Ipalco Enterprises 10-K 1 Mar 23 2022 FY Annual report Financial data

Cover Document

Cover Document $ in Millions	12 Months Ended
	Dec. 31, 2022 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	2022
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, 2022
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, 2022
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, 2022	Dec. 31, 2021	Dec. 31, 2020
REVENUES	$ 1,791,711	$ 1,426,132	$ 1,352,985
OPERATING COSTS AND EXPENSES:
Fuel	568,676	255,817	247,105
Utilities Operating Expense, Purchased Power	199,860	175,025	135,767
Utilities Operating Expense, Maintenance and Operations	493,674	449,746	416,169
Depreciation and amortization	266,504	256,085	246,896
Taxes other than income taxes	33,048	44,419	44,516
Other Operating Income (Expense), Net	(3,201)	5,630	0
Operating Expenses	1,558,561	1,175,462	1,090,453
Operating Income (Loss)	233,150	250,670	262,532
OTHER INCOME / (EXPENSE), NET:
Allowance for equity funds used during construction	4,784	5,412	4,574
Interest Expense	(131,232)	(125,626)	(129,493)
Loss on early extinguishment of debt	(237)	0	(2,424)
Other income / (expense), net	12,020	17,667	3,370
Total other income / (expense), net	(114,665)	(102,547)	(123,973)
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest	118,485	148,123	138,559
Less: income tax expense	21,859	28,941	28,592
NET INCOME	96,626	119,182	109,967
Less: dividends on and redemption of preferred stock	3,509	3,213	3,213
NET INCOME APPLICABLE TO COMMON STOCK	93,117	115,969	106,754
Indianapolis Power And Light Company
REVENUES	1,791,711	1,426,132	1,352,985
OPERATING COSTS AND EXPENSES:
Fuel	568,676	255,817	247,105
Utilities Operating Expense, Purchased Power	199,860	175,025	135,767
Utilities Operating Expense, Maintenance and Operations	493,454	449,317	415,824
Depreciation and amortization	266,504	256,085	246,896
Taxes other than income taxes	33,048	44,419	44,516
Other Operating Income (Expense), Net	(3,201)	5,630	0
Operating Expenses	1,558,341	1,175,033	1,090,108
Operating Income (Loss)	233,370	251,099	262,877
OTHER INCOME / (EXPENSE), NET:
Allowance for equity funds used during construction	4,784	5,412	4,574
Interest Expense	(87,428)	(84,257)	(87,478)
Loss on early extinguishment of debt			(2,415)
Other income / (expense), net	12,136	17,294	4,201
Total other income / (expense), net	(70,508)	(61,551)	(78,703)
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest	162,862	189,548	184,174
Less: income tax expense	32,887	39,305	40,134
NET INCOME	129,975	150,243	144,040
Less: dividends on and redemption of preferred stock	3,509	3,213	3,213
NET INCOME APPLICABLE TO COMMON STOCK	126,466	147,030	140,827
Electricity [Member]
REVENUES	1,791,711	1,426,132	1,352,985
Electricity [Member] | Indianapolis Power And Light Company
REVENUES	$ 1,791,711	$ 1,426,132	$ 1,352,985

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
CURRENT ASSETS:
Cash and cash equivalents	$ 201,548	$ 6,912
Restricted Cash and Cash Equivalents	5	5
Accounts Receivable, after Allowance for Credit Loss, Current	216,523	179,136
Inventory, Net	123,608	101,899
Regulatory assets	119,723	63,813
Income Taxes Receivable, Current	18,000	15,566
Other Assets, Current	27,427	40,173
Total current assets	706,829	407,499
NON-CURRENT ASSETS:
Property, plant and equipment	6,982,314	6,643,929
Less: Accumulated depreciation	3,243,968	2,895,881
	3,738,346	3,748,048
Construction work in progress	294,985	210,297
Property, Plant and Equipment, Net	4,033,331	3,958,345
OTHER NON-CURRENT ASSETS:
Intangible assets - net	138,978	106,316
Regulatory assets, non-current	593,939	656,977
Assets for Plan Benefits, Defined Benefit Plan	33,611	49,182
Derivative Asset, Noncurrent	12,172	0
Other non-current assets	70,354	61,448
Total other non-current assets	849,054	873,923
TOTAL ASSETS	5,589,214	5,239,767
CURRENT LIABILITIES:
Short-term debt	0	60,294
Accounts payable	189,845	179,834
Accrued taxes	22,474	25,898
Accrued interest	33,447	30,634
Customer deposits	35,097	28,916
Regulatory liabilities	23,348	4,241
Accrued and other current liabilities	19,014	18,696
Total current liabilities	323,225	348,513
Long-term Debt and Lease Obligation	3,016,810	2,671,656
Deferred Income Tax Liabilities, Net	312,641	290,727
NON-CURRENT LIABILITIES:
Regulatory liabilities	612,585	826,709
Accrued other postretirement benefits	3,085	4,290
Asset retirement obligations	218,729	189,509
Other non-current liabilities	11,621	4,597
Total non-current liabilities	4,175,471	4,036,870
Liabilities	4,498,696	4,385,383
Common shareholders' equity:
Additional Paid in Capital	1,068,357	848,565
Accumulated Other Comprehensive Income (Loss), Net of Tax	22,269	(29,407)
Accumulated deficit	(108)	(24,558)
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	1,090,518	794,600
Cumulative preferred stock of subsidiary	0	59,784
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	5,589,214	5,239,767
Accounts receivable and unbilled revenue, allowance for doubtful accounts	1,117	647
Derivative Liability, Noncurrent	0	49,382
Indianapolis Power And Light Company
CURRENT ASSETS:
Cash and cash equivalents	199,103	2,756
Restricted Cash and Cash Equivalents	5	5
Accounts Receivable, after Allowance for Credit Loss, Current	216,572	179,181
Inventory, Net	123,608	101,899
Regulatory assets	119,723	63,813
Income Taxes Receivable, Current	6,682	6,653
Other Assets, Current	27,422	40,128
Total current assets	693,110	394,430
NON-CURRENT ASSETS:
Property, plant and equipment	6,982,314	6,643,929
Less: Accumulated depreciation	3,243,968	2,895,881
	3,738,346	3,748,048
Construction work in progress	294,985	210,297
Property, Plant and Equipment, Net	4,033,331	3,958,345
OTHER NON-CURRENT ASSETS:
Intangible assets - net	138,978	106,316
Regulatory assets, non-current	593,939	656,977
Assets for Plan Benefits, Defined Benefit Plan	33,611	49,182
Other non-current assets	67,008	57,737
Total other non-current assets	833,536	870,212
TOTAL ASSETS	5,559,977	5,222,987
CURRENT LIABILITIES:
Short-term debt	0	60,294
Accounts payable	189,806	179,602
Accrued taxes	22,474	25,898
Accrued interest	25,054	22,241
Customer deposits	35,097	28,916
Regulatory liabilities	23,348	4,241
Accrued and other current liabilities	26,214	25,896
Total current liabilities	321,993	347,088
Long-term Debt and Lease Obligation	2,143,147	1,799,502
Deferred Income Tax Liabilities, Net	305,107	300,178
NON-CURRENT LIABILITIES:
Regulatory liabilities	612,585	826,709
Accrued other postretirement benefits	3,085	4,290
Asset retirement obligations	218,729	189,509
Other non-current liabilities	11,621	4,597
Total non-current liabilities	3,294,274	3,124,785
Liabilities	3,616,267	3,471,873
Common shareholders' equity:
Common Stock, Value, Issued	324,537	324,537
Additional Paid in Capital	1,193,107	939,993
Accumulated deficit	426,066	426,800
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	1,943,710	1,691,330
Cumulative preferred stock of subsidiary	0	59,784
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	5,559,977	5,222,987
Accounts receivable and unbilled revenue, allowance for doubtful accounts	$ 1,117	$ 647

Consolidated Statements Of Cash

Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$ 96,626	$ 119,182	$ 109,967
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	266,504	256,085	246,896
Amortization of deferred financing costs and debt discounts	3,914	3,915	3,942
Deferred income taxes and investment tax credit adjustments - net	(6,706)	(7,378)	2,854
Loss on early extinguishment of debt	237	0	2,424
Allowance for equity funds used during construction	(4,784)	(5,412)	(4,574)
Gain on acquisition	0	(5,630)	0
Change in certain assets and liabilities:
Accounts receivable	(37,387)	(13,943)	(4,103)
Inventories	(47,489)	(12,017)	(15,240)
Accounts payable	(32,038)	(21,417)	20,322
Accrued and other current liabilities	6,532	(13,017)	(8,214)
Accrued taxes payable/receivable	(5,858)	638	6,695
Accrued interest	2,813	(1,099)	(3,601)
Pension and other postretirement benefit assets and liabilities	(8,727)	(16,592)	(6,991)
Short-term and long-term regulatory assets and liabilities	38,863	(104,759)	(13,390)
Prepayments and other current assets	19,056	(4,593)	(578)
Other long term liabilities	(14,384)	10,446	4,421
Other - net	5,098	(2,026)	(4,761)
Net cash provided by operating activities	346,346	225,217	295,425
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(496,510)	(291,510)	(235,700)
Project development costs	(3,910)	(1,304)	(2,401)
Cost of removal payments	(23,948)	(35,260)	(19,484)
Purchase of intangibles	0	(26,261)	0
Other	(719)	(14,380)	(18,184)
Net cash used in investing activities	(525,087)	(368,715)	(275,769)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under revolving credit facilities	300,000	320,000	115,000
Repayments under revolving credit facilities	360,000	335,000	40,000
Short-term borrowings	200,000	0	0
Repayment of short-term borrowings	(200,000)	0	0
Long-term borrowings	350,000	95,000	565,000
Retirement of long-term debt, including early payment premium	0	(95,000)	(562,135)
Distributions to shareholders	(101,986)	(131,476)	(108,739)
Equity contributions from shareholders	253,000	275,000	0
Redemption of preferred stock	(60,080)	0	0
Preferred dividends of subsidiary	(3,213)	(3,213)	(3,213)
Payments of deferred financing costs and discounts	(4,309)	(1,387)	(7,346)
Other	(35)	(131)	(153)
Net cash provided by (used in) financing activities	373,377	123,793	(41,586)
Net change in cash, cash equivalents and restricted cash	194,636	(19,705)	(21,930)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	201,553	6,917	26,622
Cash and Cash Equivalents, at Carrying Value	201,548	6,912
Cash paid during the period for:
Interest (net of amount capitalized)	115,277	118,052	122,938
Income taxes	31,000	27,500	27,000
Non-cash investing activities:
Accruals for capital expenditures	66,949	81,325	54,360
Right-of-Use Asset Obtained in Exchange for Finance Lease Liability	(3,402)	19,763	0
Indianapolis Power And Light Company
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	129,975	150,243	144,040
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	266,504	256,085	246,896
Amortization of deferred financing costs and debt discounts	2,511	2,536	2,335
Deferred income taxes and investment tax credit adjustments - net	(6,584)	(7,373)	3,078
Loss on early extinguishment of debt			2,415
Allowance for equity funds used during construction	(4,784)	(5,412)	(4,574)
Gain on acquisition	0	(5,630)	0
Change in certain assets and liabilities:
Accounts receivable	(37,391)	(13,746)	(4,071)
Inventories	(47,489)	(12,017)	(15,240)
Accounts payable	(32,232)	(21,502)	20,621
Accrued and other current liabilities	6,532	(13,017)	(8,214)
Accrued taxes payable/receivable	(3,452)	(2,302)	18,012
Accrued interest	2,813	(1,099)	(518)
Pension and other postretirement benefit assets and liabilities	(8,727)	(16,592)	(6,991)
Short-term and long-term regulatory assets and liabilities	38,863	(104,759)	(13,390)
Prepayments and other current assets	19,016	(4,556)	(569)
Other long term liabilities	(21,717)	5,566	(5,460)
Other - net	4,967	(1,645)	(714)
Net cash provided by operating activities	373,269	247,784	333,999
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(496,510)	(291,510)	(235,700)
Project development costs	(3,910)	(1,304)	(2,401)
Cost of removal payments	(23,948)	(35,260)	(19,484)
Purchase of intangibles	0	26,261	0
Loans to Parent	0	0	26,110
Loan repayments from parents	0	6,110	20,000
Other	(719)	(14,380)	(18,184)
Net cash used in investing activities	(525,087)	(362,605)	(281,879)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under revolving credit facilities	300,000	320,000	115,000
Repayments under revolving credit facilities	360,000	335,000	40,000
Short-term borrowings	200,000	0	0
Repayment of short-term borrowings	200,000	0	0
Long-term borrowings	350,000	95,000	90,000
Retirement of long-term debt, including early payment premium	0	(95,000)	(90,000)
Distributions to shareholders	(127,200)	(155,700)	(147,600)
Redemption of preferred stock	60,080	0	0
Preferred dividends of subsidiary	(3,213)	(3,213)	(3,213)
Proceeds from Contributions from Parent	253,000	275,000	0
Payments of deferred financing costs and discounts	(4,309)	(1,325)	(792)
Other	(33)	(131)	(153)
Net cash provided by (used in) financing activities	348,165	99,631	(76,758)
Net change in cash, cash equivalents and restricted cash	196,347	(15,190)	(24,638)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	199,108	2,761	17,951
Cash and Cash Equivalents, at Carrying Value	199,103	2,756
Cash paid during the period for:
Interest (net of amount capitalized)	80,104	82,880	84,869
Income taxes	39,500	40,800	27,000
Non-cash investing activities:
Accruals for capital expenditures	66,949	81,325	$ 54,360
Right-of-Use Asset Obtained in Exchange for Finance Lease Liability	$ 15,819	$ 19,763

