and no event of default existed. During the years ended December 31, 2023, 2022 and 2021, IPALCO declared and paid distributions to its shareholders totaling $104.3 million, $102.0 million and $131.5 million, respectively. Equity Transactions with Noncontrolling Interests The Hardy Hills Solar Project has been financed with a tax equity structure, in which a tax equity investor receives a portion of the economic attributes of the facility, including tax attributes, that vary over the life of the project. On December 1, 2023, the Class B Member and the Class A Member, entered into an Equity Capital Contribution Agreement, pursuant to which each member made certain capital contributions to Hardy Hills JV. The Class A member made total contributions of $79.3 million through December 31, 2023. A noncontrolling interest was recorded by AES Indiana at the amount of cash contributed by the Class A Member.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2023
Entity Information [Line Items]
Commitments and Contingencies	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 3 – 5 More Than (In Millions) Purchase obligations: Coal, gas, purchased power and related transportation $ 933.5 $ 249.7 $ 267.3 $ 225.7 $ 190.8 Other $ 409.1 $ 355.0 $ 32.8 $ 20.2 $ 1.1 Purchase obligations: Purchase commitments for coal, gas, purchased power and related transportation: AES Indiana enters into long-term contracts for the purchase of coal, gas, purchased power and related transportation. In general, these contracts are subject to variable quantities or prices and are terminable only in limited circumstances. Purchase orders and other contractual obligations: At December 31, 2023, we had various other contractual obligations including contracts to purchase goods and services with various terms and expiration dates, as well as obligations under long-term construction contracts. Due to uncertainty regarding the timing and payment of future obligations to the Service Company, and our ability to terminate such obligations upon 90 days' notice, we have excluded such amounts in the contractual obligations table above. This table also does not include (i) regulatory liabilities (see Note 2, " Regulatory Matters "), (ii) derivatives (see Note 5, " Derivative Instruments and Hedging Activities "), (iii) taxes (see Note 7, " Income Taxes "), (iv) pension and other postretirement employee benefit liabilities (see Note 8, " Benefit Plans ") and (v) contingencies (see Note 10, " Commitments and Contingencies "). See the indicated notes to the Financial Statements for additional information on the items excluded. Contingencies Legal Matters IPALCO and AES Indiana are involved in litigation arising in the normal course of business. We accrue for litigation and claims when it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. While the ultimate outcome of outstanding litigation cannot be predicted with certainty, management believes that final outcomes will not have a material adverse effect on IPALCO’s results of operations, financial condition and cash flows. Accruals for legal loss contingencies were not material as of December 31, 2023 and 2022. Coal Ash Insurance Litigation In August 2021, AES Indiana filed a civil action against various third-party insurance providers. The complaint seeks damages for breach of contract and a declaratory judgment declaring that such insurers must defend and indemnify AES Indiana under liability insurance policies issued between 1950 and the filing of the civil action against certain environmental liabilities arising from CCR at Harding Street, Petersburg and Eagle Valley. At this time, we cannot predict the outcome of this matter. Environmental Matters We are subject to various federal, state, regional and local environmental protection and health and safety laws and regulations governing, among other things, the generation, storage, handling, use, disposal and transportation of regulated materials, including ash; the use and discharge of water used in generation boilers and for cooling purposes; the emission and discharge of hazardous and other materials, including GHGs, into the environment; climate change; and the health and safety of our employees. These laws and regulations often require a lengthy and complex process of obtaining and renewing permits and other governmental authorizations from federal, state and local agencies. Violation of these laws, regulations or permits can result in substantial fines, other sanctions, permit revocation and/or facility shutdowns. We cannot assure that we have been or will be at all times in full compliance with such laws, regulations and permits. Accruals for environmental contingencies were not material as of December 31, 2023 and 2022. NSR and other CAA NOVs In October 2009, AES Indiana received a NOV and Finding of Violation from the EPA pursuant to the CAA Section 113(a). The NOV alleged violations of the CAA at AES Indiana’s three primarily coal-fired electric generating facilities at the time, dating back to 1986. The alleged violations primarily pertain to the PSD and non-attainment NSR requirements under the CAA. In addition, on October 1, 2015, AES Indiana received a NOV from the EPA pursuant to CAA Section 113(a) alleging violations of the CAA, the Indiana SIP, and the Title V operating permit related to alleged particulate matter and opacity violations at AES Indiana Petersburg Unit 3. Also, on February 5, 2016, the EPA issued a NOV pursuant to CAA Section 113(a) alleging violations of PSD, non-attainment NSR and other CAA regulations, the Indiana SIP, and the Title V operating permit at Petersburg Generating Station. On August 31, 2020, AES Indiana reached a settlement with the EPA, the DOJ and IDEM resolving the purported violations of the CAA with respect to the coal-fired generation units at AES Indiana's Petersburg location. The settlement agreement, in the form of a proposed judicial consent decree was approved and entered by the U.S. District Court for the Southern District of Indiana on March 23, 2021, and includes, among other items, the following requirements: annual caps on NO x and SO 2 emissions and more stringent emissions limits than AES Indiana's prior Title V air permit; payment of civil penalties totaling $1.525 million (the payment of which was satisfied by AES Indiana in April 2021); a $5 million environmental mitigation project consisting of the construction and operation of a new, non-emitting source of generation at the site; expenditure of $0.325 million on a state-only environmentally beneficial project to preserve local, ecologically-significant lands; and retirement of Units 1 and 2 prior to July 1, 2023 (which has occurred). AES Indiana previously had a contingent liability recorded related to these NSR and other CAA NOV matters.
Indianapolis Power And Light Company
Entity Information [Line Items]
Commitments and Contingencies	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 3 – 5 More Than (In Millions) Purchase obligations: Coal, gas, purchased power and related transportation $ 933.5 $ 249.7 $ 267.3 $ 225.7 $ 190.8 Other $ 409.1 $ 355.0 $ 32.8 $ 20.2 $ 1.1 Purchase obligations: Purchase commitments for coal, gas, purchased power and related transportation: AES Indiana enters into long-term contracts for the purchase of coal, gas, purchased power and related transportation. In general, these contracts are subject to variable quantities or prices and are terminable only in limited circumstances. Purchase orders and other contractual obligations: At December 31, 2023, we had various other contractual obligations including contracts to purchase goods and services with various terms and expiration dates, as well as obligations under long-term construction contracts. Due to uncertainty regarding the timing and payment of future obligations to the Service Company, and our ability to terminate such obligations upon 90 days' notice, we have excluded such amounts in the contractual obligations table above. This table also does not include (i) regulatory liabilities (see Note 2, " Regulatory Matters "), (ii) derivatives (see Note 5, " Derivative Instruments and Hedging Activities "), (iii) taxes (see Note 7, " Income Taxes "), (iv) pension and other postretirement employee benefit liabilities (see Note 8, " Benefit Plans ") and (v) contingencies (see Note 10, " Commitments and Contingencies "). See the indicated notes to the Financial Statements for additional information on the items excluded. Contingencies Legal Matters AES Indiana is involved in litigation arising in the normal course of business. AES Indiana accrues for litigation and claims when it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. While the ultimate outcome of outstanding litigation cannot be predicted with certainty, management believes that final outcomes will not have a material adverse effect on AES Indiana’s results of operations, financial condition and cash flows. Accruals for legal loss contingencies were not material as of December 31, 2023 and 2022. Coal Ash Insurance Litigation In August 2021, AES Indiana filed a civil action against various third-party insurance providers. The complaint seeks damages for breach of contract and a declaratory judgment declaring that such insurers must defend and indemnify AES Indiana under liability insurance policies issued between 1950 and the filing of the civil action against certain environmental liabilities arising from CCR at Harding Street, Petersburg and Eagle Valley. At this time, we cannot predict the outcome of this matter. Environmental Matters AES Indiana is subject to various federal, state, regional and local environmental protection and health and safety laws and regulations governing, among other things, the generation, storage, handling, use, disposal and transportation of regulated materials, including ash; the use and discharge of water used in generation boilers and for cooling purposes; the emission and discharge of hazardous and other materials, including GHGs, into the environment; climate change; and the health and safety of AES Indiana's employees. These laws and regulations often require a lengthy and complex process of obtaining and renewing permits and other governmental authorizations from federal, state and local agencies. Violation of these laws, regulations or permits can result in substantial fines, other sanctions, permit revocation and/or facility shutdowns. AES Indiana cannot assure that it has been or will be at all times in full compliance with such laws, regulations and permits. Accruals for environmental contingencies were not material as of December 31, 2023 and 2022.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2023
Entity Information [Line Items]
Related Party Transactions	RELATED PARTY TRANSACTIONS AES Indiana participates in a property insurance program in which AES Indiana buys insurance from AES Global Insurance Company, a wholly-owned subsidiary of AES. AES Indiana is not self-insured on property insurance, but does take a $5 million per occurrence deductible. Except for AES Indiana’s large substations, AES Indiana does not carry insurance on transmission and distribution assets, which are considered to be outside the scope of property insurance. AES and other AES subsidiaries, including IPALCO, also participate in the AES global insurance program. AES Indiana pays premiums for a policy that is written and administered by a third-party insurance company. The premiums paid to this third-party administrator by the participants are paid to AES Global Insurance Company and all claims are paid from a trust fund funded by and owned by AES Global Insurance Company, but controlled by the third-party administrator. AES Indiana also has third-party insurance in which the premiums are paid directly to the third-party insurers. The cost to AES Indiana of coverage under the property insurance program with AES Global Insurance Company was approximately $11.7 million, $9.5 million, and $7.0 million in 2023, 2022 and 2021, respectively, and is recorded in “ Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations. As of December 31, 2023 and 2022, we had prepaid approximately $7.5 million and $3.4 million, respectively, for coverage under these plans, which is recorded in " Prepayments and other current assets " on the accompanying Consolidated Balance Sheets. AES Indiana participates in an agreement with Health and Welfare Benefit Plans LLC, an affiliate of AES, to participate in a group benefits program, including but not limited to, health, dental, vision and life benefits. Health and Welfare Benefit Plans LLC administers the financial aspects of the group insurance program, receives all premium payments from the participating affiliates, and makes all vendor payments. The cost of coverage under this program was approximately $19.0 million, $25.2 million, and $23.7 million in 2023, 2022 and 2021, respectively, and is recorded in “ Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations. We had no prepaids for coverage under this plan as of December 31, 2023 and 2022, respectively. AES files federal and state income tax returns which consolidate IPALCO and its subsidiaries. Under a tax sharing agreement with AES, IPALCO is responsible for the income taxes associated with its own taxable income and records the provision for income taxes using a separate return method. IPALCO had a receivable balance under this agreement of $36.5 million and $18.0 million as of December 31, 2023 and 2022, respectively, which is recorded in “ Taxes receivable” on the accompanying Consolidated Balance Sheets. See Note 7, " Income Taxes " for more information. Long-term Compensation Plan During 2023, 2022 and 2021, many of AES Indiana’s non-union employees received benefits under the AES Long-term Compensation Plan, a deferred compensation program. This type of plan is a common employee retention tool used in our industry. Benefits under this plan are granted in the form of performance units payable in cash and AES restricted stock units. Restricted stock units vest ratably over a three-year period. The performance units payable in cash vest at the end of the three-year performance period and are subject to certain AES performance criteria. Total deferred compensation expense recorded during 2023, 2022 and 2021 was $0.3 million, $0.2 million and $0.2 million, respectively, and was included in “ Operating expenses - Operation and maintenance” on IPALCO’s Consolidated Statements of Operations. The value of these benefits is being recognized over the 36 month vesting period and a portion is recorded as miscellaneous deferred credits with the remainder recorded as “ Paid in capital” on IPALCO’s Consolidated Balance Sheets in accordance with ASC 718 “Compensation – Stock Compensation.” See also Note 8, “ Benefit Plans” to the Financial Statements for a description of benefits awarded to AES Indiana employees by AES under the RSP. Service Company Total costs incurred by the Service Company on behalf of IPALCO were $73.8 million, $60.3 million and $58.4 million during 2023, 2022 and 2021, respectively. Total costs incurred by IPALCO on behalf of the Service Company during 2023, 2022 and 2021 were $11.9 million, $10.0 million and $10.4 million, respectively, which are included as a reduction to charges from the Service Company. These costs were included in “ Operating expenses - Operation and maintenance” on IPALCO’s Consolidated Statements of Operations. IPALCO had a payable balance with the Service company of $25.6 million and $2.1 million as of December 31, 2023 and 2022, respectively, which is recorded in " Accounts payable " on the accompanying Consolidated Balance Sheets. Other In the second quarter of 2023, AES Indiana engaged a vendor that is a related party through a competitive RFP process as part of its replacement capacity resource construction projects. AES Indiana had payments of $223.3 million to this vendor during the year ended December 31, 2023, which are included in " Other non-current assets " on the accompanying Consolidated Balance Sheets. Transactions with various other related parties were $7.4 million, $5.7 million and $4.3 million during 2023, 2022 and 2021, respectively. These expenses were primarily recorded in “ Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations.
Indianapolis Power And Light Company
Entity Information [Line Items]
Related Party Transactions	RELATED PARTY TRANSACTIONS AES Indiana participates in a property insurance program in which AES Indiana buys insurance from AES Global Insurance Company, a wholly-owned subsidiary of AES. AES Indiana is not self-insured on property insurance, but does take a $5 million per occurrence deductible. Except for AES Indiana’s large substations, AES Indiana does not carry insurance on transmission and distribution assets, which are considered to be outside the scope of property insurance. AES and other AES subsidiaries, including AES Indiana, also participate in the AES global insurance program. AES Indiana pays premiums for a policy that is written and administered by a third-party insurance company. The premiums paid to this third-party administrator by the participants are paid to AES Global Insurance Company and all claims are paid from a trust fund funded by and owned by AES Global Insurance Company, but controlled by the third-party administrator. AES Indiana also has third-party insurance in which the premiums are paid directly to the third-party insurers. The cost to AES Indiana of coverage under the property insurance program with AES Global Insurance Company was approximately $11.7 million, $9.5 million, and $7.0 million in 2023, 2022 and 2021, respectively, and is recorded in “ Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations. As of December 31, 2023 and 2022, AES Indiana had prepaid approximately $7.5 million and $3.4 million, respectively, for coverage under these plans, which is recorded in " Prepayments and other current assets " on the accompanying Consolidated Balance Sheets. AES Indiana participates in an agreement with Health and Welfare Benefit Plans LLC, an affiliate of AES, to participate in a group benefits program, including but not limited to, health, dental, vision and life benefits. Health and Welfare Benefit Plans LLC administers the financial aspects of the group insurance program, receives all premium payments from the participating affiliates, and makes all vendor payments. The cost of coverage under this program was approximately $19.0 million, $25.2 million, and $23.7 million in 2023, 2022 and 2021, respectively, and is recorded in “ Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations. AES Indiana had no prepaids for coverage under this plan as of December 31, 2023 and 2022, respectively. AES files federal and state income tax returns which consolidate IPALCO and its subsidiaries, including AES Indiana. Under a tax sharing agreement with IPALCO, AES Indiana is responsible for the income taxes associated with its own taxable income and records the provision for income taxes using a separate return method. AES Indiana had a receivable balance under this agreement of $5.1 million and $6.7 million as of December 31, 2023 and 2022, respectively, which is recorded in “ Taxes receivable” on the accompanying Consolidated Balance Sheets. See Note 7, " Income Taxes " for more information. Long-term Compensation Plan During 2023, 2022 and 2021, many of AES Indiana’s non-union employees received benefits under the AES Long-term Compensation Plan, a deferred compensation program. This type of plan is a common employee retention tool used in our industry. Benefits under this plan are granted in the form of performance units payable in cash and AES restricted stock units. Restricted stock units vest ratably over a three-year period. The performance units payable in cash vest at the end of the three-year performance period and are subject to certain AES performance criteria. Total deferred compensation expense recorded during 2023, 2022 and 2021 was $0.3 million, $0.2 million and $0.2 million, respectively, and was included in “ Operating expenses - Operation and maintenance” on AES Indiana’s Consolidated Statements of Operations. The value of these benefits is being recognized over the 36 month vesting period and a portion is recorded as miscellaneous deferred credits with the remainder recorded as “ Paid in capital” on AES Indiana’s Consolidated Balance Sheets in accordance with ASC 718 “Compensation – Stock Compensation.” See also Note 8, “Benefit Plans” to the audited consolidated financial statements of AES Indiana for a description of benefits awarded to AES Indiana employees by AES under the RSP. Service Company Total costs incurred by the Service Company on behalf of AES Indiana were $73.6 million, $60.1 million and $58.2 million during 2023, 2022 and 2021, respectively. Total costs incurred by AES Indiana on behalf of the Service Company during 2023, 2022 and 2021 were $11.9 million, $10.0 million and $10.4 million, respectively, which are included as a reduction to charges from the Service Company. These costs were included in “ Operating expenses - Operation and maintenance” on AES Indiana’s Consolidated Statements of Operations. AES Indiana had a payable balance with the Service company of $25.6 million and $2.1 million as of December 31, 2023 and 2022, respectively, which is recorded in " Accounts payable " on the accompanying Consolidated Balance Sheets. Other During the year ended December 31, 2021, AES Indiana received loan repayments of $6.1 million from IPALCO. In the second quarter of 2023, AES Indiana engaged a vendor that is a related party through a competitive RFP process as part of its replacement capacity resource construction projects. AES Indiana had payments of $223.3 million to this vendor during the year ended December 31, 2023, which are included in " Other non-current assets " on the accompanying Consolidated Balance Sheets. Additionally, transactions with various other related parties were $7.4 million, $5.7 million and $4.3 million during 2023, 2022 and 2021, respectively. These expenses were primarily recorded in “ Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations.

Business Segment Information

Business Segment Information	12 Months Ended
	Dec. 31, 2023
Entity Information [Line Items]
Business Segment Information	BUSINESS SEGMENTS IPALCO manages its business through one reportable operating segment, the Utility segment. The primary segment performance measure is income / (loss) from continuing operations before income tax as management has concluded that this measure best reflects the underlying business performance of IPALCO and is the most relevant measure considered in IPALCO's internal evaluation of the financial performance of its segment. The Utility segment is comprised of AES Indiana, a vertically integrated electric utility, with all other nonutility business activities aggregated separately. See Note 1, " Overview and Summary of Significant Accounting Policies" for further information on AES Indiana. The “Other” nonutility category primarily includes the 2024 IPALCO Notes and 2030 IPALCO Notes and related interest expense, balance associated with IPALCO's interest rate hedges, cash and other immaterial balances. The accounting policies of the identified segment are consistent with those policies and procedures described in the summary of significant accounting policies. The following table provides information about IPALCO’s business segments (in thousands): 2023 2022 2021 Utility Other Total Utility Other Total Utility Other Total Revenue $ 1,649,917 $ — $ 1,649,917 $ 1,791,711 $ — $ 1,791,711 $ 1,426,132 $ — $ 1,426,132 Depreciation and amortization $ 287,863 $ — $ 287,863 $ 266,504 $ — $ 266,504 $ 256,085 $ — $ 256,085 Interest expense $ 99,051 $ 43,875 $ 142,926 $ 87,428 $ 43,804 $ 131,232 $ 84,256 $ 41,370 $ 125,626 Income/(loss) before income tax $ 115,763 $ (44,021) $ 71,742 $ 162,862 $ (44,377) $ 118,485 $ 189,548 $ (41,425) $ 148,123 Capital expenditures (1) $ 902,705 $ — $ 902,705 $ 496,510 $ — $ 496,510 $ 291,546 $ — $ 291,546 (1) Capital expenditures includes $0 thousand, $0 thousand and $36 thousand of payments for financed capital expenditures in 2023, 2022 and 2021, respectively. As of December 31, 2023 As of December 31, 2022 As of December 31, 2021 Total assets $ 6,129,581 $ 51,942 $ 6,181,523 $ 5,559,977 $ 29,237 $ 5,589,214 $ 5,222,987 $ 16,780 $ 5,239,767
Indianapolis Power And Light Company
Entity Information [Line Items]
Business Segment Information	BUSINESS SEGMENTS Operating segments are components of an enterprise that engage in business activities from which it may earn revenue and incur expenses, for which separate financial information is available, and is evaluated regularly by the chief operating decision maker in assessing performance and deciding how to allocate resources. All of AES Indiana’s current business consists of the generation, transmission, distribution and sale of electric energy, and therefore AES Indiana had only one reportable segment.

Revenue

Revenue	12 Months Ended
	Dec. 31, 2023
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer [Text Block]	REVENUE Revenue is primarily earned from retail and wholesale electricity sales and electricity transmission and distribution delivery services. Revenue is recognized upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Revenue is recorded net of any taxes assessed on and collected from customers, which are remitted to the governmental authorities. Retail revenue - AES Indiana energy sales to utility customers are based on the reading of meters at the customer’s location that occurs on a systematic basis throughout the month. AES Indiana sells electricity directly to end-users, such as homes and businesses, and bills customers directly. Retail revenue have a single performance obligation, as the promise to transfer energy and other distribution and/or transmission services are not separately identifiable from other promises in the contracts and, therefore, are not distinct. Additionally, as the performance obligation is satisfied over time as energy is delivered, and the same method is used to measure progress, the performance obligation meets the criteria to be considered a series. In exchange for the exclusive right to sell or distribute electricity in our service area, AES Indiana is subject to rate regulation by federal and state regulators. This regulation sets the framework for the prices (“tariffs”) that AES Indiana is allowed to charge customers for electric services. Since tariffs are approved by the regulator, the price that AES Indiana has the right to bill corresponds directly with the value to the customer of AES Indiana’s performance completed in each period. Therefore, revenue under these contracts is recognized using an output method measured by the MWhs delivered each month at the approved tariff. Customer payments are typically due on a monthly basis. Wholesale revenue - Power produced at the generation stations in excess of our retail load is sold into the MISO market. Such sales are made at either the day-ahead or real-time hourly market price, and these sales are classified as wholesale revenue. We sell to and purchase power from MISO, and such sales and purchases are settled and accounted for on a net hourly basis. In the MISO market, wholesale revenue is recorded at the spot price based on the quantities of MWh delivered in each hour during each month. As a member of MISO, we are obligated to declare the availability of our energy production into the wholesale energy market, but we are not obligated to commit our previously declared availability. As such, contract terms end as the energy for each day is delivered to the market in the case of the day-ahead market and for each hour in the case of the real-time market. Miscellaneous revenue - Miscellaneous revenue is mainly comprised of MISO transmission revenue and capacity revenue. MISO transmission revenue is earned when AES Indiana’s power lines are used in transmission of energy by power producers other than AES Indiana. As AES Indiana owns and operates transmission lines in central and southern Indiana, demand charges collected from network customers by MISO are allocated to the appropriate transmission owners (including AES Indiana) and recognized as transmission revenue. Capacity revenue is also included in miscellaneous revenue, and represent compensation received from MISO for making installed generation capacity available to satisfy system integrity and reliability requirements through the annual MISO capacity auction. Capacity, which is a stand-ready obligation to deliver energy when called upon by the RTO, is measured using MWs. Transmission and capacity revenue each have a single performance obligation, as they each represent a distinct service or good. Additionally, as these performance obligations are satisfied over time and the same method is used to measure progress, the performance obligations meet the criteria to be considered a series. For transmission revenue, the price that the transmission operator has the right to bill corresponds directly with the value to the customer of AES Indiana’s performance completed in each period as the price paid is the transmission operator's allocation of the tariff rate (as approved by the regulator) charged to network participants. For capacity revenue, the capacity price that clears at the auction is fixed and AES Indiana is compensated based on the cleared MWs and cleared price. AES Indiana’s revenue from contracts with customers was $1,616.5 million, $1,760.0 million and $1,389.2 million for the years ended December 31, 2023 , 2022 and 2021, respectively. The following table presents our revenue from contracts with customers and other revenue (in thousands): For the Years Ended December 31, 2023 2022 2021 Retail Revenue Retail revenue from contracts with customers: Residential $ 660,559 $ 688,487 $ 595,692 Small commercial and industrial 241,800 247,655 211,997 Large commercial and industrial 619,899 625,351 518,069 Public lighting 9,767 9,832 8,888 Other (1) 14,016 17,845 16,785 Total retail revenue from contracts with customers 1,546,041 1,589,170 1,351,431 Alternative revenue programs 30,414 29,171 35,248 Wholesale Revenue Wholesale revenue from contracts with customers 56,557 148,517 25,059 Miscellaneous Revenue Capacity revenue 8,210 11,750 734 Transmission and other revenue 5,654 10,534 11,480 Total miscellaneous revenue from contracts with customers 13,864 22,284 12,214 Other miscellaneous revenue (2) 3,041 2,569 2,180 Total Revenue $ 1,649,917 $ 1,791,711 $ 1,426,132 (1) Other retail revenue from contracts with customers includes miscellaneous charges to customers, including reconnection and late fee charges. (2) Other miscellaneous revenue includes lease and other miscellaneous revenue not accounted for under ASC 606. The balances of receivables from contracts with customers were $218.8 million and $198.3 million as of December 31, 2023 and 2022, respectively. Payment terms for all receivables from contracts with customers typically do not extend beyond 30 days, unless a customer qualifies for payment extension. The Company has elected to apply the optional disclosure exemptions under ASC 606. Therefore, the Company has not included disclosure pertaining to revenue expected to be recognized in any future year related to remaining performance obligations, as we exclude contracts with an original length of one year or less, contracts for which we recognize revenue based on the amount we have the right to invoice for services performed, and contracts with variable consideration allocated entirely to a wholly unsatisfied performance obligation when the consideration relates specifically to our efforts to satisfy the performance obligation and depicts the amount to which we expect to be entitled.
Indianapolis Power And Light Company
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer [Text Block]	Revenue is primarily earned from retail and wholesale electricity sales and electricity transmission and distribution delivery services. Revenue is recognized upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Revenue is recorded net of any taxes assessed on and collected from customers, which are remitted to the governmental authorities. Retail revenue - AES Indiana energy sales to utility customers are based on the reading of meters at the customer’s location that occurs on a systematic basis throughout the month. AES Indiana sells electricity directly to end-users, such as homes and businesses, and bills customers directly. Retail revenue have a single performance obligation, as the promise to transfer energy and other distribution and/or transmission services are not separately identifiable from other promises in the contracts and, therefore, are not distinct. Additionally, as the performance obligation is satisfied over time as energy is delivered, and the same method is used to measure progress, the performance obligation meets the criteria to be considered a series. In exchange for the exclusive right to sell or distribute electricity in our service area, AES Indiana is subject to rate regulation by federal and state regulators. This regulation sets the framework for the prices (“tariffs”) that AES Indiana is allowed to charge customers for electric services. Since tariffs are approved by the regulator, the price that AES Indiana has the right to bill corresponds directly with the value to the customer of AES Indiana’s performance completed in each period. Therefore, revenue under these contracts is recognized using an output method measured by the MWhs delivered each month at the approved tariff. Customer payments are typically due on a monthly basis. Wholesale revenue - Power produced at the generation stations in excess of our retail load is sold into the MISO market. Such sales are made at either the day-ahead or real-time hourly market price, and these sales are classified as wholesale revenue. We sell to and purchase power from MISO, and such sales and purchases are settled and accounted for on a net hourly basis. In the MISO market, wholesale revenue is recorded at the spot price based on the quantities of MWh delivered in each hour during each month. As a member of MISO, we are obligated to declare the availability of our energy production into the wholesale energy market, but we are not obligated to commit our previously declared availability. As such, contract terms end as the energy for each day is delivered to the market in the case of the day-ahead market and for each hour in the case of the real-time market. Miscellaneous revenue - Miscellaneous revenue is mainly comprised of MISO transmission revenue and capacity revenue. MISO transmission revenue is earned when AES Indiana’s power lines are used in transmission of energy by power producers other than AES Indiana. As AES Indiana owns and operates transmission lines in central and southern Indiana, demand charges collected from network customers by MISO are allocated to the appropriate transmission owners (including AES Indiana) and recognized as transmission revenue. Capacity revenue is also included in miscellaneous revenue, and represent compensation received from MISO for making installed generation capacity available to satisfy system integrity and reliability requirements through the annual MISO capacity auction. Capacity, which is a stand-ready obligation to deliver energy when called upon by the RTO, is measured using MWs. Transmission and capacity revenue each have a single performance obligation, as they each represent a distinct service or good. Additionally, as these performance obligations are satisfied over time and the same method is used to measure progress, the performance obligations meet the criteria to be considered a series. For transmission revenue, the price that the transmission operator has the right to bill corresponds directly with the value to the customer of AES Indiana’s performance completed in each period as the price paid is the transmission operator's allocation of the tariff rate (as approved by the regulator) charged to network participants. For capacity revenue, the capacity price that clears at the auction is fixed and AES Indiana is compensated based on the cleared MWs and cleared price. AES Indiana’s revenue from contracts with customers was $1,616.5 million , $1,760.0 million and $1,389.2 million for the years ended December 31, 2023 , 2022 and 2021, respectively. The following table presents AES Indiana's revenue from contracts with customers and other revenue (in thousands): For the Years Ended December 31, 2023 2022 2021 Retail Revenue Retail revenue from contracts with customers: Residential $ 660,559 $ 688,487 $ 595,692 Small commercial and industrial 241,800 247,655 211,997 Large commercial and industrial 619,899 625,351 518,069 Public lighting 9,767 9,832 8,888 Other (1) 14,016 17,845 16,785 Total retail revenue from contracts with customers 1,546,041 1,589,170 1,351,431 Alternative revenue programs 30,414 29,171 35,248 Wholesale Revenue Wholesale revenue from contracts with customers 56,557 148,517 25,059 Miscellaneous Revenue Capacity revenue 8,210 11,750 734 Transmission and other revenue 5,654 10,534 11,480 Total miscellaneous revenue from contracts with customers 13,864 22,284 12,214 Other miscellaneous revenue (2) 3,041 2,569 2,180 Total Revenue $ 1,649,917 $ 1,791,711 $ 1,426,132 (1) Other retail revenue from contracts with customers includes miscellaneous charges to customers, including reconnection and late fee charges. (2) Other miscellaneous revenue includes lease and other miscellaneous revenue not accounted for under ASC 606. The balances of receivables from contracts with customers were $218.8 million and $198.3 million as of December 31, 2023 and 2022, respectively. Payment terms for all receivables from contracts with customers typically do not extend beyond 30 days, unless a customer qualifies for payment extension. AES Indiana has elected to apply the optional disclosure exemptions under ASC 606. Therefore, AES Indiana has not included disclosure pertaining to revenue expected to be recognized in any future year related to remaining performance obligations, as we exclude contracts with an original length of one year or less, contracts for which we recognize revenue based on the amount we have the right to invoice for services performed, and contracts with variable consideration allocated entirely to a wholly unsatisfied performance obligation when the consideration relates specifically to our efforts to satisfy the performance obligation and depicts the amount to which AES Indiana expects to be entitled.

Leases

Leases	12 Months Ended
	Dec. 31, 2023
Entity Information [Line Items]
Leases	LEASES LESSEE The Company is the lessee under financing leases primarily for land. Right-of-use assets are long-term by nature. The following table summarizes the amounts recognized on the Consolidated Balance Sheets related to lease asset and liability balances as of the periods indicated (in thousands): Consolidated Balance Sheet Classification December 31, 2023 December 31, 2022 Assets Right-of-use assets — finance leases Other non-current assets $ 16,357 $ 15,819 Liabilities Finance lease liabilities (noncurrent) Long-term debt $ 17,769 $ 16,361 Total finance lease liabilities $ 17,769 $ 16,361 The following table summarizes supplemental balance sheet information related to leases as of the periods indicated: Lease Term and Discount Rate December 31, 2023 December 31, 2022 Weighted-average remaining lease term — finance leases 35 years 36 years Weighted-average discount rate — finance leases 5.30 % 5.650 % The following table summarizes the components of lease expense recognized in " Operating Costs and Expenses " on the accompanying Consolidated Statements of Operations for the years ended December 31, 2023 , 2022 and 2021, respectively (in thousands): For the Year Ended December 31, Components of Lease Cost 2023 2022 2021 Finance lease cost: Amortization of right-of-use assets $ 445 $ 542 $ — Interest on lease liabilities 933 782 — Total lease cost $ 1,378 $ 1,324 $ — Operating cash outflows from finance leases were $0.6 million, $0.3 million and $0.0 million for the years ended December 31, 2023 , 2022 and 2021, respectively. The following table shows the future lease payments under finance leases together with the present value of the net lease payments as of December 31, 2023 for 2024 through 2028 and thereafter (in thousands): Finance Leases 2024 $ 891 2025 909 2026 927 2027 945 2028 965 Thereafter 39,958 Total $ 44,595 Less: Imputed interest (26,826) Present value of lease payments $ 17,769 LESSOR The Company is the lessor under operating leases for land, office space and operating equipment. Lease receipts from such contracts are recognized as operating lease revenue on a straight-line basis over the lease term whereas contingent rentals are recognized when earned. The following table presents lease revenue from operating leases in which the Company is the lessor for the periods indicated (in thousands): For the Year Ended December 31, 2023 2022 2021 Total lease revenue $ 1,537 $ 1,134 $ 1,439 The following table presents the underlying gross assets and accumulated depreciation of operating leases included in Property, plant and equipment, net for the periods indicated (in thousands): Property, Plant and Equipment, Net December 31, 2023 December 31, 2022 Gross assets $ 4,341 $ 4,334 Less: Accumulated depreciation (1,222) (1,060) Net assets $ 3,119 $ 3,274 The option to extend or terminate a lease is based on customary early termination provisions in the contract. The following table shows the future minimum lease receipts through 2028 and thereafter (in thousands): Operating Leases 2024 $ 544 2025 553 2026 554 2027 554 2028 354 Thereafter 891 Total $ 3,450
Future Minimum Lease Receipts	The following table shows the future minimum lease receipts through 2028 and thereafter (in thousands): Operating Leases 2024 $ 544 2025 553 2026 554 2027 554 2028 354 Thereafter 891 Total $ 3,450
Subsidiaries [Member]
Entity Information [Line Items]
Leases	LEASES LESSEE The Company is the lessee under financing leases primarily for land. Right-of-use assets are long-term by nature. The following table summarizes the amounts recognized on the Consolidated Balance Sheets related to lease asset and liability balances as of the periods indicated (in thousands): Consolidated Balance Sheet Classification December 31, 2023 December 31, 2022 Assets Right-of-use assets — finance leases Other non-current assets $ 16,357 $ 15,819 Liabilities Finance lease liabilities (noncurrent) Long-term debt $ 17,769 $ 16,361 Total finance lease liabilities $ 17,769 $ 16,361 The following table summarizes supplemental balance sheet information related to leases as of the periods indicated: Lease Term and Discount Rate December 31, 2023 December 31, 2022 Weighted-average remaining lease term — finance leases 35 years 36 years Weighted-average discount rate — finance leases 5.30% 5.650% The following table summarizes the components of lease expense recognized in " Operating Costs and Expenses " on the accompanying Consolidated Statements of Operations for the years ended December 31, 2023 , 2022 and 2021, respectively (in thousands): For the Year Ended December 31, Components of Lease Cost 2023 2022 2021 Finance lease cost: Amortization of right- of-use assets $ 445 $ 542 $ — Interest on lease liabilities 933 782 — Total lease cost $ 1,378 $ 1,324 $ — Operating cash outflows from finance leases were $0.6 million, $0.3 million and $0.0 million for the years ended December 31, 2023 , 2022 and 2021, respectively. The following table shows the future lease payments under finance leases together with the present value of the net lease payments as of December 31, 2023 for 2024 through 2028 and thereafter (in thousands): Finance Leases 2024 $ 891 2025 909 2026 927 2027 945 2028 965 Thereafter 39,958 Total $ 44,595 Less: Imputed interest (26,826) Present value of lease payments $ 17,769 LESSOR The Company is the lessor under operating leases for land, office space and operating equipment. Lease receipts from such contracts are recognized as operating lease revenue on a straight-line basis over the lease term whereas contingent rentals are recognized when earned. The following table presents lease revenue from operating leases in which the Company is the lessor for the periods indicated (in thousands): For the Year Ended December 31, 2023 2022 2021 Total lease revenue $ 1,537 $ 1,134 $ 1,439 The following table presents the underlying gross assets and accumulated depreciation of operating leases included in Property, plant and equipment, net for the periods indicated (in thousands): Property, Plant and Equipment, Net December 31, 2023 December 31, 2022 Gross assets $ 4,341 $ 4,334 Less: Accumulated depreciation (1,222) (1,060) Net assets $ 3,119 $ 3,274 The option to extend or terminate a lease is based on customary early termination provisions in the contract. The following table shows the future minimum lease receipts through 2028 and thereafter (in thousands): Operating Leases 2024 $ 544 2025 553 2026 554 2027 554 2028 354 Thereafter 891 Total $ 3,450
Future Minimum Lease Receipts	The following table shows the future minimum lease receipts through 2028 and thereafter (in thousands): Operating Leases 2024 $ 544 2025 553 2026 554 2027 554 2028 354 Thereafter 891 Total $ 3,450

Schedule I - Condensed Financia

Schedule I - Condensed Financial Information Of Registrant	12 Months Ended
	Dec. 31, 2023
Condensed Financial Information Disclosure [Abstract]
Schedule I - Condensed Financial Information Of Registrant	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. The fair value of current financial assets and liabilities approximate their reported carrying amounts. The estimated fair values of the Company’s assets and liabilities have been determined using available market information. Because these amounts are estimates and based on hypothetical transactions to sell assets or transfer liabilities, the use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts. Fair Value Hierarchy and Valuation Techniques ASC 820 defined and established a framework for measuring fair value and expands disclosures about fair value measurements for financial assets and liabilities that are adjusted to fair value on a recurring basis and/or financial assets and liabilities that are measured at fair value on a nonrecurring basis, which have been adjusted to fair value during the period. In accordance with ASC 820, we have categorized our financial assets and liabilities that are adjusted to fair value, based on the priority of the inputs to the valuation technique, following the three-level fair value hierarchy prescribed by ASC 820 as follows: Level 1 - unadjusted quoted prices for identical assets or liabilities in an active market; Level 2 - inputs from quoted prices in markets where trading occurs infrequently or quoted prices of instruments with similar attributes in active markets; and Level 3 - unobservable inputs reflecting management’s own assumptions about the inputs used in pricing the asset or liability. Whenever possible, quoted prices in active markets are used to determine the fair value of our financial instruments. Our financial instruments are not held for trading or other speculative purposes. The estimated fair value of financial instruments has been determined by using available market information and appropriate valuation methodologies. However, considerable judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we could realize in a current market exchange. The use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts. Financial Assets VEBA Assets IPALCO has VEBA investments that are to be used to fund certain employee postretirement health care benefit plans. These assets are primarily comprised of open-ended mutual funds, which are valued using the net assets value per unit. These investments are recorded at fair value within " Other non-current assets " on the accompanying Unconsolidated Balance Sheets and classified as equity securities. All changes to fair value on the VEBA investments are included in income in the period that the changes occur. These changes to fair value were not material for the years ended December 31, 2023, 2022, or 2021. Any unrealized gains or losses are recorded in " Other income / (expense), net " on the accompanying Unconsolidated Statements of Operations. Financial Assets Interest Rate Hedges IPALCO's interest rate hedges have a combined notional amount of $400.0 million. All changes in the market value of the interest rate hedges are recorded in AOCI. See also Note 3, " Derivative Instruments and Hedging Activities - Cash Flow Hedges " for further information. Summary The fair value of assets at December 31, 2023 and 2022 measured on a recurring basis and the respective category within the fair value hierarchy for IPALCO was determined as follows: Fair Value as of December 31, 2023 Fair Value as of December 31, 2022 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total (In Thousands) Financial assets: VEBA investments: Money market funds $ 127 $ — $ — $ 127 $ 5 $ — $ — $ 5 Mutual funds 3,425 — — 3,425 3,223 — — 3,223 Total VEBA investments 3,552 — — 3,552 3,228 — — 3,228 Interest rate hedges — 14,294 — 14,294 — 12,172 — 12,172 Total financial assets measured at fair value $ 3,552 $ 14,294 $ — $ 17,846 $ 3,228 $ 12,172 $ — $ 15,400 Financial Instruments not Measured at Fair Value in the Unconsolidated Balance Sheets Debt The fair value of our outstanding fixed-rate debt has been determined on the basis of the quoted market prices of the specific securities issued and outstanding. In certain circumstances, the market for such securities was inactive and therefore the valuation was adjusted to consider changes in market spreads for similar securities. Accordingly, the purpose of this disclosure is not to approximate the value on the basis of how the debt might be refinanced. The following table shows the face value and the fair value of fixed-rate indebtedness (Level 2) for the periods ending: December 31, 2023 December 31, 2022 Face Value Fair Value Face Value Fair Value (In Thousands) Fixed-rate $ 880,000 $ 839,471 $ 880,000 $ 816,411 Total indebtedness $ 880,000 $ 839,471 $ 880,000 $ 816,411 The difference between the face value and the carrying value of this indebtedness represents the following: • unamortized deferred financing costs of $4.6 million and $5.9 million at December 31, 2023 and 2022, respectively; and • unamortized discounts of $0.3 million and $0.4 million at December 31, 2023 and 2022, respectively. 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 Sales Net Notional Interest rate hedges Designated USD $ 400,000 $ — $ 400,000 (a) Refers to whether the derivative instruments have been designated as a cash flow hedge. Cash Flow Hedges As part of our risk management processes, we identify the relationships between hedging instruments and hedged items, as well as the risk management objective and strategy for undertaking various hedge transactions. The fair values of cash flow hedges determined by current public market prices will continue to fluctuate with changes in market prices up to contract expiration. The change in the fair value of a hedging instrument is recorded in other comprehensive income and amounts deferred are reclassified to earnings in the same income statement line as the hedged item in the period in which it settles. In March 2019, we entered into three forward interest rate swaps to hedge the interest risk associated with refinancing the IPALCO 2020 maturities. The three interest rate swaps had a combined notional amount of $400.0 million. In April 2020, we de-designated the swaps as cash flow hedges and froze the AOCL of $72.3 million at the date of de-designation. The interest rate swaps were then amended and re-designated as cash flow hedges to hedge the interest rate risk associated with refinancing the 2024 IPALCO Notes. The amended interest rate swaps have a combined notional amount of $400.0 million and will be settled when the 2024 IPALCO Notes are refinanced. The $72.3 million of AOCL associated with the interest rate swaps through the date of the amendment will be amortized out of AOCL into interest expense over the remaining life of the 2030 IPALCO Notes, while any changes in fair value associated with the amended interest rate swaps will be recognized in AOCL going forward. The following tables provide information on gains or losses recognized in AOCL for the cash flow hedges for the period indicated: Interest Rate Hedges for the Year Ended December 31, $ in thousands (net of tax) 2023 2022 2021 Beginning accumulated derivative gain / (loss) in AOCL $ 22,269 $ (29,407) $ (43,420) Net gains associated with current period hedging transactions 1,594 46,245 10,393 Net losses reclassified to interest expense 5,431 5,431 3,620 Ending accumulated derivative gain / (loss) in AOCI / (AOCL) $ 29,294 $ 22,269 $ (29,407) Loss expected to be reclassified to earnings in the next twelve months $ (5,375) Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months) 9 When applicable, IPALCO has elected not to offset derivative assets and liabilities and not to offset net derivative positions against the right to reclaim cash collateral pledged (an asset) or the obligation to return cash collateral received (a liability) under derivative agreements. As of December 31, 2023 and 2022, IPALCO did not have any offsetting positions. The following table summarizes the fair value, balance sheet classification and hedging designation of IPALCO's derivative instruments: December 31, Commodity Hedging Designation Balance sheet classification 2023 2022 Interest rate hedges Cash Flow Hedge Derivative assets, current $ 14,294 $ — Interest rate hedges Cash Flow Hedge Derivative assets, non-current $ — $ 12,172 The following table presents IPALCO’s long-term indebtedness: December 31, Series Due 2023 2022 (In Thousands) Long-Term Debt 3.70% Senior Secured Notes September 2024 405,000 405,000 4.25% Senior Secured Notes May 2030 475,000 475,000 Unamortized discount – net (319) (425) Deferred financing costs – net (4,554) (5,912) Total long-term debt 875,127 873,663 Less: current portion of long-term debt 405,000 — Net long-term debt $ 470,127 $ 873,663 IPALCO’s Senior Secured Notes and Term Loan The 2024 IPALCO Notes are due September 1, 2024. Although current liquid funds are not sufficient to repay the collective amounts due under the 2024 IPALCO Notes at maturity, the Company believes it will be able to refinance the 2024 IPALCO Notes based on conversations with investment bankers, which currently indicate more than adequate demand for new IPALCO debt at its current credit ratings, and considering the Company's previous successful debt issuances. Pursuant to a registration rights agreement dated April 14, 2020, IPALCO agreed to register the 2030 IPALCO Notes under the Securities Act by filing an exchange offer registration statement or, under specified circumstances, a shelf registration statement with the SEC. IPALCO filed a registration statement on Form S-4 with respect to the 2030 IPALCO Notes with the SEC on March 22, 2021 in respect of its obligations under such registration rights agreement, and this registration statement was declared effective on April 7, 2021. The exchange offer closed on May 11, 2021.

Schedule II - Valuation And Qua

Schedule II - Valuation And Qualifying Accounts And Reserves	12 Months Ended
	Dec. 31, 2023
SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract]
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 Charged to Charged to Other Net Balance at Year ended December 31, 2023 Accumulated Provisions Deducted from Assets – Doubtful Accounts $ 1,117 $ 8,930 $ — $ 7,764 $ 2,283 Deducted from Inventories Valuation Allowance for Materials and Supplies $ 5,160 $ 736 $ — $ 2,456 $ 3,440 Year ended December 31, 2022 Accumulated Provisions Deducted from Assets – Doubtful Accounts $ 647 $ 7,478 $ — $ 7,008 $ 1,117 Deducted from Inventories Valuation Allowance for Materials and Supplies $ 3,107 $ 2,053 $ — $ — $ 5,160 Year ended December 31, 2021 Accumulated Provisions Deducted from Assets – Doubtful Accounts $ 3,155 $ 3,940 $ — $ 6,448 $ 647 Deducted from Inventories Valuation Allowance for Materials and Supplies $ 6,133 $ 758 $ — $ 3,784 $ 3,107 AES INDIANA and SUBSIDIARIES Valuation and Qualifying Accounts and Reserves For the Years Ended December 31, 2023, 2022 and 2021 (In Thousands) Column A – Description Column B Column C – Additions Column D – Deductions Column E Balance at Beginning Charged to Charged to Other Net Balance at Year ended December 31, 2023 Accumulated Provisions Deducted from Assets – Doubtful Accounts $ 1,117 $ 8,930 $ — $ 7,764 $ 2,283 Deducted from Inventories Valuation Allowance for Materials and Supplies $ 5,160 $ 736 $ — $ 2,456 $ 3,440 Year ended December 31, 2022 Accumulated Provisions Deducted from Assets – Doubtful Accounts $ 647 $ 7,478 $ — $ 7,008 $ 1,117 Deducted from Inventories Valuation Allowance for Materials and Supplies $ 3,107 $ 2,053 $ — $ — $ 5,160 Year ended December 31, 2021 Accumulated Provisions Deducted from Assets – Doubtful Accounts $ 3,155 $ 3,940 $ — $ 6,448 $ 647 Deducted from Inventories Valuation Allowance for Materials and Supplies $ 6,133 $ 758 $ — $ 3,784 $ 3,107

Overview and Summary of Signi_2

Overview and Summary of Significant Accounting Policies (Policy)	12 Months Ended
	Dec. 31, 2023
Entity Information [Line Items]
Property, Plant and Equipment, Policy [Policy Text Block]	Property, Plant and Equipment Property, plant and equipment is stated at original cost as defined for regulatory purposes. The cost of additions to property, plant and equipment and replacements of retirement units of property are charged to plant accounts. Units of property replaced or abandoned in the ordinary course of business are retired from the plant accounts at cost; such amounts, less salvage, are charged to accumulated depreciation. Depreciation is computed by the straight-line method based on functional rates approved by the IURC and averaged 3.7%, 3.8% and 3.7% during 2023, 2022 and 2021, respectively. Depreciation expense was $244.8 million, $247.5 million, and $239.1 million for the years ended December 31, 2023, 2022 and 2021, respectively. "Depreciation and amortization" expense on the accompanying Consolidated Statements of Operations is presented net of regulatory deferrals of depreciation expense and also includes amortization of intangible assets and amortization of previously deferred regulatory costs.
Schedule of Accounts, Notes, Loans and Financing Receivable [Table Text Block]	The following table summarizes our accounts receivable balances at December 31: As of December 31, 2023 2022 (In Thousands) Accounts receivable, net Customer receivables $ 125,715 $ 125,540 Unbilled revenue 91,463 74,488 Amounts due from related parties 5,178 239 Other 13,848 17,373 Allowance for credit losses (2,283) (1,117) Total accounts receivable, net $ 233,921 $ 216,523
Inventory, Policy [Policy Text Block]	Inventories We maintain coal, fuel oil, natural gas, materials and supplies inventories for use in the production of electricity. These inventories are accounted for at the lower of cost or net realizable value, using the average cost. The following table summarizes our inventories balances at December 31: As of December 31, 2023 2022 (In Thousands) Inventories Fuel $ 77,198 $ 60,497 Materials and supplies, net 66,392 63,111 Total inventories $ 143,590 $ 123,608
Intangible Assets, Finite-Lived, Policy [Policy Text Block]	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 8 $ 261,872 $ 205,910 Project development intangible assets 28 84,097 39,455 Other Various 797 797 Less: Accumulated amortization (111,110) (107,184) Intangible assets - net $ 235,656 $ 138,978 For the Years Ended December 31, 2023 2022 2021 Amortization expense $ 14,570 $ 10,122 $ 11,241 Estimated future amortization Years ending December 31, 2024 $ 20,764 2025 20,764 2026 22,550 2027 22,550 2028 22,550 Total $ 109,178
Principles of Consolidation	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	Use of Management Estimates The preparation of financial statements in conformity with GAAP requires that management make certain estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements. The reported amounts of revenue and expenses during the reporting period may also be affected by the estimates and assumptions management is required to make. Actual results may differ from those estimates. Significant items subject to such estimates and assumptions include: recognition of revenue including unbilled revenue; the carrying value of property, plant and equipment; the valuation of insurance and claims liabilities; the valuation of allowances for credit losses and deferred income taxes; regulatory assets and liabilities; liabilities recorded for income tax exposures; litigation; contingencies; and assets and liabilities related to AROs and employee benefits.
Cash and Cash Equivalents, Restricted Cash and Cash Equivalents, Policy [Policy Text Block]	Cash and Cash Equivalents Cash and cash equivalents are stated at cost, which approximates fair value. All highly liquid short-term investments with original maturities of three months or less are considered cash equivalents. Restricted Cash Restricted cash includes cash which is restricted as to withdrawal or usage. The nature of the restrictions includes restrictions imposed by agreements related to deposits held as collateral. The following table provides a summary of cash, cash equivalents, and restricted cash amounts reported within the Consolidated Balance Sheets that reconcile to the total of such amounts as shown on the Consolidated Statements of Cash Flows: As of December 31, 2023 2022 (In Thousands) Cash, cash equivalents and restricted cash Cash and cash equivalents $ 28,579 $ 201,548 Restricted cash (included in Prepayments and other current assets) 5 5 Total cash, cash equivalents and restricted cash $ 28,584 $ 201,553
Revenues and Accounts Receivable	Accounts Receivable and Allowance for Credit Losses The following table summarizes our accounts receivable balances at December 31: As of December 31, 2023 2022 (In Thousands) Accounts receivable, net Customer receivables $ 125,715 $ 125,540 Unbilled revenue 91,463 74,488 Amounts due from related parties 5,178 239 Other 13,848 17,373 Allowance for credit losses (2,283) (1,117) Total accounts receivable, net $ 233,921 $ 216,523
Contingencies	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.
Concentration of Risk	Concentrations of Risk Substantially all of AES Indiana’s customers are located within the Indianapolis area. Approximately 68% of AES Indiana’s employees are covered by collective bargaining agreements in two bargaining units: a physical unit and a clerical-technical unit. AES Indiana’s contract with the physical unit expires on December 4, 2024, and the contract with the clerical-technical unit expires February 12, 2026. Additionally, AES Indiana has long-term coal contracts with one supplier, and substantially all of AES Indiana's coal is currently mined in the state of Indiana.
Allowance For Funds Used During Construction	AFUDC In accordance with the Uniform System of Accounts prescribed by FERC, AES Indiana capitalizes an allowance for the net cost of funds (interest on borrowed funds and a reasonable rate of return on equity funds) used for construction purposes during the period of construction with a corresponding credit to income. AES Indiana capitalized amounts using pretax composite rates of 7.1%, 5.4% and 5.7% during 2023, 2022 and 2021, respectively. AFUDC equity and AFUDC debt were as follows for the years ended December 31, 2023, 2022 and 2021: 2023 2022 2021 (In Thousands) AFUDC equity $ 9,315 $ 4,784 $ 5,412 AFUDC debt $ 13,739 $ 8,215 $ 4,815
Derivatives	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”
Impairment of Long-Lived Assets	Impairment of Long-lived Assets GAAP requires that we test long-lived assets for impairment when indicators of impairment exist. If an asset is deemed to be impaired, we are required to write down the asset to its fair value with a charge to current earnings. The net book value of our property, plant, and equipment was $4.5 billion and $4.0 billion as of December 31, 2023 and 2022, respectively. As of December 31, 2023 and 2022, AES Indiana had $259.9 million and $287.5 million, respectively, of long-term regulatory assets associated with Petersburg Unit 1 and 2 retirement costs (for further discussion, see Note 2, “Regulatory Matters - IRP Filings and Replacement Generation” and Note 3 , "Property, Plant and Equipment" ) . We do not believe any of these assets are currently impaired. In making this assessment, we consider such factors as: the overall condition and generating and distribution capacity of the assets; the expected ability to recover additional expenditures in the assets; the anticipated demand and relative pricing of retail electricity in our service territory and wholesale electricity in the region; and the cost of fuel.
Income Taxes	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 Repair and maintenance costs are expensed as incurred.
Per Share Data	Per Share Data IPALCO is owned by AES U.S. Investments and CDPQ. IPALCO does not report earnings on a per-share basis.
Lessee, Leases	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.
Pension and Other Postretirement Plans, Pensions, Policy	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.
Revenue Recognition, Revenue Reductions	Revenue Recognition Revenue related to the sale of energy is generally recognized when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to certain customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is accrued. In making its estimates of unbilled revenue, AES Indiana uses models that consider various factors including daily generation volumes; known amounts of energy usage by nearly all residential, commercial and industrial customers; and estimated customer rates based on prior period billings. Given the use of these models, and that customers are billed on a monthly cycle, we believe it is unlikely that materially different results will occur in future periods when revenue is billed. An allowance for potential credit losses is maintained and amounts are written off when normal collection efforts have been exhausted. Our provision for expected credit losses included in “Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations was $7.5 million, $5.9 million and $3.0 million for the years ended December 31, 2023, 2022 and 2021, respectively. AES Indiana’s basic rates include a provision for fuel costs as established in AES Indiana’s most recent rate proceeding, which last adjusted AES Indiana’s rates in December 2018. AES Indiana is permitted to recover actual costs of purchased power and fuel consumed, subject to certain restrictions. This is accomplished through quarterly FAC proceedings, in which AES Indiana estimates the amount of fuel and purchased power costs in future periods. Through these proceedings, AES Indiana is also permitted to recover, in future rates, underestimated fuel and purchased power costs from prior periods, subject to certain restrictions, and therefore the over or underestimated costs are deferred or accrued and amortized into fuel expense in the same period that AES Indiana’s rates are adjusted. See also Note 2, “ Regulatory Matters ” for a discussion of other costs that AES Indiana is permitted to recover through periodic rate adjustment proceedings and the status of current rate adjustment proceedings. In addition, we are one of many transmission system owner members of MISO, a RTO which maintains functional control over the combined transmission systems of its members and manages one of the largest energy markets in the U.S. See Note 13, " Revenue " for additional information of MISO sales and other revenue streams.
Credit Loss, Financial Instrument	The following table is a rollforward of our allowance for credit losses related to the accounts receivable balances for the periods indicated: For the Years Ended December 31, 2023 2022 (In Thousands) Allowance for credit losses: Beginning balance $ 1,117 $ 647 Current period provision 7,413 5,851 Write-offs charged against allowance (7,764) (7,008) Recoveries collected 1,517 1,627 Ending Balance $ 2,283 $ 1,117 The allowance for credit losses primarily relates to utility customer receivables, including unbilled amounts. Expected credit loss estimates are developed by disaggregating customers into those with similar credit risk
Indianapolis Power And Light Company
Entity Information [Line Items]
Property, Plant and Equipment, Policy [Policy Text Block]	Property, Plant and Equipment Property, plant and equipment is stated at original cost as defined for regulatory purposes. The cost of additions to property, plant and equipment and replacements of retirement units of property are charged to plant accounts. Units of property replaced or abandoned in the ordinary course of business are retired from the plant accounts at cost; such amounts, less salvage, are charged to accumulated depreciation. Depreciation is computed by the straight-line method based on functional rates approved by the IURC and averaged 3.7%, 3.8% and 3.7% during 2023, 2022 and 2021, respectively. Depreciation expense was $244.8 million, $247.5 million, and $239.1 million for the years ended December 31, 2023, 2022 and 2021, respectively. "Depreciation and amortization" expense on the accompanying Consolidated Statements of Operations is presented net of regulatory deferrals of depreciation expense and also includes amortization of intangible assets and amortization of previously deferred regulatory costs.
Schedule of Accounts, Notes, Loans and Financing Receivable [Table Text Block]	The following table summarizes our accounts receivable balances at December 31: As of December 31, 2023 2022 (In Thousands) Accounts receivable, net Customer receivables $ 125,715 $ 125,540 Unbilled revenue 91,463 74,488 Amounts due from related parties 5,227 288 Other 13,848 17,373 Allowance for credit losses (2,283) (1,117) Total accounts receivable, net $ 233,970 $ 216,572
Intangible Assets, Finite-Lived, Policy [Policy Text Block]	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 8 $ 261,872 $ 205,910 Project development intangible assets 28 84,097 39,455 Other Various 797 797 Less: Accumulated amortization (111,110) (107,184) Intangible assets - net $ 235,656 $ 138,978 For the Years Ended December 31, 2023 2022 2021 Amortization expense $ 14,570 $ 10,122 $ 11,241 Estimated future amortization Years ending December 31, 2024 $ 20,764 2025 20,764 2026 22,550 2027 22,550 2028 22,550 Total $ 109,178
Principles of Consolidation	Principles of Consolidation AES Indiana’s consolidated financial statements are prepared in accordance with GAAP and in conjunction with the rules and regulations of the SEC. The consolidated financial statements include the accounts of AES Indiana and its wholly owned subsidiaries . Furthermore, VIEs in which the Company has an ownership interest and is the primary beneficiary, thus controlling the VIE, as described below, have been consolidated. All intercompany items have been eliminated in consolidation. Certain costs for shared resources amongst AES Indiana and IPALCO, such as labor and benefits, are allocated to each entity based on allocation methodologies that management believes to be reasonable. We have evaluated subsequent events through the date this report is issued. If AES Indiana enters into transactions impacting equity interests in its affiliates, AES Indiana must determine whether the transaction impacts the Company's consolidation conclusion by first determining whether the transaction should be evaluated under the variable interest model or the voting model. In determining which consolidation model applies to the transaction, AES Indiana is required to make judgments about how the entity operates, the most significant of which are whether (i) the entity has sufficient equity to finance its activities, (ii) the equity holders, as a group, have the characteristics of a controlling financial interest, and (iii) whether the entity has non-substantive voting rights. If the entity is determined to be a variable interest entity and AES Indiana is determined to have power and benefits, the entity will be consolidated by AES Indiana. Noncontrolling Interests Noncontrolling interests are classified as a separate component of equity in the Consolidated Balance Sheets and Consolidated Statements of Changes in Equity. Additionally, net income attributable to noncontrolling interests is reflected separately from consolidated net income on the Consolidated Statements of Operations. Any change in ownership of a subsidiary while the controlling financial interest is retained is accounted for as an equity transaction between the controlling and noncontrolling interests. Losses continue to be attributed to the noncontrolling interests, even when the noncontrolling interests' basis has been reduced to zero. Allocation of Earnings Hardy Hills JV is subject to profit-sharing arrangements where the allocation of earnings, cash distributions, and tax benefits are not based on fixed ownership percentages. This arrangement exists to designate different allocations of value among the investors, where the allocations change in form or percentage over the life of the partnership. AES Indiana uses the HLBV method when it is a reasonable approximation of the profit-sharing arrangement. The HLBV method calculates the proceeds that would be attributable to each partner based on the liquidation provisions of the respective operating partnership agreement if the partnership was to be liquidated at book value at the balance sheet date. Each partner’s share of income in the period is equal to the change in the amount of net equity they are legally able to claim based on a hypothetical liquidation of the entity at the end of a reporting period compared to the beginning of that period, adjusted for any capital transactions (for further discussion about the Equity Capital Contribution Agreement, see Note 2, " Regulatory Matters - IRP Filings and Replacement Generation "). The HLBV method is used to calculate the earnings attributable to noncontrolling interest when the business is consolidated by AES Indiana. In the early months of operations of a renewable generation facility where HLBV results in a significant decrease in the hypothetical liquidation proceeds attributable to the tax equity investor due to the recognition of investment tax credits ("ITCs") or other adjustments as required by the U.S. Internal Revenue Code, the Company records the impact (sometimes referred to as the ‘Day one gain’) to income in the same period.
Use of Management Estimates	Use of Management Estimates The preparation of financial statements in conformity with GAAP requires that management make certain estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements. The reported amounts of revenue and expenses during the reporting period may also be affected by the estimates and assumptions management is required to make. Actual results may differ from those estimates. Significant items subject to such estimates and assumptions include: recognition of revenue including unbilled revenue; the carrying value of property, plant and equipment; the valuation of insurance and claims liabilities; the valuation of allowances for credit losses and deferred income taxes; regulatory assets and liabilities; liabilities recorded for income tax exposures; litigation; contingencies; and assets and liabilities related to AROs and employee benefits.
Cash and Cash Equivalents, Restricted Cash and Cash Equivalents, Policy [Policy Text Block]	Cash and Cash Equivalents Cash and cash equivalents are stated at cost, which approximates fair value. All highly liquid short-term investments with original maturities of three months or less are considered cash equivalents. Restricted Cash Restricted cash includes cash which is restricted as to withdrawal or usage. The nature of the restrictions includes restrictions imposed by agreements related to deposits held as collateral. The following table provides a summary of cash, cash equivalents, and restricted cash amounts reported within the Consolidated Balance Sheets that reconcile to the total of such amounts as shown on the Consolidated Statements of Cash Flows: As of December 31, 2023 2022 (In Thousands) Cash, cash equivalents and restricted cash Cash and cash equivalents $ 25,767 $ 199,103 Restricted cash (included in Prepayments and other current assets) 5 5 Total cash, cash equivalents and restricted cash $ 25,772 $ 199,108
Revenues and Accounts Receivable	Accounts Receivable and Allowance for Credit Losses The following table summarizes our accounts receivable balances at December 31: As of December 31, 2023 2022 (In Thousands) Accounts receivable, net Customer receivables $ 125,715 $ 125,540 Unbilled revenue 91,463 74,488 Amounts due from related parties 5,227 288 Other 13,848 17,373 Allowance for credit losses (2,283) (1,117) Total accounts receivable, net $ 233,970 $ 216,572
Contingencies	Contingencies AES Indiana accrues for loss contingencies when the amount of the loss is probable and estimable. AES Indiana is subject to various environmental regulations and is involved in certain legal proceedings. If AES Indiana’s actual environmental and/or legal obligations are different from our estimates, the recognition of the actual amounts may have a material impact on our results of operations, financial condition and cash flows; although that has not been the case during the periods covered by this report. Accruals for loss contingencies were not material as of December 31, 2023 and 2022. See Note 10, " Commitments and Contingencies - Contingencies " for additional information.
Concentration of Risk	Concentrations of Risk Substantially all of AES Indiana’s customers are located within the Indianapolis area. Approximately 68% of AES Indiana’s employees are covered by collective bargaining agreements in two bargaining units: a physical unit and a clerical-technical unit. AES Indiana’s contract with the physical unit expires on December 4, 2024, and the contract with the clerical-technical unit expires February 12, 2026. Additionally, AES Indiana has long-term coal contracts with one supplier, and substantially all of AES Indiana's coal is currently mined in the state of Indiana.
Allowance For Funds Used During Construction	AFUDC In accordance with the Uniform System of Accounts prescribed by FERC, AES Indiana capitalizes an allowance for the net cost of funds (interest on borrowed funds and a reasonable rate of return on equity funds) used for construction purposes during the period of construction with a corresponding credit to income. AES Indiana capitalized amounts using pretax composite rates of 7.1%, 5.4% and 5.7% during 2023, 2022 and 2021, respectively. AFUDC equity and AFUDC debt were as follows for the years ended December 31, 2023, 2022 and 2021: 2023 2022 2021 (In Thousands) AFUDC equity $ 9,315 $ 4,784 $ 5,412 AFUDC debt $ 13,739 $ 8,215 $ 4,815
Derivatives	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.
Impairment of Long-Lived Assets	Impairment of Long-lived Assets GAAP requires that AES Indiana test long-lived assets for impairment when indicators of impairment exist. If an asset is deemed to be impaired, AES Indiana is required to write down the asset to its fair value with a charge to current earnings. The net book value of AES Indiana’s property, plant, and equipment was $4.5 billion and $4.0 billion as of December 31, 2023 and 2022, respectively. As of December 31, 2023 and 2022, AES Indiana had $259.9 million and $287.5 million, respectively, of long-term regulatory assets associated with Petersburg Unit 1 and 2 retirement costs (for further discussion, see Note 2, “Regulatory Matters - IRP Filings and Replacement Generation” and Note 3 , "Property, Plant and Equipment" ). AES Indiana does not believe any of these assets are currently impaired. In making this assessment, AES Indiana considers such factors as: the overall condition and generating and distribution capacity of the assets; the expected ability to recover additional expenditures in the assets; the anticipated demand and relative pricing of retail electricity in its service territory and wholesale electricity in the region; and the cost of fuel.
Pension and Postretirement Benefits	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.
Repair and Maintenance Costs	Repair and Maintenance Costs Repair and maintenance costs are expensed as incurred.
Per Share Data	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.