Consolidated Statements Of Comm

Consolidated Statements Of Common Shareholders' Equity (Deficit) And Noncontrolling Interest - USD ($) $ in Thousands	Total	Paid In Capital [Member]	AOCI Attributable to Parent [Member]	Accumulated Deficit [Member]	Cumulative Preferred Stock Of Subsidiary [Member]	Preferred Stock	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]
Other Comprehensive Income (Loss), Net of Tax	$ (23,670)		$ (23,670)	$ 0
Beginning Balance at Dec. 31, 2019	546,476	$ 590,784	(19,750)	(24,558)	$ 59,784		$ 1,424,499	$ 324,537	$ 664,719	$ 435,243	$ 59,784
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income applicable to common stock	106,754			109,967			140,827
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)
Net income	109,967						144,040			144,040
Dividends, Preferred Stock										3,213
Return of Capital		(1,985)
Cash dividends declared on common stock							(140,600)			(140,600)
Distributions to AES	(108,739)			(106,754)
Equity contributions from shareholders	0
Other	167	167					167		167
Ending Balance at Dec. 31, 2020	520,988	588,966	(43,420)	(24,558)	59,784		1,424,893	324,537	664,886	435,470	59,784
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Comprehensive Income (Loss), Net of Tax, Attributable to Noncontrolling Interest	109,967
Proceeds from Contributions from Parent							0		0
Other Comprehensive Income (Loss), Net of Tax	14,013		14,013	0
Net income applicable to common stock	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)
Net income	119,182						150,243			150,243
Dividends, Preferred Stock										3,213
Return of Capital		(15,507)
Cash dividends declared on common stock							(155,700)			(155,700)
Distributions to AES	(131,476)			(115,969)
Equity contributions from shareholders	275,000	275,000
Other	106	106					107		107
Ending Balance at Dec. 31, 2021	794,600	848,565	(29,407)	(24,558)	59,784		1,691,330	324,537	939,993	426,800	59,784
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Comprehensive Income (Loss), Net of Tax, Attributable to Noncontrolling Interest	119,182
Proceeds from Contributions from Parent							275,000		275,000
Other Comprehensive Income (Loss), Net of Tax	51,676		51,676
Net income applicable to common stock	93,117			96,626			126,466
Preferred Stock Dividends, Income Statement Impact	3,509					$ 3,213	3,509				3,213
Payments of Ordinary Dividends, Preferred Stock and Preference Stock	(3,213)			(3,213)	(3,213)		(3,213)				(3,213)
Net income	96,626						129,975			129,975
Dividends, Preferred Stock							3,200			3,213
Return of Capital		(33,319)
Cash dividends declared on common stock							(127,200)			(127,200)
Distributions to AES	(101,986)			(68,667)
Equity contributions from shareholders	253,000	253,000
Other	111	111					114		114
Ending Balance at Dec. 31, 2022	1,090,518	$ 1,068,357	$ 22,269	(108)	0		1,943,710	$ 324,537	1,193,107	$ 426,066	$ 0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Comprehensive Income (Loss), Net of Tax, Attributable to Noncontrolling Interest	96,626
Proceeds from Contributions from Parent							$ 253,000		$ 253,000
Preferred Stock, Redemption Amount	$ (296)			$ 296	$ 59,784

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income Statement - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Net Income (Loss) Available to Common Stockholders, Basic	$ 93,117	$ 115,969	$ 106,754
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax	(15,309)	(3,441)	8,876
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	46,245	10,393	(27,779)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Tax	(1,798)	(1,199)	(1,313)
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax	51,676	14,013	(23,670)
Other Comprehensive Income (Loss), Net of Tax	51,676	14,013	(23,670)
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	144,793	129,982	83,084
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	$ 5,431	$ 3,620	$ 4,109

Overview and Summary of Signifi

Overview and Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2022
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 519,000 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. Our largest generating station, Petersburg, is coal-fired, and AES Indiana retired 230 MW Petersburg Unit 1 on May 31, 2021 and has plans to retire 415 MW Petersburg Unit 2 in 2023, which would result in 630 MW of total retired economic capacity at this station. AES Indiana plans to convert the remaining two coal units at Petersburg to natural gas by the end of 2025 (for further discussion, see Note 2, " Regulatory Matters - IRP Filings and Replacement Generation "). The second largest station, Harding Street, uses natural gas and fuel oil to power combustion turbines. In addition, AES Indiana operates a 20 MW battery energy storage unit at this location, which provides frequency response. The third station, Eagle Valley, is a CCGT natural gas plant. The fourth station, Georgetown, is a small peaking station that uses natural gas to power combustion turbines. As of December 31, 2022, AES Indiana’s net electric generation capacity for winter is 3,475 MW and net summer capacity is 3,330 MW. On December 17, 2021, AES Indiana, through its wholly-owned subsidiary AES Indiana Devco Holdings 1, LLC, completed the acquisition of Hardy Hills Solar Energy LLC, including the development of a 195 MW solar project (the "Hardy Hills Solar Project"). As amended in December 2022 and subject to IURC approval, the Hardy Hills Solar Project is now expected to be completed in 2024. In July 2021, AES Indiana, through its wholly-owned subsidiary AES Indiana Devco Holdings 2, LLC, executed an agreement to acquire a 250 MW solar and 180 MWh energy storage facility (the "Petersburg Solar Project"). As amended in October 2022 and subject to IURC approval, the Petersburg Solar Project is now expected to be completed in 2025. IPALCO’s other direct subsidiary is Mid-America. Mid-America is the holding company for IPALCO’s unregulated activities, which have not been material to the financial statements in the periods covered by this report. IPALCO’s regulated business is conducted through AES Indiana. IPALCO has two business segments: utility and nonutility. The utility segment consists of the operations of AES Indiana and everything else is included in the nonutility segment. Principles of Consolidation IPALCO’s consolidated financial statements are prepared in accordance with GAAP and in conjunction with the rules and regulations of the SEC. The consolidated financial statements include the accounts of IPALCO, its regulated utility subsidiary, AES Indiana, and its unregulated subsidiary, Mid-America. All intercompany items have been eliminated in consolidation. Certain costs for shared resources amongst AES Indiana and IPALCO, such as labor and benefits, are allocated to each entity based on allocation methodologies that management believes to be reasonable. We have evaluated subsequent events through the date this report is issued. Use of Management Estimates The preparation of financial statements in conformity with GAAP requires that management make certain estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements. The reported amounts of revenues and expenses during the reporting period may also be affected by the estimates and assumptions management is required to make. Actual results may differ from those estimates. Significant items subject to such estimates and assumptions include: recognition of revenue including unbilled revenues; 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. Regulatory Accounting The retail utility operations of AES Indiana are subject to the jurisdiction of the IURC. AES Indiana’s wholesale power transactions are subject to the jurisdiction of the FERC. These agencies regulate AES Indiana’s utility business operations, tariffs, accounting, depreciation allowances, services, issuances of securities and the sale and acquisition of utility properties. The financial statements of AES Indiana are based on GAAP, including the provisions of FASB ASC 980 “Regulated Operations,” which gives recognition to the ratemaking and accounting practices of these agencies. See also Note 2, “Regulatory Matters - Regulatory Assets and Liabilities” for a discussion of specific regulatory assets and liabilities. Cash 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, 2022 2021 (In Thousands) Cash, cash equivalents and restricted cash Cash and cash equivalents $ 201,548 $ 6,912 Restricted cash (included in Prepayments and other current assets) 5 5 Total cash, cash equivalents and restricted cash $ 201,553 $ 6,917 Accounts Receivable and Allowance for Credit Losses The following table summarizes our accounts receivable balances at December 31: As of December 31, 2022 2021 (In Thousands) Accounts receivable, net Customer receivables $ 125,540 $ 100,952 Unbilled revenues 74,488 64,758 Amounts due from related parties 239 169 Other 17,373 13,904 Allowance for credit losses (1,117) (647) Total accounts receivable, net $ 216,523 $ 179,136 The following table is a rollforward of our allowance for credit losses related to the accounts receivable balances for the periods indicated (in Thousands): Year Ended December 31, 2022 Beginning Allowance Balance at January 1, 2022 Current Period Provision Write-offs Charged Against Allowances Recoveries Collected Ending Allowance Balance at Allowance for credit losses $ 647 $ 5,851 $ (7,008) $ 1,627 $ 1,117 Year Ended December 31, 2021 Beginning Allowance Balance at January 1, 2021 Current Period Provision Write-offs Charged Against Allowances Recoveries Collected Ending Allowance Balance at Allowance for credit losses $ 3,155 $ 2,035 $ (6,448) $ 1,905 $ 647 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, 2022 2021 (In Thousands) Inventories Fuel $ 60,497 $ 41,626 Materials and supplies, net 63,111 60,273 Total inventories $ 123,608 $ 101,899 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 3.8%, 3.7% and 3.7% during 2022, 2021 and 2020, respectively. Depreciation expense was $247.5 million, $239.1 million, and $232.8 million for the years ended December 31, 2022, 2021 and 2020, respectively. "Depreciation and amortization" expense on the accompanying Consolidated Statements of Operations is presented net of regulatory deferrals of depreciation expense and also includes amortization of intangible assets and amortization of previously deferred regulatory costs. Allowance For Funds Used During Construction In accordance with the Uniform System of Accounts prescribed by FERC, AES Indiana capitalizes an allowance for the net cost of funds (interest on borrowed funds and a reasonable rate of return on equity funds) used for construction purposes during the period of construction with a corresponding credit to income. AES Indiana capitalized amounts using pretax composite rates of 5.4%, 5.7% and 6.9% during 2022, 2021 and 2020, respectively. Impairment of Long-lived Assets GAAP requires that we test long-lived assets for impairment when indicators of impairment exist. If an asset is deemed to be impaired, we are required to write down the asset to its fair value with a charge to current earnings. The net book value of our property, plant, and equipment was $4.0 billion and $4.0 billion as of December 31, 2022 and 2021, respectively. As of December 31, 2022 and 2021, AES Indiana had $287.5 million and $300.1 million, respectively, of long-term regulatory assets associated with the Petersburg Unit 1 retirement and the probable Petersburg Unit 2 retirement (for further discussion, see Note 2, “Regulatory Matters - IRP 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 include capitalized software and project development intangible assets amortized over their useful lives. Capitalized software of $205.9 million and $162.0 million and its corresponding accumulated amortization of $107.2 million and $95.8 million is recorded as of December 31, 2022 and 2021, respectively. Amortization expense for capitalized software was $10.1 million, $11.2 million and $10.6 million for the years ended December 31, 2022, 2021 and 2020, respectively. These capitalized software intangible assets have a 7 year-weighted average amortization period and the estimated amortization expense is approximately $30.7 million over the next 5 years ($9.8 million in 2023, $5.3 million in 2024, $5.2 million in 2025, $5.2 million in 2026 and $5.2 million in 2027). Project development intangible assets were $39.5 million as of December 31, 2022 and 2021. These project development intangible assets have a 30 year-weighted average amortization period and the estimated amortization expense is approximately $4.9 million over the next 5 years ($0.0 million in 2023, $1.0 million in 2024, $1.3 million in 2025, $1.3 million in 2026 and $1.3 million in 2027). 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 $8.2 million and $9.1 million as of December 31, 2022 and 2021, respectively, which are recorded within " Other non-current assets " on the accompanying Consolidated Balance Sheets. Contingencies IPALCO accrues for loss contingencies when the amount of the loss is probable and estimable. We are subject to various environmental regulations and are involved in certain legal proceedings. If AES Indiana’s actual environmental and/or legal obligations are different from our estimates, the recognition of the actual amounts may have a material impact on our results of operations, financial condition and cash flows; although that has not been the case during the periods covered by this report. As of December 31, 2022 and 2021, total loss contingencies accrued were $0.1 million and $0.2 million, respectively, which were included in “Accrued and Other Current Liabilities” and " Other Non-Current Liabilities ", respectively, on the accompanying Consolidated Balance Sheets. Concentrations of Risk Substantially all of AES Indiana’s customers are located within the Indianapolis area. Approximately 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 two suppliers, and substantially all of AES Indiana's coal is currently mined in the state of Indiana. Financial Derivatives All derivatives are recognized as either assets or liabilities in the balance sheets and are measured at fair value. Changes in the fair value are recorded in earnings unless the derivative is designated as a cash flow hedge of a forecasted transaction or it qualifies for the normal purchases and sales exception. AES Indiana has contracts involving the physical delivery of energy and fuel. 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, 2022, 2021 and 2020 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, 2022 2021 2020 Net losses on cash flow hedges (Note 5): Interest expense $ 7,229 $ 4,819 $ 5,422 Income tax effect (1,798) (1,199) (1,313) Total reclassifications for the period, net of income taxes $ 5,431 $ 3,620 $ 4,109 See Note 5, " Derivative Instruments and Hedging Activities - Cash Flow Hedges " for further information on the changes in the components of AOCL. Revenue Recognition Revenues related to the sale of energy are generally recognized when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to certain customers since the date of the last meter reading are estimated and the corresponding unbilled revenues is accrued. In making its estimates of unbilled revenues, AES Indiana uses complex models that consider various factors including daily generation volumes; known amounts of energy usage by nearly all residential, commercial and industrial customers; estimated line losses; and estimated customer rates based on prior period billings. Given the use of these models, and that customers are billed on a monthly cycle, we believe it is unlikely that materially different results will occur in future periods when revenue is billed. The effect on 2022 revenues and ending unbilled revenues of a one percentage point change in estimated line losses for the month of December 2022 is immaterial. An allowance for potential credit losses is maintained and amounts are written off when normal collection efforts have been exhausted. Our provision for expected credit losses included in “Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations was $5.9 million, $3.0 million and $4.8 million for the years ended December 31, 2022, 2021 and 2020, 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, " Revenues " 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 9, " 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 8, " 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 The following table provides a brief description of recent accounting pronouncements that had an impact on the Company’s Financial Statements. Accounting pronouncements not listed below were assessed and determined to be either not applicable or did not have a material impact on the Company’s Financial Statements. New Accounting Standards Adopted ASU Number and Name Description Date of Adoption Effect on the Financial Statements upon adoption 2020-04, 2021-01 and 2022-06, Reference Rate Form (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting The amendments in these updates provide optional expedients and exceptions for applying GAAP to contracts, hedging relationships and other transactions that reference to LIBOR or another reference rate expected to be discontinued by reference rate reform, and clarify that certain optional expedients and exceptions in Topic 848 for contract modifications and hedge accounting apply to derivatives that are affected by the discounting transition. These amendments are effective for a limited period of time (March 12, 2020 - December 31, 2024). March 12, 2020 - December 31, 2024 The Company adopted this standard on a prospective basis and it did not have a material impact on the Financial Statements. ASC 326 - Financial Instruments - Credit Losses On January 1, 2020, the Company adopted ASC 326 Financial Instruments - Credit Losses and its subsequent corresponding updates ("ASC 326"). The new standard updates the impairment model for financial assets measured at amortized cost, known as the Current Expected Credit Loss ("CECL") model. For trade and other receivables, held-to-maturity debt securities, loans and other instruments, entities are required to use a new forward-looking "expected loss" model that generally results in the earlier recognition of an allowance for credit losses. For available-for-sale debt securities with unrealized losses, entities measure credit losses as it was done under previous GAAP, except that unrealized losses due to credit-related factors are now recognized as an allowance on the balance sheet with a corresponding adjustment to earnings in the income statement. The Company applied the modified retrospective method of adoption for ASC 326. Under this transition method, the Company applied the transition provisions starting at the date of adoption. The CECL model primarily impacts the calculation of the Company's expected credit losses in gross customer trade accounts receivable. The adoption of ASC 326 and the application of CECL on our trade accounts receivable did not have a material impact on our Financial Statements.
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 519,000 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. Our largest generating station, Petersburg, is coal-fired, and AES Indiana retired 230 MW Petersburg Unit 1 on May 31, 2021 and has plans to retire 415 MW Petersburg Unit 2 in 2023, which would result in 630 MW of total retired economic capacity at this station. AES Indiana plans to convert the remaining two coal units at Petersburg to natural gas by the end of 2025 (for further discussion, see Note 2, " Regulatory Matters - IRP Filings and Replacement Generation "). The second largest station, Harding Street, uses natural gas and fuel oil to power combustion turbines. In addition, AES Indiana operates a 20 MW battery energy storage unit at this location, which provides frequency response. The third station, Eagle Valley, is a CCGT natural gas plant. The fourth station, Georgetown, is a small peaking station that uses natural gas to power combustion turbines. As of December 31, 2022, AES Indiana’s net electric generation capacity for winter is 3,475 MW and net summer capacity is 3,330 MW. On December 17, 2021, AES Indiana, through its wholly-owned subsidiary AES Indiana Devco Holdings 1, LLC, completed the acquisition of Hardy Hills Solar Energy LLC, including the development of a 195 MW solar project (the "Hardy Hills Solar Project"). As amended in December 2022 and subject to IURC approval, the Hardy Hills Solar Project is now expected to be completed in 2024. In July 2021, AES Indiana, through its wholly-owned subsidiary AES Indiana Devco Holdings 2, LLC, executed an agreement to acquire a 250 MW solar and 180 MWh energy storage facility (the "Petersburg Solar Project"). As amended in October 2022 and subject to IURC approval, the Petersburg Solar Project is now expected to be completed in 2025. Principles of Consolidation AES Indiana’s consolidated financial statements are prepared in accordance with GAAP and in conjunction with the rules and regulations of the SEC. The consolidated financial statements include the accounts of AES Indiana and its wholly owned subsidiaries AES Indiana Devco Holdings 1, LLC and AES Indiana Devco Holdings 2, LLC (these entities were formed on November 18, 2020 and May 27, 2021, respectively, related to the replacement generation project for retired Petersburg units) . All intercompany items have been eliminated in consolidation. Certain costs for shared resources amongst AES Indiana and IPALCO, such as labor and benefits, are allocated to each entity based on allocation methodologies that management believes to be reasonable. We have evaluated subsequent events through the date this report is issued. Use of Management Estimates The preparation of financial statements in conformity with GAAP requires that management make certain estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements. The reported amounts of revenues and expenses during the reporting period may also be affected by the estimates and assumptions management is required to make. Actual results may differ from those estimates. Significant items subject to such estimates and assumptions include: recognition of revenues including unbilled revenues; 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. Regulatory Accounting The retail utility operations of AES Indiana are subject to the jurisdiction of the IURC. AES Indiana’s wholesale power transactions are subject to the jurisdiction of the FERC. These agencies regulate AES Indiana’s utility business operations, tariffs, accounting, depreciation allowances, services, issuances of securities and the sale and acquisition of utility properties. The financial statements of AES Indiana are based on GAAP, including the provisions of FASB ASC 980 “Regulated Operations,” which gives recognition to the ratemaking and accounting practices of these agencies. See also Note 2, “Regulatory Matters - Regulatory Assets and Liabilities” for a discussion of specific regulatory assets and liabilities. Cash 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, 2022 2021 (In Thousands) Cash, cash equivalents and restricted cash Cash and cash equivalents $ 199,103 $ 2,756 Restricted cash (included in Prepayments and other current assets) 5 5 Total cash, cash equivalents and restricted cash $ 199,108 $ 2,761 Accounts Receivable and Allowance for Credit Losses The following table summarizes our accounts receivable balances at December 31: As of December 31, 2022 2021 (In Thousands) Accounts receivable, net Customer receivables $ 125,540 $ 100,952 Unbilled revenues 74,488 64,758 Amounts due from related parties 288 214 Other 17,373 13,904 Allowance for credit losses (1,117) (647) Total accounts receivable, net $ 216,572 $ 179,181 The following table is a rollforward of our allowance for credit losses related to the accounts receivable balances for the periods indicated (in Thousands): Year Ended December 31, 2022 Beginning Allowance Balance at January 1, 2022 Current Period Provision Write-offs Charged Against Allowances Recoveries Collected Ending Allowance Balance at Allowance for credit losses $ 647 $ 5,851 $ (7,008) $ 1,627 $ 1,117 Year Ended December 31, 2021 Beginning Allowance Balance at January 1, 2021 Current Period Provision Write-offs Charged Against Allowances Recoveries Collected Ending Allowance Balance at Allowance for credit losses $ 3,155 $ 2,035 $ (6,448) $ 1,905 $ 647 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, 2022 2021 (In Thousands) Inventories Fuel $ 60,497 $ 41,626 Materials and supplies, net 63,111 60,273 Total inventories $ 123,608 $ 101,899 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 3.8%, 3.7% and 3.7% during 2022, 2021 and 2020, respectively. Depreciation expense was $247.5 million, $239.1 million, and $232.8 million for the years ended December 31, 2022, 2021 and 2020, respectively. "Depreciation and amortization" expense on the accompanying Consolidated Statements of Operations is presented net of regulatory deferrals of depreciation expense and also includes amortization of intangible assets and amortization of previously deferred regulatory costs. Allowance For Funds Used During Construction In accordance with the Uniform System of Accounts prescribed by FERC, AES Indiana capitalizes an allowance for the net cost of funds (interest on borrowed funds and a reasonable rate of return on equity funds) used for construction purposes during the period of construction with a corresponding credit to income. AES Indiana capitalized amounts using pretax composite rates of 5.4%, 5.7% and 6.9% during 2022, 2021 and 2020, respectively. Impairment of Long-lived Assets GAAP requires that AES Indiana test long-lived assets for impairment when indicators of impairment exist. If an asset is deemed to be impaired, AES Indiana is required to write down the asset to its fair value with a charge to current earnings. The net book value of AES Indiana’s property, plant, and equipment was $4.0 billion and $4.0 billion as of December 31, 2022 and 2021, respectively. As of December 31, 2022 and 2021, AES Indiana had $287.5 million and $300.1 million, respectively, of long-term regulatory assets associated with the Petersburg Unit 1 retirement and the probable Petersburg Unit 2 retirement (for further discussion, see Note 2, “Regulatory Matters - IRP 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 include capitalized software and project development intangible assets amortized over their useful lives. Capitalized software of $205.9 million and $162.0 million and its corresponding accumulated amortization of $107.2 million and $95.8 million is recorded as of December 31, 2022 and 2021, respectively. Amortization expense for capitalized software was $10.1 million, $11.2 million and $10.6 million for the years ended December 31, 2022, 2021 and 2020, respectively. These capitalized software intangible assets have a 7 year-weighted average amortization period and the estimated amortization expense is approximately $30.7 million over the next 5 years ($9.8 million in 2023, $5.3 million in 2024, $5.2 million in 2025, $5.2 million in 2026 and $5.2 million in 2027). Project development intangible assets were $39.5 million as of December 31, 2022 and 2021. These project development intangible assets have a 30 year-weighted average amortization period and the estimated amortization expense is approximately $4.9 million over the next 5 years ($0.0 million in 2023, $1.0 million in 2024, $1.3 million in 2025, $1.3 million in 2026 and $1.3 million in 2027). 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 $8.2 million and $9.1 million as of December 31, 2022 and 2021, respectively, which are recorded within " Other non-current assets " on the accompanying Consolidated Balance Sheets. Contingencies AES Indiana accrues for loss contingencies when the amount of the loss is probable and estimable. AES Indiana is subject to various environmental regulations and is involved in certain legal proceedings. If AES Indiana’s actual environmental and/or legal obligations are different from our estimates, the recognition of the actual amounts may have a material impact on our results of operations, financial condition and cash flows; although that has not been the case during the periods covered by this report. As of December 31, 2022 and 2021, total loss contingencies accrued were $0.1 million and $0.2 million, respectively, which were included in “ Accrued and Other Current Liabilities” and " Other Non-Current Liabilities ", respectively, on the accompanying Consolidated Balance Sheets. Concentrations of Risk Substantially all of AES Indiana’s customers are located within the Indianapolis area. Approximately 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 two suppliers, and substantially all of AES Indiana's coal is currently mined in the state of Indiana. Financial Derivatives All derivatives are recognized as either assets or liabilities in the balance sheets and are measured at fair value. Changes in the fair value are recorded in earnings unless the derivative is designated as a cash flow hedge of a forecasted transaction or it qualifies for the normal purchases and sales exception. AES Indiana has contracts involving the physical delivery of energy and fuel. 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 Revenues related to the sale of energy are generally recognized when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to certain customers since the date of the last meter reading are estimated and the corresponding unbilled revenues is accrued. In making its estimates of unbilled revenues, AES Indiana uses complex models that consider various factors including daily generation volumes; known amounts of energy usage by nearly all residential, commercial and industrial customers; estimated line losses; and estimated customer rates based on prior period billings. Given the use of these models, and that customers are billed on a monthly cycle, we believe it is unlikely that materially different results will occur in future periods when revenue is billed. The effect on 2022 revenues and ending unbilled revenues of a one percentage point change in estimated line losses for the month of December 2022 is immaterial. An allowance for potential credit losses is maintained and amounts are written off when normal collection efforts have been exhausted. AES Indiana’s provision for expected credit losses included in “ Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations was $5.9 million, $3.0 million and $4.8 million for the years ended December 31, 2022, 2021 and 2020, 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, " Revenues " 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 9, " 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 8, " 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 The following table provides a brief description of recent accounting pronouncements that had an impact on the Company’s Financial Statements. Accounting pronouncements not listed below were assessed and determined to be either not applicable or did not have a material impact on the Company’s Financial Statements. New Accounting Standards Adopted ASU Number and Name Description Date of Adoption Effect on the Financial Statements upon adoption 2020-04, 2021-01 and 2022-06, Reference Rate Form (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting The amendments in these updates provide optional expedients and exceptions for applying GAAP to contracts, hedging relationships and other transactions that reference to LIBOR or another reference rate expected to be discontinued by reference rate reform, and clarify that certain optional expedients and exceptions in Topic 848 for contract modifications and hedge accounting apply to derivatives that are affected by the discounting transition. These amendments are effective for a limited period of time (March 12, 2020 - December 31, 2024). March 12, 2020 - December 31, 2024 The Company adopted this standard on a prospective basis and it did not have a material impact on the Financial Statements. ASC 326 - Financial Instruments - Credit Losses On January 1, 2020, the Company adopted ASC 326 Financial Instruments - Credit Losses and its subsequent corresponding updates ("ASC 326"). The new standard updates the impairment model for financial assets measured at amortized cost, known as the Current Expected Credit Loss ("CECL") model. For trade and other receivables, held-to-maturity debt securities, loans and other instruments, entities are required to use a new forward-looking "expected loss" model that generally results in the earlier recognition of an allowance for credit losses. For available-for-sale debt securities with unrealized losses, entities measure credit losses as it was done under previous GAAP, except that unrealized losses due to credit-related factors are now recognized as an allowance on the balance sheet with a corresponding adjustment to earnings in the income statement. The Company applied the modified retrospective method of adoption for ASC 326. Under this transition method, the Company applied the transition provisions starting at the date of adoption. The CECL model primarily impacts the calculation of the Company's expected credit losses in gross customer trade accounts receivable. The adoption of ASC 326 and the application of CECL on our trade accounts receivable did not have a material impact on our Financial Statements.