Overview and Summary of Signi_3

Overview and Summary of Significant Accounting Policies Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2023
Entity Information [Line Items]
Schedule of Utility Inventory [Table Text Block]	The following table summarizes our inventories balances at December 31: As of December 31, 2023 2022 (In Thousands) Inventories Fuel $ 77,198 $ 60,497 Materials and supplies, net 66,392 63,111 Total inventories $ 143,590 $ 123,608
Schedule of Accounts, Notes, Loans and Financing Receivable [Table Text Block]	The following table summarizes our accounts receivable balances at December 31: As of December 31, 2023 2022 (In Thousands) Accounts receivable, net Customer receivables $ 125,715 $ 125,540 Unbilled revenue 91,463 74,488 Amounts due from related parties 5,178 239 Other 13,848 17,373 Allowance for credit losses (2,283) (1,117) Total accounts receivable, net $ 233,921 $ 216,523
Schedule of Cash and Cash Equivalents [Table Text Block]	The following table provides a summary of cash, cash equivalents, and restricted cash amounts reported within the Consolidated Balance Sheets that reconcile to the total of such amounts as shown on the Consolidated Statements of Cash Flows: As of December 31, 2023 2022 (In Thousands) Cash, cash equivalents and restricted cash Cash and cash equivalents $ 28,579 $ 201,548 Restricted cash (included in Prepayments and other current assets) 5 5 Total cash, cash equivalents and restricted cash $ 28,584 $ 201,553
Reclassification out of Accumulated Other Comprehensive Income	The amounts reclassified out of AOCI / (AOCL) by component during the years ended December 31, 2023, 2022 and 2021 are as follows (in thousands): Details about AOCI / (AOCL) components Affected line item in the Consolidated Statements of Operations For the Years Ended December 31, 2023 2022 2021 Net losses on cash flow hedges (Note 5): Interest expense $ 7,229 $ 7,229 $ 4,819 Income tax effect (1,798) (1,798) (1,199) Total reclassifications for the period, net of income taxes $ 5,431 $ 5,431 $ 3,620
Indianapolis Power And Light Company
Entity Information [Line Items]
Schedule of Utility Inventory [Table Text Block]	The following table summarizes our inventories balances at December 31: As of December 31, 2023 2022 (In Thousands) Inventories Fuel $ 77,198 $ 60,497 Materials and supplies, net 66,392 63,111 Total inventories $ 143,590 $ 123,608
Schedule of Accounts, Notes, Loans and Financing Receivable [Table Text Block]	The following table summarizes our accounts receivable balances at December 31: As of December 31, 2023 2022 (In Thousands) Accounts receivable, net Customer receivables $ 125,715 $ 125,540 Unbilled revenue 91,463 74,488 Amounts due from related parties 5,227 288 Other 13,848 17,373 Allowance for credit losses (2,283) (1,117) Total accounts receivable, net $ 233,970 $ 216,572
Schedule of Cash and Cash Equivalents [Table Text Block]	As of December 31, 2023 2022 (In Thousands) Cash, cash equivalents and restricted cash Cash and cash equivalents $ 25,767 $ 199,103 Restricted cash (included in Prepayments and other current assets) 5 5 Total cash, cash equivalents and restricted cash $ 25,772 $ 199,108
Allowance for Credit Losses	The following table is a rollforward of our allowance for credit losses related to the accounts receivable balances for the periods indicated: For the Years Ended December 31, 2023 2022 (In Thousands) Allowance for credit losses: Beginning balance $ 1,117 $ 647 Current period provision 7,413 5,851 Write-offs charged against allowance (7,764) (7,008) Recoveries collected 1,517 1,627 Ending Balance $ 2,283 $ 1,117

Regulatory Matters (Tables)

Regulatory Matters (Tables)	12 Months Ended
	Dec. 31, 2023
Entity Information [Line Items]
Schedule Of Regulatory Assets And Liabilities [Table Text Block]	2023 2022 Recovery Period (In Thousands) Regulatory assets, current: Undercollections of rate riders $ 75,416 $ 26,047 Approximately 1 year (1) Fuel costs — 79,861 Approximately 1 year (1) Unamortized reacquisition premium on debt 188 — Approximately 1 year Costs being recovered through basic rates and charges 13,815 13,815 Approximately 1 year (1) Total regulatory assets, current 89,419 119,723 Regulatory assets, non-current: Unrecognized pension and other postretirement benefit plan costs 115,847 131,907 Various (2) Deferred MISO costs 21,091 34,483 Through 2026 (1) Unamortized Petersburg Unit 4 carrying charges and certain other costs 2,812 3,866 Through 2026 (1)(3) Unamortized reacquisition premium on debt 13,379 14,429 Over remaining life of debt Environmental costs 66,837 68,947 Through 2046 (1)(3) COVID-19 costs 5,426 5,426 4 years (4) Major storm damage 1,493 — To be determined TDSIC costs 35,979 18,547 36.3 years (1)(3) Petersburg Unit 1 and 2 retirement costs 259,892 287,463 Through 2034 (1)(3) Hardy Hills Solar Project development costs 6,774 5,744 30 years (3) Petersburg Energy Center Project development costs 2,469 1,582 30 years (3) Pike County BESS Project development costs 2,623 — 20 years (3) Fuel costs 4,275 20,518 Through 2025 (1) Other miscellaneous 2,887 1,027 Various (5) Total regulatory assets, non-current 541,784 593,939 Total regulatory assets $ 631,203 $ 713,662 Regulatory liabilities, current: Overcollections and other credits being passed to customers through rate riders $ 19,649 $ 15,803 Approximately 1 year (1) FTRs 3,722 7,545 Approximately 1 year (1) Total regulatory liabilities, current 23,371 23,348 Regulatory liabilities, non-current: ARO and accrued asset removal costs 451,886 518,797 Not applicable Deferred income taxes payable to customers through rates 74,796 88,662 Various Hardy Hills sponsor investment tax credit 542 — To be determined (6) Major storm damage — 5,126 To be determined Total regulatory liabilities, non-current 527,224 612,585 Total regulatory liabilities $ 550,595 $ 635,933 (1) Recovered (credited) per specific rate orders (2) AES Indiana receives a return on its discretionary funding (3) Recovered with a current return (4) Per the signed stipulation in the 2023 distribution rate case, Cause No. 45911 (5) Some of these costs are being recovered in basic rates and charges through 2026. For the remainder, recovery over four years was agreed to in the signed stipulation in the 2023 distribution rate case, Cause No. 45911. AES Indiana will include this credit in a future ECR filing. (6) Will be included in a future ECR filing
Schedule of Regulatory Assets	2. REGULATORY MATTERS General AES Indiana is subject to regulation by the IURC as to its services and facilities, the valuation of property, the construction, purchase, or lease of electric generating facilities, the classification of accounts, rates of depreciation, retail rates and charges, the issuance of securities (other than evidences of indebtedness payable less than twelve months after the date of issue), the acquisition and sale of some public utility properties or securities and certain other matters. In addition, AES Indiana is subject to the jurisdiction of the FERC with respect to, among other things, short-term borrowings not regulated by the IURC, the sale of electricity at wholesale, the transmission of electric energy in interstate commerce, the classification of accounts, reliability standards, and the acquisition and sale of utility property in certain circumstances as provided by the Federal Power Act. As a regulated entity, AES Indiana is required to use certain accounting methods prescribed by regulatory bodies which may differ from those accounting methods required to be used by unregulated entities. AES Indiana is also affected by the regulatory jurisdiction of the EPA at the federal level, and the IDEM at the state level. Other significant regulatory agencies affecting AES Indiana include, but are not limited to, the NERC, the U.S. Department of Labor and the IOSHA. Basic Rates and Charges Our basic rates and charges represent the largest component of our annual revenue. Our basic rates and charges are determined after giving consideration, on a pro-forma basis, to all allowable costs for ratemaking purposes including a fair return on the fair value of the utility property used and useful in providing service to customers. These basic rates and charges are set and approved by the IURC after public hearings. Such proceedings, which have occurred at irregular intervals, involve AES Indiana, the IURC, the Indiana Office of Utility Consumer Counselor, and other interested stakeholders. Pursuant to statute, the IURC is to conduct a periodic review of the basic rates and charges of all Indiana utilities at least once every four years, but the IURC has the authority to review the rates of any Indiana utility at any time. Once set, the basic rates and charges authorized do not assure the realization of a fair return on the fair value of property. Our declining block rate structure generally provides for residential and commercial customers to be charged a lower per kWh rate at higher consumption levels. Therefore, as volumes increase, the weighted average price per kWh decreases. Numerous factors including, but not limited to, weather, inflation, customer growth and usage, the level of actual operating and maintenance expenditures, fuel costs, generating unit availability, and capital expenditures including those required by environmental regulations can affect the return realized. Regulatory Rate Review and Base Rate Orders AES Indiana filed a petition with the IURC on June 28, 2023, for authority to increase its basic rates and charges to cover the rising operational costs and needs associated with continuing to serve its customers safely and reliably. The factors leading to AES Indiana's first base rate increase request in five years include inflationary impacts on operations and maintenance expenses, investments in the transmission and distribution systems, and modernization of its customer systems. AES Indiana is also seeking recovery of increased costs to support its vegetation management plan, which covers the removal of overhang and tree trimming in its service territory. AES Indiana also seeks to better align depreciation expense with the period in which the generation plants provide service to customers and remove operational costs of the retired Petersburg units from rates. On November 22, 2023, AES Indiana entered into a unanimous stipulation and settlement agreement (the "settlement") with the OUCC and the intervening parties which, if approved by the IURC, would increase its annual revenue requirement by $73 million. AES Indiana expects to receive an order from the IURC and place new rates into effect by the end of the second quarter of 2024. On October 31, 2018, the IURC issued an order approving an uncontested settlement agreement previously filed with the IURC by AES Indiana for a $43.9 million, or 3.2%, increase to annual revenue (the "2018 Base Rate Order"). The 2018 Base Rate Order includes recovery through rates of the CCGT at Eagle Valley completed in the first half of 2018, as well as other construction projects and changes to operating income since the 2016 Base Rate Order. New basic rates and charges became effective on December 5, 2018. The 2018 Base Rate Order provides that annual wholesale margins earned above (or below) the benchmark of $16.3 million shall be passed back (or charged) to customer rates through a rate adjustment mechanism. Similarly, the 2018 Base Rate Order provides that all capacity sales above (or below) a benchmark of $11.3 million shall be passed back (or charged) to customer rates through a rate adjustment mechanism. FAC and Authorized Annual Jurisdictional Net Operating Income AES Indiana may apply to the IURC for a change in AES Indiana’s fuel charge every three months to recover AES Indiana’s estimated fuel costs, including the energy portion of purchased power costs, which may be above or below the levels included in AES Indiana’s basic rates and charges. AES Indiana must present evidence in each FAC proceeding that it has made every reasonable effort to acquire fuel and generate or purchase power or both so as to provide electricity to its retail customers at the lowest fuel cost reasonably possible. Independent of the IURC’s ability to review basic rates and charges, Indiana law requires electric utilities under the jurisdiction of the IURC to meet operating expense and income test requirements as a condition for approval of requested changes in the FAC. A utility may be unable to recover all of its fuel costs if its rolling twelve-month operating income, determined at quarterly measurement dates, exceeds its authorized annual jurisdictional net operating income and there are not sufficient applicable cumulative net operating income deficiencies (“Cumulative Deficiencies”) to offset it. The Cumulative Deficiencies calculation provides that only five years’ worth of historical earnings deficiencies or surpluses are included, unless it has been greater than five years since the most recent rate case. In calendar years 2021 and 2022, AES Indiana reported earnings in excess of the authorized level for certain quarterly reporting periods in those years. AES Indiana has not reported earnings in excess of the authorized level for any FAC periods in the calendar year 2023. Prior to 2020, AES Indiana was not required to reduce its fuel cost recovery because of its Cumulative Deficiencies. During 2020, AES Indiana's Cumulative Deficiencies dropped to zero. AES Indiana recorded a reduction to revenue of $0.0 million, $0.3 million and $5.5 million in 2023, 2022 and 2021, respectively. As of the FAC period ending with the twelve months of October 31, 2023, AES Indiana has Cumulative Deficiencies; therefore, AES will not be required to reduce its fuel cost recovery for future earnings in excess of the authorized level until there are no longer Cumulative Deficiencies. ECCRA AES Indiana may apply to the IURC for approval of a rate adjustment known as the ECCRA periodically to recover costs (including a return) to comply with certain environmental regulations applicable to AES Indiana’s generating stations and to recover certain investments in renewable and battery storage projects. The total amount of AES Indiana’s environmental equipment and renewable projects approved for ECCRA recovery as of December 31, 2023 was $129.7 million. The jurisdictional revenue requirement approved by the IURC to be included in AES Indiana’s rates for the twelve-month period ending February 2024 is a net cost to customers of $8.9 million. DSM Through various rate orders from the IURC, AES Indiana has been able to recover its costs of implementing various DSM programs throughout the periods covered by this report. In 2023, 2022 and 2021, AES Indiana also had the ability to receive performance incentives, dependent upon the level of success of the programs. Performance incentives included in rates for the years ended December 31, 2023, 2022 and 2021 were $2.7 million, $8.3 million and $7.2 million, respectively. On December 29, 2020, the IURC approved a settlement agreement establishing a new three year DSM plan for AES Indiana through 2023. The approval included cost recovery of programs as well as performance incentives, depending on the level of success of the programs. The order also approved recovery of lost revenue, consistent with the provisions of the settlement agreement. AES Indiana filed a petition with the IURC on May 26, 2023 asking for approval of a one year DSM interim plan. On December 27, 2023, the IURC approved a one-year DSM plan for AES Indiana through 2024. The approval included cost recovery of programs as well as performance incentives, depending on the level of success of the programs. The order also approved recovery of lost revenue, consistent with the provisions of the settlement agreement. Wind and Solar Power Purchase Agreements We are currently committed under a power purchase agreement to purchase all wind-generated electricity through 2029 from a wind project in Indiana ("Hoosier Wind Project"). On July 28, 2023, AES Indiana executed the Purchase Agreement and is currently in the process of acquiring this project. The existing power purchase agreement will be terminated upon closing (see "IRP Filings and Replacement Generation - Hoosier Wind Project" below for further information). We are also committed under another agreement to purchase all wind-generated electricity through 2031 from a project in Minnesota. The Indiana project has a maximum output capacity of approximately 100 MW and the Minnesota project has a maximum output capacity of approximately 200 MW. In addition, we have 94.5 MW of solar-generated electricity in our service territory under long-term contracts (these long-term contracts have expiration dates ranging from 2026 to 2033), of which 94.0 MW was in operation as of December 31, 2023. We have authority from the IURC to recover the costs for all of these agreements through an adjustment mechanism administered within the FAC. If and when AES Indiana sells the renewable energy attributes (in the form of renewable energy credits) generated from these facilities, the proceeds would pass back to benefit AES Indiana’s retail customers through the FAC. TDSIC In 2013, Senate Enrolled Act 560, the Transmission, Distribution, and Storage System Improvement Charge ("TDSIC") statute, was signed into law. The TDSIC statute was revised in 2019. Among other provisions, this legislation provides for cost recovery outside of a base rate proceeding for new or replacement electric and gas transmission, distribution, and storage projects that a public utility undertakes for the purposes of safety, reliability, system modernization, or economic development. Provisions of the TDSIC statute require that, among other things, requests for recovery include a plan of at least five years and not more than seven for eligible investments. The first eighty percent of eligible costs can be recovered using a periodic rate adjustment mechanism. The cost recovery mechanism is referred to as a TDSIC mechanism. Recoverable costs include a return on, and of, the investment, including AFUDC, post-in-service carrying charges, operation and maintenance expenses, depreciation and property taxes. The remaining twenty percent of recoverable costs are to be deferred for future recovery in the public utility’s next base rate case. The periodic rate adjustment mechanism is capped at an annual increase of no more than two percent of total retail revenue. On March 4, 2020, the IURC issued an order approving the projects in a seven-year TDSIC Plan for eligible transmission, distribution and storage system improvements totaling $1.2 billion from 2020 through 2026. Beginning in June 2020, AES Indiana files an annual TDSIC rate adjustment for a return on and of investments through March 31 with rates requested to be effective each November. Annual TDSIC plan update filings are required to be staggered by six months as ordered by the IURC and are filed each December. The total amount of AES Indiana’s equipment net of depreciation, including carrying costs, approved for TDSIC recovery as of December 31, 2023 was $399.6 million. The jurisdictional revenue requirement approved by the IURC to be included in AES Indiana’s rates for the twelve-month period ending October 2024 is a net cost to customers of $56.5 million. IRP Filings and Replacement Generation Electric utilities in Indiana are required to submit Integrated Resource Plans (IRPs) every three years. The IRPs are subject to a rigorous stakeholder process. IRPs describe how the utility plans to deliver safe, reliable, and efficient electricity at just and reasonable rates. 2022 IRP AES Indiana held public advisory meetings for the 2022 IRP in January, April, June, September and October of 2022. Changes to our generation portfolio are evaluated and decided through the IRP. AES Indiana issued an all-source Request for Proposal on April 14, 2022, in order to competitively procure energy and capacity in the near term; such need was evaluated in AES Indiana's 2022 IRP. In December 2022, AES Indiana filed its 2022 IRP with the IURC, which describes AES Indiana's Preferred Resource Portfolio for meeting generation capacity needs for serving AES Indiana's retail customers over the next several years. The Preferred Resource Portfolio is AES Indiana's reasonable least cost option and provides a cleaner and more diverse generation mix for customers. The 2022 IRP short-term action plan includes converting the two remaining coal units at Petersburg to natural gas. AES Indiana has not yet filed for the regulatory approvals from the IURC to convert Petersburg units 3 and 4; however, AES Indiana expects to do so in the first half of 2024. Construction is expected to begin in 2025 and be completed by the end of 2026. Additionally, AES Indiana plans to add up to 1,300 MW of wind, solar, and battery energy storage by 2027. As new technologies, such as green hydrogen, small modular reactors and carbon capture are developed and cost effective, AES Indiana will evaluate them in the future planning processes. As a result of the plan to convert Petersburg units 3 and 4 to natural gas, AES Indiana recorded a $1.5 million write off of capital projects during the period ended December 31, 2022 to " Operating expenses - Operation and maintenance " on the accompanying Consolidated Statements of Operations. 2019 IRP In December 2019, AES Indiana filed its 2019 IRP, which included the retirement of approximately 630 MW of coal-fired generation at Petersburg Units 1 and 2 in 2021 and 2023, respectively. Based on extensive modeling, AES Indiana determined that the cost of operating Petersburg Units 1 and 2 exceeded the value customers received compared to alternative resources. Retirement of these units allowed the company to cost-effectively diversify the portfolio and transition to lower cost and cleaner resources while maintaining a reliable system. AES Indiana issued an all-source Request for Proposal on December 20, 2019, in order to competitively procure replacement capacity by June 1, 2023, which was the first year AES Indiana was expected to have a capacity shortfall. Our modeling indicated that a combination of wind, solar, storage, and energy efficiency would be the lowest reasonable cost option for the replacement capacity. As a result of the plans to retire Petersburg Units 1 and 2, AES Indiana recorded $0.7 million, $2.1 million, and $0.8 million of obsolescence losses, during the periods ended December 31, 2023, 2022, and 2021, respectively, for materials and supplies inventory AES Indiana did not believe will be utilized by the planned retirement dates, which is recorded in " Operating expenses - Operation and maintenance " on the accompanying Consolidated Statements of Operations. As a result of the plans to retire Petersburg Units 1 and 2, AES Indiana filed a petition with the IURC on February 26, 2021 for approvals and cost recovery associated with these retirements. On August 6, 2021, AES Indiana filed an uncontested Stipulation and Settlement Agreement with the other parties in the case which includes: (1) AES Indiana's creation of regulatory assets for the net book value of Petersburg units 1 and 2 upon retirement; (2) a method for amortization of the regulatory assets; and (3) recovery of the regulatory assets through ongoing amortization in AES Indiana’s future rate cases. The Settlement Agreement also reserves all rights of all the parties with respect to the ratemaking treatment related to the regulatory assets, including the proper rate of return and mechanisms for recovery. On November 17, 2021, the IURC approved the Settlement Agreement without modification. AES Indiana retired 230 MW Petersburg Unit 1 in May 2021 and 415 MW Petersburg Unit 2 in June 2023. AES Indiana had $35.7 million and $224.2 million of Petersburg Units 1 and 2 retirement costs, respectively, net of accumulated amortization, recorded as long-term regulatory assets as of December 31, 2023. AES Indiana had $47.6 million and $239.9 million of Petersburg Units 1 and 2 retirement costs, respectively, net of accumulated amortization, recorded as long-term regulatory assets as of December 31, 2022. Hardy Hills Solar Project In January 2021, AES Indiana, through a wholly-owned subsidiary, executed an agreement for the acquisition and construction of the 195 MW Hardy Hills Solar Project to be developed in Clinton County, Indiana. In December 2022, the agreement was amended to revise the project schedule, including shifting the completion date to 2024, and adjusting for increased project costs. On January 13, 2023, AES Indiana filed a petition with the IURC for approval of these revisions, which was approved in August 2023. On June 16, 2021, AES Indiana received an order from the IURC approving a petition and case-in-chief seeking a CPCN for this solar project, including a joint venture structure between an AES Indiana subsidiary and one or more tax equity partners upon completion and approval for recovery of project development costs and carrying costs on AES Indiana's investment in the project. The transaction closed in December 2021 and was accounted for as an asset acquisition of a variable interest entity that did not meet the definition of a business; therefore, the individual assets and liabilities were recorded at their fair values. Total net assets of $51.6 million were recorded in the accompanying Consolidated Balance Sheets associated with the transaction, primarily consisting of a development project intangible asset (see Note 1, "Overview and Summary of Significant Accounting Policies - Intangible Assets" ). A gain for the difference between the consideration transferred and the assets and liabilities recognized was recorded in “ Operating costs and expenses - Other, net” on the accompanying Consolidated Statements of Operations. Total consideration included a future payment contingent on certain future costs incurred by the project. As such, a $3.2 million contingent liability was recorded in " Other Non-Current Liabilities" on the accompanying Consolidated Balance Sheets as of December 31, 2021. During 2022, this liability was remeasured due to updated cost estimates and was reduced to $0.0 million. On December 1, 2023, AES Indiana, through a wholly-owned subsidiary (the "Class B Member"), and a third-party investor (the "Class A Member"), entered into an Equity Capital Contribution Agreement, pursuant to which each member made certain capital contributions to Hardy Hills JV. The Class A member made total contributions of $79.3 million through December 31, 2023. Hardy Hills JV is consolidated by the Class B Member under the Variable Interest Model, and noncontrolling interest (“NCI”) was recorded by AES Indiana at the amount of cash contributed by the Class A Member. In December 2023, the first stage of the construction for the Hardy Hills Solar Project was completed and placed in service, with initial operations for over half of the project commencing on December 28, 2023. Upon the first stage of the project being placed in service, the Company recognized $26.1 million of earnings from tax attributes using the HLBV method. The final stage for construction of the project is expected to be completed during the first half of 2024. Petersburg Energy Center Project In July 2021, AES Indiana, through a wholly-owned subsidiary, executed an agreement for the acquisition and construction of a 250 MW solar and 45MW (180 MWh) energy storage facility to be developed in Pike County, Indiana. In October 2022, the agreement was amended to revise the project schedule, including shifting the completion date to 2025, and adjusting for increased project costs. On December 22, 2022, AES Indiana filed a petition with the IURC for approval of these revisions, which was approved in May 2023. On August 31, 2023, AES Indiana closed on the agreement for the acquisition and construction of the Petersburg Energy Center Project. This transaction was accounted for as an asset acquisition of a variable interest entity that did not meet the definition of a business; therefore, the individual assets were recorded at their fair values. Total net assets of $48.7 million were recorded in the accompanying Consolidated Balance Sheets associated with the transaction, primarily consisting of project development intangible assets (see Note 1, "Overview and Summary of Significant Accounting Policies - Intangible Assets" for further information). Pike County BESS Project In June 2023, AES Indiana, through a wholly-owned subsidiary, executed an agreement for the construction of the 200 MW (800 MWh) Pike County BESS Project to be developed at the AES Indiana Petersburg Plant site in Pike County, Indiana. On July 19, 2023, AES Indiana filed a petition and case-in-chief with the IURC seeking approval for a Clean Energy Project and associated timely cost recovery under Indiana Code for this project. A hearing for this case was held in October 2023, and IURC approval was received on January 17, 2024. The Pike County BESS Project is expected to be completed in 2024. Hoosier Wind Project On July 5, 2023, AES Indiana filed a Notice of Intent with the IURC to request approval of a Clean Energy Project and for issuance of a CPCN for the Hoosier Wind Project acquisition. The proposed Project is the acquisition of the Hoosier Wind Project, which is an existing 106 MW wind facility located in Benton County, Indiana. The Company executed the Purchase Agreement on July 28, 2023. A CPCN for this case was filed in early August 2023, and IURC approval was received on January 24, 2024. The acquisition of the Hoosier Wind Project is expected to be completed in the first quarter of 2024. Incentives for Clean Energy Projects Indiana Code 8-1-8 (the "clean energy statute") offers certain incentives for clean energy projects. Primarily, it allows for the timely recovery of costs and expenses incurred during construction and operation of eligible projects outside of a base rate proceeding. Clean energy projects eligible for incentives under this statute include renewable energy resources such as wind, photovoltaic cells and panels, solar energy, and energy storage systems or technologies, among others. AES Indiana filed for and received IURC approval of the Hoosier Wind Project and Pike County BESS Project under this statute. AES Indiana continues to evaluate projects which may also be filed under this statute. IURC COVID-19 Orders Due to the COVID-19 pandemic, there was a disconnection moratorium in 2020 for IURC-jurisdictional utilities, as well as suspension of certain utility fees (late fees, convenience fees, deposits, and disconnection/reconnection fees) from residential customers. The IURC authorized Indiana utilities to use regulatory accounting for any impacts associated with the moratorium and suspension. The IURC also authorized regulatory accounting treatment for COVID-19 related uncollectible and incremental bad debt expense. As a result of the IURC's COVID-19 related orders issued in 2020, AES Indiana has recorded a regulatory asset of $5.4 million as of December 31, 2023 and 2022, which will be recovered through base rates under the stipulation and settlement agreement entered into on November 22, 2023, if approved by the IURC. EDG Rates On March 1, 2021, AES Indiana filed a petition with the IURC for approval of its proposed rate for the procurement of EDG and related consumer EDG credit issues. The EDG rate replaced the net metering program beginning in July 2022, when net metering was no longer available to new customers. The IURC approved the EDG rate by order dated January 26, 2022, On March 16, 2022, the IURC denied the petition for reconsideration filed by the other parties on February 15, 2022. The matter was subject to an appeal filed by the other parties on February 22, 2022, which was held in abeyance by the Indiana Court of Appeals pending resolution of a petition to transfer to the Indiana Supreme Court filed in a similar case involving a different and unaffiliated utility. The stay was extended by the Indiana Court of Appeals on July 11, 2022. On January 4, 2023, the Indiana Supreme Court issued a final decision in favor of the utility in the similar case that served as the basis of the stay in the AES Indiana case. On February 3, 2023, the OUCC moved to dismiss the appeal, which motion was granted on February 13, 2023. EV Portfolio Program On January 27, 2023, AES Indiana filed with the IURC a request to approve its EV Portfolio and associated accounting and ratemaking treatment. The EV Portfolio includes two separate parts: (1) a set of EV specific rates, tariffs, and alternative pricing structures, and (2) a set of Public Use EV Pilot Programs. The EV portfolio is designed to produce net benefits for all customers through new retail margins and grid optimization. The projected costs to successfully implement the services proposed in the EV Portfolio are estimated at $16.2 million over the three-year period. AES Indiana requested approval to defer as a regulatory asset and recover in future base rates the cost necessary to implement the EV Portfolio, including carrying charges. A hearing on this request was held in July 2023. On November 22, 2023, the IURC issued an order approving AES Indiana's EV Portfolio filing with approval to defer as a regulatory asset and to seek recovery in future base rates the cost necessary to implement the EV Portfolio, including carrying charges with no other significant modifications. Storm Outage Restoration Inquiry On July 11, 2023, the OUCC and the Citizens Action Coalition (“CAC”) filed a Joint Petition through which they requested the IURC open an investigation into AES Indiana’s practices and procedures regarding storm outage restoration. A technical conference was held on October 2, 2023, to discuss AES Indiana’s response to outages and storm restoration; particularly the storms that occurred between June 29, 2023 and July 2, 2023. House Bill 1002 In the first quarter of 2022, the 2022 Indiana General Assembly passed House Enrolled Act 1002, which includes language regarding the repeal of the URT. AES Indiana filed a rate adjustment with the IURC on April 29, 2022, which was approved by the IURC on June 28, 2022. AES Indiana began charging the new rates excluding URT in July 2022. Prior to the repeal, the URT was recoverable through a current charge to customer rates. After the repeal, the new rates approved by the IURC adjusted both revenue and tax expense. As a result, the repeal of the URT had no impact on the Company's net income. Regulatory Assets and Liabilities Regulatory assets represent deferred costs or credits that have been included as allowable costs or credits for ratemaking purposes. AES Indiana has recorded regulatory assets or liabilities relating to certain costs or credits as authorized by the IURC or established regulatory practices in accordance with ASC 980. AES Indiana is amortizing non tax-related regulatory assets to expense over periods ranging from 1 to 43 years. Tax-related regulatory assets represent the net income tax costs to be considered in future regulatory proceedings generally as the tax-related amounts are paid. The amounts of regulatory assets and regulatory liabilities at December 31 are as follows: 2023 2022 Recovery Period (In Thousands) Regulatory assets, current: Undercollections of rate riders $ 75,416 $ 26,047 Approximately 1 year (1) Fuel costs — 79,861 Approximately 1 year (1) Unamortized reacquisition premium on debt 188 — Approximately 1 year Costs being recovered through basic rates and charges 13,815 13,815 Approximately 1 year (1) Total regulatory assets, current 89,419 119,723 Regulatory assets, non-current: Unrecognized pension and other postretirement benefit plan costs 115,847 131,907 Various (2) Deferred MISO costs 21,091 34,483 Through 2026 (1) Unamortized Petersburg Unit 4 carrying charges and certain other costs 2,812 3,866 Through 2026 (1)(3) Unamortized reacquisition premium on debt 13,379 14,429 Over remaining life of debt Environmental costs 66,837 68,947 Through 2046 (1)(3) COVID-19 costs 5,426 5,426 4 years (4) Major storm damage 1,493 — To be determined TDSIC costs 35,979 18,547 36.3 years (1)(3) Petersburg Unit 1 and 2 retirement costs 259,892 287,463 Through 2034 (1)(3) Hardy Hills Solar Project development costs 6,774 5,744 30 years (3) Petersburg Energy Center Project development costs 2,469 1,582 30 years (3) Pike County BESS Project development costs 2,623 — 20 years (3) Fuel costs 4,275 20,518 Through 2025 (1) Other miscellaneous 2,887 1,027 Various (5) Total regulatory assets, non-current 541,784 593,939 Total regulatory assets $ 631,203 $ 713,662 Regulatory liabilities, current: Overcollections and other credits being passed to customers through rate riders $ 19,649 $ 15,803 Approximately 1 year (1) FTRs 3,722 7,545 Approximately 1 year (1) Total regulatory liabilities, current 23,371 23,348 Regulatory liabilities, non-current: ARO and accrued asset removal costs 451,886 518,797 Not applicable Deferred income taxes payable to customers through rates 74,796 88,662 Various Hardy Hills sponsor investment tax credit 542 — To be determined (6) Major storm damage — 5,126 To be determined Total regulatory liabilities, non-current 527,224 612,585 Total regulatory liabilities $ 550,595 $ 635,933 (1) Recovered (credited) per specific rate orders (2) AES Indiana receives a return on its discretionary funding (3) Recovered with a current return (4) Per the signed stipulation in the 2023 distribution rate case, Cause No. 45911 (5) Some of these costs are being recovered in basic rates and charges through 2026. For the remainder, recovery over four years was agreed to in the signed stipulation in the 2023 distribution rate case, Cause No. 45911. AES Indiana will include this credit in a future ECR filing. (6) Will be included in a future ECR filing Current Regulatory Assets and Liabilities Current regulatory assets and liabilities primarily represent costs that are being recovered per specific rate orders; recovery for the remaining costs is probable, but not certain. As current assets, this includes undercollection of adjustment mechanisms for: (i) DSM, (ii) ECCRA costs, (iii) Off System Sales Margin Sharing, (iv) Capacity rider costs and (v) TDSIC. It also includes the current portion of deferred MISO costs and environmental costs collected through base rates which are described in greater detail below. With the exception of environmental costs, these costs do not earn a return on investment. As current liabilities, this includes (i) overcollection of MISO rider costs, (ii) Green Power, and (iii) deferred fuel costs. Deferred Fuel Deferred fuel costs are a component of current and long-term regulatory assets or liabilities (which is a result of AES Indiana charging either more or less for fuel than our actual costs to our jurisdictional customers) and are expected to be recovered through future FAC proceedin
Indianapolis Power And Light Company
Entity Information [Line Items]
Schedule Of Regulatory Assets And Liabilities [Table Text Block]	2023 2022 Recovery Period (In Thousands) Regulatory assets, current: Undercollections of rate riders $ 75,416 $ 26,047 Approximately 1 year (1) Fuel costs — 79,861 Approximately 1 year (1) Unamortized reacquisition premium on debt 188 — Approximately 1 year Costs being recovered through basic rates and charges 13,815 13,815 Approximately 1 year (1) Total regulatory assets, current 89,419 119,723 Regulatory assets, non-current: Unrecognized pension and other postretirement benefit plan costs 115,847 131,907 Various (2) Deferred MISO costs 21,091 34,483 Through 2026 (1) Unamortized Petersburg Unit 4 carrying charges and certain other costs 2,812 3,866 Through 2026 (1)(3) Unamortized reacquisition premium on debt 13,379 14,429 Over remaining life of debt Environmental costs 66,837 68,947 Through 2046 (1)(3) COVID-19 costs 5,426 5,426 4 years (4) Major storm damage 1,493 — To be determined TDSIC costs 35,979 18,547 36.3 years (1)(3) Petersburg Unit 1 and 2 retirement costs 259,892 287,463 Through 2034 (1)(3) Hardy Hills Solar Project development costs 6,774 5,744 30 years (3) Petersburg Energy Center Project development costs 2,469 1,582 30 years (3) Pike County BESS Project development costs 2,623 — 20 years (3) Fuel costs 4,275 20,518 Through 2025 (1) Other miscellaneous 2,887 1,027 Various (5) Total regulatory assets, non-current 541,784 593,939 Total regulatory assets $ 631,203 $ 713,662 Regulatory liabilities, current: Overcollections and other credits being passed to customers through rate riders $ 19,649 $ 15,803 Approximately 1 year (1) FTRs 3,722 7,545 Approximately 1 year (1) Total regulatory liabilities, current 23,371 23,348 Regulatory liabilities, non-current: ARO and accrued asset removal costs 451,886 518,797 Not applicable Deferred income taxes payable to customers through rates 74,796 88,662 Various Hardy Hills sponsor investment tax credit 542 — To be determined (6) Major storm damage — 5,126 To be determined Total regulatory liabilities, non-current 527,224 612,585 Total regulatory liabilities $ 550,595 $ 635,933 (1) Recovered (credited) per specific rate orders (2) AES Indiana receives a return on its discretionary funding (3) Recovered with a current return (4) Per the signed stipulation in the 2023 distribution rate case, Cause No. 45911 (5) Some of these costs are being recovered in basic rates and charges through 2026. For the remainder, recovery over four years was agreed to in the signed stipulation in the 2023 distribution rate case, Cause No. 45911. AES Indiana will include this credit in a future ECR filing. (6) Will be included in a future ECR filing

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2023
Entity Information [Line Items]
Schedule Of Original Cost Of Utility Plant In Service	As of December 31, 2023 2022 (In Thousands) Production $ 3,942,052 $ 4,164,416 Transmission 487,527 461,245 Distribution 2,304,526 2,045,579 General plant 348,338 311,074 Total property, plant and equipment $ 7,082,443 $ 6,982,314
Reconciliation Of Asset Retirement Obligation Liability	The following is a roll forward of the ARO legal liability year end balances: 2023 2022 (In Thousands) Balance as of January 1 $ 218,729 $ 189,509 Liabilities incurred 17,080 1,159 Liabilities settled (11,902) (24,699) Revisions to cash flow and timing estimates 12,921 44,679 Accretion expense 13,102 8,081 Balance as of December 31 $ 249,930 $ 218,729
Indianapolis Power And Light Company
Entity Information [Line Items]
Schedule Of Original Cost Of Utility Plant In Service	As of December 31, 2023 2022 (In Thousands) Production $ 3,942,052 $ 4,164,416 Transmission 487,527 461,245 Distribution 2,304,526 2,045,579 General plant 348,338 311,074 Total property, plant and equipment $ 7,082,443 $ 6,982,314
Reconciliation Of Asset Retirement Obligation Liability	The following is a roll forward of the ARO legal liability year end balances: 2023 2022 (In Thousands) Balance as of January 1 $ 218,729 $ 189,509 Liabilities incurred 17,080 1,159 Liabilities settled (11,902) (24,699) Revisions to cash flow and timing estimates 12,921 44,679 Accretion expense 13,102 8,081 Balance as of December 31 $ 249,930 $ 218,729

Fair Value (Tables)

Fair Value (Tables)	12 Months Ended
	Dec. 31, 2023
Entity Information [Line Items]
Summary of Fair Value Assets and Liabilities Measured on a Recurring Basis, Level 3	The fair value of assets at December 31, 2023 and 2022 measured on a recurring basis and the respective category within the fair value hierarchy for IPALCO was determined as follows: Fair Value as of December 31, 2023 Fair Value as of December 31, 2022 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total (In Thousands) Financial assets: VEBA investments: Money market funds $ 127 $ — $ — $ 127 $ 5 $ — $ — $ 5 Mutual funds 3,425 — — 3,425 3,223 — — 3,223 Total VEBA investments 3,552 — — 3,552 3,228 — — 3,228 FTRs — — 1,388 1,388 — — 7,545 7,545 Interest rate hedges — 14,294 — 14,294 — 12,172 — 12,172 Total financial assets measured at fair value $ 3,552 $ 14,294 $ 1,388 $ 19,234 $ 3,228 $ 12,172 $ 7,545 $ 22,945
Reconciliation of Financial Instruments Classified as Level 3	The following table sets forth a roll forward of financial instruments, measured at fair value on a recurring basis, classified as Level 3 in the fair value hierarchy (note, amounts in this table indicate carrying values, which approximate fair values): Reconciliation of Financial Instruments Classified as Level 3 (In Thousands) Balance at January 1, 2022 $ 1,235 Issuances 15,338 Settlements (9,028) Balance at December 31, 2022 7,545 Issuances 3,624 Settlements (9,781) Balance at December 31, 2023 $ 1,388
Schedule of Face and Fair Value of Debt	The following table shows the face value and the fair value of fixed-rate and variable-rate indebtedness (Level 2) for the periods ending: December 31, 2023 December 31, 2022 Face Value Fair Value Face Value Fair Value (In Thousands) Fixed-rate $ 3,033,800 $ 2,860,467 $ 3,033,800 $ 2,775,644 Variable-rate 455,000 455,000 — — Total indebtedness $ 3,488,800 $ 3,315,467 $ 3,033,800 $ 2,775,644
Indianapolis Power And Light Company
Entity Information [Line Items]
Fair Value Assets And Liabilities Measured On A Recurring Basis Unobservable Inputs [Table Text Block]	The fair value of assets at December 31, 2023 and 2022 measured on a recurring basis and the respective category within the fair value hierarchy for AES Indiana was determined as follows: Fair Value as of December 31, 2023 Fair Value as of December 31, 2022 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total (In Thousands) Financial assets: FTRs $ — $ — $ 1,388 $ 1,388 $ — $ — $ 7,545 $ 7,545 Total financial assets measured at fair value $ — $ — $ 1,388 $ 1,388 $ — $ — $ 7,545 $ 7,545
Reconciliation of Financial Instruments Classified as Level 3	The following table sets forth a roll forward of financial instruments, measured at fair value on a recurring basis, classified as Level 3 in the fair value hierarchy (note, amounts in this table indicate carrying values, which approximate fair values): Reconciliation of Financial Instruments Classified as Level 3 (In Thousands) Balance at January 1, 2022 $ 1,235 Issuances 15,338 Settlements (9,028) Balance at December 31, 2022 7,545 Issuances 3,624 Settlements (9,781) Balance at December 31, 2023 $ 1,388
Schedule of Face and Fair Value of Debt	The following table shows the face value and the fair value of fixed-rate and variable-rate indebtedness (Level 2) for the periods ending: December 31, 2023 December 31, 2022 Face Value Fair Value Face Value Fair Value (In Thousands) Fixed-rate $ 2,153,800 $ 2,020,997 $ 2,153,800 $ 1,959,233 Variable-rate 455,000 455,000 — — Total indebtedness $ 2,608,800 $ 2,475,997 $ 2,153,800 $ 1,959,233

Derivative Instruments and He_2

Derivative Instruments and Hedging Activities (Tables)	12 Months Ended
	Dec. 31, 2023
Derivative [Line Items]
Schedule of Derivative Instruments, Effect on Other Comprehensive Income (Loss) [Table Text Block]	The following tables provide information on gains or losses recognized in AOCI / (AOCL) for the cash flow hedges for the periods indicated: Interest Rate Hedges for the Years Ended December 31, $ in thousands (net of tax) 2023 2022 2021 Beginning accumulated derivative gain / (loss) in AOCI / (AOCL) $ 22,269 $ (29,407) $ (43,420) Net gains associated with current period hedging transactions 1,594 46,245 10,393 Net losses reclassified to interest expense 5,431 5,431 3,620 Ending accumulated derivative gain / (loss) in AOCI / (AOCL) $ 29,294 $ 22,269 $ (29,407) Loss expected to be reclassified to earnings in the next twelve months $ (5,375) Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months) 9
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]	December 31, Commodity Hedging Designation Balance sheet classification 2023 2022 FTRs Not a Cash Flow Hedge Derivative assets, current $ 1,388 $ 7,545 Interest rate hedges Cash Flow Hedge Derivative assets, current $ 14,294 $ — Interest rate hedges Cash Flow Hedge Derivative assets, non-current $ — $ 12,172
Schedule of Derivative Instruments [Table Text Block]	At December 31, 2023 , AES Indiana's outstanding derivative instruments were as follows: Commodity Accounting Treatment (a) Unit Notional Sales Net Notional Interest rate hedges Designated USD $ 400,000 $ — $ 400,000 FTRs Not Designated MWh 3,919 — 3,919 (a) Refers to whether the derivative instruments have been designated as a cash flow hedge.
Subsidiaries [Member]
Derivative [Line Items]
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]	December 31, Commodity Hedging Designation Balance sheet classification 2023 2022 FTRs Not a Cash Flow Hedge Prepayments and other current assets $ 1,388 $ 7,545
Schedule of Derivative Instruments [Table Text Block]	At December 31, 2023 , AES Indiana's outstanding derivative instruments were as follows: Commodity Accounting Treatment (a) Unit Notional Sales Net Notional FTRs Not Designated MWh 3,919 — 3,919 (a) Refers to whether the derivative instruments have been designated as a cash flow hedge.

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2023
Entity Information [Line Items]
Schedule Long-Term Indebtedness	The following table presents our long-term debt: December 31, Series Due 2023 2022 (In Thousands) AES Indiana first mortgage bonds: 3.125% (1) December 2024 $ 40,000 $ 40,000 0.65% (1) August 2025 40,000 40,000 0.75% (2) April 2026 30,000 30,000 0.95% (2) April 2026 60,000 60,000 1.40% (1) August 2029 55,000 55,000 5.65% December 2032 350,000 350,000 6.60% January 2034 100,000 100,000 6.05% October 2036 158,800 158,800 6.60% June 2037 165,000 165,000 4.875% November 2041 140,000 140,000 4.65% June 2043 170,000 170,000 4.50% June 2044 130,000 130,000 4.70% September 2045 260,000 260,000 4.05% May 2046 350,000 350,000 4.875% November 2048 105,000 105,000 Unamortized discount – net (6,449) (6,651) Deferred financing costs (19,058) (20,362) Total AES Indiana first mortgage bonds 2,128,293 2,126,787 Total long-term debt – AES Indiana 2,128,293 2,126,787 Long-term debt – IPALCO: 3.70% Senior Secured Notes September 2024 405,000 405,000 4.25% Senior Secured Notes May 2030 475,000 475,000 Unamortized discount – net (319) (425) Deferred financing costs (4,554) (5,912) Total long-term debt – IPALCO 875,127 873,663 Total consolidated IPALCO long-term debt 3,003,420 3,000,450 Less: current portion of long-term debt 445,000 — Net consolidated IPALCO long-term debt $ 2,558,420 $ 3,000,450 (1) First mortgage bonds issued to the Indiana Finance Authority, to secure the loan of proceeds from tax-exempt bonds issued by the Indiana Finance Authority. (2) First mortgage bonds issued to the Indiana Finance Authority, to secure the loan of proceeds from tax-exempt bonds issued by the Indiana Finance Authority. The notes have a final maturity date of December 31, 2038, but are subject to a mandatory put in April 2026.
Schedule Of Maturities On Long-Term Indebtedness	Maturities on long-term indebtedness subsequent to December 31, 2023 are as follows: Year Amount (In Thousands) 2024 $ 445,000 2025 40,000 2026 90,000 2027 — 2028 — Thereafter 2,458,800 3,033,800 Unamortized discounts (6,768) Deferred financing costs, net (23,612) Total long-term debt $ 3,003,420
Indianapolis Power And Light Company
Entity Information [Line Items]
Schedule Long-Term Indebtedness	The following table presents AES Indiana’s long-term debt: December 31, Series Due 2023 2022 (In Thousands) AES Indiana first mortgage bonds: 3.125% (1) December 2024 $ 40,000 $ 40,000 0.65% (1) August 2025 40,000 40,000 0.75% (2) April 2026 30,000 30,000 0.95% (2) April 2026 60,000 60,000 1.40% (1) August 2029 55,000 55,000 5.650% December 2032 350,000 350,000 6.60% January 2034 100,000 100,000 6.05% October 2036 158,800 158,800 6.60% June 2037 165,000 165,000 4.875% November 2041 140,000 140,000 4.65% June 2043 170,000 170,000 4.50% June 2044 130,000 130,000 4.70% September 2045 260,000 260,000 4.05% May 2046 350,000 350,000 4.875% November 2048 105,000 105,000 Unamortized discount – net (6,449) (6,651) Deferred financing costs (19,058) (20,362) Total AES Indiana first mortgage bonds 2,128,293 2,126,787 Total consolidated AES Indiana long-term debt 2,128,293 2,126,787 Less: current portion of long-term debt 40,000 — Net consolidated AES Indiana long-term debt $ 2,088,293 $ 2,126,787 (1) First mortgage bonds issued to the Indiana Finance Authority, to secure the loan of proceeds from tax-exempt bonds issued by the Indiana Finance Authority. (2) First mortgage bonds issued to the Indiana Finance Authority, to secure the loan of proceeds from tax-exempt bonds issued by the Indiana Finance Authority. The notes have a final maturity date of December 31, 2038, but are subject to a mandatory put in April 2026.
Schedule Of Maturities On Long-Term Indebtedness	Maturities on long-term indebtedness subsequent to December 31, 2023 are as follows: Year Amount (In Thousands) 2024 $ 40,000 2025 40,000 2026 90,000 2027 — 2028 — Thereafter 1,983,800 2,153,800 Unamortized discounts (6,449) Deferred financing costs, net (19,058) Total long-term debt $ 2,128,293

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2023
Entity Information [Line Items]
Schedule Of Federal And State Income Taxed Charged To Income	Federal and state income taxes charged to income are as follows: 2023 2022 2021 (In Thousands) Components of income tax expense: Current income taxes: Federal $ (14,222) $ 22,539 $ 28,100 State (3,716) 6,026 8,218 Total current income taxes (17,938) 28,565 36,318 Deferred income taxes: Federal 24,885 (6,920) (7,286) State 7,768 214 (91) Total deferred income taxes 32,653 (6,706) (7,377) Total income tax expense $ 14,715 $ 21,859 $ 28,941
Schedule Of Effective Income Tax Rate	The provision for income taxes (including net investment tax credit adjustments) is different than the amount computed by applying the statutory tax rate to pretax income. The reasons for the difference, stated as a percentage of pretax income, are as follows: 2023 2022 2021 Federal statutory tax rate 21.0 % 21.0 % 21.0 % State income tax, net of federal tax benefit 3.9 % 3.9 % 4.0 % Depreciation flow through and amortization (12.9) % (7.8) % (6.3) % AFUDC - equity (0.3) % 0.9 % 0.4 % Noncontrolling interests in subsidiaries 9.0 % — % — % Other – net (0.2) % 0.4 % 0.4 % Effective tax rate 20.5 % 18.4 % 19.5 %
Schedule Of Deferred Tax Assets And Liabilities	The significant items comprising IPALCO’s net accumulated deferred tax liability recognized on the audited Consolidated Balance Sheets as of December 31, 2023 and 2022 are as follows: 2023 2022 (In Thousands) Deferred tax liabilities: Relating to utility property, net $ 409,675 $ 341,473 Regulatory assets recoverable through future rates 108,823 123,669 Other 17,694 17,953 Total deferred tax liabilities 536,192 483,095 Deferred tax assets: Investment tax credit 5 6 Regulatory liabilities including ARO 168,619 167,725 Investments in tax partnerships 2,501 — Other 3,579 2,723 Total deferred tax assets 174,704 170,454 Deferred income tax liability – net $ 361,488 $ 312,641
Reconciliation Of Unrecognized Tax Benefits	The following is a reconciliation of the beginning and ending amounts of unrecognized tax benefits for the years ended December 31, 2023, 2022 and 2021: 2023 2022 2021 (In Thousands) Unrecognized tax benefits at January 1 $ — $ — $ 7,368 Gross decreases – prior period tax positions — — (7,368) Unrecognized tax benefits at December 31 $ — $ — $ —
Indianapolis Power And Light Company
Entity Information [Line Items]
Schedule Of Federal And State Income Taxed Charged To Income	Federal and state income taxes charged to income are as follows: 2023 2022 2021 (In Thousands) Components of income tax expense: Current income taxes: Federal $ 1,816 $ 31,286 $ 36,353 State 268 8,185 10,325 Total current income taxes 2,084 39,471 46,678 Deferred income taxes: Federal 17,631 (6,822) (7,283) State 5,951 238 (90) Total deferred income taxes 23,582 (6,584) (7,373) Total income tax expense $ 25,666 $ 32,887 $ 39,305
Schedule Of Effective Income Tax Rate	The reasons for the difference, stated as a percentage of pretax income, are as follows: 2023 2022 2021 Federal statutory tax rate 21.0 % 21.0 % 21.0 % State income tax, net of federal tax benefit 3.9 % 3.9 % 4.0 % Depreciation flow through and amortization (8.0) % (5.7) % (4.9) % AFUDC - equity (0.2) % 0.7 % 0.3 % Noncontrolling interests in subsidiaries 5.6 % — % — % Other – net (0.1) % 0.3 % 0.3 % Effective tax rate 22.2 % 20.2 % 20.7 %
Schedule Of Deferred Tax Assets And Liabilities	The significant items comprising AES Indiana’s net accumulated deferred tax liability recognized on the audited Consolidated Balance Sheets as of December 31, 2023 and 2022 are as follows: 2023 2022 (In Thousands) Deferred tax liabilities: Relating to utility property, net $ 409,675 $ 341,473 Regulatory assets recoverable through future rates 108,823 123,669 Other 7,975 22,717 Total deferred tax liabilities 526,473 487,859 Deferred tax assets: Investment tax credit 5 6 Regulatory liabilities including ARO 168,619 167,726 Investments in tax partnerships 2,483 — Operating loss carryforwards 9,230 — Other 3,579 15,020 Total deferred tax assets 183,916 182,752 Deferred income tax liability – net $ 342,557 $ 305,107
Reconciliation Of Unrecognized Tax Benefits	The following is a reconciliation of the beginning and ending amounts of unrecognized tax benefits for the years ended December 31, 2023, 2022 and 2021: 2023 2022 2021 (In Thousands) Unrecognized tax benefits at January 1 $ — $ — $ 7,368 Gross decreases – prior period tax positions — — (7,368) Unrecognized tax benefits at December 31 $ — $ — $ —

Benefit Plans (Tables)

Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2023
Entity Information [Line Items]
Schedule Of Defined Benefit Plans Disclosures	The following table presents information relating to the Pension Plans: Pension benefits 2023 2022 (In Thousands) Change in benefit obligation: Projected benefit obligation at January 1 $ 577,530 $ 772,040 Service cost 5,189 8,949 Interest cost 29,818 18,099 Actuarial loss (gain) 9,681 (182,590) Amendments (primarily increases in pension bands) 653 — Settlements — (394) Benefits paid (73,325) (38,575) Projected benefit obligation at December 31 549,546 577,529 Change in plan assets: Fair value of plan assets at January 1 611,125 820,684 Actual return/(loss) on plan assets 52,905 (171,002) Employer contributions 114 412 Settlements — (394) Benefits paid (73,325) (38,575) Fair value of plan assets at December 31 590,819 611,125 Funded status $ 41,273 $ 33,596 Amounts recognized in the statement of financial position: Non-current assets $ 41,273 $ 33,611 Non-current liabilities — (15) Net amount recognized at end of year $ 41,273 $ 33,596 Sources of change in regulatory assets (1) : Prior service cost arising during period $ 653 $ — Net (gain)/loss arising during period (10,117) 24,069 Amortization of prior service cost (2,172) (2,589) Amortization of loss (6,145) (2,622) Total recognized in regulatory assets $ (17,781) $ 18,858 Amounts included in regulatory assets: Net loss $ 115,297 $ 131,559 Prior service cost 10,136 11,655 Total amounts included in regulatory assets $ 125,433 $ 143,214
Schedule Of Net Periodic Benefit Costs	Pension benefits for 2023 2022 2021 (In Thousands) Components of net periodic benefit cost / (credit): Service cost $ 5,189 $ 8,949 $ 9,339 Interest cost 29,818 18,099 15,660 Expected return on plan assets (33,107) (35,656) (41,815) Amortization of prior service cost 2,172 2,589 2,944 Amortization of actuarial loss 6,145 2,424 5,529 Amortization of settlement loss — 199 — Net periodic benefit cost / (credit) 10,217 (3,396) (8,343) Less: amounts capitalized 1,689 (316) (771) Amount charged to expense $ 8,528 $ (3,080) $ (7,572) Rates relevant to each year’s expense calculations: Discount rate – defined benefit pension plan 5.41 % 2.83 % 2.46 % Discount rate – supplemental retirement plan 5.32 % 2.62 % 2.31 % Expected return on defined benefit pension plan assets 5.60 % 4.45 % 5.05 % Expected return on supplemental retirement plan assets 6.45 % 5.50 % 3.60 %
Schedule Of Asset Allocation Guidelines	The following table summarizes the Company’s target pension plan allocation for 2023: Asset Category: Target Allocations Equity Securities 13.5% Debt Securities 86.5%
Schedule Of Fair Value Of Pension Plan Assets	Fair Value Measurements at December 31, 2023 (in thousands) Quoted Prices in Active Markets for Identical Assets Significant Observable Inputs Asset Category Total (Level 1) (Level 2) % Common collective trusts: Equities (a) $ 82,652 $ 2,267 $ 80,385 14 % Debt securities (b) 387,979 1,168 386,811 66 % Government debt securities (c) 117,397 178 117,219 20 % Total common collective trusts 588,028 3,613 584,415 100 % Cash and cash equivalents (d) 2,791 2,791 — — % Total pension plan assets $ 590,819 $ 6,404 $ 584,415 100 % (a) This category represents investments that invest in equity securities of U.S. companies of any market capitalization and other investments (i.e.: futures, swaps, currency forwards) of foreign, emerging markets and seeks to provide long-term total return, which includes capital appreciation and income. The funds are valued using the net asset value method. (b) This category represents investments that invest in high quality issues within the U.S. corporate bond markets and global high yield bonds and emerging markets debt denominated in local currency. The funds seek to provide current income and long-term capital preservation along with access to higher yielding, relatively liquid fixed income securities. The funds are valued using the net asset value method. (c) This category represents investments that invest in U.S. treasury strips, U.S. government agency obligations, and U.S. treasury obligations. The funds seek investment returns over the long term and are valued using the net asset value method. (d) This category represents an investment that seeks to maximize current income on cash reserves to the extent consistent with principal preservation and maintenance of liquidity from a portfolio of obligations of the U.S. Government, its agencies or municipalities, and related money market instruments. Principal preservation is a primary objective. The fund is valued at cost. Fair Value Measurements at December 31, 2022 (in thousands) Quoted Prices in Active Markets for Identical Assets Significant Observable Inputs Asset Category Total (Level 1) (Level 2) % Common collective trusts: Equities (a) $ 85,341 $ 2,017 $ 83,324 14 % Debt securities (b) 400,291 1,254 399,037 66 % Government debt securities (c) 122,704 420 122,284 20 % Total common collective trusts 608,336 3,691 604,645 100 % Cash and cash equivalents (d) 2,789 2,789 — — % Total pension plan assets $ 611,125 $ 6,480 $ 604,645 100 %
Schedule Of Expected Benefit Payments	Benefit payments, which reflect future service, are expected to be paid out of the Pension Plans as follows: Year Pension Benefits (In Thousands) 2024 $ 37,997 2025 38,794 2026 39,665 2027 40,085 2028 41,477 2029 through 2033 200,574
Indianapolis Power And Light Company
Entity Information [Line Items]
Schedule Of Defined Benefit Plans Disclosures	Pension benefits 2023 2022 (In Thousands) Change in benefit obligation: Projected benefit obligation at January 1 $ 577,530 $ 772,040 Service cost 5,189 8,949 Interest cost 29,818 18,099 Actuarial loss (gain) 9,681 (182,590) Amendments (primarily increases in pension bands) 653 — Settlements — (394) Benefits paid (73,325) (38,575) Projected benefit obligation at December 31 549,546 577,529 Change in plan assets: Fair value of plan assets at January 1 611,125 820,684 Actual return/(loss) on plan assets 52,905 (171,002) Employer contributions 114 412 Settlements — (394) Benefits paid (73,325) (38,575) Fair value of plan assets at December 31 590,819 611,125 Funded status $ 41,273 $ 33,596 Amounts recognized in the statement of financial position: Non-current assets $ 41,273 $ 33,611 Non-current liabilities — (15) Net amount recognized at end of year $ 41,273 $ 33,596 Sources of change in regulatory assets (1) : Prior service cost arising during period $ 653 $ — Net (gain)/loss arising during period (10,117) 24,069 Amortization of prior service cost (2,172) (2,589) Amortization of loss (6,145) (2,622) Total recognized in regulatory assets $ (17,781) $ 18,858 Amounts included in regulatory assets: Net loss $ 115,297 $ 131,559 Prior service cost 10,136 11,655 Total amounts included in regulatory assets $ 125,433 $ 143,214
Schedule Of Net Periodic Benefit Costs	Pension benefits for 2023 2022 2021 (In Thousands) Components of net periodic benefit cost / (credit): Service cost $ 5,189 $ 8,949 $ 9,339 Interest cost 29,818 18,099 15,660 Expected return on plan assets (33,107) (35,656) (41,815) Amortization of prior service cost 2,172 2,589 2,944 Amortization of actuarial loss 6,145 2,424 5,529 Amortization of settlement loss — 199 — Net periodic benefit cost / (credit) 10,217 (3,396) (8,343) Less: amounts capitalized 1,689 (316) (771) Amount charged to expense $ 8,528 $ (3,080) $ (7,572) Rates relevant to each year’s expense calculations: Discount rate – defined benefit pension plan 5.41 % 2.83 % 2.46 % Discount rate – supplemental retirement plan 5.32 % 2.62 % 2.31 % Expected return on defined benefit pension plan assets 5.60 % 4.45 % 5.05 % Expected return on supplemental retirement plan assets 6.45 % 5.50 % 3.60 %
Schedule Of Asset Allocation Guidelines	Asset Category: Target Allocations Equity Securities 13.5% Debt Securities 86.5%
Schedule Of Fair Value Of Pension Plan Assets	Fair Value Measurements at December 31, 2023 (in thousands) Quoted Prices in Active Markets for Identical Assets Significant Observable Inputs Asset Category Total (Level 1) (Level 2) % Common collective trusts: Equities (a) $ 82,652 $ 2,267 $ 80,385 14 % Debt securities (b) 387,979 1,168 386,811 66 % Government debt securities (c) 117,397 178 117,219 20 % Total common collective trusts 588,028 3,613 584,415 100 % Cash and cash equivalents (d) 2,791 2,791 — — % Total pension plan assets $ 590,819 $ 6,404 $ 584,415 100 % (a) This category represents investments that invest in equity securities of U.S. companies of any market capitalization and other investments (i.e.: futures, swaps, currency forwards) of foreign, emerging markets and seeks to provide long-term total return, which includes capital appreciation and income. The funds are valued using the net asset value method. (b) This category represents investments that invest in high quality issues within the U.S. corporate bond markets and global high yield bonds and emerging markets debt denominated in local currency. The funds seek to provide current income and long-term capital preservation along with access to higher yielding, relatively liquid fixed income securities. The funds are valued using the net asset value method. (c) This category represents investments that invest in U.S. treasury strips, U.S. government agency obligations, and U.S. treasury obligations. The funds seek investment returns over the long term and are valued using the net asset value method. (d) This category represents an investment that seeks to maximize current income on cash reserves to the extent consistent with principal preservation and maintenance of liquidity from a portfolio of obligations of the U.S. Government, its agencies or municipalities, and related money market instruments. Principal preservation is a primary objective. The fund is valued at cost. Fair Value Measurements at December 31, 2022 (in thousands) Quoted Prices in Active Markets for Identical Assets Significant Observable Inputs Asset Category Total (Level 1) (Level 2) % Common collective trusts: Equities (a) $ 85,341 $ 2,017 $ 83,324 14 % Debt securities (b) 400,291 1,254 399,037 66 % Government debt securities (c) 122,704 420 122,284 20 % Total common collective trusts 608,336 3,691 604,645 100 % Cash and cash equivalents (d) 2,789 2,789 — — % Total pension plan assets $ 611,125 $ 6,480 $ 604,645 100 %
Schedule Of Expected Benefit Payments	Year Pension Benefits (In Thousands) 2024 $ 37,997 2025 38,794 2026 39,665 2027 40,085 2028 41,477 2029 through 2033 200,574

Commitment and Contingencies (T

Commitment and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2023
Commitments and Contingencies Disclosure [Abstract]
Oil and Gas, Delivery Commitment	Payments due in: Total Less Than 1 Year 1 – 3 3 – 5 More Than (In Millions) Purchase obligations: Coal, gas, purchased power and related transportation $ 933.5 $ 249.7 $ 267.3 $ 225.7 $ 190.8 Other $ 409.1 $ 355.0 $ 32.8 $ 20.2 $ 1.1

Business Segment Information (T

Business Segment Information (Tables)	12 Months Ended
	Dec. 31, 2023
Segment Reporting [Abstract]
Summary Of Company's Reporting Segments	The following table provides information about IPALCO’s business segments (in thousands): 2023 2022 2021 Utility Other Total Utility Other Total Utility Other Total Revenue $ 1,649,917 $ — $ 1,649,917 $ 1,791,711 $ — $ 1,791,711 $ 1,426,132 $ — $ 1,426,132 Depreciation and amortization $ 287,863 $ — $ 287,863 $ 266,504 $ — $ 266,504 $ 256,085 $ — $ 256,085 Interest expense $ 99,051 $ 43,875 $ 142,926 $ 87,428 $ 43,804 $ 131,232 $ 84,256 $ 41,370 $ 125,626 Income/(loss) before income tax $ 115,763 $ (44,021) $ 71,742 $ 162,862 $ (44,377) $ 118,485 $ 189,548 $ (41,425) $ 148,123 Capital expenditures (1) $ 902,705 $ — $ 902,705 $ 496,510 $ — $ 496,510 $ 291,546 $ — $ 291,546 (1) Capital expenditures includes $0 thousand, $0 thousand and $36 thousand of payments for financed capital expenditures in 2023, 2022 and 2021, respectively. As of December 31, 2023 As of December 31, 2022 As of December 31, 2021 Total assets $ 6,129,581 $ 51,942 $ 6,181,523 $ 5,559,977 $ 29,237 $ 5,589,214 $ 5,222,987 $ 16,780 $ 5,239,767

Revenue (Tables)

Revenue (Tables)	12 Months Ended
	Dec. 31, 2023
Disaggregation of Revenue [Line Items]
Disaggregation of Revenue [Table Text Block]	’s revenue from contracts with customers was $1,616.5 million, $1,760.0 million and $1,389.2 million for the years ended December 31, 2023 , 2022 and 2021, respectively. The following table presents our revenue from contracts with customers and other revenue (in thousands): For the Years Ended December 31, 2023 2022 2021 Retail Revenue Retail revenue from contracts with customers: Residential $ 660,559 $ 688,487 $ 595,692 Small commercial and industrial 241,800 247,655 211,997 Large commercial and industrial 619,899 625,351 518,069 Public lighting 9,767 9,832 8,888 Other (1) 14,016 17,845 16,785 Total retail revenue from contracts with customers 1,546,041 1,589,170 1,351,431 Alternative revenue programs 30,414 29,171 35,248 Wholesale Revenue Wholesale revenue from contracts with customers 56,557 148,517 25,059 Miscellaneous Revenue Capacity revenue 8,210 11,750 734 Transmission and other revenue 5,654 10,534 11,480 Total miscellaneous revenue from contracts with customers 13,864 22,284 12,214 Other miscellaneous revenue (2) 3,041 2,569 2,180 Total Revenue $ 1,649,917 $ 1,791,711 $ 1,426,132
Revenue from Contract with Customer [Text Block]	REVENUE Revenue is primarily earned from retail and wholesale electricity sales and electricity transmission and distribution delivery services. Revenue is recognized upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Revenue is recorded net of any taxes assessed on and collected from customers, which are remitted to the governmental authorities. Retail revenue - AES Indiana energy sales to utility customers are based on the reading of meters at the customer’s location that occurs on a systematic basis throughout the month. AES Indiana sells electricity directly to end-users, such as homes and businesses, and bills customers directly. Retail revenue have a single performance obligation, as the promise to transfer energy and other distribution and/or transmission services are not separately identifiable from other promises in the contracts and, therefore, are not distinct. Additionally, as the performance obligation is satisfied over time as energy is delivered, and the same method is used to measure progress, the performance obligation meets the criteria to be considered a series. In exchange for the exclusive right to sell or distribute electricity in our service area, AES Indiana is subject to rate regulation by federal and state regulators. This regulation sets the framework for the prices (“tariffs”) that AES Indiana is allowed to charge customers for electric services. Since tariffs are approved by the regulator, the price that AES Indiana has the right to bill corresponds directly with the value to the customer of AES Indiana’s performance completed in each period. Therefore, revenue under these contracts is recognized using an output method measured by the MWhs delivered each month at the approved tariff. Customer payments are typically due on a monthly basis. Wholesale revenue - Power produced at the generation stations in excess of our retail load is sold into the MISO market. Such sales are made at either the day-ahead or real-time hourly market price, and these sales are classified as wholesale revenue. We sell to and purchase power from MISO, and such sales and purchases are settled and accounted for on a net hourly basis. In the MISO market, wholesale revenue is recorded at the spot price based on the quantities of MWh delivered in each hour during each month. As a member of MISO, we are obligated to declare the availability of our energy production into the wholesale energy market, but we are not obligated to commit our previously declared availability. As such, contract terms end as the energy for each day is delivered to the market in the case of the day-ahead market and for each hour in the case of the real-time market. Miscellaneous revenue - Miscellaneous revenue is mainly comprised of MISO transmission revenue and capacity revenue. MISO transmission revenue is earned when AES Indiana’s power lines are used in transmission of energy by power producers other than AES Indiana. As AES Indiana owns and operates transmission lines in central and southern Indiana, demand charges collected from network customers by MISO are allocated to the appropriate transmission owners (including AES Indiana) and recognized as transmission revenue. Capacity revenue is also included in miscellaneous revenue, and represent compensation received from MISO for making installed generation capacity available to satisfy system integrity and reliability requirements through the annual MISO capacity auction. Capacity, which is a stand-ready obligation to deliver energy when called upon by the RTO, is measured using MWs. Transmission and capacity revenue each have a single performance obligation, as they each represent a distinct service or good. Additionally, as these performance obligations are satisfied over time and the same method is used to measure progress, the performance obligations meet the criteria to be considered a series. For transmission revenue, the price that the transmission operator has the right to bill corresponds directly with the value to the customer of AES Indiana’s performance completed in each period as the price paid is the transmission operator's allocation of the tariff rate (as approved by the regulator) charged to network participants. For capacity revenue, the capacity price that clears at the auction is fixed and AES Indiana is compensated based on the cleared MWs and cleared price. AES Indiana’s revenue from contracts with customers was $1,616.5 million, $1,760.0 million and $1,389.2 million for the years ended December 31, 2023 , 2022 and 2021, respectively. The following table presents our revenue from contracts with customers and other revenue (in thousands): For the Years Ended December 31, 2023 2022 2021 Retail Revenue Retail revenue from contracts with customers: Residential $ 660,559 $ 688,487 $ 595,692 Small commercial and industrial 241,800 247,655 211,997 Large commercial and industrial 619,899 625,351 518,069 Public lighting 9,767 9,832 8,888 Other (1) 14,016 17,845 16,785 Total retail revenue from contracts with customers 1,546,041 1,589,170 1,351,431 Alternative revenue programs 30,414 29,171 35,248 Wholesale Revenue Wholesale revenue from contracts with customers 56,557 148,517 25,059 Miscellaneous Revenue Capacity revenue 8,210 11,750 734 Transmission and other revenue 5,654 10,534 11,480 Total miscellaneous revenue from contracts with customers 13,864 22,284 12,214 Other miscellaneous revenue (2) 3,041 2,569 2,180 Total Revenue $ 1,649,917 $ 1,791,711 $ 1,426,132 (1) Other retail revenue from contracts with customers includes miscellaneous charges to customers, including reconnection and late fee charges. (2) Other miscellaneous revenue includes lease and other miscellaneous revenue not accounted for under ASC 606. The balances of receivables from contracts with customers were $218.8 million and $198.3 million as of December 31, 2023 and 2022, respectively. Payment terms for all receivables from contracts with customers typically do not extend beyond 30 days, unless a customer qualifies for payment extension. The Company has elected to apply the optional disclosure exemptions under ASC 606. Therefore, the Company has not included disclosure pertaining to revenue expected to be recognized in any future year related to remaining performance obligations, as we exclude contracts with an original length of one year or less, contracts for which we recognize revenue based on the amount we have the right to invoice for services performed, and contracts with variable consideration allocated entirely to a wholly unsatisfied performance obligation when the consideration relates specifically to our efforts to satisfy the performance obligation and depicts the amount to which we expect to be entitled.
Indianapolis Power And Light Company
Disaggregation of Revenue [Line Items]
Disaggregation of Revenue [Table Text Block]	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 $ 660,559 $ 688,487 $ 595,692 Small commercial and industrial 241,800 247,655 211,997 Large commercial and industrial 619,899 625,351 518,069 Public lighting 9,767 9,832 8,888 Other (1) 14,016 17,845 16,785 Total retail revenue from contracts with customers 1,546,041 1,589,170 1,351,431 Alternative revenue programs 30,414 29,171 35,248 Wholesale Revenue Wholesale revenue from contracts with customers 56,557 148,517 25,059 Miscellaneous Revenue Capacity revenue 8,210 11,750 734 Transmission and other revenue 5,654 10,534 11,480 Total miscellaneous revenue from contracts with customers 13,864 22,284 12,214 Other miscellaneous revenue (2) 3,041 2,569 2,180 Total Revenue $ 1,649,917 $ 1,791,711 $ 1,426,132 (1) Other retail revenue from contracts with customers includes miscellaneous charges to customers, including reconnection and late fee charges. (2) Other miscellaneous revenue includes lease and other miscellaneous revenue not accounted for under ASC 606.
Revenue from Contract with Customer [Text Block]	Revenue is primarily earned from retail and wholesale electricity sales and electricity transmission and distribution delivery services. Revenue is recognized upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Revenue is recorded net of any taxes assessed on and collected from customers, which are remitted to the governmental authorities. Retail revenue - AES Indiana energy sales to utility customers are based on the reading of meters at the customer’s location that occurs on a systematic basis throughout the month. AES Indiana sells electricity directly to end-users, such as homes and businesses, and bills customers directly. Retail revenue have a single performance obligation, as the promise to transfer energy and other distribution and/or transmission services are not separately identifiable from other promises in the contracts and, therefore, are not distinct. Additionally, as the performance obligation is satisfied over time as energy is delivered, and the same method is used to measure progress, the performance obligation meets the criteria to be considered a series. In exchange for the exclusive right to sell or distribute electricity in our service area, AES Indiana is subject to rate regulation by federal and state regulators. This regulation sets the framework for the prices (“tariffs”) that AES Indiana is allowed to charge customers for electric services. Since tariffs are approved by the regulator, the price that AES Indiana has the right to bill corresponds directly with the value to the customer of AES Indiana’s performance completed in each period. Therefore, revenue under these contracts is recognized using an output method measured by the MWhs delivered each month at the approved tariff. Customer payments are typically due on a monthly basis. Wholesale revenue - Power produced at the generation stations in excess of our retail load is sold into the MISO market. Such sales are made at either the day-ahead or real-time hourly market price, and these sales are classified as wholesale revenue. We sell to and purchase power from MISO, and such sales and purchases are settled and accounted for on a net hourly basis. In the MISO market, wholesale revenue is recorded at the spot price based on the quantities of MWh delivered in each hour during each month. As a member of MISO, we are obligated to declare the availability of our energy production into the wholesale energy market, but we are not obligated to commit our previously declared availability. As such, contract terms end as the energy for each day is delivered to the market in the case of the day-ahead market and for each hour in the case of the real-time market. Miscellaneous revenue - Miscellaneous revenue is mainly comprised of MISO transmission revenue and capacity revenue. MISO transmission revenue is earned when AES Indiana’s power lines are used in transmission of energy by power producers other than AES Indiana. As AES Indiana owns and operates transmission lines in central and southern Indiana, demand charges collected from network customers by MISO are allocated to the appropriate transmission owners (including AES Indiana) and recognized as transmission revenue. Capacity revenue is also included in miscellaneous revenue, and represent compensation received from MISO for making installed generation capacity available to satisfy system integrity and reliability requirements through the annual MISO capacity auction. Capacity, which is a stand-ready obligation to deliver energy when called upon by the RTO, is measured using MWs. Transmission and capacity revenue each have a single performance obligation, as they each represent a distinct service or good. Additionally, as these performance obligations are satisfied over time and the same method is used to measure progress, the performance obligations meet the criteria to be considered a series. For transmission revenue, the price that the transmission operator has the right to bill corresponds directly with the value to the customer of AES Indiana’s performance completed in each period as the price paid is the transmission operator's allocation of the tariff rate (as approved by the regulator) charged to network participants. For capacity revenue, the capacity price that clears at the auction is fixed and AES Indiana is compensated based on the cleared MWs and cleared price. AES Indiana’s revenue from contracts with customers was $1,616.5 million , $1,760.0 million and $1,389.2 million for the years ended December 31, 2023 , 2022 and 2021, respectively. The following table presents AES Indiana's revenue from contracts with customers and other revenue (in thousands): For the Years Ended December 31, 2023 2022 2021 Retail Revenue Retail revenue from contracts with customers: Residential $ 660,559 $ 688,487 $ 595,692 Small commercial and industrial 241,800 247,655 211,997 Large commercial and industrial 619,899 625,351 518,069 Public lighting 9,767 9,832 8,888 Other (1) 14,016 17,845 16,785 Total retail revenue from contracts with customers 1,546,041 1,589,170 1,351,431 Alternative revenue programs 30,414 29,171 35,248 Wholesale Revenue Wholesale revenue from contracts with customers 56,557 148,517 25,059 Miscellaneous Revenue Capacity revenue 8,210 11,750 734 Transmission and other revenue 5,654 10,534 11,480 Total miscellaneous revenue from contracts with customers 13,864 22,284 12,214 Other miscellaneous revenue (2) 3,041 2,569 2,180 Total Revenue $ 1,649,917 $ 1,791,711 $ 1,426,132 (1) Other retail revenue from contracts with customers includes miscellaneous charges to customers, including reconnection and late fee charges. (2) Other miscellaneous revenue includes lease and other miscellaneous revenue not accounted for under ASC 606. The balances of receivables from contracts with customers were $218.8 million and $198.3 million as of December 31, 2023 and 2022, respectively. Payment terms for all receivables from contracts with customers typically do not extend beyond 30 days, unless a customer qualifies for payment extension. AES Indiana has elected to apply the optional disclosure exemptions under ASC 606. Therefore, AES Indiana has not included disclosure pertaining to revenue expected to be recognized in any future year related to remaining performance obligations, as we exclude contracts with an original length of one year or less, contracts for which we recognize revenue based on the amount we have the right to invoice for services performed, and contracts with variable consideration allocated entirely to a wholly unsatisfied performance obligation when the consideration relates specifically to our efforts to satisfy the performance obligation and depicts the amount to which AES Indiana expects to be entitled.