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2022	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, 2022 2021 (In Thousands) Production $ 4,164,416 $ 4,099,110 Transmission 461,245 436,257 Distribution 2,045,579 1,831,029 General plant 311,074 277,533 Total property, plant and equipment $ 6,982,314 $ 6,643,929 As of December 31, 2022 and 2021, AES Indiana had $287.5 million and $300.1 million, respectively, of net property, plant and equipment associated with the probable Petersburg Unit 1 and Unit 2 retirements recorded as long-term regulatory assets (for further discussion, see Note 2, “ Regulatory Matters - IRP 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, 2022, securing AES Indiana’s first mortgage bonds. Total non-contractually or legally required accrued removal costs of utility plant in service at December 31, 2022 and 2021 were $694.0 million and $846.1 million, respectively; and total contractually or legally required removal costs of property, plant and equipment at December 31, 2022 and 2021 were $218.7 million and $189.5 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: 2022 2021 (In Thousands) Balance as of January 1 $ 189,509 $ 195,236 Liabilities incurred 1,159 — Liabilities settled (24,699) (13,692) Revisions to cash flow and timing estimates 44,679 — Accretion 8,081 7,965 Balance as of December 31 $ 218,729 $ 189,509
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, 2022 2021 (In Thousands) Production $ 4,164,416 $ 4,099,110 Transmission 461,245 436,257 Distribution 2,045,579 1,831,029 General plant 311,074 277,533 Total property, plant and equipment $ 6,982,314 $ 6,643,929 As of December 31, 2022 and 2021, AES Indiana had $287.5 million and $300.1 million, respectively, of net property, plant and equipment associated with the probable Petersburg Unit 1 and Unit 2 retirements recorded as long-term regulatory assets (for further discussion, see Note 2, “ Regulatory Matters - IRP 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, 2022, securing AES Indiana’s first mortgage bonds. Total non-contractually or legally required accrued removal costs of utility plant in service at December 31, 2022 and 2021 were $694.0 million and $846.1 million, respectively; and total contractually or legally required removal costs of property, plant and equipment at December 31, 2022 and 2021 were $218.7 million and $189.5 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: 2022 2021 (In Thousands) Balance as of January 1 $ 189,509 $ 195,236 Liabilities incurred 1,159 — Liabilities settled (24,699) (13,692) Revisions to cash flow and timing estimates 44,679 — Accretion 8,081 7,965 Balance as of December 31 $ 218,729 $ 189,509

Fair Value

Fair Value	12 Months Ended
	Dec. 31, 2022
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, 2022, 2021, or 2020. Any unrealized gains or losses are recorded in " Other income / (expense), net " on the accompanying Consolidated Statements of Operations. FTRs In connection with AES Indiana’s participation in MISO, in the second quarter of each year AES Indiana is granted financial instruments that can be converted into cash or FTRs based on AES Indiana’s forecasted peak load for the period. FTRs are used in the MISO market to hedge AES Indiana’s exposure to congestion charges, which result from constraints on the transmission system. AES Indiana’s FTRs are valued at the cleared auction prices for FTRs in MISO’s annual auction. Because of the infrequent nature of this valuation, the fair value assigned to the FTRs is considered a Level 3 input under the fair value hierarchy required by ASC 820. An offsetting regulatory liability has been recorded as these revenues or costs will be flowed through to customers through the FAC. As such, there is no impact on our Consolidated Statements of Operations. Forward Power Contracts AES Indiana entered into forward purchase power contracts in 2022 and 2021, respectively. As of December 31, 2022 and 2021, 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. Financial Liabilities 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 / (AOCL). See also Note 5, " Derivative Instruments and Hedging Activities - Cash Flow Hedges " for further information. Recurring Fair Value Measurements The fair value of assets and liabilities at December 31, 2022 and 2021 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, 2022 Fair Value as of December 31, 2021 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total (In Thousands) Financial assets: VEBA investments: Money market funds $ 5 $ — $ — $ 5 $ 11 $ — $ — $ 11 Mutual funds 3,223 — — 3,223 — 3,594 — 3,594 Total VEBA investments 3,228 — — 3,228 11 3,594 — 3,605 FTRs — — 7,545 7,545 — — 1,235 1,235 Interest rate hedges — 12,172 — 12,172 — — — — Total financial assets measured at fair value $ 3,228 $ 12,172 $ 7,545 $ 22,945 $ 11 $ 3,594 $ 1,235 $ 4,840 Financial liabilities: Interest rate hedges $ — $ — $ — $ — $ — $ 49,382 $ — $ 49,382 Total financial liabilities measured at fair value $ — $ — $ — $ — $ — $ 49,382 $ — $ 49,382 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, 2021 $ 543 Issuances 2,971 Settlements (2,279) Balance at December 31, 2021 $ 1,235 Issuances 15,338 Settlements (9,028) Balance at December 31, 2022 $ 7,545 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, 2022 December 31, 2021 Face Value Fair Value Face Value Fair Value (In Thousands) Fixed-rate $ 3,033,800 $ 2,775,644 $ 2,683,800 $ 3,169,118 Variable-rate — — 60,000 60,000 Total indebtedness $ 3,033,800 $ 2,775,644 $ 2,743,800 $ 3,229,118 The difference between the face value and the carrying value of this indebtedness represents the following: • unamortized deferred financing costs of $26.3 million and $25.2 million at December 31, 2022 and 2021, respectively; and • unamortized discounts of $7.1 million and $6.4 million at December 31, 2022 and 2021, 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 revenues or costs will be flowed through to customers through the FAC. As such, there is no impact on AES Indiana’s Consolidated Statements of Operations. Forward Power Contracts AES Indiana entered into forward purchase power contracts in 2022 and 2021, respectively. As of December 31, 2022 and 2021, 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 and liabilities at December 31, 2022 and 2021 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, 2022 Fair Value as of December 31, 2021 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total (In Thousands) Financial assets: FTRs $ — $ — $ 7,545 $ 7,545 $ — $ — $ 1,235 $ 1,235 Total financial assets measured at fair value $ — $ — $ 7,545 $ 7,545 $ — $ — $ 1,235 $ 1,235 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, 2021 $ 543 Issuances 2,971 Settlements (2,279) Balance at December 31, 2021 $ 1,235 Issuances 15,338 Settlements (9,028) Balance at December 31, 2022 $ 7,545 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, 2022 December 31, 2021 Face Value Fair Value Face Value Fair Value (In Thousands) Fixed-rate $ 2,153,800 $ 1,959,233 $ 1,803,800 $ 2,222,772 Variable-rate — — 60,000 60,000 Total indebtedness $ 2,153,800 $ 1,959,233 $ 1,863,800 $ 2,282,772 The difference between the face value and the carrying value of this indebtedness represents the following: • unamortized deferred financing costs of $20.4 million and $17.9 million at December 31, 2022 and 2021, respectively; and • unamortized discounts of $6.7 million and $5.9 million at December 31, 2022 and 2021, respectively.