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2023
Leases [Abstract]
Lease Balance Sheet Components	The following table summarizes the amounts recognized on the Consolidated Balance Sheets related to lease asset and liability balances as of the periods indicated (in thousands): Consolidated Balance Sheet Classification December 31, 2023 December 31, 2022 Assets Right-of-use assets — finance leases Other non-current assets $ 16,357 $ 15,819 Liabilities Finance lease liabilities (noncurrent) Long-term debt $ 17,769 $ 16,361 Total finance lease liabilities $ 17,769 $ 16,361
Lease Term and Discount Rate	The following table summarizes supplemental balance sheet information related to leases as of the periods indicated: Lease Term and Discount Rate December 31, 2023 December 31, 2022 Weighted-average remaining lease term — finance leases 35 years 36 years Weighted-average discount rate — finance leases 5.30 % 5.650 %
Lease, Cost	The following table summarizes the components of lease expense recognized in " Operating Costs and Expenses " on the accompanying Consolidated Statements of Operations for the years ended December 31, 2023 , 2022 and 2021, respectively (in thousands): For the Year Ended December 31, Components of Lease Cost 2023 2022 2021 Finance lease cost: Amortization of right-of-use assets $ 445 $ 542 $ — Interest on lease liabilities 933 782 — Total lease cost $ 1,378 $ 1,324 $ —
Schedule of Future Minimum Rental Payments for Operating Leases	The following table shows the future lease payments under finance leases together with the present value of the net lease payments as of December 31, 2023 for 2024 through 2028 and thereafter (in thousands): Finance Leases 2024 $ 891 2025 909 2026 927 2027 945 2028 965 Thereafter 39,958 Total $ 44,595 Less: Imputed interest (26,826) Present value of lease payments $ 17,769
Operating Lease, Lease Income	For the Year Ended December 31, 2023 2022 2021 Total lease revenue $ 1,537 $ 1,134 $ 1,439
Schedule of Capital Leased Assets	Property, Plant and Equipment, Net December 31, 2023 December 31, 2022 Gross assets $ 4,341 $ 4,334 Less: Accumulated depreciation (1,222) (1,060) Net assets $ 3,119 $ 3,274

Overview and Summary of Signi_4

Overview and Summary of Significant Accounting Policies (Details)		12 Months Ended
	Feb. 16, 2026	Dec. 31, 2023 USD ($) customer generating_station item MW	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2019 segment	May 31, 2021	Dec. 31, 2020 USD ($)
Significant Accounting Policies [Line Items]
Accumulated Other Comprehensive Income (Loss), Net of Tax		$ 29,294,000	$ 22,269,000	$ (29,407,000)			$ (43,420,000)
Other Comprehensive Income (Loss), Net of Tax		7,025,000	51,676,000	14,013,000
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax		1,594,000	46,245,000	10,393,000
Public Utilities, Approved Rate Increase (Decrease), Amount		43,900,000
Public Utilities, Inventory		77,198,000	60,497,000
Receivables from Customers		125,715,000	125,540,000
Cash and Cash Equivalents, at Carrying Value		28,579,000	201,548,000
Service cost		5,189,000	8,949,000	9,339,000
Interest cost		$ 29,818,000	18,099,000	$ 15,660,000
Ownership interest in IPALCO by AES U.S. Investments (percent)		82.35%
Ownership interest in IPALCO by CDPQ (percent)		17.65%
Number of customers | customer		523,000
Number of generating stations | generating_station		4
Electric generation capability for winter, megawatts | MW		3,070
Electric generation capability for summer, megawatts | MW		2,925
Total other non-current assets		$ 1,120,591,000	849,054,000
Unbilled energy revenues		91,463,000	74,488,000
Loans and Leases Receivable, Related Parties, Description		5,178,000	239,000
Provision for doubtful accounts		$ 7,413,000	$ 5,851,000
Number of suppliers | item		1
Capitalized amount, rate		7.10%	5.40%	5.70%
Depreciation rate		3.70%	3.80%	3.70%
Depreciation expense		$ 244,800,000	$ 247,500,000	$ 239,100,000
Utility plant assets		4,500,000,000	4,000,000,000
Number of segments | segment					2
Intangible assets - net		235,656,000	138,978,000
Restricted Cash and Cash Equivalents		5,000	5,000
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents		28,584,000	201,553,000	6,917,000			26,622,000
Other Receivables		13,848,000	17,373,000
Accounts Receivable, Allowance for Credit Loss		(2,283,000)	(1,117,000)
Receivables, Net, Current		233,921,000	216,523,000
Materials and Supplies, Average Cost		66,392,000	63,111,000
Inventory, Net		143,590,000	123,608,000
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax		1,594,000	46,245,000	10,393,000
Reclassification from AOCI, Current Period, Net of Tax, Attributable to Parent		5,431,000	5,431,000	3,620,000
Accounts receivable and unbilled revenue, allowance for doubtful accounts		2,283,000	1,117,000	647,000
Accounts Receivable, Allowance for Credit Loss, Writeoff		(7,764,000)	(7,008,000)
Accounts Receivable, Allowance for Credit Loss, Recovery		1,517,000	1,627,000
Income Tax Expense (Benefit)		(14,715,000)	(21,859,000)	(28,941,000)
Regulatory assets, non-current		541,784,000	593,939,000
Provision for Expected Credit Losses		$ 7,500,000	5,900,000	3,000,000
Preferred Resource Portfolio Coal-Fired Generation Retirement MW by 2023		630
Hardy Hills Solar Project MW		195
Public Utilities, Property, Plant and Equipment, Net		$ 4,500,000,000	4,000,000,000
Other Assets, Noncurrent		$ 1,120,591,000	849,054,000
Gain on acquisition				$ 5,600,000
Petersburg Unit 1 Retired MW						230
Petersburg Unit 2 Planned Retirement MW in 2023		415
Gain on remeasurement of contingent consideration			$ 3,200,000
Petersburg Energy Center Project MW		250
Public Utilities, Allowance for Funds Used During Construction, Description		9,315	4,784	5,412
Allowance for Funds Used During Construction, Capitalized Interest		$ 13,739,000	$ 8,215,000	$ 4,815,000
Pike Co BESS Project MW		200
Petersburg Energy Storage Project MW		45
Petersburg Energy Storage Project MwH		180
Pike Co BESS Project MwH		800
Software and Software Development Costs
Significant Accounting Policies [Line Items]
Acquired Finite-Lived Intangible Assets, Weighted Average Useful Life		8 years
Deferred Project Costs [Member]
Significant Accounting Policies [Line Items]
Acquired Finite-Lived Intangible Assets, Weighted Average Useful Life		28 years
Prepaid Implementation Costs for Software as a Service
Significant Accounting Policies [Line Items]
Total other non-current assets		$ 7,100,000	8,200,000
Other Assets, Noncurrent		$ 7,100,000	8,200,000
Harding Street [Member]
Significant Accounting Policies [Line Items]
Amount of New Operation for Battery Storage Unit, megawatts | MW		20
Labor Force Concentration Risk [Member]
Significant Accounting Policies [Line Items]
Concentration risk percentage		68%
Parent Company [Member]
Significant Accounting Policies [Line Items]
Accumulated Other Comprehensive Income (Loss), Net of Tax		$ 29,294,000	22,269,000	(29,407,000)			(43,420,000)
Other Comprehensive Income (Loss), Net of Tax		7,025,000	51,676,000	14,013,000
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax		1,594,000	46,245,000	10,393,000
Cash and Cash Equivalents, at Carrying Value		537,000	191,000
Total other non-current assets		1,925,088,000	1,960,939,000
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents		537,000	191,000	1,902,000			6,417,000
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax		1,594,000	46,245,000	10,393,000
Reclassification from AOCI, Current Period, Net of Tax, Attributable to Parent		5,431,000	5,431,000	3,620,000
Income Tax Expense (Benefit)		10,928,000	11,027,000	10,364,000
Other Assets, Noncurrent		1,925,088,000	1,960,939,000
Indianapolis Power And Light Company
Significant Accounting Policies [Line Items]
Public Utilities, Inventory		77,198,000	60,497,000
Receivables from Customers		125,715,000	125,540,000
Cash and Cash Equivalents, at Carrying Value		25,767,000	199,103,000
Capitalized Computer Software, Gross		261,872,000	205,910,000
Emissions Allowance		797,000	797,000
Service cost		5,189,000	8,949,000	9,339,000
Interest cost		$ 29,818,000	18,099,000	$ 15,660,000
Number of customers | customer		523,000
Electric generation capability for winter, megawatts | MW		3,070
Electric generation capability for summer, megawatts | MW		2,925
Total other non-current assets		$ 1,117,051,000	833,536,000
Unbilled energy revenues		91,463,000	74,488,000
Loans and Leases Receivable, Related Parties, Description		5,227,000	288,000
Provision for doubtful accounts		$ 7,413,000	$ 5,851,000
Capitalized amount, rate		7.10%	5.40%	5.70%
Depreciation rate		3.70%	3.80%	3.70%
Depreciation expense		$ 244,800,000	$ 247,500,000	$ 239,100,000
Utility plant assets		4,500,000,000	4,000,000,000
Capitalized Computer Software, Accumulated Amortization		(111,110,000)	(107,184,000)
Intangible assets - net		235,656,000	138,978,000
Capitalized Computer Software, Amortization		14,570,000	10,122,000	11,241,000
Finite-Lived Intangible Asset, Expected Amortization, Year One		20,764,000
Finite-Lived Intangible Asset, Expected Amortization, Year Two		20,764,000
Finite-Lived Intangible Asset, Expected Amortization, Year Three		22,550,000
Finite-Lived Intangible Asset, Expected Amortization, Year Four		22,550,000
Finite-Lived Intangible Asset, Expected Amortization, Year Five		22,550,000
Finite-Lived Intangible Assets, Amortization Expense, Rolling after Year Five		109,178,000
Restricted Cash and Cash Equivalents		5,000	5,000
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents		25,772,000	199,108,000	2,761,000			$ 17,951,000
Other Receivables		13,848,000	17,373,000
Accounts Receivable, Allowance for Credit Loss		(2,283,000)	(1,117,000)
Receivables, Net, Current		233,970,000	216,572,000
Materials and Supplies, Average Cost		66,392,000	63,111,000
Inventory, Net		$ 143,590,000	123,608,000
Allowance for Credit Losses		The following table is a rollforward of our allowance for credit losses related to the accounts receivable balances for the periods indicated: For the Years Ended December 31, 2023 2022 (In Thousands) Allowance for credit losses: Beginning balance $ 1,117 $ 647 Current period provision 7,413 5,851 Write-offs charged against allowance (7,764) (7,008) Recoveries collected 1,517 1,627 Ending Balance $ 2,283 $ 1,117
Accounts receivable and unbilled revenue, allowance for doubtful accounts		$ 2,283,000	1,117,000	647,000
Accounts Receivable, Allowance for Credit Loss, Writeoff		(7,764,000)	(7,008,000)
Accounts Receivable, Allowance for Credit Loss, Recovery		1,517,000	1,627,000
Income Tax Expense (Benefit)		(25,666,000)	(32,887,000)	(39,305,000)
Regulatory assets, non-current		541,784,000	593,939,000
Provision for Expected Credit Losses		$ 7,500,000	5,900,000	3,000,000
Preferred Resource Portfolio Coal-Fired Generation Retirement MW by 2023		630
Hardy Hills Solar Project MW		195
Public Utilities, Property, Plant and Equipment, Net		$ 4,500,000,000	4,000,000,000
Project Development Intangible Assets		84,097,000	39,455,000
Other Assets, Noncurrent		$ 1,117,051,000	833,536,000
Gain on acquisition				$ 5,600,000
Gain on remeasurement of contingent consideration			$ 3,200,000
Petersburg Energy Center Project MW		250
Public Utilities, Allowance for Funds Used During Construction, Description		9,315	4,784	5,412
Allowance for Funds Used During Construction, Capitalized Interest		$ 13,739,000	$ 8,215,000	$ 4,815,000
Pike Co BESS Project MW		200
Pike Co BESS Project MwH		800
Indianapolis Power And Light Company | Software and Software Development Costs
Significant Accounting Policies [Line Items]
Acquired Finite-Lived Intangible Assets, Weighted Average Useful Life		8 years
Indianapolis Power And Light Company | Deferred Project Costs [Member]
Significant Accounting Policies [Line Items]
Acquired Finite-Lived Intangible Assets, Weighted Average Useful Life		28 years
Indianapolis Power And Light Company | Prepaid Implementation Costs for Software as a Service
Significant Accounting Policies [Line Items]
Total other non-current assets		$ 7,100,000	8,200,000
Other Assets, Noncurrent		$ 7,100,000	8,200,000
Indianapolis Power And Light Company | Harding Street [Member]
Significant Accounting Policies [Line Items]
Amount of New Operation for Battery Storage Unit, megawatts | MW		20
Indianapolis Power And Light Company | Labor Force Concentration Risk [Member]
Significant Accounting Policies [Line Items]
Concentration risk percentage		68%
AES U.S. Holdings, LLC [Member]
Significant Accounting Policies [Line Items]
Ownership Interest in Parent Company, Percent		85%
CDPQ [Member]
Significant Accounting Policies [Line Items]
Ownership Interest in Parent Company, Percent		15%
Physical Unit [Member]
Significant Accounting Policies [Line Items]
Collective bargaining agreement expiration date	Dec. 04, 2024
Subsequent Event [Member] | Clerical-Technical Unit [Member]
Significant Accounting Policies [Line Items]
Collective bargaining agreement expiration date	Feb. 12, 2026
Petersburg Unit 1 retirement
Significant Accounting Policies [Line Items]
Regulatory assets, non-current		$ 35,700,000
Petersburg Unit 1 retirement | Indianapolis Power And Light Company
Significant Accounting Policies [Line Items]
Regulatory assets, non-current			287,463,000
Petersburg Unit 1 retirement and 2 retirement costs
Significant Accounting Policies [Line Items]
Regulatory assets, non-current		259,892,000	287,463,000
Petersburg Unit 1 retirement and 2 retirement costs | Indianapolis Power And Light Company
Significant Accounting Policies [Line Items]
Regulatory assets, non-current		259,892,000
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]
Significant Accounting Policies [Line Items]
Interest and Debt Expense		(7,229,000)	(7,229,000)	(4,819,000)
Income Tax Expense (Benefit)		(1,798,000)	(1,798,000)	(1,199,000)
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest		$ 5,431,000	$ 5,431,000	$ 3,620,000

Regulatory Matters (Narrative)

Regulatory Matters (Narrative) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2023 USD ($) MW	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020	Dec. 31, 2019	Jan. 01, 2023 USD ($)	Jul. 24, 2019 USD ($)
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities, current	$ 23,371	$ 23,348
Regulatory assets, current	89,419	119,723
Regulatory assets, non-current	$ 541,784	$ 593,939
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21%	21%	21%
Equipment recovery approved amount	$ 129,700
Revenue requirement to be included in rate	8,900
Public Utlities, Approved Shareholder Incentives	2,700	$ 8,300	$ 7,200
Regulatory Assets	631,203	713,662
Regulatory assets	89,419	119,723
Public Utilities, Approved Rate Increase (Decrease), Amount	$ 43,900
Public Utilities, Approved Rate Increase (Decrease), Percentage	3.20%
TDSIC Eligible Cost Recovery Through Periodic Rate Adjustment Mechanism Plan, Percent	80%
TDSIC Planned Recoverable Costs Deferred For Future Recovery, Percent	20%
Periodic Rate Adjustment Mechanism Cap, Percent	2%
TDSIC Plan Improvement Costs							$ 1,200,000
Preferred Resource Portfolio Coal-Fired Generation Retirement MW by 2023	630
Inventory Write-down	$ 700	2,100
Reduction to Revenue	0	300	$ 5,500
Regulatory Liability, Noncurrent	527,224	612,585
Tax rate before change due to Tax Cuts and Jobs Act of 2017				35%
Tax rate after Tax Cuts and Jobs Act of 2017			21%
COVID-19 related uncollectible and incremental bad debt expense	5,400
Regulatory Liabilities	550,595	635,933
Regulatory liabilities	527,224	612,585
Jurisdictional Revenue Requirement Approved by the IURC to be included in AES Indiana’s rates for the twelve-month period ending October 2022	$ 56,500
Hardy Hills Solar Project MW	195
Total Assets Recorded in the Accompanying Consolidated Balance Sheets Associated with the Hardy Hills Solar Project Acquisition	$ 51,600
Asset Acquisition, Consideration Transferred, Contingent Consideration		0	$ 3,200
Estimated Projected Costs to Successfully Implement the Services Proposed in the EV Portfolio	16,200
AES Indiana’s equipment approved for TDSIC recovery	399,600
Eagle Valley uncollectible outage costs, net	21,000
Customer Credit	6,800
Eagle Valley uncollectible outage costs, gross	27,800
Capital Projects, Write-Offs		1,500
Public Utilities, Requested Rate Increase (Decrease), Amount	73,000
Limited Partners' Contributed Capital	79,300
Net Income (Loss) Attributable to Noncontrolling Interest	(26,093)
Asset Acquisition, Indemnification Asset, Amount	$ 48,700
Petersburg Energy Center Project MW	250
Petersburg Energy Center Project MW Unit 1	230
Petersburg Energy Center Project MW Unit 2	415
Hoosier Wind Project MW	106
Pike Co BESS Project MwH	800
Pike Co BESS Project MW	200
Petersburg Energy Storage Project MW	45
Petersburg Energy Storage Project MwH	180
Overcollection and other credits passed to customers through rate riders [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities, current	$ 19,649	15,803
Financial Transmission Rights [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities, current	3,722	7,545
Asset Retirement Obligation Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability, Noncurrent	451,886	518,797
Regulatory liabilities	451,886	518,797
Other Regulatory Assets (Liabilities) [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability, Noncurrent	0	5,126
Regulatory liabilities	0	5,126
Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities, current	23,371	23,348
Regulatory assets, current	89,419	119,723
Regulatory assets, non-current	$ 541,784	$ 593,939
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21%	21%	21%
Equipment recovery approved amount	$ 129,700
Revenue requirement to be included in rate	8,900
Public Utlities, Approved Shareholder Incentives	2,700	$ 8,300	$ 7,200
Regulatory Assets	631,203	713,662
Regulatory assets	$ 89,419	119,723
TDSIC Eligible Cost Recovery Through Periodic Rate Adjustment Mechanism Plan, Percent	80%
TDSIC Planned Recoverable Costs Deferred For Future Recovery, Percent	20%
Periodic Rate Adjustment Mechanism Cap, Percent	2%
TDSIC Plan Improvement Costs						$ 1,200,000
Preferred Resource Portfolio Coal-Fired Generation Retirement MW by 2023	630
Inventory Write-down			800
Reduction to Revenue	$ 0	300	$ 5,500
Regulatory Liability, Noncurrent	527,224	612,585
Tax rate before change due to Tax Cuts and Jobs Act of 2017				35%
Tax rate after Tax Cuts and Jobs Act of 2017			21%
COVID-19 related uncollectible and incremental bad debt expense	5,400
Regulatory Liabilities	550,595	635,933
Regulatory liabilities	527,224	612,585
Jurisdictional Revenue Requirement Approved by the IURC to be included in AES Indiana’s rates for the twelve-month period ending October 2022	$ 56,500
Hardy Hills Solar Project MW	195
AES Indiana’s equipment approved for TDSIC recovery	$ 399,600
Public Utilities, Requested Rate Increase (Decrease), Amount	73,000
Net Income (Loss) Attributable to Noncontrolling Interest	(26,093)
Asset Acquisition, Indemnification Asset, Amount	$ 48,700
Petersburg Energy Center Project MW	250
Petersburg Energy Center Project MW Unit 1	230
Petersburg Energy Center Project MW Unit 2	415
Hoosier Wind Project MW	106
Pike Co BESS Project MwH	800
Pike Co BESS Project MW	200
Subsidiaries [Member] | HLBV Method
Regulatory Assets And Liabilities [Line Items]
Net Income (Loss) Attributable to Noncontrolling Interest	$ 26,100
Subsidiaries [Member] | Overcollection and other credits passed to customers through rate riders [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities, current	19,649	15,803
Subsidiaries [Member] | Financial Transmission Rights [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities, current	3,722	7,545
Subsidiaries [Member] | Asset Retirement Obligation Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability, Noncurrent	451,886	518,797
Regulatory liabilities	451,886	518,797
Subsidiaries [Member] | Deferred Income Tax Charge [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability, Noncurrent	74,800	88,662
Regulatory liabilities	74,800	88,662
Subsidiaries [Member] | Other Regulatory Assets (Liabilities) [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability, Noncurrent	0	5,126
Regulatory liabilities	$ 0	5,126
Indiana [Member] | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Amount of electricity required to be purchased under purchase power agreement | MW	100
Minnesota [Member] | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Amount of electricity required to be purchased under purchase power agreement | MW	200
Solar Generated Electricity [Member] | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Amount of electricity required to be purchased under purchase power agreement | MW	94.5
Solar Generated Electricity in Operation | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Amount of electricity required to be purchased under purchase power agreement | MW	94
Minimum [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Assets Amortization Period	1 year
Environmental Costs Amortization Period	3 years
TDSIC Costs Amortization Period	1 year
Minimum [Member] | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Assets Amortization Period					1 year
Environmental Costs Amortization Period	3 years
TDSIC Costs Amortization Period	1 year
Maximum [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Assets Amortization Period	43 years
Environmental Costs Amortization Period	43 years
TDSIC Costs Amortization Period	36 years
ECCRA Rider Amortization Recovery Period	30 years
Maximum [Member] | Pike Co BESS Project
Regulatory Assets And Liabilities [Line Items]
ECCRA Rider Amortization Recovery Period	20 years
Maximum [Member] | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Assets Amortization Period					43 years
Environmental Costs Amortization Period	43 years
TDSIC Costs Amortization Period	36 years
Deferred Income Tax Charge [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability, Noncurrent	$ 74,796	88,662
Regulatory liabilities	74,796	88,662
Deferred Income Tax Charge [Member] | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability, Noncurrent	74,796
Regulatory liabilities	74,796
Undercollections of rate riders [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, current	75,416	26,047
Regulatory assets	75,416	26,047
Undercollections of rate riders [Member] | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, current	75,416	26,047
Regulatory assets	75,416	26,047
Amounts being recovered through base rates [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, current	13,815	13,815
Regulatory assets	13,815	13,815
Amounts being recovered through base rates [Member] | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, current	13,815	13,815
Regulatory assets	13,815	13,815
Pension Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	115,847	131,907
Pension Costs [Member] | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	115,847	131,907
Deferred Project Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current		34,483
Deferred Project Costs [Member] | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current		34,483
Unamortized Carrying Charges And Certain Other Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	2,812	3,866
Unamortized Carrying Charges And Certain Other Costs [Member] | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	2,812	3,866
Loss on Reacquired Debt [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	13,379	14,429
Loss on Reacquired Debt [Member] | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	13,379	14,429
Environmental Restoration Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	66,837	68,947
Environmental Restoration Costs [Member] | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	66,837	68,947
Other Miscellaneous [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	2,887	1,027
Other Miscellaneous [Member] | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	2,887	1,027
Deferred MISO Non-fuel Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	21,091
Deferred MISO Non-fuel Costs [Member] | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	21,091
COVID-19
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	5,426	5,426
COVID-19 | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	5,426	5,426
TDSIC projects
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	35,979	18,547
TDSIC projects | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	35,979	18,547
Petersburg Unit 1 retirement
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	35,700
Petersburg Unit 1 retirement | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current		287,463
Petersburg Unit 2 retirement
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	224,200
Hardy Hills Solar Project
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	6,774	5,744
Hardy Hills Solar Project | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	6,774	5,744
Petersburg Solar Project
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	2,469	1,582
Petersburg Solar Project | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	2,469	1,582
Fuel Costs
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, current	0	79,861
Regulatory assets, non-current	4,275	20,518
Regulatory assets	0	79,861
Fuel Costs | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	4,275	20,518
Petersburg Unit 1 retirement and 2 retirement costs
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	259,892	287,463
Petersburg Unit 1 retirement and 2 retirement costs | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	259,892
Major Storm Damage
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	1,493	0
Major Storm Damage | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	1,493	0
Pike Co BESS Project Development Costs
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	2,623	0
Pike Co BESS Project Development Costs | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	2,623	0
Unamortized Investment Tax Credit [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability, Noncurrent	542	0
Regulatory liabilities	542	0
Unamortized Reacquisition Debt Premium
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, current	188	0
Regulatory assets	188	$ 0
Benchmark for annual wholesale margins [Member]
Regulatory Assets And Liabilities [Line Items]
Approved Rate Order Benefits to Customers	16,300
Benchmark for annual capacity sales [Member]
Regulatory Assets And Liabilities [Line Items]
Approved Rate Order Benefits to Customers	$ 11,300

Regulatory Matters (Schedule Of

Regulatory Matters (Schedule Of Regulatory Assets And Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, current	$ 89,419	$ 119,723
Regulatory assets, noncurrent	541,784	593,939
Total regulatory assets	631,203	713,662
Regulatory liabilities, current	23,371	23,348
Regulatory Liability, Noncurrent	527,224	612,585
Total regulatory liabilities	550,595	635,933
Overcollection and other credits passed to customers through rate riders [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities, current	19,649	15,803
Financial Transmission Rights [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities, current	3,722	7,545
Asset Retirement Obligation Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability, Noncurrent	451,886	518,797
Other Regulatory Assets (Liabilities) [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability, Noncurrent	0	5,126
Undercollections of rate riders [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, current	75,416	26,047
Amounts being recovered through base rates [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, current	13,815	13,815
Unrecognized Pension And Other Post Retirement Benefit Plan Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	115,847	131,907
Deferred Income Tax Charge [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability, Noncurrent	74,796	88,662
Deferred MISO Non-fuel Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	21,091
Unamortized Petersburg Unit 4 Carrying Charges And Certain Other Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	2,812	3,866
Unamortized Reacquisition Premium On Debt [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	13,379	14,429
Environmental Projects [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	66,837	68,947
Other Miscellaneous [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	2,887	1,027
Hardy Hills Solar Project
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	6,774	5,744
Petersburg Solar Project
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	2,469	1,582
Fuel Costs
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, current	0	79,861
Regulatory assets, noncurrent	4,275	20,518
Petersburg Unit 1 retirement and 2 retirement costs
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	259,892	287,463
Major Storm Damage
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	1,493	0
Pike Co BESS Project Development Costs
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	2,623	0
Unamortized Reacquisition Debt Premium
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, current	188	0
Indianapolis Power And Light Company
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, current	89,419	119,723
Regulatory assets, noncurrent	541,784	593,939
Total regulatory assets	631,203	713,662
Regulatory liabilities, current	23,371	23,348
Regulatory Liability, Noncurrent	527,224	612,585
Total regulatory liabilities	550,595	635,933
Indianapolis Power And Light Company | Overcollection and other credits passed to customers through rate riders [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities, current	19,649	15,803
Indianapolis Power And Light Company | Financial Transmission Rights [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities, current	3,722	7,545
Indianapolis Power And Light Company | Asset Retirement Obligation Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability, Noncurrent	451,886	518,797
Indianapolis Power And Light Company | Deferred Income Tax Charge [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability, Noncurrent	74,800	88,662
Indianapolis Power And Light Company | Other Regulatory Assets (Liabilities) [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability, Noncurrent	0	5,126
Indianapolis Power And Light Company | Investment Tax Credit Carryforward
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability, Noncurrent		0
Indianapolis Power And Light Company | Undercollections of rate riders [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, current	75,416	26,047
Indianapolis Power And Light Company | Amounts being recovered through base rates [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, current	13,815	13,815
Indianapolis Power And Light Company | Unrecognized Pension And Other Post Retirement Benefit Plan Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	115,847	131,907
Indianapolis Power And Light Company | Deferred Income Tax Charge [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability, Noncurrent	74,796
Indianapolis Power And Light Company | Deferred MISO Non-fuel Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	21,091
Indianapolis Power And Light Company | Unamortized Petersburg Unit 4 Carrying Charges And Certain Other Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	2,812	3,866
Indianapolis Power And Light Company | Unamortized Reacquisition Premium On Debt [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	13,379	14,429
Indianapolis Power And Light Company | Environmental Projects [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	66,837	68,947
Indianapolis Power And Light Company | Other Miscellaneous [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	2,887	1,027
Indianapolis Power And Light Company | Hardy Hills Solar Project
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	6,774	5,744
Indianapolis Power And Light Company | Petersburg Solar Project
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	2,469	1,582
Indianapolis Power And Light Company | Fuel Costs
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	4,275	20,518
Indianapolis Power And Light Company | Petersburg Unit 1 retirement and 2 retirement costs
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	259,892
Indianapolis Power And Light Company | Investment Tax Credit Carryforward
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability, Noncurrent	542
Indianapolis Power And Light Company | Major Storm Damage
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	1,493	0
Indianapolis Power And Light Company | Pike Co BESS Project Development Costs
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	$ 2,623	$ 0