Regulatory Matters

Regulatory Matters	12 Months Ended
	Dec. 31, 2022
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 revenues. AES Indiana’s basic rates and charges are determined after giving consideration, on a pro-forma basis, to all allowable costs for ratemaking purposes including a fair return on the fair value of the utility property used and useful in providing service to customers. These basic rates and charges are set and approved by the IURC after public hearings. Such proceedings, which have occurred at irregular intervals, involve AES Indiana, the IURC, the Indiana Office of Utility Consumer Counselor, and other interested stakeholders. Pursuant to statute, the IURC is to conduct a periodic review of the basic rates and charges of all Indiana utilities at least once every four years, but the IURC has the authority to review the rates of any Indiana utility at any time. Once set, the basic rates and charges authorized do not assure the realization of a fair return on the fair value of property. AES Indiana’s declining block rate structure generally provides for residential and commercial customers to be charged a lower per kWh rate at higher consumption levels. Therefore, as volumes increase, the weighted average price per kWh decreases. Numerous factors including, but not limited to, weather, inflation, customer growth and usage, the level of actual operating and maintenance expenditures, fuel costs, generating unit availability, and capital expenditures including those required by environmental regulations can affect the return realized. Base Rate Orders On October 31, 2018, the IURC issued an order approving an uncontested settlement agreement previously filed with the IURC by AES Indiana for a $43.9 million, or 3.2%, increase to annual revenues (the "2018 Base Rate Order"). The 2018 Base Rate Order includes recovery through rates of the CCGT at Eagle Valley completed in the first half of 2018, as well as other construction projects and changes to operating income since the 2016 Base Rate Order. New basic rates and charges became effective on December 5, 2018. The 2018 Base Rate Order also provides customers approximately $50 million in benefits, which flowed to customers over the two-year period that began March 2019, via the ECCRA rate adjustment mechanism. As of December 31, 2022 and 2021, these credits have been fully returned to customers. In addition, the 2018 Base Rate Order provides that annual wholesale margins earned above (or below) the benchmark of $16.3 million shall be passed back (or charged) to customer rates through a rate adjustment mechanism. Prior to the 2018 Base Rate Order, wholesale sales margins were shared with customers 50% above and below an established benchmark of $6.3 million. Similarly, the 2018 Base Rate Order provides that all capacity sales above (or below) a benchmark of $11.3 million shall be passed back (or charged) to customer rates through a rate adjustment mechanism. The 2018 Base Rate Order also approved changes to AES Indiana's depreciation and amortization rates (including no longer deferring depreciation on the CCGT at Eagle Valley) which altogether represent a net expense increase of approximately $28.7 million annually. FAC and Authorized Annual Jurisdictional Net Operating Income AES Indiana may apply to the IURC for a change in AES Indiana’s fuel charge every three months to recover AES Indiana’s estimated fuel costs, including the energy portion of purchased power costs, which may be above or below the levels included in AES Indiana’s basic rates and charges. AES Indiana must present evidence in each FAC proceeding that it has made every reasonable effort to acquire fuel and generate or purchase power or both so as to provide electricity to its retail customers at the lowest fuel cost reasonably possible. Independent of the IURC’s ability to review basic rates and charges, Indiana law requires electric utilities under the jurisdiction of the IURC to meet operating expense and income test requirements as a condition for approval of requested changes in the FAC. A utility may be unable to recover all of its fuel costs if its rolling twelve-month operating income, determined at quarterly measurement dates, exceeds its authorized annual jurisdictional net operating income and there are not sufficient applicable cumulative net operating income deficiencies (“Cumulative Deficiencies”) to offset it. The Cumulative Deficiencies calculation provides that only five years’ worth of historical earnings deficiencies or surpluses are included, unless it has been greater than five years since the most recent rate case. In each of the last three calendar years, AES Indiana has reported earnings in excess of the authorized level for each of the four quarterly reporting periods in those years. AES Indiana was not required to reduce its fuel cost recovery in 2019 because of its Cumulative Deficiencies. During 2020, AES Indiana's Cumulative Deficiencies dropped to zero and thus AES Indiana recorded a reduction to revenues of $0.3 million, $5.5 million and $10.0 million in 2022, 2021 and 2020, respectively. AES Indiana's regulatory liability attributed to the Cumulative Deficiencies calculation was $0.0 million and $0.5 million as of December 31, 2022 and 2021, respectively, which is recorded within " Regulatory liabilities, current " on the accompanying Consolidated Balance Sheets. ECCRA AES Indiana may apply to the IURC for approval of a rate adjustment known as the ECCRA periodically to recover costs (including a return) to comply with certain environmental regulations applicable to AES Indiana’s generating stations. The total amount of AES Indiana’s environmental equipment approved for ECCRA recovery as of December 31, 2022 was $22.8 million. The jurisdictional revenue requirement approved by the IURC to be included in AES Indiana’s rates for the twelve-month period ending February 2023 is a net cost to customers of $1.6 million. The only environmental equipment still remaining in the ECCRA as of December 31, 2022 are certain projects associated with NAAQS compliance. DSM Through various rate orders from the IURC, AES Indiana has been able to recover its costs of implementing various DSM programs throughout the periods covered by this report. In 2022, 2021 and 2020, 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, 2022, 2021 and 2020 were $8.3 million, $7.2 million and $6.0 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 revenues, consistent with the provisions of the settlement agreement. Wind and Solar Power Purchase Agreements AES Indiana is committed under a power purchase agreement to purchase all wind-generated electricity through 2029 from a wind project in Indiana. AES Indiana is also committed under another agreement to purchase all wind-generated electricity through 2031 from a project in Minnesota. The Indiana project has a maximum output capacity of approximately 100 MW and the Minnesota project has a maximum output capacity of approximately 200 MW. In addition, AES Indiana has 94.5 MW of solar-generated electricity in its service territory under long-term contracts (these long-term contracts have expiration dates ranging from 2026 to 2033), of which 94.0 MW was in operation as of December 31, 2022. AES Indiana has authority from the IURC to recover the costs for all of these agreements through an adjustment mechanism administered within the FAC. If and when AES Indiana sells the renewable energy attributes (in the form of renewable energy credits) generated from these facilities, the proceeds would pass back to benefit AES Indiana’s retail customers through the FAC. TDSIC In 2013, Senate Enrolled Act 560, the Transmission, Distribution, and Storage System Improvement Charge ("TDSIC") statute, was signed into law. The TDSIC statute was revised in 2019. Among other provisions, this legislation provides for cost recovery outside of a base rate proceeding for new or replacement electric and gas transmission, distribution, and storage projects that a public utility undertakes for the purposes of safety, reliability, system modernization, or economic development. Provisions of the TDSIC statute require that, among other things, requests for recovery include a plan of at least five years and not more than seven for eligible investments. The first eighty percent of eligible costs can be recovered using a periodic rate adjustment mechanism. The cost recovery mechanism is referred to as a TDSIC mechanism. Recoverable costs include a return on, and of, the investment, including AFUDC, post-in-service carrying charges, operation and maintenance expenses, depreciation and property taxes. The remaining twenty percent of recoverable costs are to be deferred for future recovery in the public utility’s next base rate case. The periodic rate adjustment mechanism is capped at an annual increase of no more than two percent of total retail revenues. On March 4, 2020, the IURC issued an order approving the projects in a seven-year TDSIC Plan for eligible transmission, distribution and storage system improvements totaling $1.2 billion from 2020 through 2026. Beginning in June 2020, AES Indiana files an annual TDSIC rate adjustment for a return on and of investments through March 31 with rates requested to be effective each November. Annual TDSIC plan update filings are required to be staggered by six months as ordered by the IURC and are filed each December. The total amount of AES Indiana’s equipment approved for TDSIC recovery as of December 31, 2022 was $324.0 million, The jurisdictional revenues requirement approved by the IURC to be included in AES Indiana’s rates for the twelve-month period ending October 2023 is a net cost to customers of $34.3 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 by the end of 2025. AES Indiana has not yet filed for the necessary regulatory approvals from the IURC to convert Petersburg units 3 and 4; however, AES Indiana expects to do so at the appropriate time. 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 has determined that the cost of operating Petersburg Units 1 and 2 exceeds the value customers receive compared to alternative resources. Retirement of these units allows the company to cost-effectively diversify the portfolio and transition to lower cost and cleaner resources while maintaining a reliable system. AES Indiana issued an all-source Request for Proposal on December 20, 2019, in order to competitively procure replacement capacity by June 1, 2023, which 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 $2.1 million, $0.8 million, and $0.0 million of obsolescence losses, during the periods ended December 31, 2022, 2021, and 2020, respectively, for materials and supplies inventory AES Indiana does not believe will be utilized by the planned retirement dates, which is recorded in " Operating expenses - Operation and maintenance " on the accompanying Consolidated Statements of Operations. 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 on May 31, 2021 and expects to retire Unit 2 in 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. AES Indiana had $60.1 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, 2021. Hardy Hills Solar Project In January 2021, AES Indiana, through its wholly-owned subsidiary AES Indiana Devco Holdings 1, LLC, executed an agreement for the acquisition and construction of the 195 MW Hardy Hills Solar Project to be developed in Clinton County, Indiana. As amended in December 2022 and subject to IURC approval, the Hardy Hills Solar Project is now expected to be completed in 2024. 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. Petersburg Solar Project In July 2021, AES Indiana, through its wholly-owned subsidiary AES Indiana Devco Holdings 2, LLC, executed an agreement for the acquisition and construction of a 250 MW solar and 180 MWh energy storage facility to be developed in Pike County, Indiana. As amended in October 2022 and subject to IURC approval, the Petersburg Solar Project is now expected to be completed in 2025. On July 30, 2021, AES Indiana filed a petition and case-in-chief with the IURC seeking a CPCN for this solar project and on November 24, 2021, AES Indiana received an order from the IURC approving the project, including a joint venture structure between an AES Indiana subsidiary and one or more tax equity partners upon completion and approval for recovery of project development costs and carrying costs on AES Indiana's investment in the project. 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. Additionally, the clean energy statute provides for a 120-day procedural schedule for the IURC to issue a determination of a project's eligibility. 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 Hardy Hills and Petersburg Energy Center under this statute (and other applicable statutes) and currently has a related request for IURC approval of contract amendments pending before the IURC. 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 through August 14, 2020, which has lapsed. Additionally, the IURC authorized Indiana utilities to use regulatory accounting for any impacts associated with prohibiting utility disconnections, waiver or exclusion of certain utility fees (i.e., late fees, convenience fees, deposits, and reconnection fees), and also required utilities to use expanded payment arrangements to aid customers. The IURC also authorized regulatory accounting treatment for COVID-19 related uncollectible and incremental bad debt expense. On August 12, 2020, the IURC required all jurisdictional utilities to continue offering extended payment arrangements for a minimum of six months to all customers for an additional 60 days, until October 12, 2020, which the IURC again extended through December 31, 2020 for residential customers on October 27, 2020. The IURC also continued to suspend the collection of certain utility fees (late fees, deposits, and disconnection/reconnection fees) from residential customers for an additional 60 days, until October 12, 2020, after which utilities were allowed to resume charging convenience fees as set forth in the rate and charges established in their Commission-approved tariffs. As a result of the IURC's COVID-19 related orders issued in 2020, AES Indiana has recorded a regulatory asset of $5.4 million as of December 31, 2022 and 2021. On August 25, 2021, the IURC closed the investigation to consider and address the impacts of the COVID-19 pandemic. For further discussion on the COVID-19 pandemic, see Note 15, " Risks and Uncertainties - COVID-19 Pandemic. " Excess Distributed Generation Rates On March 1, 2021, AES Indiana filed a petition with the IURC for approval of its proposed rate for the procurement of excess distributed generation ("EDG") and related consumer EDG credit issues. The EDG rate 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 remains subject to the pending appeal filed by the other parties on February 22, 2022, which is currently being 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 and currently remains in effect. 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. Electric Vehicle Portfolio Program On January 27, 2023, AES Indiana filed with the IURC a request to approve its Electric Vehicle (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. 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 Utility Receipts Tax ("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 revenues 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: 2022 2021 Recovery Period (In Thousands) Regulatory Assets Current: Undercollections of rate riders $ 26,047 $ 41,108 Approximately 1 year (1) Fuel costs 79,861 8,890 Approximately 1 year (1) Costs being recovered through basic rates and charges 13,815 13,815 Approximately 1 year (1) Total current regulatory assets 119,723 63,813 Long-term: Unrecognized pension and other postretirement benefit plan costs 131,907 114,887 Various (2) Deferred MISO costs 34,483 47,875 Through 2026 (1) Unamortized Petersburg Unit 4 carrying charges and certain other costs 3,866 4,921 Through 2026 (1)(3) Unamortized reacquisition premium on debt 14,429 15,703 Over remaining life of debt Environmental costs 68,947 71,201 Through 2046 (1)(3) COVID-19 costs 5,426 5,426 To be determined TDSIC costs 18,547 8,540 36.3 years (1)(3) Petersburg Unit 1 and 2 retirement costs 287,463 300,067 Through 2034 (1)(3) Hardy Hills Solar Project costs 5,744 2,907 To be determined (3) Petersburg Solar Project costs 1,582 881 To be determined Fuel costs 20,518 83,513 Through 2025 (1) Other miscellaneous 1,027 1,056 Various (4) Total long-term regulatory assets 593,939 656,977 Total regulatory assets $ 713,662 $ 720,790 Regulatory Liabilities Current: Overcollections and other credits being passed to customers through rate riders $ 15,803 $ 3,006 Approximately 1 year (1) FTRs 7,545 1,235 Approximately 1 year (1) Total current regulatory liabilities 23,348 4,241 Long-term: ARO and accrued asset removal costs 518,797 722,774 Not applicable Deferred income taxes payable to customers through rates 88,662 100,171 Various Major storm damage 5,126 3,764 To be determined Total long-term regulatory liabilities 612,585 826,709 Total regulatory liabilities $ 635,933 $ 830,950 (1) Recovered (credited) per specific rate orders (2) AES Indiana receives a return on its discretionary funding (3) Recovered with a current return (4) The majority of these costs are being recovered in basic rates and charges through 2026. For the remainder, recovery is probable, but the timing is not yet determined. 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) Green Power, (iii) Deferred Fuel Costs and (iv) 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) ECCRA costs, (iii) Off System Sales Margin Sharing, (iv) Capacity rider costs, (v) FAC 133 sub-docket costs and (vi) the NOI liability that is credited to customers in the FAC filing. Deferred Fuel Deferred fuel costs are a component of current and long-term regulatory assets or liabilities (which is a result of AES Indiana charging either more or less for fuel than our actual costs to our jurisdictional customers) and are expected to be recovered through future FAC proceedings. AES Indiana records deferred fuel in accordance with standards prescribed by the FERC. The deferred fuel adjustment is the result of variances between estimated fuel and purchased power costs in AES Indiana’s FAC and actual fuel and purchased power costs. AES Indiana is generally permitted to recover underestimated fuel and purchased power costs in future rates through the FAC proceedings and therefore the costs are deferred when incurred and amortized into fuel expense in the same period that AES Indiana’s rates are adjusted to reflect these costs. The Eagle Valley CCGT was on unplanned outage from late April 2021 until mid-March 2022, impacting several FAC periods. The FAC 133 IURC Order issued on November 24, 2021 approved the FAC 133 fuel cost factor on an interim basis subject to refund pending the outcome of a sub-docket created to examine the Eagle Valley CCGT extended outage. A procedural schedule for the sub-docket was established by the IURC. AES Indiana filed testimony in the FAC sub-docket in May 2022. AES Indiana's subsequent FAC filings have included a reduced FAC factor requested by AES Indiana in order to mitigate the rate impact on customers, primarily caused by rising commodity pricing and the Eagle Valley extended outage, that deferred the collection of certain variances estimated to be due to the Eagle Valley unplanned outage until a future FAC filing or the resolution in the FAC sub-docket for the Eagle Valley outage. Such FAC deferrals are recorded in long-term regulatory assets until the timing of collection is known. This treatment ceased with the FAC 138 filing in December 2022. On October 25, 2022, AES Indiana and various intervening parties reached a unanimous settlement regarding the Eagle Valley CCGT unplanned outage. This settlement resolves all issues related to the FAC sub-docket and all outage related costs including energy purchases, Off-System Sales margins, Capacity trackers and base rate proceedings. As part of this comprehensive settlement, AES Indiana agreed not to recover $21.0 million of previously deferred costs and to credit an additional $6.8 million to customers in future rates. As such, AES Indiana recorded a $27.8 million charge to " Power purchased " in the Consolidated Statements of Operations during the third quarter of 2022. On January 18, 2023, AES Indiana received an order from the IURC approving the settlement. Unrecognized Pension and Postretirement Benefit Plan Costs In accordance with ASC 715 “Compensation – Retirement Benefits” and ASC 980, we recognize a regulatory asset equal to the unrecognized actuarial gains and losses and prior service costs. Pension expenses or income are recorded based on the benefit plan’s actuarially determined pension liability or asset and associated level of annual expenses or income to be recognized. The other postretirement benefit plan’s deferred benefit cost is the excess of the other postretirement benefit liability over the amount previously recognized. Deferred MISO Costs These consist of administrative costs for transmission services, transmission expansion cost sharing, and certain other operational and administrative costs from the MISO market. These costs are being recovered per specific rate order. Unamortized Petersburg Unit 4 Carrying Charges and Certain Other Costs These consist of deferred debt carrying costs, depreciation, and post-in-service Allowance for Funds Used During Construction ("AFUDC") on Petersburg Unit 4. These costs are being recovered per specific rate order. Unamortized Reacquisition Premium on Debt This regulatory asset represents losses on long-term debt reacquired or redeemed in prior periods that have been deferred. These deferred losses are being amortized over the lives of the original issues in accordance with the rules of the FERC and the IURC. Environmental Costs These consist of various costs incurred to comply with environmental regulations. These costs were approved for recovery either through AES Indiana's ECCRA proceedings or in the 2018 Base Rate Order. Amortization periods vary, ranging from 3 to 43 years. COVID-19 Costs These cons

Derivative Instruments and Hedg

Derivative Instruments and Hedging Activities	12 Months Ended
	Dec. 31, 2022
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, 2022 , 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 5,388 — 5,388 (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 Year Ended December 31, $ in thousands (net of tax) 2022 2021 2020 Beginning accumulated derivative losses in AOCL $ (29,407) $ (43,420) $ (19,750) Net gains / (losses) associated with current period hedging transactions 46,245 10,393 (27,779) Net losses reclassified to interest expense, net of tax 5,431 3,620 4,109 Ending accumulated derivative gains / (losses) in AOCI / (AOCL) $ 22,269 $ (29,407) $ (43,420) Losses 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) 21 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 $1.3 million and $6.0 million related to forward power contracts during the years ended December 31, 2022 and 2021, 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, 2022 and 2021, 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 2022 2021 FTRs Not a Cash Flow Hedge Prepayments and other current assets $ 7,545 $ 1,235 Interest rate hedges Cash Flow Hedge Derivative assets, non-current $ 12,172 $ — Interest rate hedges Cash Flow Hedge Derivative liabilities, non-current $ — $ 49,382
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, 2022 , AES Indiana's outstanding derivative instruments were as follows: Commodity Accounting Treatment (a) Unit Notional Sales Net Notional FTRs Not Designated MWh 5,388 — 5,388 (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 $1.3 million and $6.0 million related to forward power contracts during the years ended December 31, 2022 and 2021, 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, 2022 and 2021, 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 2022 2021 FTRs Not a Cash Flow Hedge Prepayments and other current assets $ 7,545 $ 1,235

Equity

Equity	12 Months Ended
	Dec. 31, 2022
Entity Information [Line Items]
Equity	EQUITY AND CUMULATIVE PREFERRED STOCK 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, 2022, 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 " below 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, 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, 2022, 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, 2022, 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, 2022, 2021 and 2020, IPALCO declared and paid distributions to its shareholders totaling $102.0 million, $131.5 million and $108.7 million, respectively. 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 each year ended December 31, 2022, 2021 and 2020, total preferred stock dividends declared were $3.2 million. 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. At December 31, 2022 and 2021, preferred stock consisted of the following: December 31, Shares Call Price 2022 2021 Par Value, plus premium, if applicable (In Thousands) Cumulative $100 par value, authorized 2,000,000 shares 4% Series 47,611 $ 118.00 $ — $ 5,410 4.2% Series 19,331 $ 103.00 — 1,933 4.6% Series 2,481 $ 103.00 — 248 4.8% Series 21,930 $ 101.00 — 2,193 5.65% Series 500,000 $ 100.00 — 50,000 Total cumulative preferred stock 591,353 $ — $ 59,784
Indianapolis Power And Light Company
Entity Information [Line Items]
Equity	EQUITY AND CUMULATIVE PREFERRED STOCK Paid in Capital and Capital Stock On December 12, 2022 and December 13, 2021, respectively, AES Indiana received equity capital contributions of $253.0 million and $275.0 million from IPALCO. The proceeds are intended primarily for funding needs related to AES Indiana’s TDSIC and replacement generation projects. All of the outstanding common stock of AES Indiana is owned by IPALCO. AES Indiana’s common stock is pledged under the 2024 IPALCO Notes and 2030 IPALCO Notes. There have been no changes in the capital stock of AES Indiana during the three years ended December 31, 2022. 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, 2022, 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 " below 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, 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, 2022, and as of the filing of this report, AES Indiana was in compliance with all covenants and no event of default existed. During the years ended December 31, 2022, 2021 and 2020, AES Indiana declared dividends to its shareholder totaling $127.2 million, $155.7 million, and $140.6 million, respectively. 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 each year ended December 31, 2022, 2021 and 2020, total preferred stock dividends declared were $3.2 million. 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. At December 31, 2022 and 2021, preferred stock consisted of the following: December 31, Shares Call Price 2022 2021 Par Value, plus premium, if applicable (In Thousands) Cumulative $100 par value, authorized 2,000,000 shares 4% Series 47,611 $ 118.00 $ — $ 5,410 4.2% Series 19,331 $ 103.00 — 1,933 4.6% Series 2,481 $ 103.00 — 248 4.8% Series 21,930 $ 101.00 — 2,193 5.65% Series 500,000 $ 100.00 — 50,000 Total cumulative preferred stock 591,353 $ — $ 59,784 (a) AES Indiana's preferred stock was redeemed on December 30, 2022.