Property, Plant and Equipment_2

Property, Plant and Equipment (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Public Utility, Property, Plant and Equipment [Line Items]
Revisions to cash flow and timing estimates	$ 12,921	$ 44,679
Direct first mortgage lien	2,153,800
Non-contractually required removal costs of utility plant in service	680,900	694,000
Contractually required removal costs of utility plant in service	249,900	218,700
Regulatory assets, non-current	541,784	593,939
Regulatory assets, non-current	541,784	593,939
Entity Information [Line Items]
Regulatory assets, non-current	541,784	593,939
Contractually required removal costs of utility plant in service	249,900	218,700
Non-contractually required removal costs of utility plant in service	680,900	694,000
Direct first mortgage lien	2,153,800
Petersburg Unit 1 retirement
Public Utility, Property, Plant and Equipment [Line Items]
Regulatory assets, non-current	35,700
Regulatory assets, non-current	35,700
Entity Information [Line Items]
Regulatory assets, non-current	35,700
Petersburg Unit 1 retirement and 2 retirement costs
Public Utility, Property, Plant and Equipment [Line Items]
Regulatory assets, non-current	259,892	287,463
Regulatory assets, non-current	259,892	287,463
Entity Information [Line Items]
Regulatory assets, non-current	259,892	287,463
Subsidiaries [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Revisions to cash flow and timing estimates	12,921	44,679
Direct first mortgage lien	2,153,800
Non-contractually required removal costs of utility plant in service	680,900	694,000
Contractually required removal costs of utility plant in service	249,900	218,700
Regulatory assets, non-current	541,784	593,939
Regulatory assets, non-current	541,784	593,939
Entity Information [Line Items]
Regulatory assets, non-current	541,784	593,939
Contractually required removal costs of utility plant in service	249,900	218,700
Non-contractually required removal costs of utility plant in service	680,900	694,000
Direct first mortgage lien	2,153,800
Subsidiaries [Member] | Petersburg Unit 1 retirement
Public Utility, Property, Plant and Equipment [Line Items]
Regulatory assets, non-current		287,463
Regulatory assets, non-current		287,463
Entity Information [Line Items]
Regulatory assets, non-current		$ 287,463
Subsidiaries [Member] | Petersburg Unit 1 retirement and 2 retirement costs
Public Utility, Property, Plant and Equipment [Line Items]
Regulatory assets, non-current	259,892
Regulatory assets, non-current	259,892
Entity Information [Line Items]
Regulatory assets, non-current	$ 259,892

Property, Plant and Equipment_3

Property, Plant and Equipment (Schedule Of Original Cost Of Utility Plant In Service) (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Entity Information [Line Items]
Production	$ 3,942,052	$ 4,164,416
Transmission	487,527	461,245
Distribution	2,304,526	2,045,579
General plant	348,338	311,074
Total utility plant in service	7,082,443	6,982,314
Indianapolis Power And Light Company
Entity Information [Line Items]
Production	3,942,052	4,164,416
Transmission	487,527	461,245
Distribution	2,304,526	2,045,579
General plant	348,338	311,074
Total utility plant in service	$ 7,082,443	$ 6,982,314

Property, Plant and Equipment A

Property, Plant and Equipment ARO (Reconciliation of Asset Retirement Obligation Liability) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance as of January 1	$ 218,729	$ 189,509
Liabilities settled	(11,902)	(24,699)
Revisions to cash flow and timing estimates	12,921	44,679
Accretion expense	13,102	8,081
Balance as of December 31	249,930	218,729
Asset Retirement Obligation, Liabilities Incurred	17,080	1,159
Indianapolis Power And Light Company
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance as of January 1	218,729	189,509
Liabilities settled	11,902	24,699
Revisions to cash flow and timing estimates	12,921	44,679
Accretion expense	13,102	8,081
Balance as of December 31	249,930	$ 218,729
Asset Retirement Obligation, Liabilities Incurred	$ 17,080

Fair Value (Narrative) (Details

Fair Value (Narrative) (Details) MWh in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2023 USD ($) MWh	Dec. 31, 2022 USD ($)
Entity Information [Line Items]
Investments, Fair Value Disclosure	$ 3,552	$ 3,228
Revisions to cash flow and timing estimates	12,921	44,679
Deferred financing costs, net	23,612
Unamortized debt discount	6,768
Asset retirement obligations	249,930	218,729
Regulatory assets, non-current	541,784	593,939
Financial transmission rights	1,388	7,545
Total financial assets measured at fair value	19,234	22,945
Unamortized Debt Discount
Entity Information [Line Items]
Unamortized debt discount	6,800	7,100
Unamortized Deferred Financing Cost
Entity Information [Line Items]
Deferred financing costs, net	24,800	26,300
Interest Rate Swap [Member] | Designated as Hedging Instrument [Member]
Entity Information [Line Items]
Derivative, Notional Amount, Purchase (Sales), Net	400,000
Purchase of Derivative Instruments Interest Rate Swap	400,000
Sale of Derivative Instruments Interest Rate Swap	$ 0
FTR [Member] | Not Designated as Hedging Instrument [Member]
Entity Information [Line Items]
Sale of Units Derivative Instruments Financial Transmission Rights | MWh	0
Petersburg Unit 1 retirement
Entity Information [Line Items]
Regulatory assets, non-current	$ 35,700
Indianapolis Power And Light Company
Entity Information [Line Items]
Revisions to cash flow and timing estimates	12,921	44,679
Deferred financing costs, net	20,200	20,400
Unamortized debt discount	6,449	6,651
Asset retirement obligations	249,930	218,729
Regulatory assets, non-current	541,784	593,939
Financial transmission rights	1,388	7,545
Total financial assets measured at fair value	1,388	7,545
Indianapolis Power And Light Company | Variable Rate [Member]
Entity Information [Line Items]
Unamortized debt discount	$ (6,400)	6,700
Indianapolis Power And Light Company | FTR [Member] | Not Designated as Hedging Instrument [Member]
Entity Information [Line Items]
Sale of Units Derivative Instruments Financial Transmission Rights | MWh	0
Indianapolis Power And Light Company | Petersburg Unit 1 retirement
Entity Information [Line Items]
Regulatory assets, non-current		287,463
Money Market Funds [Member]
Entity Information [Line Items]
Investments, Fair Value Disclosure	$ 127	5
Mutual Fund [Member]
Entity Information [Line Items]
Investments, Fair Value Disclosure	3,425	3,223
Fair Value, Inputs, Level 1 [Member]
Entity Information [Line Items]
Investments, Fair Value Disclosure	3,552	3,228
Financial transmission rights	0	0
Total financial assets measured at fair value	3,552	3,228
Fair Value, Inputs, Level 1 [Member] | Indianapolis Power And Light Company
Entity Information [Line Items]
Financial transmission rights	0	0
Total financial assets measured at fair value	0	0
Fair Value, Inputs, Level 2 [Member]
Entity Information [Line Items]
Investments, Fair Value Disclosure	0	0
Financial transmission rights	0	0
Total financial assets measured at fair value	14,294	12,172
Fair Value, Inputs, Level 2 [Member] | Indianapolis Power And Light Company
Entity Information [Line Items]
Financial transmission rights	0	0
Total financial assets measured at fair value	0	0
Fair Value, Inputs, Level 3 [Member]
Entity Information [Line Items]
Investments, Fair Value Disclosure	0	0
Financial transmission rights	1,388	7,545
Total financial assets measured at fair value	1,388	7,545
Fair Value, Inputs, Level 3 [Member] | Indianapolis Power And Light Company
Entity Information [Line Items]
Financial transmission rights	1,388	7,545
Total financial assets measured at fair value	$ 1,388	$ 7,545

Fair Value (Summary Of Fair Val

Fair Value (Summary Of Fair Value Assets And Liabilities Measured On A Recurring Basis, Level 3) (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Entity Information [Line Items]
Investments, Fair Value Disclosure	$ 3,552	$ 3,228
Financial transmission rights	1,388	7,545
Total financial assets measured at fair value	19,234	22,945
Indianapolis Power And Light Company
Entity Information [Line Items]
Financial transmission rights	1,388	7,545
Total financial assets measured at fair value	1,388	7,545
Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Entity Information [Line Items]
Investments, Fair Value Disclosure	3,552	3,228
Financial transmission rights	0	0
Total financial assets measured at fair value	3,552	3,228
Quoted Prices In Active Markets For Identical Assets (Level 1) [Member] | Indianapolis Power And Light Company
Entity Information [Line Items]
Financial transmission rights	0	0
Total financial assets measured at fair value	0	0
Significant Observable Inputs (Level 2) [Member]
Entity Information [Line Items]
Investments, Fair Value Disclosure	0	0
Financial transmission rights	0	0
Total financial assets measured at fair value	14,294	12,172
Significant Observable Inputs (Level 2) [Member] | Indianapolis Power And Light Company
Entity Information [Line Items]
Financial transmission rights	0	0
Total financial assets measured at fair value	0	0
Unobservable Inputs (Level 3) [Member]
Entity Information [Line Items]
Investments, Fair Value Disclosure	0	0
Financial transmission rights	1,388	7,545
Total financial assets measured at fair value	1,388	7,545
Unobservable Inputs (Level 3) [Member] | Indianapolis Power And Light Company
Entity Information [Line Items]
Financial transmission rights	1,388	7,545
Total financial assets measured at fair value	1,388	7,545
Money Market Funds [Member]
Entity Information [Line Items]
Investments, Fair Value Disclosure	127	5
Mutual Fund [Member]
Entity Information [Line Items]
Investments, Fair Value Disclosure	$ 3,425	$ 3,223

Fair Value (Reconciliation Of F

Fair Value (Reconciliation Of Financial Instruments Classified As Level 3) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Forward Power Contracts Fair Value Disclosure	$ 14,294	$ 12,172
Total financial assets measured at fair value	19,234	22,945
Financial transmission rights	1,388	7,545
Investments, Fair Value Disclosure	3,552	3,228
Mutual Fund [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Investments, Fair Value Disclosure	3,425	3,223
Money Market Funds [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Investments, Fair Value Disclosure	127	5
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Total financial assets measured at fair value	3,552	3,228
Financial transmission rights	0	0
Investments, Fair Value Disclosure	3,552	3,228
Significant Observable Inputs (Level 2) [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Total financial assets measured at fair value	14,294	12,172
Financial transmission rights	0	0
Investments, Fair Value Disclosure	0	0
Unobservable Inputs (Level 3) [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Total financial assets measured at fair value	1,388	7,545
Financial transmission rights	1,388	7,545
Investments, Fair Value Disclosure	0	0
Derivative Financial Instruments, net Liabilities [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	7,545	1,235
Issuances	3,624	15,338
Settlements	(9,781)	(9,028)
Ending balance	1,388	7,545
Indianapolis Power And Light Company
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Total financial assets measured at fair value	1,388	7,545
Financial transmission rights	1,388	7,545
Indianapolis Power And Light Company | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Total financial assets measured at fair value	0	0
Financial transmission rights	0	0
Indianapolis Power And Light Company | Significant Observable Inputs (Level 2) [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Total financial assets measured at fair value	0	0
Financial transmission rights	0	0
Indianapolis Power And Light Company | Unobservable Inputs (Level 3) [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Total financial assets measured at fair value	1,388	7,545
Financial transmission rights	1,388	7,545
Parent Company [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Forward Power Contracts Fair Value Disclosure	14,294	12,172
Total financial assets measured at fair value	17,846	15,400
Investments, Fair Value Disclosure	3,552	3,228
Parent Company [Member] | Mutual Fund [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Investments, Fair Value Disclosure	3,425	3,223
Parent Company [Member] | Money Market Funds [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Investments, Fair Value Disclosure	127	5
Parent Company [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Forward Power Contracts Fair Value Disclosure	0	0
Total financial assets measured at fair value	3,552	3,228
Investments, Fair Value Disclosure	3,552	3,228
Parent Company [Member] | Fair Value, Inputs, Level 1 [Member] | Mutual Fund [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Investments, Fair Value Disclosure	3,425	3,223
Parent Company [Member] | Fair Value, Inputs, Level 1 [Member] | Money Market Funds [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Investments, Fair Value Disclosure	127	5
Parent Company [Member] | Significant Observable Inputs (Level 2) [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Forward Power Contracts Fair Value Disclosure	14,294	12,172
Total financial assets measured at fair value	14,294	12,172
Investments, Fair Value Disclosure	0	0
Parent Company [Member] | Significant Observable Inputs (Level 2) [Member] | Mutual Fund [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Investments, Fair Value Disclosure	0	0
Parent Company [Member] | Significant Observable Inputs (Level 2) [Member] | Money Market Funds [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Investments, Fair Value Disclosure	0	0
Parent Company [Member] | Unobservable Inputs (Level 3) [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Forward Power Contracts Fair Value Disclosure	0	0
Total financial assets measured at fair value	0	0
Investments, Fair Value Disclosure		0
Parent Company [Member] | Unobservable Inputs (Level 3) [Member] | Mutual Fund [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Investments, Fair Value Disclosure	0	0
Parent Company [Member] | Unobservable Inputs (Level 3) [Member] | Money Market Funds [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Investments, Fair Value Disclosure	$ 0	$ 0

Fair Value (Schedule Of Face An

Fair Value (Schedule Of Face And Fair Value Of Debt) (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Debt Instrument [Line Items]
Unamortized discounts	$ 6,768
Face Value	3,488,800	$ 3,033,800
Fair Value	3,315,467	2,775,644
Indianapolis Power And Light Company
Debt Instrument [Line Items]
Unamortized discounts	6,449	6,651
Face Value	2,608,800	2,153,800
Fair Value	2,475,997	1,959,233
Fixed Rate [Member]
Debt Instrument [Line Items]
Face Value	3,033,800	3,033,800
Fair Value	2,860,467	2,775,644
Fixed Rate [Member] | Indianapolis Power And Light Company
Debt Instrument [Line Items]
Face Value	2,153,800	2,153,800
Fair Value	2,020,997	1,959,233
Variable Rate [Member]
Debt Instrument [Line Items]
Face Value	455,000	0
Fair Value	455,000	0
Variable Rate [Member] | Indianapolis Power And Light Company
Debt Instrument [Line Items]
Unamortized discounts	(6,400)	6,700
Face Value	455,000	0
Fair Value	$ 455,000	$ 0

Derivative Instruments and He_3

Derivative Instruments and Hedging Activities (Details) MWh in Thousands	12 Months Ended
	Dec. 31, 2023 USD ($) MWh	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Apr. 08, 2020 USD ($)
Interest Rate Derivative Assets, at Fair Value	$ 14,294,000	$ 0
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax	$ (528,000)	(15,309,000)	$ (3,441,000)
Number of Interest Rate Swaps	3
Other Comprehensive Income (Loss), Net of Tax	$ 1,594,000	46,245,000	10,393,000
Accumulated Other Comprehensive Income (Loss), Net of Tax	29,294,000	22,269,000	(29,407,000)	$ (43,420,000)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	1,594,000	46,245,000	10,393,000
Reclassification from AOCI, Current Period, Net of Tax, Attributable to Parent	5,431,000	5,431,000	3,620,000
Interest Rate Contract [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax	29,294,000	22,269,000	(29,407,000)
Interest Rate Cash Flow Hedge Gain (Loss) to be Reclassified During Next 12 Months, Net	$ (5,375)
Maximum Length of Time Hedged in Cash Flow Hedge	9 years
Interest Rate Swap [Member]
Accumulated Other Income (Loss)					$ 72,300,000
Accumulated Other Income (Loss)					$ 72,300,000
Not Designated as Hedging Instrument [Member] | FTR [Member]
Purchase of Units Derivative Instruments Financial Transmission Rights | MWh	3,919
Sale of Units Derivative Instruments Financial Transmission Rights | MWh	0
Derivative, Nonmonetary Notional Amount, Purchase (Sales), Net | MWh	3,919
Not Designated as Hedging Instrument [Member] | Realized Gains Forward Power Contracts
Derivative Instruments Not Designated as Hedging Instruments, Gain	$ 0	1,300,000
Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Purchase of Derivative Instruments Interest Rate Swap	400,000,000
Sale of Derivative Instruments Interest Rate Swap	0
Derivative, Notional Amount, Purchase (Sales), Net	400,000,000
Other Current Assets [Member] | Not Designated as Hedging Instrument [Member] | FTR [Member]
Derivative Asset, Fair Value, Gross Asset	1,388,000	7,545,000
Derivative Liability, Current | Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative Liability, Fair Value, Gross Liability	0	12,172,000
Parent Company [Member]
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax	(528,000)	(15,309,000)	(3,441,000)
Other Comprehensive Income (Loss), Net of Tax	1,594,000	46,245,000	10,393,000
Accumulated Other Comprehensive Income (Loss), Net of Tax	29,294,000	22,269,000	(29,407,000)	$ (43,420,000)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	1,594,000	46,245,000	10,393,000
Reclassification from AOCI, Current Period, Net of Tax, Attributable to Parent	5,431,000	5,431,000	3,620,000
Parent Company [Member] | Interest Rate Contract [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax	29,294,000	22,269,000	$ (29,407,000)
Interest Rate Cash Flow Hedge Gain (Loss) to be Reclassified During Next 12 Months, Net	$ (5,375)
Maximum Length of Time Hedged in Cash Flow Hedge	9 years
Parent Company [Member] | Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Purchase of Derivative Instruments Interest Rate Swap	$ 400,000,000
Sale of Derivative Instruments Interest Rate Swap	0
Derivative, Notional Amount, Purchase (Sales), Net	400,000,000
Parent Company [Member] | Derivative Liability, Current | Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative Liability, Fair Value, Gross Liability	$ 0	12,172,000,000
Subsidiaries [Member] | Not Designated as Hedging Instrument [Member] | FTR [Member]
Purchase of Units Derivative Instruments Financial Transmission Rights | MWh	3,919
Sale of Units Derivative Instruments Financial Transmission Rights | MWh	0
Derivative, Nonmonetary Notional Amount, Purchase (Sales), Net | MWh	3,919
Subsidiaries [Member] | Not Designated as Hedging Instrument [Member] | Realized Gains Forward Power Contracts
Derivative Instruments Not Designated as Hedging Instruments, Gain	$ 0	1,300,000
Subsidiaries [Member] | Other Current Assets [Member] | Not Designated as Hedging Instrument [Member] | FTR [Member]
Derivative Asset, Fair Value, Gross Asset	$ 1,388,000,000	$ 7,545,000,000

Debt (Narrative) (Details)

Debt (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Debt Instrument [Line Items]
Secured debt gross	$ 3,003,420,000
Aggregate principal amount	3,488,800,000	$ 3,033,800,000
Net proceeds from debt issuance	0	350,000,000	$ 95,000,000
Long-term debt	3,003,420,000	3,000,450,000
Maximum borrowing capacity	350,000,000
Line of Credit Facility, Remaining Borrowing Capacity	100,000,000
Maximum amount of short-term indebtedness outstanding	750,000,000
Authorized amount of debt to be issued	740,000,000
Preferred Stock Issuable in Lieu of Portion of Maximum Authorized Amount of Debt	65,000,000
Debt Instrument, Unused Borrowing Capacity, Amount	390,000,000
Letter of Credit [Member]
Debt Instrument [Line Items]
Line of credit facility, accordion feature	150,000,000
Indianapolis Power And Light Company
Debt Instrument [Line Items]
Secured debt gross	2,128,293,000
Aggregate principal amount	2,608,800,000	2,153,800,000
Net proceeds from debt issuance	0	350,000,000	$ 95,000,000
Long-term debt	2,128,293,000	2,126,787,000
Maximum borrowing capacity	350,000,000
Line of Credit Facility, Remaining Borrowing Capacity	100,000,000
Maximum amount of short-term indebtedness outstanding	750,000,000
Authorized amount of debt to be issued	740,000,000
Preferred Stock Issuable in Lieu of Portion of Maximum Authorized Amount of Debt	65,000,000
First mortgage bonds	$ 2,128,293,000	2,126,787,000
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed	100%
Debt Instrument, Unused Borrowing Capacity, Amount	$ 390,000,000
Maximum long-term credit agreements and liquidity facilities	750,000,000
Indianapolis Power And Light Company | Letter of Credit [Member]
Debt Instrument [Line Items]
Line of credit facility, accordion feature	150,000,000
Indianapolis Power And Light Company | Line of Credit [Member]
Debt Instrument [Line Items]
Long-term Line of Credit	155,000,000	0
Ipalco Enterprises, Inc. [Member]
Debt Instrument [Line Items]
Aggregate principal amount	880,000,000	880,000,000
Long-term debt	470,653,000	873,663,000
First Mortgage Bonds [Member] | Indianapolis Power And Light Company
Debt Instrument [Line Items]
Secured debt gross	$ 2,153,800,000
FMB Twenty [Member] | Indianapolis Power And Light Company
Debt Instrument [Line Items]
Debt instrument, stated interest rate	4.05%
First mortgage bonds	$ 350,000,000	350,000,000
First Mortgage Bond Nine [Member] | Indianapolis Power And Light Company
Debt Instrument [Line Items]
Debt instrument, stated interest rate	3.125%
First mortgage bonds	$ 40,000,000	40,000,000
First Mortgage Bond 4.65% Due June 2043 [Member] | Indianapolis Power And Light Company
Debt Instrument [Line Items]
Debt instrument, stated interest rate	4.65%
First mortgage bonds	$ 170,000,000	170,000,000
First Mortgage Bond 4.70% Due September 2045 [Member] | Indianapolis Power And Light Company
Debt Instrument [Line Items]
Debt instrument, stated interest rate	4.50%
First mortgage bonds	$ 130,000,000	130,000,000
First Mortgage Bond Nineteen [Member] | Indianapolis Power And Light Company
Debt Instrument [Line Items]
Debt instrument, stated interest rate	4.70%
First mortgage bonds	$ 260,000,000	260,000,000
Three Point Seven Zero Percent Senior Secured Notes [Domain] | Ipalco Enterprises, Inc. [Member]
Debt Instrument [Line Items]
Debt instrument, stated interest rate	3.70%
Long-term debt	$ 405,000,000	405,000,000
FMB Twenty - one [Member] | Indianapolis Power And Light Company
Debt Instrument [Line Items]
Debt instrument, stated interest rate	4.875%
First mortgage bonds	$ 105,000,000	105,000,000
First Mortgage Bond Thirteen [Member] | Indianapolis Power And Light Company
Debt Instrument [Line Items]
Debt instrument, stated interest rate	6.60%
First mortgage bonds	$ 100,000,000	100,000,000
First Mortgage Bond Fourteen [Member] | Indianapolis Power And Light Company
Debt Instrument [Line Items]
Debt instrument, stated interest rate	6.05%
First mortgage bonds	$ 158,800,000	158,800,000
First Mortgage Bond Fifteen [Member] | Indianapolis Power And Light Company
Debt Instrument [Line Items]
Debt instrument, stated interest rate	6.60%
First mortgage bonds	$ 165,000,000	165,000,000
First Mortgage Bond Sixteen [Member] | Indianapolis Power And Light Company
Debt Instrument [Line Items]
Debt instrument, stated interest rate	4.875%
First mortgage bonds	$ 140,000,000	140,000,000
FMB Twenty - three | Indianapolis Power And Light Company
Debt Instrument [Line Items]
Debt instrument, stated interest rate	0.95%
First mortgage bonds	$ 60,000,000	60,000,000
Aggregated Principal Amount of Environmental Facilities Refunding Revenue Bonds Series 2021 A&B | Indianapolis Power And Light Company
Debt Instrument [Line Items]
First mortgage bonds	$ 95,000,000
FMB Twenty - Four | Indianapolis Power And Light Company
Debt Instrument [Line Items]
Debt instrument, stated interest rate	1.40%
First mortgage bonds	$ 55,000,000	55,000,000
FMB Twenty - five | Indianapolis Power And Light Company
Debt Instrument [Line Items]
Debt instrument, stated interest rate	0.65%
First mortgage bonds	$ 40,000,000	40,000,000
FMB Twenty - two | Indianapolis Power And Light Company
Debt Instrument [Line Items]
Debt instrument, stated interest rate	0.75%
First mortgage bonds	$ 30,000,000	30,000,000
First Mortgage Bond Twenty Two
Debt Instrument [Line Items]
Long-term debt	345,600,000
First mortgage bonds	$ 350,000,000
First Mortgage Bond Twenty Two | Indianapolis Power And Light Company
Debt Instrument [Line Items]
Debt instrument, stated interest rate	5.65%
Long-term debt	$ 345,600,000
First mortgage bonds	$ 350,000,000	350,000,000
Four Point Two Five Percent Senior Secured Notes | Ipalco Enterprises, Inc. [Member]
Debt Instrument [Line Items]
Debt instrument, stated interest rate	4.25%
Long-term debt	$ 475,000,000	475,000,000
$200M Term Loan Maturing June 2023
Debt Instrument [Line Items]
Short-Term Bank Loans and Notes Payable	200,000,000
$200M Term Loan Maturing June 2023 | Indianapolis Power And Light Company
Debt Instrument [Line Items]
Short-Term Bank Loans and Notes Payable	200,000,000
$300M Term Loan Maturing November 2024 | Indianapolis Power And Light Company
Debt Instrument [Line Items]
Short-Term Bank Loans and Notes Payable	$ 300,000,000
Series 2021A bonds | Indianapolis Power And Light Company
Debt Instrument [Line Items]
Debt instrument, stated interest rate	1.40%
Series 2021B bonds | Indianapolis Power And Light Company
Debt Instrument [Line Items]
Debt instrument, stated interest rate	0.65%
Aggregated Principal Amount of Environmental Facilities Refunding Revenue Bonds Series 2011 A&B | Indianapolis Power And Light Company
Debt Instrument [Line Items]
First mortgage bonds	$ 95,000,000
Line of Credit [Member] | Committed Line of Credit
Debt Instrument [Line Items]
Long-term Line of Credit	$ 155,000,000	$ 0

Debt (Schedule Long-Term Indebt

Debt (Schedule Long-Term Indebtedness) (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Debt Instrument [Line Items]
Unamortized discount - net	$ (6,768)
Debt Issuance Costs, Net	(23,612)
Long-term debt	3,003,420	$ 3,000,450
Current portion of long-term debt	445,000	0
Long-term debt	2,558,420	3,000,450
First Mortgage Bond Twenty Two
Debt Instrument [Line Items]
First mortgage bonds	350,000
Long-term debt	345,600
Ipalco Enterprises, Inc. [Member]
Debt Instrument [Line Items]
Unamortized discount - net	(319)	(425)
Debt Issuance Costs, Net	(4,554)	(5,912)
Debt, Long-Term and Short-Term, Combined Amount	875,127	873,663
Long-term debt	470,653	873,663
Current portion of long-term debt	405,000	0
Long-term debt	470,127	873,663
Ipalco Enterprises, Inc. [Member] | Three Point Seven Zero Percent Senior Secured Notes [Domain]
Debt Instrument [Line Items]
Long-term debt	$ 405,000	405,000
Debt, stated interest rate	3.70%
Ipalco Enterprises, Inc. [Member] | Four Point Two Five Percent Senior Secured Notes
Debt Instrument [Line Items]
Long-term debt	$ 475,000	475,000
Debt, stated interest rate	4.25%
Indianapolis Power And Light Company
Debt Instrument [Line Items]
First mortgage bonds	$ 2,128,293	2,126,787
Unamortized discount - net	(6,449)	(6,651)
Debt Issuance Costs, Net	(20,200)	(20,400)
Long-term debt	2,128,293	2,126,787
Current portion of long-term debt	40,000	0
Long-term debt	2,088,293	2,126,787
Indianapolis Power And Light Company | First Mortgage Bond 4.55% Due December 2024 [Member]
Debt Instrument [Line Items]
First mortgage bonds	$ 40,000	40,000
Debt, stated interest rate	3.125%
Indianapolis Power And Light Company | First Mortgage Bond 6.60% Due January 2034 [Member]
Debt Instrument [Line Items]
First mortgage bonds	$ 100,000	100,000
Debt, stated interest rate	6.60%
Indianapolis Power And Light Company | First Mortgage Bond 6.05% Due October 2036 [Member]
Debt Instrument [Line Items]
First mortgage bonds	$ 158,800	158,800
Debt, stated interest rate	6.05%
Indianapolis Power And Light Company | First Mortgage Bond 6.60% Due June 2037 [Member]
Debt Instrument [Line Items]
First mortgage bonds	$ 165,000	165,000
Debt, stated interest rate	6.60%
Indianapolis Power And Light Company | First Mortgage Bond 4.875% Due November 2041 [Member]
Debt Instrument [Line Items]
First mortgage bonds	$ 140,000	140,000
Debt, stated interest rate	4.875%
Indianapolis Power And Light Company | First Mortgage Bond 4.65% Due June 2043 [Member]
Debt Instrument [Line Items]
First mortgage bonds	$ 170,000	170,000
Debt, stated interest rate	4.65%
Indianapolis Power And Light Company | First Mortgage Bond 4.70% Due September 2045 [Member]
Debt Instrument [Line Items]
First mortgage bonds	$ 130,000	130,000
Debt, stated interest rate	4.50%
Indianapolis Power And Light Company | First Mortgage Bond Nineteen [Member]
Debt Instrument [Line Items]
First mortgage bonds	$ 260,000	260,000
Debt, stated interest rate	4.70%
Indianapolis Power And Light Company | FMB Twenty [Member]
Debt Instrument [Line Items]
First mortgage bonds	$ 350,000	350,000
Debt, stated interest rate	4.05%
Indianapolis Power And Light Company | FMB Twenty - one [Member]
Debt Instrument [Line Items]
First mortgage bonds	$ 105,000	105,000
Debt, stated interest rate	4.875%
Indianapolis Power And Light Company | FMB Twenty - two
Debt Instrument [Line Items]
First mortgage bonds	$ 30,000	30,000
Debt, stated interest rate	0.75%
Indianapolis Power And Light Company | FMB Twenty - three
Debt Instrument [Line Items]
First mortgage bonds	$ 60,000	60,000
Debt, stated interest rate	0.95%
Indianapolis Power And Light Company | FMB Twenty - Four
Debt Instrument [Line Items]
First mortgage bonds	$ 55,000	55,000
Debt, stated interest rate	1.40%
Indianapolis Power And Light Company | FMB Twenty - five
Debt Instrument [Line Items]
First mortgage bonds	$ 40,000	40,000
Debt, stated interest rate	0.65%
Indianapolis Power And Light Company | First Mortgage Bond Twenty Two
Debt Instrument [Line Items]
First mortgage bonds	$ 350,000	350,000
Long-term debt	$ 345,600
Debt, stated interest rate	5.65%
Secured Debt [Member] | Indianapolis Power And Light Company
Debt Instrument [Line Items]
Unamortized discount - net	$ (6,449)
Debt Issuance Costs, Net	$ (19,058)	$ (20,362)

Debt (Schedule Of Maturities On

Debt (Schedule Of Maturities On Long-Term Indebtedness) (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Entity Information [Line Items]
2024	$ 445,000
2025	40,000
2026	90,000
2027	0
2028	0
Thereafter	2,458,800
Long-Term Debt, Gross	3,033,800
Unamortized discounts	(6,768)
Debt Issuance Costs, Net	(23,612)
Deferred financing costs, net	3,003,420
Subsidiaries [Member]
Entity Information [Line Items]
Debt Issuance Costs, Net	(19,058)
Subsidiaries [Member]
Entity Information [Line Items]
2024	40,000
2025	40,000
2026	90,000
2027	0
2028	0
Thereafter	1,983,800
Long-Term Debt, Gross	2,153,800
Unamortized discounts	(6,449)	$ (6,651)
Debt Issuance Costs, Net	(20,200)	$ (20,400)
Deferred financing costs, net	$ 2,128,293

Income Taxes (Narrative) (Detai

Income Taxes (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Entity Information [Line Items]
Income taxes	$ 0	$ 31,000,000	$ 27,500,000
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21%	21%	21%
Unrecognized Tax Benefits	$ 0	$ 0	$ 0	$ 7,368,000
Indianapolis Power And Light Company
Entity Information [Line Items]
Income taxes	$ 0	$ 39,500,000	$ 40,800,000
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21%	21%	21%
Unrecognized Tax Benefits	$ 0	$ 0	$ 0	$ 7,368,000

Income Taxes (Schedule Of Feder

Income Taxes (Schedule Of Federal And State Income Taxed Charged To Income) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Taxes [Line Items]
Income tax expense	$ 14,715	$ 21,859	$ 28,941
Charged To Utility Operating Expense [Member]
Income Taxes [Line Items]
Current income taxes, Federal	(14,222)	22,539	28,100
Current income taxes, State	(3,716)	6,026	8,218
Total current income taxes	(17,938)	28,565	36,318
Deferred income taxes, Federal	24,885	(6,920)	(7,286)
Deferred income taxes, State	7,768	214	(91)
Total deferred income taxes	32,653	(6,706)	(7,377)
Indianapolis Power And Light Company
Income Taxes [Line Items]
Income tax expense	25,666	32,887	39,305
Indianapolis Power And Light Company | Charged To Utility Operating Expense [Member]
Income Taxes [Line Items]
Current income taxes, Federal	1,816	31,286	36,353
Current income taxes, State	268	8,185	10,325
Total current income taxes	2,084	39,471	46,678
Deferred income taxes, Federal	17,631	(6,822)	(7,283)
Deferred income taxes, State	5,951	238	(90)
Total deferred income taxes	23,582	(6,584)	(7,373)
Income tax expense	$ 25,666	$ 32,887	$ 39,305

Income Taxes (Schedule Of Effec

Income Taxes (Schedule Of Effective Income Tax Rate) (Details)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Entity Information [Line Items]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21%	21%	21%
State income tax, net of federal tax benefit	3.90%	3.90%	4%
Depreciation flow through and amortization	(12.90%)	(7.80%)	(6.30%)
Effective Income Tax Rate Reconciliation, Funds Used during Construction, Equity	(0.30%)	0.90%	0.40%
Effective Income Tax Rate Reconciliation, Noncontrolling Interest Income (Loss), Percent	9%	0%	0%
Other - net	(0.20%)	0.40%	0.40%
Effective tax rate	20.50%	18.40%	19.50%
Indianapolis Power And Light Company
Entity Information [Line Items]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21%	21%	21%
State income tax, net of federal tax benefit	3.90%	3.90%	4%
Depreciation flow through and amortization	(8.00%)	(5.70%)	(4.90%)
Effective Income Tax Rate Reconciliation, Funds Used during Construction, Equity	(0.20%)	0.70%	0.30%
Effective Income Tax Rate Reconciliation, Noncontrolling Interest Income (Loss), Percent	5.60%	0%	0%
Other - net	(0.10%)	0.30%	0.30%
Effective tax rate	22.20%	20.20%	20.70%

Income Taxes (Schedule Of Defer

Income Taxes (Schedule Of Deferred Tax Assets And Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Entity Information [Line Items]
Relating to utility property, net	$ 409,675	$ 341,473
Regulatory assets recoverable through future rates	108,823	123,669
Other	17,694	17,953
Total deferred tax liabilities	536,192	483,095
Investment tax credit	5	6
Regulatory liabilities including ARO	168,619	167,725
Deferred Tax Assets, Investment in Subsidiaries	2,501	0
Other	3,579	2,723
Total deferred tax assets	174,704	170,454
Deferred Income Tax Liabilities, Net	361,488	312,641
Indianapolis Power And Light Company
Entity Information [Line Items]
Relating to utility property, net	409,675	341,473
Regulatory assets recoverable through future rates	108,823	123,669
Other	7,975	22,717
Total deferred tax liabilities	526,473	487,859
Investment tax credit	5	6
Regulatory liabilities including ARO	168,619	167,726
Deferred Tax Assets, Investment in Subsidiaries	2,483	0
Operating Loss Carryforwards	9,230	0
Other	3,579	15,020
Total deferred tax assets	183,916	182,752
Deferred Income Tax Liabilities, Net	$ 342,557	$ 305,107