Debt

Debt	12 Months Ended
	Dec. 31, 2022
Entity Information [Line Items]
Debt	DEBT Long-Term Debt The following table presents our long-term debt: December 31, Series Due 2022 2021 (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 — 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 (6,651) (5,855) Deferred financing costs (20,362) (17,913) Total AES Indiana first mortgage bonds 2,126,787 1,780,032 Total long-term debt – AES Indiana 2,126,787 1,780,032 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 (425) (527) Deferred financing costs (5,912) (7,319) Total long-term debt – IPALCO 873,663 872,154 Total consolidated IPALCO long-term debt 3,000,450 2,652,186 Less: current portion of long-term debt — — Net consolidated IPALCO long-term debt $ 3,000,450 $ 2,652,186 (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, 2022 and 2021, AES Indiana had $0.0 million and $60.0 million in outstanding borrowings on the committed Credit Agreement, respectively. Debt Maturities Maturities on long-term indebtedness subsequent to December 31, 2022, are as follows: Year Amount (In Thousands) 2023 $ — 2024 445,000 2025 40,000 2026 90,000 2027 — Thereafter 2,458,800 Total $ 3,033,800 Significant Transactions AES Indiana Term Loan In June 2022, AES Indiana entered into an unsecured $200.0 million 364-day term loan agreement. The AES Indiana 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 AES Indiana 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 In April 2020, IPALCO completed the sale of $475 million aggregate principal amount of 4.25% 2030 IPALCO Notes pursuant to Rule 144A and Regulation S under the Securities Act of 1933, as amended. We used the net proceeds from this offering to retire the $65 million IPALCO Term Loan Agreement on April 14, 2020. The remaining net proceeds, together with cash on hand, were used to redeem the 2020 IPALCO Notes on May 14, 2020, and to pay certain related fees, expenses and make-whole premiums. A loss on early extinguishment of debt of $2.4 million for the 2020 IPALCO Notes is included as a separate line item within " Other Income/(Expense), Net " in the accompanying Consolidated Statements of Operations. Pursuant to a registration rights agreement dated April 14, 2020, IPALCO agreed to register the 2030 IPALCO Notes under the Securities Act by filing an exchange offer registration statement or, under specified circumstances, a shelf registration statement with the SEC. IPALCO filed a registration statement on Form S-4 with respect to the 2030 IPALCO Notes with the SEC on March 22, 2021 in respect of its obligations under such registration rights agreement, and this registration statement was declared effective on April 7, 2021. The exchange offer closed on May 11, 2021. 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, 2022. 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 $400.0 million remains available under the order as of December 31, 2022. 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, 2022. 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. 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, 2022. 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, 2022. 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 Long-Term Debt The following table presents AES Indiana’s long-term debt: December 31, Series Due 2022 2021 (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 — 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 (6,651) (5,855) Deferred financing costs (20,362) (17,913) Total AES Indiana first mortgage bonds 2,126,787 1,780,032 Total consolidated AES Indiana long-term debt 2,126,787 1,780,032 Less: current portion of long-term debt — — Net consolidated AES Indiana long-term debt $ 2,126,787 $ 1,780,032 (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, 2022 and 2021, AES Indiana had $0.0 million and $60.0 million in outstanding borrowings on the committed Credit Agreement, respectively. Debt Maturities Maturities on long-term indebtedness subsequent to December 31, 2022, are as follows: Year Amount (In Thousands) 2023 $ — 2024 40,000 2025 40,000 2026 90,000 2027 — Thereafter 1,983,800 Total $ 2,153,800 Significant Transactions AES Indiana Term Loan In June 2022, AES Indiana entered into an unsecured $200.0 million 364-day term loan agreement. The AES Indiana 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 AES Indiana 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, 2022. 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 $400.0 million remains available under the order as of December 31, 2022. 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, 2022. 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. 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, 2022. 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, 2022. 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, 2022
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 March 27, 2001, but is open for all subsequent periods. IPALCO made tax sharing payments to AES of $31.0 million, $27.5 million and $27.0 million in 2022, 2021 and 2020, respectively. Income Tax Provision Federal and state income taxes charged to income are as follows: 2022 2021 2020 (In Thousands) Components of income tax expense: Current income taxes: Federal $ 22,539 $ 28,100 $ 19,489 State 6,026 8,218 6,249 Total current income taxes 28,565 36,318 25,738 Deferred income taxes: Federal (6,920) (7,286) 323 State 214 (91) 2,531 Total deferred income taxes (6,706) (7,377) 2,854 Net amortization of investment credit — — — Total income tax expense $ 21,859 $ 28,941 $ 28,592 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: 2022 2021 2020 Federal statutory tax rate 21.0 % 21.0 % 21.0 % State income tax, net of federal tax benefit 3.9 % 4.0 % 4.2 % Depreciation flow through and amortization (7.8) % (6.3) % (6.8) % Additional funds used during construction - equity 0.9 % 0.4 % 1.0 % Other – net 0.4 % 0.4 % 1.2 % Effective tax rate 18.4 % 19.5 % 20.6 % 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, 2022 and 2021 are as follows: 2022 2021 (In Thousands) Deferred tax liabilities: Relating to utility property, net $ 341,473 $ 369,783 Regulatory assets recoverable through future rates 123,669 126,531 Other 17,953 14,326 Total deferred tax liabilities 483,095 510,640 Deferred tax assets: Investment tax credit 6 7 Regulatory liabilities including ARO 167,725 200,948 Employee benefit plans — — Other 2,723 18,958 Total deferred tax assets 170,454 219,913 Deferred income tax liability – net $ 312,641 $ 290,727 Uncertain Tax Positions The following is a reconciliation of the beginning and ending amounts of unrecognized tax benefits for the years ended December 31, 2022, 2021 and 2020: 2022 2021 2020 (In Thousands) Unrecognized tax benefits at January 1 $ — $ 7,368 $ 7,056 Gross increases – current period tax positions — — 312 Gross decreases – prior period tax positions — (7,368) — Unrecognized tax benefits at December 31 $ — $ — $ 7,368 The prior period unrecognized tax benefits represent tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. As a result of the resolution of federal and state audits in 2021, IPALCO reviewed its uncertain positions and determined that they are more likely than not to be sustained upon examination by taxing authorities. Consequently, the uncertain tax positions were reversed; because of the impact of deferred tax accounting the reversal did not affect the annual effective tax rate but were reclassified to plant related deferred tax balances. Tax years subsequent to March 27, 2001 remain open to examination by taxing authorities. While it is often difficult to predict the final outcome or the timing of resolution of any particular uncertain tax position, we believe unrecognized tax benefits of $0 at December 31, 2022 and 2021, 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 March 27, 2001, but is open for all subsequent periods. AES Indiana made tax sharing payments to IPALCO of $39.5 million, $40.8 million and $27.0 million in 2022, 2021 and 2020, respectively. Income Tax Provision Federal and state income taxes charged to income are as follows: 2022 2021 2020 (In Thousands) Components of income tax expense: Current income taxes: Federal $ 31,286 $ 36,353 $ 28,395 State 8,185 10,325 8,661 Total current income taxes 39,471 46,678 37,056 Deferred income taxes: Federal (6,822) (7,283) 503 State 238 (90) 2,576 Total deferred income taxes (6,584) (7,373) 3,079 Net amortization of investment credit — — — Total income tax expense $ 32,887 $ 39,305 $ 40,135 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: 2022 2021 2020 Federal statutory tax rate 21.0 % 21.0 % 21.0 % State income tax, net of federal tax benefit 3.9 % 4.0 % 4.2 % Depreciation flow through and amortization (5.7) % (4.9) % (5.1) % Additional funds used during construction - equity 0.7 % 0.3 % 0.7 % Other – net 0.3 % 0.3 % 1.0 % Effective tax rate 20.2 % 20.7 % 21.8 % 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, 2022 and 2021 are as follows: 2022 2021 (In Thousands) Deferred tax liabilities: Relating to utility property, net $ 341,473 $ 369,783 Regulatory assets recoverable through future rates 123,669 126,531 Other 22,717 18,283 Total deferred tax liabilities 487,859 514,597 Deferred tax assets: Investment tax credit 6 7 Regulatory liabilities including ARO 167,726 205,099 Employee benefit plans — — Other 15,020 9,313 Total deferred tax assets 182,752 214,419 Deferred income tax liability – net $ 305,107 $ 300,178 Uncertain Tax Positions The following is a reconciliation of the beginning and ending amounts of unrecognized tax benefits for the years ended December 31, 2022, 2021 and 2020: 2022 2021 2020 (In Thousands) Unrecognized tax benefits at January 1 $ — $ 7,368 $ 7,056 Gross increases – current period tax positions — — 312 Gross decreases – prior period tax positions — (7,368) — Unrecognized tax benefits at December 31 $ — $ — $ 7,368 The prior period unrecognized tax benefits represent tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. As a result of the resolution of federal and state audits in 2021, AES Indiana reviewed its uncertain positions and determined that they are more likely than not to be sustained upon examination by taxing authorities. Consequently, the uncertain tax positions were reversed; because of the impact of deferred tax accounting the reversal did not affect the annual effective tax rate but were reclassified to plant related deferred tax balances. Tax years subsequent to March 27, 2001 remain open to examination by taxing authorities. While it is often difficult to predict the final outcome or the timing of resolution of any particular uncertain tax position, AES Indiana believes unrecognized tax benefits of $0 at December 31, 2022 and 2021, 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, 2022
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 78% 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 $3.6 million, $3.4 million and $3.4 million for 2022, 2021 and 2020, respectively. The RSP Approximately 22% 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 $2.1 million, $1.9 million and $1.8 million for 2022, 2021 and 2020, respectively. Defined Benefit Plans Approximately 68% of AES Indiana’s active employees are covered by the qualified Defined Benefit Pension Plan; while approximately 10% of active employees are IBEW clerical-technical unit employees who are only eligible for the Thrift Plan. The remaining 22% 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, 2022 was 20. 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 130 active employees and 24 retirees (including spouses) were receiving such benefits or entitled to future benefits as of January 1, 2022. The plan is unfunded. These postretirement health care benefits and the related unfunded obligation of $3.2 million and $3.9 million at December 31, 2022 and 2021, 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 2022 2021 (In Thousands) Change in benefit obligation: Projected benefit obligation at January 1 $ 772,040 $ 842,525 Service cost 8,949 9,339 Interest cost 18,099 15,660 Actuarial gain (182,590) (37,858) Amendments (primarily increases in pension bands) — 5,575 Settlements (394) — Benefits paid (38,575) (63,201) Projected benefit obligation at December 31 577,529 772,040 Change in plan assets: Fair value of plan assets at January 1 820,684 850,020 Actual (loss)/return on plan assets (171,002) 33,841 Employer contributions 412 24 Settlements (394) — Benefits paid (38,575) (63,201) Fair value of plan assets at December 31 611,125 820,684 Funded status $ 33,596 $ 48,644 Amounts recognized in the statement of financial position: Non-current assets $ 33,611 $ 49,182 Non-current liabilities (15) (538) Net amount recognized at end of year $ 33,596 $ 48,644 Sources of change in regulatory assets (1) : Prior service cost arising during period $ — $ 5,575 Net loss/(gain) arising during period 24,069 (29,884) Amortization of prior service cost (2,589) (2,944) Amortization of loss (2,622) (5,529) Total recognized in regulatory assets $ 18,858 $ (32,782) Amounts included in regulatory assets: Net loss $ 131,559 $ 110,113 Prior service cost 11,655 14,244 Total amounts included in regulatory assets $ 143,214 $ 124,357 (1) Amounts that would otherwise be charged/credited to Accumulated Other Comprehensive Income or Loss upon application of ASC 715, “Compensation – Retirement Benefits,” are recorded as a regulatory asset or liability because AES Indiana has historically recovered and currently recovers pension and other postretirement benefit expenses in rates. These are unrecognized amounts not yet recognized as components of net periodic benefit costs. Significant Gains Related to Changes in the Benefit Obligation for the Period As shown in the table above, an actuarial gain of $182.6 million decreased the benefit obligation for the year ended December 31, 2022 and an actuarial gain of $37.9 million decreased the benefit obligation for the year ended December 31, 2021. The actuarial gains in 2022 and 2021 were primarily due to increases 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 2022 net actuarial loss of $24.1 million recognized in regulatory assets is comprised of two parts: (1) a $182.6 million pension liability actuarial gain primarily due to an increase in the discount rate used to value pension liabilities; partially offset by (2) a $206.7 million pension asset actuarial loss primarily due to lower than expected return on assets. The unrecognized net loss of $131.6 million in the Pension Plans has accumulated over time primarily due to the long-term declining trend in corporate bond rates and the adoption of new mortality tables which increased the expected benefit obligation due to the longer expected lives of plan participants. During 2022, the accumulated net loss increased due to lower than expected return on pension assets, which was partially offset by a combination of higher discount rates used to value pension liabilities, as well as the year 2022 amortization of accumulated loss. The unrecognized net loss, to the extent that it exceeds 10% of the greater of the benefit obligation or the assets, will be amortized and included as a component of net periodic benefit cost in future years. The amortization period is approximately 11.46 years based on estimated demographic data as of December 31, 2022. The projected benefit obligation of $577.5 million less the fair value of assets of $611.1 million results in an overfunded status of $33.6 million at December 31, 2022. Pension benefits for 2022 2021 2020 (In Thousands) Components of net periodic benefit (credit) / cost: Service cost $ 8,949 $ 9,339 $ 8,272 Interest cost 18,099 15,660 22,151 Expected return on plan assets (35,656) (41,815) (37,779) Amortization of prior service cost 2,589 2,944 3,677 Amortization of actuarial loss 2,424 5,529 8,115 Amortization of settlement loss 199 — — Net periodic benefit (credit) / cost (3,396) (8,343) 4,436 Less: amounts capitalized 316 771 372 Amount charged to expense $ (3,080) $ (7,572) $ 4,064 Rates relevant to each year’s expense calculations: Discount rate – defined benefit pension plan 2.83 % 2.46 % 3.33 % Discount rate – supplemental retirement plan 2.62 % 2.31 % 3.05 % Expected return on defined benefit pension plan assets 4.45 % 5.05 % 5.05 % Expected return on supplemental retirement plan assets 5.50 % 3.60 % 4.45 % 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 2022, pension expense / (income) was determined using an assumed long-term rate of return on plan assets of 4.45% for the Defined Benefit Pension Plan and 5.50% for the Supplemental Retirement Plan. As of the December 31, 2022 measurement date, AES Indiana increased the discount rate from 2.83% to 5.41% for the Defined Benefit Pension Plan and from 2.62% to 5.32% for the Supplemental Retirement Plan. The discount rate assumptions affect the pension expense / (income) determined for 2023. In addition, AES Indiana increased the expected long-term rate of return on plan assets from 4.45% to 5.60% for the Defined Benefit Pension Plan and increased the expected long-term rate of return for the Supplemental Retirement Plan from 5.50% to 6.45% for 2023. The expected long-term rate of return assumption affects the pension expense / (income) determined for 2023. The effect on 2023 total pension expense / (income) of a 25 basis point increase and decrease in the assumed discount rate is $(0.2) million and $0.2 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, 2022. 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 2023 are determined as of the plans' measurement date of December 31, 2022. 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 2022: Asset Category: Target Allocations Equity Securities 13.5% Debt Securities 86.5% 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. Fair Value Measurements at December 31, 2021 (in thousands) Quoted Prices in Active Markets for Identical Assets Significant Observable Inputs Asset Category Total (Level 1) (Level 2) % Common collective trusts: Equities (a) $ 183,203 $ 2,778 $ 180,425 22 % Debt securities (b) 481,077 1,637 479,440 59 % Government debt securities (c) 154,051 324 153,727 19 % Total common collective trusts 818,331 4,739 813,592 100 % Cash and cash equivalents (d) 2,353 2,490 — — % Total pension plan assets $ 820,684 $ 7,229 $ 813,592 100 % (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 $0.4 million, $0.0 million, and $0.1 million to the Pension Plans in 2022, 2021 and 2020, 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 99%. 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 $6.2 million in 2023 (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 2023. 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, 2022, 2021 and 2020 were $38.6 million, $63.2 million and $38.5 million, respectively. Expected benefit payments are expected to be paid out of the Pension Plans as follows: Year Pension Benefits (In Thousands) 2023 $ 40,922 2024 41,855 2025 42,433 2026 43,191 2027 43,446 2028 through 2032 216,734
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 78% 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 $3.6 million, $3.4 million and $3.4 million for 2022, 2021 and 2020, respectively. The RSP Approximately 22% 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 $2.1 million, $1.9 million and $1.8 million for 2022, 2021 and 2020, respectively. Defined Benefit Plans Approximately 68% of AES Indiana’s active employees are covered by the qualified Defined Benefit Pension Plan; while approximately 10% of active employees are IBEW clerical-technical unit employees who are only eligible for the Thrift Plan. The remaining 22% 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, 2022 was 20. 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 130 active employees and 24 retirees (including spouses) were receiving such benefits or entitled to future benefits as of January 1, 2022. The plan is unfunded. These postretirement health care benefits and the related unfunded obligation of $3.2 million and $3.9 million at December 31, 2022 and 2021, 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 2022 2021 (In Thousands) Change in benefit obligation: Projected benefit obligation at January 1 $ 772,040 $ 842,525 Service cost 8,949 9,339 Interest cost 18,099 15,660 Actuarial gain (182,590) (37,858) Amendments (primarily increases in pension bands) — 5,575 Settlements (394) — Benefits paid (38,575) (63,201) Projected benefit obligation at December 31 577,529 772,040 Change in plan assets: Fair value of plan assets at January 1 820,684 850,020 Actual (loss)/return on plan assets (171,002) 33,841 Employer contributions 412 24 Settlements (394) — Benefits paid (38,575) (63,201) Fair value of plan assets at December 31 611,125 820,684 Funded status $ 33,596 $ 48,644 Amounts recognized in the statement of financial position: Non-current assets $ 33,611 $ 49,182 Non-current liabilities (15) (538) Net amount recognized at end of year $ 33,596 $ 48,644 Sources of change in regulatory assets (1) : Prior service cost arising during period $ — $ 5,575 Net loss/(gain) arising during period 24,069 (29,884) Amortization of prior service cost (2,589) (2,944) Amortization of loss (2,622) (5,529) Total recognized in regulatory assets $ 18,858 $ (32,782) Amounts included in regulatory assets: Net loss $ 131,559 $ 110,113 Prior service cost 11,655 14,244 Total amounts included in regulatory assets $ 143,214 $ 124,357 (1) Amounts that would otherwise be charged/credited to Accumulated Other Comprehensive Income or Loss upon application of ASC 715, “Compensation – Retirement Benefits,” are recorded as a regulatory asset or liability because AES Indiana has historically recovered and currently recovers pension and other postretirement benefit expenses in rates. These are unrecognized amounts not yet recognized as components of net periodic benefit costs. Significant Gains Related to Changes in the Benefit Obligation for the Period As shown in the table above, an actuarial gain of $182.6 million decreased the benefit obligation for the year ended December 31, 2022 and an actuarial gain of $37.9 million decreased the benefit obligation for the year ended December 31, 2021. The actuarial gains in 2022 and 2021 were primarily due to increases 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 2022 net actuarial loss of $24.1 million recognized in regulatory assets is comprised of two parts: (1) a $182.6 million pension liability actuarial gain primarily due to an increase in the discount rate used to value pension liabilities; partially offset by (2) a $206.7 million pension asset actuarial loss primarily due to lower than expected return on assets. The unrecognized net loss of $131.6 million in the Pension Plans has accumulated over time primarily due to the long-term declining trend in corporate bond rates and the adoption of new mortality tables which increased the expected benefit obligation due to the longer expected lives of plan participants. During 2022, the accumulated net loss increased due to lower than expected return on pension assets, which was partially offset by a combination of higher discount rates used to value pension liabilities, as well as the year 2022 amortization of accumulated loss. The unrecognized net loss, to the extent that it exceeds 10% of the greater of the benefit obligation or the assets, will be amortized and included as a component of net periodic benefit cost in future years. The amortization period is approximately 11.46 years based on estimated demographic data as of December 31, 2022. The projected benefit obligation of $577.5 million less the fair value of assets of $611.1 million results in an overfunded status of $33.6 million at December 31, 2022. Pension benefits for 2022 2021 2020 (In Thousands) Components of net periodic benefit (credit) / cost: Service cost $ 8,949 $ 9,339 $ 8,272 Interest cost 18,099 15,660 22,151 Expected return on plan assets (35,656) (41,815) (37,779) Amortization of prior service cost 2,589 2,944 3,677 Amortization of actuarial loss 2,424 5,529 8,115 Amortization of settlement loss 199 — — Net periodic benefit (credit) / cost (3,396) (8,343) 4,436 Less: amounts capitalized 316 771 372 Amount charged to expense $ (3,080) $ (7,572) $ 4,064 Rates relevant to each year’s expense calculations: Discount rate – defined benefit pension plan 2.83 % 2.46 % 3.33 % Discount rate – supplemental retirement plan 2.62 % 2.31 % 3.05 % Expected return on defined benefit pension plan assets 4.45 % 5.05 % 5.05 % Expected return on supplemental retirement plan assets 5.50 % 3.60 % 4.45 % 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 2022, pension expense / (income) was determined using an assumed long-term rate of return on plan assets of 4.45% for the Defined Benefit Pension Plan and 5.50% for the Supplemental Retirement Plan. As of the December 31, 2022 measurement date, AES Indiana increased the discount rate from 2.83% to 5.41% for the Defined Benefit Pension Plan and from 2.62% to 5.32% for the Supplemental Retirement Plan. The discount rate assumptions affect the pension expense / (income) determined for 2023. In addition, AES Indiana increased the expected long-term rate of return on plan assets from 4.45% to 5.60% for the Defined Benefit Pension Plan and increased the expected long-term rate of return for the Supplemental Retirement Plan from 5.50% to 6.45% for 2023. The expected long-term rate of return assumption affects the pension expense / (income) determined for 2023. The effect on 2023 total pension expense / (income) of a 25 basis point increase and decrease in the assumed discount rate is $(0.2) million and $0.2 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, 2022. 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 2023 are determined as of the plans' measurement date of December 31, 2022. 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 2022: Asset Category: Target Allocations Equity Securities 13.5% Debt Securities 86.5% 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. Fair Value Measurements at December 31, 2021 (in thousands) Quoted Prices in Active Markets for Identical Assets Significant Observable Inputs Asset Category Total (Level 1) (Level 2) % Common collective trusts: Equities (a) $ 183,203 $ 2,778 $ 180,425 22 % Debt securities (b) 481,077 1,637 479,440 59 % Government debt securities (c) 154,051 324 153,727 19 % Total common collective trusts 818,331 4,739 813,592 100 % Cash and cash equivalents (d) 2,353 2,490 — — % Total pension plan assets $ 820,684 $ 7,229 $ 813,592 100 % (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 $0.4 million, $0.0 million, and $0.1 million to the Pension Plans in 2022, 2021 and 2020, 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 99%. 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 $6.2 million in 2023 (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 2023. 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, 2022, 2021 and 2020 were $38.6 million, $63.2 million and $38.5 million, respectively. Expected benefit payments are expected to be paid out of the Pension Plans as follows: Year Pension Benefits (In Thousands) 2023 $ 40,922 2024 41,855 2025 42,433 2026 43,191 2027 43,446 2028 through 2032 216,734