Income Taxes (Reconciliation Of

Income Taxes (Reconciliation Of Unrecognized Tax Benefits) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits at January 1	$ 0	$ 0	$ 7,368,000
Gross decreases - prior period tax positions	0	0	(7,368,000)
Unrecognized tax benefits at December 31	0	0	0
Indianapolis Power And Light Company
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits at January 1	0	0	7,368,000
Gross decreases - prior period tax positions	0	0	(7,368,000)
Unrecognized tax benefits at December 31	$ 0	$ 0	$ 0

Benefit Plans (Narrative) (Deta

Benefit Plans (Narrative) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2024 USD ($)	Dec. 31, 2023 USD ($) employee	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Jan. 01, 2023 USD ($)	Jan. 01, 2022 USD ($)
Defined Benefit Plan Disclosure [Line Items]
Noncurrent liabilities		$ 0	$ 15
Benefit obligation in excess of plan assets		41,273	33,596
Asset, Defined Benefit Pension Plan, Noncurrent		41,273	33,611
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		9,681	(182,590)
Net loss (gain) arising during period		(10,117)	(24,069)
Pension liability actuarial loss, change in discount rate			(182,600)
Amount included in regulatory assets and liabilities		115,297	131,559
Defined Benefit Plan, Pension Plan with Projected Benefit Obligation in Excess of Plan Assets, Plan Assets		$ 590,800
Expected return on plan assets		5.60%
Effect of 25 basis point increase in discount rate on pension expense		$ (800)
Effect of 25 basis point decrease in discount rate on pension expense		800
Employer contributions during quarter		$ 114	412	$ 0
Funded target liability (percent)		98%
Pension expense		$ 73,300	38,600	63,200
Service cost		5,189	8,949	9,339
Interest cost		29,818	18,099	15,660
Deferred Compensation Arrangement with Individual, Compensation Expense		300	200	$ 200
Defined Benefit Plan, Benefit Obligation		549,546	$ 577,529		$ 577,530	$ 772,040
Pension Liability Actuarial Gain, Change in Discount Rate		9,700
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, Tax		10,100
Accumulated Defined Benefit Plans Adjustment, Net Gain (Loss) Attributable to Parent
Defined Benefit Plan Disclosure [Line Items]
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, Tax		$ 19,800
Pension Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Percentage of employees covered by the plan		65%
Discount rate		5.41%	2.83%	2.46%
Expected return on plan assets		5.60%	4.45%	5.05%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate		5.15%	5.41%
Supplemental Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Number of plan participants | employee		19
Discount rate		5.32%	2.62%	2.31%
Expected return on plan assets		6.45%	5.50%	3.60%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate		5.66%	5.32%
Postretirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Number of plan participants, active | employee		123
Number of plan participants, retired | employee		26
Indianapolis Power And Light Company
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Pension Plan with Projected Benefit Obligation in Excess of Plan Assets, Projected Benefit Obligation		$ 549,500
Defined Benefit Plan, Plan with Accumulated Benefit Obligation in Excess of Plan Assets, Plan Assets		590,800
Noncurrent liabilities		0	$ 15
Benefit obligation in excess of plan assets		41,273	33,596
Asset, Defined Benefit Pension Plan, Noncurrent		41,273	33,611
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		9,681	182,590
Net loss (gain) arising during period		10,100	(24,069)
Amount included in regulatory assets and liabilities		$ 115,297	$ 131,559
Minimum percentage of unrecognized net loss over benefit obligation or assets in order to be amortized		10%
Amortization period of unrecognized loss		11 years 7 months 28 days
Expected return on plan assets		5.60%	5.60%
Effect of 25 basis point increase in discount rate on pension expense		$ (800)
Effect of 25 basis point decrease in discount rate on pension expense		800
Employer contributions during quarter		$ 114	$ 412	$ 0
Funded target liability (percent)		98%
Pension expense		$ 73,300	38,600	63,200
Service cost		5,189	8,949	9,339
Interest cost		29,818	18,099	15,660
Deferred Compensation Arrangement with Individual, Compensation Expense		300	200	$ 200
Defined Benefit Plan, Benefit Obligation		549,546	$ 577,529		$ 577,530	$ 772,040
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, Tax		$ (10,117)
Indianapolis Power And Light Company | Pension Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Percentage of employees covered by the plan		65%
Discount rate		5.41%	2.83%	2.46%
Expected return on plan assets		5.60%	4.45%	5.05%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate		5.15%	5.41%
Indianapolis Power And Light Company | Supplemental Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Number of plan participants | employee		19
Discount rate		5.32%	2.62%	2.31%
Expected return on plan assets		6.45%	5.50%	3.60%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate		5.66%	5.32%
Indianapolis Power And Light Company | Postretirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Number of plan participants, active | employee		123
Number of plan participants, retired | employee		26
Indianapolis Power And Light Company | Postretirement Health Coverage [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Benefit Obligation		$ 3,000	$ 3,200
Indianapolis Power And Light Company | Change in Assumptions for Defined Benefit Plans
Defined Benefit Plan Disclosure [Line Items]
Expected return on plan assets		5.20%
Subsequent Event [Member] | Indianapolis Power And Light Company
Defined Benefit Plan Disclosure [Line Items]
Normal service cost	$ 6,300
Plan expenses	$ 400
Thrift Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Percentage of employees covered by the plan		77%
Defined contripution plan contributions		$ 3,700	3,600	$ 3,400
Thrift Plan [Member] | Indianapolis Power And Light Company
Defined Benefit Plan Disclosure [Line Items]
Percentage of employees covered by the plan		77%
Defined contripution plan contributions		$ 3,700	3,600	3,400
Retirement Savings Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Percentage of employees covered by the plan		23%
Percentage of employee's base compensation matched		5%
Defined Contribution, Employer Matching Contribution, Non-discretionary, percent of match		4%
Defined contripution plan contributions		$ 2,500	2,100	1,900
Retirement Savings Plan [Member] | Indianapolis Power And Light Company
Defined Benefit Plan Disclosure [Line Items]
Percentage of employees covered by the plan		23%
Percentage of employee's base compensation matched		5%
Defined Contribution, Employer Matching Contribution, Non-discretionary, percent of match		4%
Defined contripution plan contributions		$ 2,500	$ 2,100	$ 1,900
Union Employees [Member] | Thrift Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Percentage of employees covered by the plan		12%
Union Employees [Member] | Thrift Plan [Member] | Indianapolis Power And Light Company
Defined Benefit Plan Disclosure [Line Items]
Percentage of employees covered by the plan		12%
Expected Increase or Decrease in Discount Rate [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Effect of Twenty Five Basis Point Increase Or Decrease In Discount Rate On Pension Expense		2,500%
Expected Increase or Decrease in Discount Rate [Member] | Indianapolis Power And Light Company
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Effect of Twenty Five Basis Point Increase Or Decrease In Discount Rate On Pension Expense		2,500%
Forecast [Member] | Pension Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected return on plan assets	5.20%
Forecast [Member] | Supplemental Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected return on plan assets	6.35%
Forecast [Member] | Indianapolis Power And Light Company | Supplemental Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected return on plan assets	6.35%

Benefit Plans (Schedule Of Defi

Benefit Plans (Schedule Of Defined Benefit Plans Disclosures) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Change in benefit obligation:
Projected benefit obligation at beginning Measurement Date (see below)	$ 577,529
Service cost	5,189	$ 8,949	$ 9,339
Interest cost	29,818	18,099	15,660
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)	(9,681)	182,590
Amendments (primarily increases in pension bands)	653	0
Defined Benefit Plan, Benefit Obligation, Payment for Settlement	0	(394)
Benefits paid	73,325	38,575
Projected benefit obligation at ending Measurement Date	549,546	577,529
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	611,125	820,684
Actual return on plan assets	52,905	(171,002)
Employer contributions during quarter	114	412	0
Defined Benefit Plan, Plan Assets, Payment for Settlement	0	394
Benefits paid	(73,325)	(38,575)
Defined Benefit Plan Fair Value of plan assets	590,819	611,125
Fair value of plan assets at ending Measurement Date	590,819	611,125	820,684
Unfunded status	41,273	33,596
Asset, Defined Benefit Pension Plan, Noncurrent	(41,273)	(33,611)
Amounts recognized in the statement of financial position under ASC 715:
Noncurrent liabilities	0	(15)
Asset, Defined Benefit Plan, Noncurrent, Net	41,273	33,596
Sources of change in regulatory assets(1):
Prior service cost (credit) arising during period	653	0
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, Tax	10,100
Net loss (gain) arising during period	(10,117)	(24,069)
Amortization of prior service cost	(2,172)	(2,589)
Amortization of gain (loss)	(6,145)	(2,622)
Total recognized in regulatory assets	(17,781)	18,858
Net loss (gain)	115,297	131,559
Prior service cost (credit)	10,136	11,655
Total amounts included in regulatory assets (liabilities)	$ 125,433	$ 143,214
Percentage by asset category	100%	100%
Assets for Plan Benefits, Defined Benefit Plan	$ 41,172	$ 33,611
Expected return on plan assets	5.60%
Fair Value, Inputs, Level 1 [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	$ 6,480
Fair value of plan assets at ending Measurement Date	6,404	6,480
Significant Observable Inputs (Level 2) [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	604,645
Fair value of plan assets at ending Measurement Date	584,415	604,645
Indianapolis Power And Light Company
Change in benefit obligation:
Projected benefit obligation at beginning Measurement Date (see below)	577,529
Service cost	5,189	8,949	9,339
Interest cost	29,818	18,099	15,660
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)	(9,681)	(182,590)
Amendments (primarily increases in pension bands)	653	0
Defined Benefit Plan, Benefit Obligation, Payment for Settlement	0	(394)
Benefits paid	(73,325)	38,575
Projected benefit obligation at ending Measurement Date	549,546	577,529
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	611,125	820,684
Actual return on plan assets	52,905	(171,002)
Employer contributions during quarter	114	412	0
Defined Benefit Plan, Plan Assets, Payment for Settlement	0	(394)
Benefits paid	(73,325)	(38,575)
Fair value of plan assets at ending Measurement Date	590,819	611,125	$ 820,684
Unfunded status	41,273	33,596
Asset, Defined Benefit Pension Plan, Noncurrent	(41,273)	(33,611)
Amounts recognized in the statement of financial position under ASC 715:
Noncurrent liabilities	0	(15)
Asset, Defined Benefit Plan, Noncurrent, Net	41,273	33,596
Sources of change in regulatory assets(1):
Prior service cost (credit) arising during period	653	0
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, Tax	(10,117)
Net loss (gain) arising during period	10,100	(24,069)
Amortization of prior service cost	(2,172)	(2,589)
Amortization of gain (loss)	(6,145)	(2,622)
Total recognized in regulatory assets	(17,781)	18,858
Net loss (gain)	115,297	131,559
Prior service cost (credit)	10,136	11,655
Total amounts included in regulatory assets (liabilities)	$ 125,433	$ 143,214
Percentage by asset category	100%	100%
Assets for Plan Benefits, Defined Benefit Plan	$ 41,172	$ 33,611
Expected return on plan assets	5.60%	5.60%
Indianapolis Power And Light Company | Fair Value, Inputs, Level 1 [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	$ 6,480
Fair value of plan assets at ending Measurement Date	6,404	$ 6,480
Indianapolis Power And Light Company | Significant Observable Inputs (Level 2) [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	604,645
Fair value of plan assets at ending Measurement Date	584,415	604,645
US Government Debt Securities [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	122,704
Fair value of plan assets at ending Measurement Date	$ 117,397	$ 122,704
Sources of change in regulatory assets(1):
Percentage by asset category	20%	20%
US Government Debt Securities [Member] | Fair Value, Inputs, Level 1 [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	$ 420
Fair value of plan assets at ending Measurement Date	178	$ 420
US Government Debt Securities [Member] | Significant Observable Inputs (Level 2) [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	122,284
Fair value of plan assets at ending Measurement Date	117,219	122,284
US Government Debt Securities [Member] | Indianapolis Power And Light Company
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	122,704
Fair value of plan assets at ending Measurement Date	$ 117,397	$ 122,704
Sources of change in regulatory assets(1):
Percentage by asset category	20%	20%
US Government Debt Securities [Member] | Indianapolis Power And Light Company | Fair Value, Inputs, Level 1 [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	$ 420
Fair value of plan assets at ending Measurement Date	178	$ 420
US Government Debt Securities [Member] | Indianapolis Power And Light Company | Significant Observable Inputs (Level 2) [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	122,284
Fair value of plan assets at ending Measurement Date	117,219	122,284
Defined Benefit Plan, Common Collective Trust
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	608,336
Fair value of plan assets at ending Measurement Date	$ 588,028	$ 608,336
Sources of change in regulatory assets(1):
Percentage by asset category	100%	100%
Defined Benefit Plan, Common Collective Trust | Fair Value, Inputs, Level 1 [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	$ 3,691
Fair value of plan assets at ending Measurement Date	3,613	$ 3,691
Defined Benefit Plan, Common Collective Trust | Significant Observable Inputs (Level 2) [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	604,645
Fair value of plan assets at ending Measurement Date	584,415	604,645
Defined Benefit Plan, Common Collective Trust | Indianapolis Power And Light Company
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	608,336
Fair value of plan assets at ending Measurement Date	$ 588,028	$ 608,336
Sources of change in regulatory assets(1):
Percentage by asset category	100%	100%
Defined Benefit Plan, Common Collective Trust | Indianapolis Power And Light Company | Fair Value, Inputs, Level 1 [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	$ 3,691
Fair value of plan assets at ending Measurement Date	3,613	$ 3,691
Defined Benefit Plan, Common Collective Trust | Indianapolis Power And Light Company | Significant Observable Inputs (Level 2) [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	604,645
Fair value of plan assets at ending Measurement Date	584,415	604,645
Short-Term Investments [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	2,789
Fair value of plan assets at ending Measurement Date	$ 2,791	$ 2,789
Sources of change in regulatory assets(1):
Percentage by asset category	0%	0%
Short-Term Investments [Member] | Fair Value, Inputs, Level 1 [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	$ 2,789
Fair value of plan assets at ending Measurement Date	2,791	$ 2,789
Short-Term Investments [Member] | Significant Observable Inputs (Level 2) [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	0
Fair value of plan assets at ending Measurement Date	0	0
Short-Term Investments [Member] | Indianapolis Power And Light Company
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	2,789
Fair value of plan assets at ending Measurement Date	$ 2,791	$ 2,789
Sources of change in regulatory assets(1):
Percentage by asset category	0%	0%
Short-Term Investments [Member] | Indianapolis Power And Light Company | Fair Value, Inputs, Level 1 [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	$ 2,789
Fair value of plan assets at ending Measurement Date	2,791	$ 2,789
Equity Securities | Indianapolis Power And Light Company
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	85,341
Fair value of plan assets at ending Measurement Date		$ 85,341
Sources of change in regulatory assets(1):
Percentage by asset category		14%
Equity Securities | Indianapolis Power And Light Company | Fair Value, Inputs, Level 1 [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	2,017
Fair value of plan assets at ending Measurement Date		$ 2,017
Equity Securities | Indianapolis Power And Light Company | Significant Observable Inputs (Level 2) [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	83,324
Fair value of plan assets at ending Measurement Date		83,324
Fixed Income [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	400,291
Fair value of plan assets at ending Measurement Date	$ 387,979	$ 400,291
Sources of change in regulatory assets(1):
Percentage by asset category	66%	66%
Fixed Income [Member] | Fair Value, Inputs, Level 1 [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	$ 1,254
Fair value of plan assets at ending Measurement Date	1,168	$ 1,254
Fixed Income [Member] | Significant Observable Inputs (Level 2) [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	399,037
Fair value of plan assets at ending Measurement Date	386,811	399,037
Fixed Income [Member] | Indianapolis Power And Light Company
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	400,291
Fair value of plan assets at ending Measurement Date	$ 387,979	$ 400,291
Sources of change in regulatory assets(1):
Percentage by asset category	66%	66%
Fixed Income [Member] | Indianapolis Power And Light Company | Fair Value, Inputs, Level 1 [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	$ 1,254
Fair value of plan assets at ending Measurement Date	1,168	$ 1,254
Fixed Income [Member] | Indianapolis Power And Light Company | Significant Observable Inputs (Level 2) [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	399,037
Fair value of plan assets at ending Measurement Date	386,811	399,037
Equity Funds [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	85,341
Fair value of plan assets at ending Measurement Date	$ 82,652	$ 85,341
Sources of change in regulatory assets(1):
Percentage by asset category	14%	14%
Equity Funds [Member] | Fair Value, Inputs, Level 1 [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	$ 2,017
Fair value of plan assets at ending Measurement Date	2,267	$ 2,017
Equity Funds [Member] | Significant Observable Inputs (Level 2) [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	83,324
Fair value of plan assets at ending Measurement Date	80,385	$ 83,324
Equity Funds [Member] | Indianapolis Power And Light Company
Change in plan assets:
Fair value of plan assets at beginning Measurement Date
Fair value of plan assets at ending Measurement Date	$ 82,652
Sources of change in regulatory assets(1):
Percentage by asset category	14%
Equity Funds [Member] | Indianapolis Power And Light Company | Fair Value, Inputs, Level 1 [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date
Fair value of plan assets at ending Measurement Date	$ 2,267
Equity Funds [Member] | Indianapolis Power And Light Company | Significant Observable Inputs (Level 2) [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date
Fair value of plan assets at ending Measurement Date	$ 80,385

Benefit Plans (Information For

Benefit Plans (Information For Pension Plans With A Benefit Obligation In Excess Of Plan Assets) (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Entity Information [Line Items]
Defined Benefit Plan, Pension Plan with Projected Benefit Obligation in Excess of Plan Assets, Plan Assets	$ 590,800
Benefit obligation in excess of plan assets	(41,273)	$ (33,596)
Indianapolis Power And Light Company
Entity Information [Line Items]
Defined Benefit Plan, Pension Plan with Projected Benefit Obligation in Excess of Plan Assets, Projected Benefit Obligation	549,500
Benefit obligation in excess of plan assets	$ (41,273)	$ (33,596)

Benefit Plans (Information Fo_2

Benefit Plans (Information For Pension Plans With An Accumulated Benefit Obligation In Excess Of Plan Assets) (Details) $ in Millions	Dec. 31, 2023 USD ($)
Indianapolis Power And Light Company
Entity Information [Line Items]
Plan assets	$ 590.8

Benefit Plans (Schedule Of Net

Benefit Plans (Schedule Of Net Periodic Benefit Costs) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 5,189	$ 8,949	$ 9,339
Interest cost	29,818	18,099	15,660
Expected return on assets	(33,107)	(35,656)	(41,815)
Defined Benefit Plan Amortization of prior service cost net of acceleration component of curtailment charge	2,172	2,589	2,944
Amortization of actuarial loss	6,145	2,424	5,529
Amortization of settlement loss	0	199	0
Net periodic benefit cost	10,217	(3,396)	(8,343)
Less: amounts capitalized	(1,689)	(316)	(771)
Amount charged to expense	$ 8,528	(3,080)	(7,572)
Expected return on plan assets	5.60%
Asset, Defined Benefit Pension Plan, Noncurrent	$ 41,273	33,611
Indianapolis Power And Light Company
Defined Benefit Plan Disclosure [Line Items]
Service cost	5,189	8,949	9,339
Interest cost	29,818	18,099	15,660
Expected return on assets	(33,107)	(35,656)	(41,815)
Defined Benefit Plan Amortization of prior service cost net of acceleration component of curtailment charge	2,172	2,589	2,944
Amortization of actuarial loss	6,145	2,424	5,529
Amortization of settlement loss	0	199	0
Net periodic benefit cost	10,217	(3,396)	(8,343)
Less: amounts capitalized	1,689	(316)	(771)
Amount charged to expense	$ 8,528	$ (3,080)	$ (7,572)
Expected return on plan assets	5.60%	5.60%
Asset, Defined Benefit Pension Plan, Noncurrent	$ 41,273	$ 33,611
Pension Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	5.41%	2.83%	2.46%
Expected return on plan assets	5.60%	4.45%	5.05%
Pension Benefit [Member] | Indianapolis Power And Light Company
Defined Benefit Plan Disclosure [Line Items]
Discount rate	5.41%	2.83%	2.46%
Expected return on plan assets	5.60%	4.45%	5.05%
Supplemental Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	5.32%	2.62%	2.31%
Expected return on plan assets	6.45%	5.50%	3.60%
Supplemental Retirement Plan [Member] | Indianapolis Power And Light Company
Defined Benefit Plan Disclosure [Line Items]
Discount rate	5.32%	2.62%	2.31%
Expected return on plan assets	6.45%	5.50%	3.60%

Benefit Plans (Schedule Of Asse

Benefit Plans (Schedule Of Asset Allocation Guidelines) (Details)	Dec. 31, 2023
Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	13.50%
Equity Securities [Member] | Indianapolis Power And Light Company
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	13.50%
Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	86.50%
Debt Securities [Member] | Indianapolis Power And Light Company
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	86.50%

Benefit Plans (Schedule Of Fair

Benefit Plans (Schedule Of Fair Value Of Pension Plan Assets) (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 590,819	$ 611,125	$ 820,684
Percentage by asset category	100%	100%
Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 6,404	$ 6,480
Significant Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	584,415	604,645
Short-Term Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 2,791	$ 2,789
Percentage by asset category	0%	0%
Short-Term Investments [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 2,791	$ 2,789
Short-Term Investments [Member] | Significant Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
US Government Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 117,397	$ 122,704
Percentage by asset category	20%	20%
US Government Debt Securities [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 178	$ 420
US Government Debt Securities [Member] | Significant Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	117,219	122,284
Equity Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 82,652	$ 85,341
Percentage by asset category	14%	14%
Equity Funds [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 2,267	$ 2,017
Equity Funds [Member] | Significant Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	80,385	83,324
Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 387,979	$ 400,291
Percentage by asset category	66%	66%
Fixed Income [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 1,168	$ 1,254
Fixed Income [Member] | Significant Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	386,811	399,037
Defined Benefit Plan, Common Collective Trust
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 588,028	$ 608,336
Percentage by asset category	100%	100%
Defined Benefit Plan, Common Collective Trust | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 3,613	$ 3,691
Defined Benefit Plan, Common Collective Trust | Significant Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	584,415	604,645
Indianapolis Power And Light Company
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 590,819	$ 611,125	$ 820,684
Percentage by asset category	100%	100%
Indianapolis Power And Light Company | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 6,404	$ 6,480
Indianapolis Power And Light Company | Significant Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	584,415	604,645
Indianapolis Power And Light Company | Short-Term Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 2,791	$ 2,789
Percentage by asset category	0%	0%
Indianapolis Power And Light Company | Short-Term Investments [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 2,791	$ 2,789
Indianapolis Power And Light Company | US Government Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 117,397	$ 122,704
Percentage by asset category	20%	20%
Indianapolis Power And Light Company | US Government Debt Securities [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 178	$ 420
Indianapolis Power And Light Company | US Government Debt Securities [Member] | Significant Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	117,219	122,284
Indianapolis Power And Light Company | Equity Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 82,652
Percentage by asset category	14%
Indianapolis Power And Light Company | Equity Funds [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 2,267
Indianapolis Power And Light Company | Equity Funds [Member] | Significant Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	80,385
Indianapolis Power And Light Company | Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 387,979	$ 400,291
Percentage by asset category	66%	66%
Indianapolis Power And Light Company | Fixed Income [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 1,168	$ 1,254
Indianapolis Power And Light Company | Fixed Income [Member] | Significant Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	386,811	399,037
Indianapolis Power And Light Company | Defined Benefit Plan, Common Collective Trust
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 588,028	$ 608,336
Percentage by asset category	100%	100%
Indianapolis Power And Light Company | Defined Benefit Plan, Common Collective Trust | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 3,613	$ 3,691
Indianapolis Power And Light Company | Defined Benefit Plan, Common Collective Trust | Significant Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 584,415	$ 604,645

Benefit Plans (Schedule Of Expe

Benefit Plans (Schedule Of Expected Benefit Payments) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Entity Information [Line Items]
2016	$ 37,997
2017	38,794
2018	39,665
2019	40,085
2020	41,477
2021 through 2025 (in total)	$ 200,574
Expected return on plan assets	5.60%
Pension Benefit [Member]
Entity Information [Line Items]
Expected return on plan assets	5.60%	4.45%	5.05%
Indianapolis Power And Light Company
Entity Information [Line Items]
2016	$ 37,997
2017	38,794
2018	39,665
2019	40,085
2020	41,477
2021 through 2025 (in total)	$ 200,574
Expected return on plan assets	5.60%	5.60%
Indianapolis Power And Light Company | Pension Benefit [Member]
Entity Information [Line Items]
Expected return on plan assets	5.60%	4.45%	5.05%

Equity (Narrative) (Details)

Equity (Narrative) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)
Class of Stock [Line Items]
Ownership percentage by parent	82.35%
Equity contributions from AES		$ 253,000	$ 275,000
Equity contributions from shareholders	$ 0	253,000	275,000
Debt to Capitalization Ratio, Maximum	1
Interest Coverage Ratio	2.50
Interest Coverage Ratio, Minimum	1
Leverage Ratio	0.67
Payments of Ordinary Dividends, Common Stock	$ 104,287	101,986	131,476
Number of separate series of cumulative preferred stock	5
Total preferred stock dividends declared	$ 0	3,213
Equity Capital Contributions	208,300		226,500
Preferred Stock Redemption Premium	300
Limited Partners' Contributed Capital	79,300
$200M Term Loan Maturing June 2023
Class of Stock [Line Items]
Short-Term Bank Loans and Notes Payable	200,000
Indianapolis Power And Light Company
Class of Stock [Line Items]
Equity contributions from AES	$ 0	253,000	275,000
Debt to capitalization ratio	0.67
Debt to Capitalization Ratio, Maximum	1
Dividends, Common Stock, Cash	$ 140,200	127,200	155,700
Payments of Ordinary Dividends, Common Stock	$ 140,200	127,200	155,700
Number of separate series of cumulative preferred stock	5
Total preferred stock dividends declared	$ 3,200
Preferred Stock, Voting Rights	2
Equity Capital Contributions	$ 253,000	275,000
Preferred Stock, Redemption Amount		60,100
Dividends, Preferred Stock, Stock	0	3,200	3,200
Indianapolis Power And Light Company | $200M Term Loan Maturing June 2023
Class of Stock [Line Items]
Short-Term Bank Loans and Notes Payable	200,000
AES U.S. Investments [Member]
Class of Stock [Line Items]
Equity Capital Contributions	$ 208,300		226,500
AES U.S. Holdings, LLC [Member]
Class of Stock [Line Items]
Ownership Interest in Parent Company, Percent	85%
CDPQ [Member]
Class of Stock [Line Items]
Ownership Interest in Parent Company, Percent	15%
Equity Capital Contributions	$ 31,300		34,000
Equity Capital Contribution to IPALCO	44,700		48,500
AES US Holdings LLC
Class of Stock [Line Items]
Equity Capital Contributions	$ 177,000		192,500
Minimum [Member]
Class of Stock [Line Items]
Dividend rate on preferred stock	4%
Minimum [Member] | Indianapolis Power And Light Company
Class of Stock [Line Items]
Dividend rate on preferred stock	4%
Maximum [Member]
Class of Stock [Line Items]
Dividend rate on preferred stock	5.65%
Maximum [Member] | Indianapolis Power And Light Company
Class of Stock [Line Items]
Dividend rate on preferred stock	5.65%
Additional Paid-in Capital [Member]
Class of Stock [Line Items]
Equity contributions from AES		253,000	275,000
Equity contributions from shareholders
Additional Paid-in Capital [Member] | Indianapolis Power And Light Company
Class of Stock [Line Items]
Equity contributions from AES	0	253,000	275,000
Retained Earnings [Member] | Indianapolis Power And Light Company
Class of Stock [Line Items]
Dividends, Common Stock, Cash	$ 140,200	127,200	155,700
Total preferred stock dividends declared		$ 3,213	$ 3,213

Commitments and Contingencies (

Commitments and Contingencies (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Entity Information [Line Items]
Coal, Gas, Purchased Power and Related Transportation Purchase Obligations, Net	$ 933,500
Other Purchase Obligations, Net	409,100
Coal, Gas, Purchased Power and Related Transportation Purchase Obligations Less Than 1 Year	249,700
Coal, Gas, Purchased Power and Related Transportation Purchase Obligations in Years 1 through 3	267,300
Coal, Gas, Purchased Power and Related Transportation Purchase Obligations Years 3 through 5	225,700
Coal, Gas, Purchased Power and Related Transportation Purchase Obligations After Year 5	190,800
Other Purchase Obligations, After Year 5	1,100
Other Purchase Obligations Years 3 through 5	20,200
Other Purchase Obligations Years 1 through 3	32,800
Other Purchase Obligations Less than 1 Year	355,000
Other Assets, Noncurrent	1,120,591,000	$ 849,054,000
Civil penalty	1,525,000
Payments for Environmental Liabilities	5,000,000
Prepaid Implementation Costs for Software as a Service
Entity Information [Line Items]
Other Assets, Noncurrent	7,100,000	8,200,000
Indianapolis Power And Light Company
Entity Information [Line Items]
Coal, Gas, Purchased Power and Related Transportation Purchase Obligations, Net	933,500
Other Purchase Obligations, Net	409,100
Coal, Gas, Purchased Power and Related Transportation Purchase Obligations Less Than 1 Year	249,700
Coal, Gas, Purchased Power and Related Transportation Purchase Obligations in Years 1 through 3	267,300
Coal, Gas, Purchased Power and Related Transportation Purchase Obligations Years 3 through 5	225,700
Coal, Gas, Purchased Power and Related Transportation Purchase Obligations After Year 5	190,800
Other Purchase Obligations, After Year 5	1,100
Other Purchase Obligations Years 3 through 5	20,200
Other Purchase Obligations Years 1 through 3	32,800
Other Purchase Obligations Less than 1 Year	355,000
Other Assets, Noncurrent	1,117,051,000	833,536,000
Civil penalty	1,525,000
Payments for Environmental Liabilities	5,000,000
Indianapolis Power And Light Company | Prepaid Implementation Costs for Software as a Service
Entity Information [Line Items]
Other Assets, Noncurrent	$ 7,100,000	$ 8,200,000

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Related Party Transaction [Line Items]
Self-insured retention per occurrence	$ 5,000
Insurance expense	11,700	$ 9,500	$ 7,000
Prepaid insurance	7,500	3,400
Health coverage expense	19,000	25,200	23,700
Income taxes receivable	36,500	18,000
Deferred Compensation Arrangement with Individual, Compensation Expense	300	200	200
Billings from related party	7,400	5,700	4,300
Parent Loan Repayment	6,100
Service Company [Member]
Related Party Transaction [Line Items]
Costs incurred by related party	73,800	60,300	58,400
Receivables from Related Party	25,600	2,100
Affiliated Entity
Related Party Transaction [Line Items]
Billings from related party	223,300
Ipalco Enterprises, Inc. [Member]
Related Party Transaction [Line Items]
Costs incurred by related party	11,900	10,000	10,400
Indianapolis Power And Light Company
Related Party Transaction [Line Items]
Self-insured retention per occurrence	5,000
Insurance expense	11,700	9,500	7,000
Prepaid insurance	7,500	3,400
Health coverage expense	19,000	25,200	23,700
Income taxes receivable	5,100	6,700
Deferred Compensation Arrangement with Individual, Compensation Expense	300	200	200
Costs incurred by related party	11,900	10,000	10,400
Billings from related party	7,400	5,700	4,300
Indianapolis Power And Light Company | Service Company [Member]
Related Party Transaction [Line Items]
Costs incurred by related party	$ 73,600	$ 60,100	$ 58,200

Business Segment Information (D

Business Segment Information (Details)	12 Months Ended
	Dec. 31, 2023 segment
Indianapolis Power And Light Company
Debt Instrument [Line Items]
Reportable segments	1

Business Segment Information (S

Business Segment Information (Summary Of Company's Reporting Segments) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Segment Reporting Information [Line Items]
REVENUE	$ 1,649,917	$ 1,791,711	$ 1,426,132
Depreciation and amortization	287,863	266,504	256,085
Interest Expense	142,926	131,232	125,626
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest	71,742	118,485	148,123
Property, Plant and Equipment, Additions	902,705	496,510	291,546
Tax benefit	14,715	21,859	28,941
Net income	57,027	96,626	119,182
TOTAL ASSETS	6,181,523	5,589,214	5,239,767
Accruals for capital expenditures	124,626	66,949	81,325
Financed Capital Expenditures	0	0	36
Electric [Member]
Segment Reporting Information [Line Items]
REVENUE	1,649,917	1,791,711	1,426,132
Depreciation and amortization	287,863	266,504	256,085
Interest Expense	99,051	87,428	84,256
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest	115,763	162,862	189,548
Property, Plant and Equipment, Additions		496,510	291,546
TOTAL ASSETS	6,129,581	5,559,977	5,222,987
Other Segments [Member]
Segment Reporting Information [Line Items]
Depreciation and amortization	0	0	0
Interest Expense	43,875	43,804	41,370
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest	(44,021)	(44,377)	(41,425)
Property, Plant and Equipment, Additions	0	0	0
TOTAL ASSETS	$ 51,942	$ 29,237	$ 16,780

Revenue (Details)

Revenue (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2019	Dec. 31, 2018	Jan. 31, 2018
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	$ 1,616,500			$ 1,760,000	$ 1,389,200
REVENUE	1,649,917	$ 1,791,711	$ 1,426,132
Contract with Customer, Asset, before Allowance for Credit Loss	218,800	198,300
Retail Revenue [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	1,546,041	1,589,170	1,351,431
Other non-606 revenue	30,414	29,171	35,248
Retail Revenue [Member] | Utility
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	14,016	17,845	16,785
Retail Revenue [Member] | Residential Revenue | Utility
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	660,559	688,487	595,692
Retail Revenue [Member] | Small Commercial and Industrial | Utility
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	241,800	247,655	211,997
Retail Revenue [Member] | Large Commercial and Industrial | Utility
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	619,899	625,351	518,069
Retail Revenue [Member] | Public Lighting | Utility
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	9,767	9,832	8,888
Wholesale Revenue [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	56,557	148,517	25,059
Miscellaneous revenue [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	13,864	22,284	12,214
RTO Capacity Revenue	8,210	11,750	734
Other non-606 revenue	3,041	2,569	2,180
Miscellaneous revenue [Member] | Transmission revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	5,654	10,534	11,480
Electricity [Member]
Disaggregation of Revenue [Line Items]
REVENUE	1,649,917	1,791,711	1,426,132
Indianapolis Power And Light Company
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	1,616,500	1,760,000	1,389,200
REVENUE	1,649,917	1,791,711	1,426,132
Contract with Customer, Asset, before Allowance for Credit Loss				$ 218,800		$ 198,300
Indianapolis Power And Light Company | Retail Revenue [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	1,546,041	1,589,170	1,351,431
Other non-606 revenue	30,414	29,171	35,248
Indianapolis Power And Light Company | Retail Revenue [Member] | Utility
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	14,016	17,845	16,785
Indianapolis Power And Light Company | Retail Revenue [Member] | Residential Revenue | Utility
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	660,559	688,487	595,692
Indianapolis Power And Light Company | Retail Revenue [Member] | Small Commercial and Industrial | Utility
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	241,800	247,655	211,997
Indianapolis Power And Light Company | Retail Revenue [Member] | Large Commercial and Industrial | Utility
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	619,899	625,351	518,069
Indianapolis Power And Light Company | Retail Revenue [Member] | Public Lighting | Utility
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	9,767	9,832	8,888
Indianapolis Power And Light Company | Wholesale Revenue [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	56,557	148,517	25,059
Indianapolis Power And Light Company | Miscellaneous revenue [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	13,864	22,284	12,214
RTO Capacity Revenue	8,210	11,750	734
Other non-606 revenue	3,041	2,569	2,180
Indianapolis Power And Light Company | Miscellaneous revenue [Member] | Transmission revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	5,654	10,534	11,480
Indianapolis Power And Light Company | Electricity [Member]
Disaggregation of Revenue [Line Items]
REVENUE	$ 1,649,917	$ 1,791,711	$ 1,426,132

Leases (Details)

Leases (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Lessee, Lease, Description [Line Items]
Property Subject to or Available for Operating Lease, Accumulated Depreciation	$ (1,222)	$ (1,060)
Property, Plant, and Equipment, Lessor Asset under Operating Lease, after Accumulated Depreciation	3,119	3,274
Property Subject to or Available for Operating Lease, Gross	4,341	4,334
Lessor, Operating Lease, Payment to be Received, Year One	544
Lessor, Operating Lease, Payment to be Received, Year Two	553
Lessor, Operating Lease, Payment to be Received, Year Three	554
Lessor, Operating Lease, Payment to be Received, Year Four	554
Lessor, Operating Lease, Payment to be Received, Year Five	354
Lessor, Operating Lease, Payment to be Received, after Year Five	$ 891
Future Minimum Lease Receipts	The following table shows the future minimum lease receipts through 2028 and thereafter (in thousands): Operating Leases 2024 $ 544 2025 553 2026 554 2027 554 2028 354 Thereafter 891 Total $ 3,450
Operating Lease, Lease Income	$ 1,537	1,134	$ 1,439
Lessor, Operating Lease, Payments to be Received	3,450
Finance Lease, Liability, Noncurrent	17,769	16,361
Finance Lease, Liability	$ 17,769	$ 16,361
Finance Lease, Weighted Average Remaining Lease Term	35 years	36 years
Finance Lease, Weighted Average Discount Rate, Percent	5.30%	5.65%
Finance Lease, Liability, to be Paid, Next Rolling 12 Months	$ 891
Finance Lease, Liability, Payments, Due in Rolling Year Two	909
Finance Lease, Liability, to be Paid, Year Three	927
Finance Lease, Liability, to be Paid, Year Four	945
Finance Lease, Liability, to be Paid, Year Five	965
Finance Lease, Liability, to be Paid, after Year Five	39,958
Total Future Lease Payments	44,595
Imputed interest	(26,826)
Finance Lease, Right-of-Use Asset, Amortization	445	$ 542	0
Finance Lease, Interest Expense	933	782	0
Lease, Cost	1,378	1,324	0
Operating Lease, Payments, Use	600	300	0
Finance Lease, Right-of-Use Asset, before Accumulated Amortization	16,357	15,819
Subsidiaries [Member]
Lessee, Lease, Description [Line Items]
Property Subject to or Available for Operating Lease, Accumulated Depreciation	1,222	1,060
Property, Plant, and Equipment, Lessor Asset under Operating Lease, after Accumulated Depreciation	3,119	3,274
Property Subject to or Available for Operating Lease, Gross	4,341	4,334
Lessor, Operating Lease, Payment to be Received, Year One	544
Lessor, Operating Lease, Payment to be Received, Year Two	553
Lessor, Operating Lease, Payment to be Received, Year Three	554
Lessor, Operating Lease, Payment to be Received, Year Four	554
Lessor, Operating Lease, Payment to be Received, Year Five	354
Lessor, Operating Lease, Payment to be Received, after Year Five	$ 891
Future Minimum Lease Receipts	The following table shows the future minimum lease receipts through 2028 and thereafter (in thousands): Operating Leases 2024 $ 544 2025 553 2026 554 2027 554 2028 354 Thereafter 891 Total $ 3,450
Operating Lease, Lease Income	$ 1,537	1,134	1,439
Lessor, Operating Lease, Payments to be Received	3,450
Finance Lease, Liability, Noncurrent	17,769	16,361
Finance Lease, Liability	$ 17,769	$ 16,361
Finance Lease, Weighted Average Remaining Lease Term	35 years	36 years
Finance Lease, Weighted Average Discount Rate, Percent	530%	565%
Finance Lease, Liability, to be Paid, Remainder of Fiscal Year	$ 891
Finance Lease, Liability, Payments, Due in Rolling Year Two	909
Finance Lease, Liability, to be Paid, Year Three	927
Finance Lease, Liability, to be Paid, Year Four	945
Finance Lease, Liability, to be Paid, Year Five	965
Finance Lease, Liability, to be Paid, after Year Five	39,958
Total Future Lease Payments	44,595
Imputed interest	(26,826)
Finance Lease, Right-of-Use Asset, Amortization	445	$ 542	0
Finance Lease, Interest Expense	933	782	0
Lease, Cost	1,378	1,324	$ 0
Operating Lease, Payments, Use	600
Finance Lease, Right-of-Use Asset, before Accumulated Amortization	$ 16,357	$ 15,819

Schedule I - Condensed Financ_2

Schedule I - Condensed Financial Information Of Registrant (Narrative) (Details) MWh in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2023 USD ($) MWh	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)
Condensed Financial Statements, Captions [Line Items]
Equity contributions from AES		$ 253,000	$ 275,000
Ownership percentage by parent	82.35%
Equity contributions from shareholders	$ 0	253,000	275,000
Investments, Fair Value Disclosure	3,552	3,228
Forward Power Contracts Fair Value Disclosure	14,294	12,172
Total financial assets measured at fair value	19,234	22,945
Unobservable Inputs (Level 3) [Member]
Condensed Financial Statements, Captions [Line Items]
Investments, Fair Value Disclosure	0	0
Total financial assets measured at fair value	1,388	7,545
Fair Value, Inputs, Level 1 [Member]
Condensed Financial Statements, Captions [Line Items]
Investments, Fair Value Disclosure	3,552	3,228
Total financial assets measured at fair value	3,552	3,228
Significant Observable Inputs (Level 2) [Member]
Condensed Financial Statements, Captions [Line Items]
Investments, Fair Value Disclosure	0	0
Total financial assets measured at fair value	14,294	12,172
Mutual Fund [Member]
Condensed Financial Statements, Captions [Line Items]
Investments, Fair Value Disclosure	3,425	3,223
Money Market Funds [Member]
Condensed Financial Statements, Captions [Line Items]
Investments, Fair Value Disclosure	127	5
Ipalco Enterprises, Inc. [Member]
Condensed Financial Statements, Captions [Line Items]
Equity contributions from AES		253,000
Equity contributions from shareholders	0	253,000	275,000
Investments, Fair Value Disclosure	3,552	3,228
Forward Power Contracts Fair Value Disclosure	14,294	12,172
Total financial assets measured at fair value	17,846	15,400
Ipalco Enterprises, Inc. [Member] | Unobservable Inputs (Level 3) [Member]
Condensed Financial Statements, Captions [Line Items]
Investments, Fair Value Disclosure		0
Forward Power Contracts Fair Value Disclosure	0	0
Total financial assets measured at fair value	0	0
Ipalco Enterprises, Inc. [Member] | Fair Value, Inputs, Level 1 [Member]
Condensed Financial Statements, Captions [Line Items]
Investments, Fair Value Disclosure	3,552	3,228
Forward Power Contracts Fair Value Disclosure	0	0
Total financial assets measured at fair value	3,552	3,228
Ipalco Enterprises, Inc. [Member] | Significant Observable Inputs (Level 2) [Member]
Condensed Financial Statements, Captions [Line Items]
Investments, Fair Value Disclosure	0	0
Forward Power Contracts Fair Value Disclosure	14,294	12,172
Total financial assets measured at fair value	14,294	12,172
Ipalco Enterprises, Inc. [Member] | Mutual Fund [Member]
Condensed Financial Statements, Captions [Line Items]
Investments, Fair Value Disclosure	3,425	3,223
Ipalco Enterprises, Inc. [Member] | Mutual Fund [Member] | Unobservable Inputs (Level 3) [Member]
Condensed Financial Statements, Captions [Line Items]
Investments, Fair Value Disclosure	0	0
Ipalco Enterprises, Inc. [Member] | Mutual Fund [Member] | Fair Value, Inputs, Level 1 [Member]
Condensed Financial Statements, Captions [Line Items]
Investments, Fair Value Disclosure	3,425	3,223
Ipalco Enterprises, Inc. [Member] | Mutual Fund [Member] | Significant Observable Inputs (Level 2) [Member]
Condensed Financial Statements, Captions [Line Items]
Investments, Fair Value Disclosure	0	0
Ipalco Enterprises, Inc. [Member] | Money Market Funds [Member]
Condensed Financial Statements, Captions [Line Items]
Investments, Fair Value Disclosure	127	5
Ipalco Enterprises, Inc. [Member] | Money Market Funds [Member] | Unobservable Inputs (Level 3) [Member]
Condensed Financial Statements, Captions [Line Items]
Investments, Fair Value Disclosure	0	0
Ipalco Enterprises, Inc. [Member] | Money Market Funds [Member] | Fair Value, Inputs, Level 1 [Member]
Condensed Financial Statements, Captions [Line Items]
Investments, Fair Value Disclosure	127	5
Ipalco Enterprises, Inc. [Member] | Money Market Funds [Member] | Significant Observable Inputs (Level 2) [Member]
Condensed Financial Statements, Captions [Line Items]
Investments, Fair Value Disclosure	0	0
Subsidiaries [Member]
Condensed Financial Statements, Captions [Line Items]
Equity contributions from AES	0	253,000	$ 275,000
Total financial assets measured at fair value	1,388	7,545
Subsidiaries [Member] | Unobservable Inputs (Level 3) [Member]
Condensed Financial Statements, Captions [Line Items]
Total financial assets measured at fair value	1,388	7,545
Subsidiaries [Member] | Fair Value, Inputs, Level 1 [Member]
Condensed Financial Statements, Captions [Line Items]
Total financial assets measured at fair value	0	0
Subsidiaries [Member] | Significant Observable Inputs (Level 2) [Member]
Condensed Financial Statements, Captions [Line Items]
Total financial assets measured at fair value	0	$ 0
Parent | Unobservable Inputs (Level 3) [Member]
Condensed Financial Statements, Captions [Line Items]
Investments, Fair Value Disclosure	0
Interest Rate Swap [Member] | Designated as Hedging Instrument [Member]
Condensed Financial Statements, Captions [Line Items]
Purchase of Derivative Instruments Interest Rate Swap	400,000
Sale of Derivative Instruments Interest Rate Swap	0
Derivative, Notional Amount, Purchase (Sales), Net	400,000
Interest Rate Swap [Member] | Designated as Hedging Instrument [Member] | Ipalco Enterprises, Inc. [Member]
Condensed Financial Statements, Captions [Line Items]
Purchase of Derivative Instruments Interest Rate Swap	400,000
Sale of Derivative Instruments Interest Rate Swap	0
Derivative, Notional Amount, Purchase (Sales), Net	$ 400,000
FTR [Member] | Not Designated as Hedging Instrument [Member]
Condensed Financial Statements, Captions [Line Items]
Purchase of Units Derivative Instruments Financial Transmission Rights | MWh	3,919
Sale of Units Derivative Instruments Financial Transmission Rights | MWh	0
Derivative, Nonmonetary Notional Amount, Purchase (Sales), Net | MWh	3,919
FTR [Member] | Not Designated as Hedging Instrument [Member] | Subsidiaries [Member]
Condensed Financial Statements, Captions [Line Items]
Purchase of Units Derivative Instruments Financial Transmission Rights | MWh	3,919
Sale of Units Derivative Instruments Financial Transmission Rights | MWh	0
Derivative, Nonmonetary Notional Amount, Purchase (Sales), Net | MWh	3,919

Schedule I - Condensed Financ_3

Schedule I - Condensed Financial Information Of Registrant (Unconsolidated Balance Sheet) (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Condensed Financial Statements, Captions [Line Items]
Cash and cash equivalents	$ 28,579	$ 201,548
Total current assets	574,030	706,829
Derivative Asset, Noncurrent	0	12,172
Total other non-current assets	1,120,591	849,054
TOTAL ASSETS	6,181,523	5,589,214	$ 5,239,767
Short-term debt	899,159	0
Accounts payable	292,851	189,845
Accumulated deficit	25,182	(108)
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	1,129,722	1,090,518
Total common shareholder's deficit	1,076,468	1,090,518	794,600	$ 520,988
Long-term debt	2,558,420	3,000,450
Deferred Income Taxes and Other Tax Liabilities, Noncurrent	18,931	7,329
Accrued interest	33,639	33,447
Total current liabilities	1,328,455	323,225
Total non-current liabilities	3,723,346	4,175,471
Liabilities	5,051,801	4,498,696
Additional Paid in Capital	1,021,992	1,068,357
Accumulated Other Comprehensive Income (Loss), Net of Tax	29,294	22,269	(29,407)	(43,420)
TOTAL LIABILITIES AND EQUITY	6,181,523	5,589,214
Restricted Cash and Cash Equivalents	5	5
Income Taxes Receivable, Current	36,481	18,000
Other Assets, Current	26,358	19,882
Parent Company [Member]
Condensed Financial Statements, Captions [Line Items]
Cash and cash equivalents	537	191
Total current assets	53,798	19,018
Investment in subsidiaries	1,921,548	1,945,556
Other Assets	3,540	3,211
Total other non-current assets	1,925,088	1,960,939
TOTAL ASSETS	1,978,886	1,979,957
Short-term debt	404,474	0
Accounts payable	0	87
Accumulated deficit	25,182	(108)
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	1,076,468	1,090,518	794,600	520,988
Long-term debt	470,127	873,663
Accrued interest	8,360	8,360
Total current liabilities	412,834	8,447
Total non-current liabilities	489,584	880,992
Liabilities	902,418	889,439
Additional Paid in Capital	1,021,992	1,068,357
Accumulated Other Comprehensive Income (Loss), Net of Tax	29,294	22,269	$ (29,407)	$ (43,420)
TOTAL LIABILITIES AND EQUITY	1,978,886	1,979,957
Income Taxes Receivable, Current	14,294	0
Other Assets, Current	$ 7,626	$ 7,509

Schedule I - Condensed Financ_4

Schedule I - Condensed Financial Information Of Registrant (Unconsolidated Statements Of Income) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Condensed Financial Statements, Captions [Line Items]
Interest Expense	$ (142,926)	$ (131,232)	$ (125,626)
Other (expense) / income, net	(410)	11,783	17,667
Total other expense, net	(134,021)	(114,665)	(102,547)
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest	71,742	118,485	148,123
Income tax expense	14,715	21,859	28,941
Net income	57,027	96,626	119,182
Parent Company [Member]
Condensed Financial Statements, Captions [Line Items]
Equity in earnings of subsidiaries	116,190	126,466	147,030
Interest Expense	(43,877)	(43,805)	(41,380)
Other (expense) / income, net	(121)	(571)	(45)
Total other expense, net	72,192	82,090	105,605
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest	72,192	82,090	105,605
Income tax expense	(10,928)	(11,027)	(10,364)
Net income	$ 83,120	$ 93,117	$ 115,969

Schedule I - Condensed Financ_5

Schedule I - Condensed Financial Information Of Registrant (Unconsolidated Statements Of Cash Flows) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Condensed Financial Statements, Captions [Line Items]
Net income	$ 57,027	$ 96,626	$ 119,182
Amortization of debt issuance costs and discounts	(3,880)	(3,914)	(3,915)
Increase (Decrease) in Accounts Payable	46,993	32,038	21,417
Accrued taxes payable/receivable	(18,375)	(5,858)	638
Other - net	(4,268)	5,335	(2,026)
Distributions to shareholders	104,287	101,986	131,476
Equity contributions from shareholders	0	253,000	275,000
Other - net	313	35	131
Net change in cash, cash equivalents and restricted cash	(172,969)	194,636	(19,705)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	28,584	201,553	6,917	$ 26,622
Interest Paid, Excluding Capitalized Interest, Operating Activities	129,113	115,277	118,052
Income Taxes Paid, Net	0	31,000	27,500
Parent Company [Member]
Condensed Financial Statements, Captions [Line Items]
Net income	83,120	93,117	115,969
Equity in earnings of subsidiaries	(116,190)	(126,466)	(147,030)
Cash dividends received from subsidiary companies	140,200	127,200	155,700
Amortization of debt issuance costs and discounts	(1,474)	(1,403)	(1,379)
Deferred income taxes - net	9,276	(121)	(5)
Increase (Decrease) in Accounts Payable	(23)	(194)	(85)
Accrued taxes payable/receivable	(20,022)	(2,406)	2,940
Other - net	6,798	7,744	4,265
Net cash provided by operating activities	104,633	100,277	133,133
Investment in subsidiaries	0	(253,000)	(275,000)
Net cash used in investing activities	0	(253,000)	(275,000)
Repayments of Loans to Subsidiary	0	0	6,110
Distributions to shareholders	104,287	101,986	(131,476)
Equity contributions from shareholders	0	253,000	275,000
Other - net	0	2	62
Net cash provided by financing activities	(104,287)	151,012	137,352
Net change in cash, cash equivalents and restricted cash	346	(1,711)	(4,515)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	537	191	1,902	$ 6,417
Interest Paid, Excluding Capitalized Interest, Operating Activities	35,569	35,173	35,172
Income Taxes Paid, Net	$ 0	$ 31,000	$ 27,500

Schedule I - Condensed Financ_6

Schedule I - Condensed Financial Information Of Registrant (Unconsolidated Statements Of Common Shareholders' Equity (Deficit)) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Condensed Financial Statements, Captions [Line Items]
Other Comprehensive Income (Loss), Net of Tax	$ 7,025	$ 51,676	$ 14,013
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning Balance	1,090,518
Net income / (loss)	83,120	93,117	115,969
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	90,145	144,793	129,982
Distributions to AES	(104,287)	(101,986)	(131,476)
Equity contributions from shareholders	0	253,000	275,000
Other	92	111	106
Ending Balance	1,129,722	1,090,518
Contributions from shareholders		253,000	275,000
Parent Company [Member]
Condensed Financial Statements, Captions [Line Items]
Other Comprehensive Income (Loss), Net of Tax	7,025	51,676	14,013
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning Balance	1,090,518	794,600	520,988
Net income / (loss)	83,120	93,117	115,969
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	90,145	144,793	129,982
Distributions to AES	104,287	101,986	131,476
Equity contributions from shareholders	0	253,000	275,000
Other	92	111	106
Ending Balance	1,076,468	1,090,518	794,600
Net cash used in investing activities	0	(253,000)	(275,000)
Contributions from shareholders		253,000
Subsidiaries [Member]
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning Balance	1,943,710
Net income / (loss)	116,190	126,466	147,030
Other	92	114	107
Ending Balance	1,973,046	1,943,710
Contributions from shareholders	0	253,000	275,000
Paid In Capital [Member]
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Return of Capital	(46,500)	(33,300)	(15,500)
Equity contributions from shareholders
Other	92	111	106
Contributions from shareholders		253,000	275,000
Paid In Capital [Member] | Parent Company [Member]
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning Balance	1,068,357	848,565	588,966
Return of Capital	(46,457)	(33,319)	(15,507)
Other	92	111	106
Ending Balance	1,021,992	1,068,357	848,565
Contributions from shareholders		253,000
Paid In Capital [Member] | Subsidiaries [Member]
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Other	92	114	107
Contributions from shareholders	0	253,000	275,000
AOCI Attributable to Parent [Member]
Condensed Financial Statements, Captions [Line Items]
Other Comprehensive Income (Loss), Net of Tax	7,025	51,676	14,013
AOCI Attributable to Parent [Member] | Parent Company [Member]
Condensed Financial Statements, Captions [Line Items]
Other Comprehensive Income (Loss), Net of Tax	7,025	51,676	14,013
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning Balance	22,269	(29,407)	(43,420)
Ending Balance	29,294	22,269	(29,407)
Accumulated Deficit [Member]
Condensed Financial Statements, Captions [Line Items]
Other Comprehensive Income (Loss), Net of Tax	0	0	0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income / (loss)	83,120	96,626	119,182
Distributions to AES	(57,830)	(68,667)	(115,969)
Accumulated Deficit [Member] | Parent Company [Member]
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning Balance	(108)	(24,558)	(24,558)
Net income / (loss)	83,120	93,117	115,969
Distributions to AES	57,830	68,667	115,969
Ending Balance	$ 25,182	$ (108)	$ (24,558)

Schedule I - Condensed Financ_7

Schedule I - Condensed Financial Information Of Registrant (Long-Term Indebtedness) (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Condensed Financial Statements, Captions [Line Items]
Unamortized discount - net	$ (6,768)
Debt Issuance Costs, Net	(23,612)
Long-term debt	3,003,420	$ 3,000,450
Current portion of long-term debt	445,000	0
Net Long-term Debt	2,558,420	3,000,450
Parent Company [Member]
Condensed Financial Statements, Captions [Line Items]
Unamortized discount - net	(319)	(425)
Debt Issuance Costs, Net	(4,554)	(5,912)
Debt, Long-Term and Short-Term, Combined Amount	875,127	873,663
Long-term debt	470,653	873,663
Current portion of long-term debt	405,000	0
Net Long-term Debt	470,127	873,663
Parent Company [Member] | Three Point Seven Zero Percent Senior Secured Notes [Domain]
Condensed Financial Statements, Captions [Line Items]
Long-term debt	$ 405,000	405,000
Debt, stated interest rate	3.70%
Parent Company [Member] | Four Point Two Five Percent Senior Secured Notes
Condensed Financial Statements, Captions [Line Items]
Long-term debt	$ 475,000	$ 475,000
Debt, stated interest rate	4.25%

Schedule I - Condensed Financ_8

Schedule I - Condensed Financial Information Of Registrant Schedule I - Condensed Financial Information Of Registrant (Unconsolidated Statements of Comprehensive Income/(Loss)) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Condensed Statement of Income Captions [Line Items]
Net Income (Loss) Available to Common Stockholders, Basic	$ 83,120	$ 93,117	$ 115,969
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	1,594	46,245	10,393
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax	7,025	51,676	14,013
Other Comprehensive Income (Loss), Net of Tax	7,025	51,676	14,013
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	90,145	144,793	129,982
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax	(528)	(15,309)	(3,441)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Tax	(1,798)	(1,798)	(1,199)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	5,431	5,431	3,620
Dividends on and redemption of preferred stock	0	3,509	3,213
Parent Company [Member]
Condensed Statement of Income Captions [Line Items]
Net Income (Loss) Available to Common Stockholders, Basic	83,120	93,117	115,969
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	1,594	46,245	10,393
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax	7,025	51,676	14,013
Other Comprehensive Income (Loss), Net of Tax	7,025	51,676	14,013
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	90,145	144,793	129,982
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax	(528)	(15,309)	(3,441)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Tax	(1,798)	(1,798)	(1,199)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	5,431	5,431	3,620
Subsidiaries [Member]
Condensed Statement of Income Captions [Line Items]
Net Income (Loss) Available to Common Stockholders, Basic	116,190	126,466	147,030
Dividends on and redemption of preferred stock	$ 0	$ 3,509	$ 3,213

Schedule I - Condensed Financ_9

Schedule I - Condensed Financial Information Of Registrant Schedule I - Condensed Financial Information Of Registrant (Derivative Instruments and Hedging Activities) (Details) MWh in Thousands	12 Months Ended
	Dec. 31, 2023 USD ($) MWh	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)
Number of Interest Rate Swaps	3
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	$ 1,594,000	$ 46,245,000	$ 10,393,000
Accumulated Other Comprehensive Income (Loss), Net of Tax	29,294,000	22,269,000	(29,407,000)	$ (43,420,000)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	1,594,000	46,245,000	10,393,000
Reclassification from AOCI, Current Period, Net of Tax, Attributable to Parent	5,431,000	5,431,000	3,620,000
Interest Rate Contract [Member]
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax	29,294,000	22,269,000	(29,407,000)
Interest Rate Cash Flow Hedge Gain (Loss) to be Reclassified During Next 12 Months, Net	$ (5,375)
Maximum Length of Time Hedged in Cash Flow Hedge	9 years
Not Designated as Hedging Instrument [Member] | FTR [Member]
Purchase of Units Derivative Instruments Financial Transmission Rights | MWh	3,919
Sale of Units Derivative Instruments Financial Transmission Rights | MWh	0
Derivative, Nonmonetary Notional Amount, Purchase (Sales), Net | MWh	3,919
Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Purchase of Derivative Instruments Interest Rate Swap	$ 400,000,000
Sale of Derivative Instruments Interest Rate Swap	0
Derivative, Notional Amount, Purchase (Sales), Net	400,000,000
Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | Derivative Liability, Current
Derivative Liability, Fair Value, Gross Liability	0	12,172,000
Parent Company [Member]
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	1,594,000	46,245,000	10,393,000
Accumulated Other Comprehensive Income (Loss), Net of Tax	29,294,000	22,269,000	(29,407,000)	$ (43,420,000)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	1,594,000	46,245,000	10,393,000
Reclassification from AOCI, Current Period, Net of Tax, Attributable to Parent	5,431,000	5,431,000	3,620,000
Parent Company [Member] | Interest Rate Contract [Member]
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax	29,294,000	22,269,000	$ (29,407,000)
Interest Rate Cash Flow Hedge Gain (Loss) to be Reclassified During Next 12 Months, Net	$ (5,375)
Maximum Length of Time Hedged in Cash Flow Hedge	9 years
Parent Company [Member] | Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Purchase of Derivative Instruments Interest Rate Swap	$ 400,000,000
Sale of Derivative Instruments Interest Rate Swap	0
Derivative, Notional Amount, Purchase (Sales), Net	400,000,000
Parent Company [Member] | Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | Derivative Liability, Current
Derivative Liability, Fair Value, Gross Liability	$ 0	$ 12,172,000,000

Schedule I - Condensed Finan_10

Schedule I - Condensed Financial Information Of Registrant (Fair Value) (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022	Apr. 08, 2020
Condensed Financial Information Disclosure [Abstract]
Total financial assets measured at fair value	$ 19,234	$ 22,945
Investments, Fair Value Disclosure	3,552	3,228
Total financial assets measured at fair value	19,234	22,945
Face Value	3,488,800	3,033,800
Fair Value	3,315,467	2,775,644
Long-term debt	3,003,420	3,000,450
Deferred financing costs, net	23,612
Unamortized discounts	6,768
Interest Rate Swap [Member]
Accumulated Other Income (Loss)			$ 72,300
Interest Rate Swap [Member] | Designated as Hedging Instrument [Member]
Derivative, Notional Amount, Purchase (Sales), Net	400,000
Fixed Rate [Member]
Face Value	3,033,800	3,033,800
Fair Value	2,860,467	2,775,644
Variable Rate [Member]
Face Value	455,000	0
Fair Value	455,000	0
Parent Company [Member]
Condensed Financial Information Disclosure [Abstract]
Total financial assets measured at fair value	17,846	15,400
Investments, Fair Value Disclosure	3,552	3,228
Total financial assets measured at fair value	17,846	15,400
Face Value	880,000	880,000
Fair Value	839,471	816,411
Long-term debt	470,653	873,663
Deferred financing costs, net	4,554	5,912
Unamortized discounts	319	425
Parent Company [Member] | Interest Rate Swap [Member] | Designated as Hedging Instrument [Member]
Derivative, Notional Amount, Purchase (Sales), Net	400,000
Parent Company [Member] | Fixed Rate [Member]
Face Value	880,000	880,000
Fair Value	$ 839,471	816,411
Parent Company [Member] | Four Point Two Five Percent Senior Secured Notes
Debt instrument, stated interest rate	4.25%
Long-term debt	$ 475,000	475,000
Subsidiaries [Member]
Condensed Financial Information Disclosure [Abstract]
Total financial assets measured at fair value	1,388	7,545
Total financial assets measured at fair value	1,388	7,545
Face Value	2,608,800	2,153,800
Fair Value	2,475,997	1,959,233
Long-term debt	2,128,293	2,126,787
First mortgage bonds	2,128,293	2,126,787
Deferred financing costs, net	20,200	20,400
Unamortized discounts	6,449	6,651
Subsidiaries [Member] | Fixed Rate [Member]
Face Value	2,153,800	2,153,800
Fair Value	2,020,997	1,959,233
Subsidiaries [Member] | Variable Rate [Member]
Face Value	455,000	0
Fair Value	455,000	0
Unamortized discounts	$ (6,400)	6,700
Subsidiaries [Member] | FMB Twenty - three
Debt instrument, stated interest rate	0.95%
First mortgage bonds	$ 60,000	60,000
Fair Value, Inputs, Level 1 [Member]
Condensed Financial Information Disclosure [Abstract]
Total financial assets measured at fair value	3,552	3,228
Investments, Fair Value Disclosure	3,552	3,228
Total financial assets measured at fair value	3,552	3,228
Fair Value, Inputs, Level 1 [Member] | Parent Company [Member]
Condensed Financial Information Disclosure [Abstract]
Total financial assets measured at fair value	3,552	3,228
Investments, Fair Value Disclosure	3,552	3,228
Total financial assets measured at fair value	3,552	3,228
Fair Value, Inputs, Level 1 [Member] | Subsidiaries [Member]
Condensed Financial Information Disclosure [Abstract]
Total financial assets measured at fair value	0	0
Total financial assets measured at fair value	0	0
Significant Observable Inputs (Level 2) [Member]
Condensed Financial Information Disclosure [Abstract]
Total financial assets measured at fair value	14,294	12,172
Investments, Fair Value Disclosure	0	0
Total financial assets measured at fair value	14,294	12,172
Significant Observable Inputs (Level 2) [Member] | Parent Company [Member]
Condensed Financial Information Disclosure [Abstract]
Total financial assets measured at fair value	14,294	12,172
Investments, Fair Value Disclosure	0	0
Total financial assets measured at fair value	14,294	12,172
Significant Observable Inputs (Level 2) [Member] | Subsidiaries [Member]
Condensed Financial Information Disclosure [Abstract]
Total financial assets measured at fair value	0	0
Total financial assets measured at fair value	0	0
Unobservable Inputs (Level 3) [Member]
Condensed Financial Information Disclosure [Abstract]
Total financial assets measured at fair value	1,388	7,545
Investments, Fair Value Disclosure	0	0
Total financial assets measured at fair value	1,388	7,545
Unobservable Inputs (Level 3) [Member] | Parent Company [Member]
Condensed Financial Information Disclosure [Abstract]
Total financial assets measured at fair value	0	0
Investments, Fair Value Disclosure		0
Total financial assets measured at fair value	0	0
Unobservable Inputs (Level 3) [Member] | Subsidiaries [Member]
Condensed Financial Information Disclosure [Abstract]
Total financial assets measured at fair value	1,388	7,545
Total financial assets measured at fair value	1,388	7,545
Money Market Funds [Member]
Investments, Fair Value Disclosure	127	5
Money Market Funds [Member] | Parent Company [Member]
Investments, Fair Value Disclosure	127	5
Money Market Funds [Member] | Fair Value, Inputs, Level 1 [Member] | Parent Company [Member]
Investments, Fair Value Disclosure	127	5
Money Market Funds [Member] | Significant Observable Inputs (Level 2) [Member] | Parent Company [Member]
Investments, Fair Value Disclosure	0	0
Money Market Funds [Member] | Unobservable Inputs (Level 3) [Member] | Parent Company [Member]
Investments, Fair Value Disclosure	0	0
Mutual Fund [Member]
Investments, Fair Value Disclosure	3,425	3,223
Mutual Fund [Member] | Parent Company [Member]
Investments, Fair Value Disclosure	3,425	3,223
Mutual Fund [Member] | Fair Value, Inputs, Level 1 [Member] | Parent Company [Member]
Investments, Fair Value Disclosure	3,425	3,223
Mutual Fund [Member] | Significant Observable Inputs (Level 2) [Member] | Parent Company [Member]
Investments, Fair Value Disclosure	0	0
Mutual Fund [Member] | Unobservable Inputs (Level 3) [Member] | Parent Company [Member]
Investments, Fair Value Disclosure	$ 0	$ 0

Schedule II - Valuation And Q_2

Schedule II - Valuation And Qualifying Accounts And Reserves (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
SEC Schedule, 12-09, Allowance, Credit Loss [Member]
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
Balance at beginning of period	$ 1,117	$ 647	$ 3,155
Charged to Income	8,930	7,478	3,940
Net Write-offs	7,764	7,008	6,448
Balance at End of Period	2,283	1,117	647
SEC Schedule, 12-09, Valuation Allowances and Reserves, Additions, Charge to Other Account	0	0	0
SEC Schedule, 12-09, Reserve, Inventory
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
Balance at beginning of period	5,160	3,107	6,133
Charged to Income	736	2,053	758
Net Write-offs	2,456	0	3,784
Balance at End of Period	3,440	5,160	3,107
SEC Schedule, 12-09, Valuation Allowances and Reserves, Additions, Charge to Other Account	0	0	0
Indianapolis Power And Light Company | SEC Schedule, 12-09, Allowance, Credit Loss [Member]
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
Balance at beginning of period	1,117	647	3,155
Charged to Income	8,930	7,478	3,940
Net Write-offs	7,764	7,008	6,448
Balance at End of Period	2,283	1,117	647
SEC Schedule, 12-09, Valuation Allowances and Reserves, Additions, Charge to Other Account	0	0	0
Indianapolis Power And Light Company | SEC Schedule, 12-09, Reserve, Inventory
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
Balance at beginning of period	5,160	3,107	6,133
Charged to Income	736	2,053	758
Net Write-offs	2,456	0	3,784
Balance at End of Period	3,440	5,160	3,107
SEC Schedule, 12-09, Valuation Allowances and Reserves, Additions, Charge to Other Account	$ 0	$ 0	$ 0