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2022
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, 2022, 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 $ 1,188.8 $ 323.3 $ 331.1 $ 232.4 $ 302.0 Other $ 422.4 349.1 59.5 8.8 5.0 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, 2022, 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 8, " Income Taxes "), (iv) pension and other postretirement employee benefit liabilities (see Note 9, " Benefit Plans ") and (v) contingencies (see Note 10, " Commitments and Contingencies "). See the indicated notes to the Financial Statements for additional information on the items excluded. 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. As of December 31, 2022 and 2021, total legal loss contingencies accrued were $0.1 million and $0.2 million, respectively, which primarily related to personal injury litigation. During 2021, we entered into settlements resolving a significant portion of the legal loss contingencies previously accrued. The legal loss contingencies and settlement related accruals are included in "Accrued and other current liabilities" and " Other Non-Current Liabilities" on the accompanying Consolidated Balance Sheets. We maintain an amount of insurance protection for such litigation that we believe is adequate. As of December 31, 2022 and 2021, we have $0.0 million and $12.5 million, respectively, of receivables for insurance recoveries determined to be probable recorded in "Prepayments and other current assets" on the accompanying Consolidated Balance Sheets. While the ultimate outcome of outstanding litigation cannot be predicted with certainty, management believes that final outcomes will not have a material adverse effect on IPALCO’s results of operations, financial condition and cash flows. 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. New Source Review and other CAA NOVs In October 2009, AES Indiana received a NOV and Finding of Violation from the EPA pursuant to the CAA Section 113(a). The NOV alleged violations of the CAA at AES Indiana’s three primarily coal-fired electric generating facilities at the time, dating back to 1986. The alleged violations primarily pertain to the PSD and non-attainment New Source Review (NSR) requirements under the CAA. In addition, on October 1, 2015, AES Indiana received a NOV from the EPA pursuant to CAA Section 113(a) alleging violations of the CAA, the Indiana SIP, and the Title V operating permit related to alleged particulate matter and opacity violations at AES Indiana Petersburg Unit 3. Also, on February 5, 2016, the EPA issued a NOV pursuant to CAA Section 113(a) alleging violations of PSD, non-attainment NSR and other CAA regulations, the Indiana SIP, and the Title V operating permit at Petersburg Generating Station. On August 31, 2020, AES Indiana reached a settlement with the EPA, the DOJ and IDEM resolving the purported violations of the CAA with respect to the coal-fired generation units at AES Indiana's Petersburg location. The settlement agreement, in the form of a proposed judicial consent decree was approved and entered by the U.S. District Court for the Southern District of Indiana on March 23, 2021, and includes, among other items, the following requirements: annual caps on NO x and SO 2 emissions and more stringent emissions limits than AES Indiana's current Title V air permit; payment of civil penalties totaling $1.525 million (the payment of which was satisfied by AES Indiana in April 2021); a $5 million environmental mitigation project consisting of the construction and operation of a new, non-emitting source of generation at the site; expenditure of $0.325 million on a state-only environmentally beneficial project to preserve local, ecologically-significant lands; and retirement of Units 1 and 2 prior to July 1, 2023. If AES Indiana does not meet this retirement obligation, it must install a Selective Non-Catalytic Reduction System (SNCR) on Unit 4. AES Indiana previously had a contingent liability recorded related to these New Source Review 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, 2022, 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 $ 1,188.8 $ 323.3 $ 331.1 $ 232.4 $ 302.0 Other $ 422.4 349.1 59.5 8.8 5.0 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, 2022, 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 8, " Income Taxes "), (iv) pension and other postretirement employee benefit liabilities (see Note 9, " Benefit Plans ") and (v) contingencies (see Note 10, " Commitments and Contingencies "). See the indicated notes to the Financial Statements for additional information on the items excluded. 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. As of December 31, 2022 and 2021, total legal loss contingencies accrued were $0.1 million and $0.2 million, respectively, which primarily related to personal injury litigation. During 2021, AES Indiana entered into settlements resolving a significant portion of the legal loss contingencies previously accrued. The legal loss contingencies and settlement related accruals are included in "Accrued and other current liabilities" and " Other Non-Current Liabilities" on the accompanying Consolidated Balance Sheets. AES Indiana maintains an amount of insurance protection for such litigation that it believes is adequate. As of December 31, 2022 and 2021, AES Indiana has $0.0 million and $12.5 million, respectively, of receivables for insurance recoveries determined to be probable recorded in "Prepayments and other current assets" on the accompanying Consolidated Balance Sheets. While the ultimate outcome of outstanding litigation cannot be predicted with certainty, management believes that final outcomes will not have a material adverse effect on AES Indiana’s results of operations, financial condition and cash flows. 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. New Source Review and other CAA NOVs In October 2009, AES Indiana received a NOV and Finding of Violation from the EPA pursuant to the CAA Section 113(a). The NOV alleged violations of the CAA at AES Indiana’s three primarily coal-fired electric generating facilities at the time, dating back to 1986. The alleged violations primarily pertain to the PSD and non-attainment New Source Review (NSR) requirements under the CAA. In addition, on October 1, 2015, AES Indiana received a NOV from the EPA pursuant to CAA Section 113(a) alleging violations of the CAA, the Indiana SIP, and the Title V operating permit related to alleged particulate matter and opacity violations at AES Indiana Petersburg Unit 3. Also, on February 5, 2016, the EPA issued a NOV pursuant to CAA Section 113(a) alleging violations of PSD, non-attainment NSR and other CAA regulations, the Indiana SIP, and the Title V operating permit at Petersburg Generating Station. On August 31, 2020, AES Indiana reached a settlement with the EPA, the DOJ and IDEM resolving the purported violations of the CAA with respect to the coal-fired generation units at AES Indiana's Petersburg location. The settlement agreement, in the form of a proposed judicial consent decree was approved and entered by the U.S. District Court for the Southern District of Indiana on March 23, 2021, and includes, among other items, the following requirements: annual caps on NO x and SO 2 emissions and more stringent emissions limits than AES Indiana's current Title V air permit; payment of civil penalties totaling $1.525 million (the payment of which was satisfied by AES Indiana in April 2021); a $5 million environmental mitigation project consisting of the construction and operation of a new, non-emitting source of generation at the site; expenditure of $0.325 million on a state-only environmentally beneficial project to preserve local, ecologically-significant lands; and retirement of Units 1 and 2 prior to July 1, 2023. If AES Indiana does not meet this retirement obligation, it must install a Selective Non-Catalytic Reduction System (SNCR) on Unit 4. AES Indiana previously had a contingent liability recorded related to these New Source Review and other CAA NOV matters.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2022
Entity Information [Line Items]
Related Party Transactions	RELATED PARTY TRANSACTIONSAES 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 $9.5 million, $7.0 million, and $5.6 million in 2022, 2021 and 2020, respectively, and is recorded in “ Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations. As of December 31, 2022 and 2021, we had prepaid approximately $3.4 million and $2.3 million, respectively, for coverage under these plans, which is recorded in " Prepayments and other current assets " on the accompanying Consolidated Balance Sheets. AES Indiana participates in an agreement with Health and Welfare Benefit Plans LLC, an affiliate of AES, to participate in a group benefits program, including but not limited to, health, dental, vision and life benefits. Health and Welfare Benefit Plans LLC administers the financial aspects of the group insurance program, receives all premium payments from the participating affiliates, and makes all vendor payments. The cost of coverage under this program was approximately $25.2 million, $23.7 million, and $21.0 million in 2022, 2021 and 2020, 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, 2022 and 2021, 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 $18.0 million and $15.6 million as of December 31, 2022 and 2021, respectively, which is recorded in “ Taxes receivable” on the accompanying Consolidated Balance Sheets. See Note 8, " Income Taxes " for more information. Long-term Compensation Plan During 2022, 2021 and 2020, 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 2022, 2021 and 2020 was $0.2 million, $0.2 million and $0.3 million, respectively, and was included in “ Operating expenses - Operation and maintenance” on IPALCO’s Consolidated Statements of Operations. The value of these benefits is being recognized over the 36 month vesting period and a portion is recorded as miscellaneous deferred credits with the remainder recorded as “ Paid in capital” on IPALCO’s Consolidated Balance Sheets in accordance with ASC 718 “Compensation – Stock Compensation.” See also Note 9, “ Benefit Plans” to the Financial Statements for a description of benefits awarded to AES Indiana employees by AES under the RSP. Service Company Total costs incurred by the Service Company on behalf of IPALCO were $60.3 million, $58.4 million and $55.7 million during 2022, 2021 and 2020, respectively. Total costs incurred by IPALCO on behalf of the Service Company during 2022, 2021 and 2020 were $10.0 million, $10.4 million and $10.6 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. As of December 31, 2022, IPALCO had a prepaid balance with the Service Company of $2.1 million, which is recorded in " Prepayments and other current assets " on the accompanying Consolidated Balance Sheets. As of December 31, 2021, IPALCO had a payable balance with the Service Company of $5.9 million, which is recorded in “ Accounts payable” on the accompanying Consolidated Balance Sheets. Other Transactions with various other related parties were $5.7 million, $4.3 million and $6.5 million during 2022, 2021 and 2020, 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 TRANSACTIONSAES 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 $9.5 million, $7.0 million, and $5.6 million in 2022, 2021 and 2020, respectively, and is recorded in “ Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations. As of December 31, 2022 and 2021, AES Indiana had prepaid approximately $3.4 million and $2.3 million, respectively, for coverage under these plans, which is recorded in " Prepayments and other current assets " on the accompanying Consolidated Balance Sheets. AES Indiana participates in an agreement with Health and Welfare Benefit Plans LLC, an affiliate of AES, to participate in a group benefits program, including but not limited to, health, dental, vision and life benefits. Health and Welfare Benefit Plans LLC administers the financial aspects of the group insurance program, receives all premium payments from the participating affiliates, and makes all vendor payments. The cost of coverage under this program was approximately $25.2 million, $23.7 million, and $21.0 million in 2022, 2021 and 2020, 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, 2022 and 2021, respectively. AES files federal and state income tax returns which consolidate IPALCO and its subsidiaries, including AES Indiana. Under a tax sharing agreement with IPALCO, AES Indiana is responsible for the income taxes associated with its own taxable income and records the provision for income taxes using a separate return method. AES Indiana had a receivable balance under this agreement of $6.7 million and $6.7 million as of December 31, 2022 and 2021, respectively, which is recorded in “ Taxes receivable” on the accompanying Consolidated Balance Sheets. See Note 8, " Income Taxes " for more information. Long-term Compensation Plan During 2022, 2021 and 2020, 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 2022, 2021 and 2020 was $0.2 million, $0.2 million and $0.3 million, respectively, and was included in “ Operating expenses - Operation and maintenance” on AES Indiana’s Consolidated Statements of Operations. The value of these benefits is being recognized over the 36 month vesting period and a portion is recorded as miscellaneous deferred credits with the remainder recorded as “ Paid in capital” on AES Indiana’s Consolidated Balance Sheets in accordance with ASC 718 “Compensation – Stock Compensation.” See also Note 9, “Benefit Plans” to the audited consolidated financial statements of AES Indiana for a description of benefits awarded to AES Indiana employees by AES under the RSP. Service Company Total costs incurred by the Service Company on behalf of AES Indiana were $60.1 million, $58.2 million and $55.5 million during 2022, 2021 and 2020, respectively. Total costs incurred by AES Indiana on behalf of the Service Company during 2022, 2021 and 2020 were $10.0 million, $10.4 million and $10.6 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. As of December 31, 2022, AES Indiana had a prepaid balance with the Service Company of $2.1 million, which is recorded in " Prepayments and other current assets " on the accompanying Consolidated Balance Sheets. As of December 31, 2021, AES Indiana had a payable balance with the Service Company of $5.9 million, which is recorded in “ Accounts payable” on the accompanying Consolidated Balance Sheets. Other During the year ended December 31, 2021, AES Indiana received loan repayments of $6.1 million from IPALCO. During the year ended December 31, 2020, AES Indiana made loans to IPALCO, net of repayments, of $6.1 million. Additionally, transactions with various other related parties were $5.7 million, $4.3 million and $6.5 million during 2022, 2021 and 2020, 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, 2022	Dec. 31, 2019
Entity Information [Line Items]
Business Segment Information		BUSINESS SEGMENT INFORMATION 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 “All 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): 2022 2021 2020 Utility All Other Total Utility All Other Total Utility All Other Total Revenues $ 1,791,711 $ — $ 1,791,711 $ 1,426,132 $ — $ 1,426,132 $ 1,352,985 $ — $ 1,352,985 Depreciation and amortization $ 266,504 $ — $ 266,504 $ 256,085 $ — $ 256,085 $ 246,896 $ — $ 246,896 Interest expense $ 87,428 $ 43,804 $ 131,232 $ 84,256 $ 41,370 $ 125,626 $ 87,281 $ 42,212 $ 129,493 Income/(loss) from operations before income tax $ 162,862 $ (44,377) $ 118,485 $ 189,548 $ (41,425) $ 148,123 $ 184,174 $ (45,615) $ 138,559 Capital expenditures (1) $ 496,510 $ — $ 496,510 $ 291,546 $ — $ 291,546 $ 235,736 $ — $ 235,736 (1) Capital expenditures includes $0 thousand, $36 thousand and $36 thousand of payments for financed capital expenditures in 2022, 2021 and 2020, respectively. As of December 31, 2022 As of December 31, 2021 As of December 31, 2020 Total assets $ 5,559,977 $ 29,237 $ 5,589,214 $ 5,222,987 $ 16,780 $ 5,239,767 $ 4,952,408 $ 17,511 $ 4,969,919
Indianapolis Power And Light Company
Entity Information [Line Items]
Business Segment Information	BUSINESS SEGMENT INFORMATIONOperating segments are components of an enterprise that engage in business activities from which it may earn revenues and incur expenses, for which separate financial information is available, and is evaluated regularly by the chief operating decision maker in assessing performance and deciding how to allocate resources. All of AES Indiana’s current business consists of the generation, transmission, distribution and sale of electric energy, and therefore AES Indiana had only one reportable segment.

Revenue

Revenue	12 Months Ended
	Dec. 31, 2022
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer [Text Block]	REVENUES Revenues are primarily earned from retail and wholesale electricity sales and electricity transmission and distribution delivery services. Revenues are 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. Revenues are recorded net of any taxes assessed on and collected from customers, which are remitted to the governmental authorities. Retail revenues - AES Indiana energy sales to utility customers are based on the reading of meters at the customer’s location that occurs on a systematic basis throughout the month. AES Indiana sells electricity directly to end-users, such as homes and businesses, and bills customers directly. Retail revenues have a single performance obligation, as the promise to transfer energy and other distribution and/or transmission services are not separately identifiable from other promises in the contracts and, therefore, are not distinct. Additionally, as the performance obligation is satisfied over time as energy is delivered, and the same method is used to measure progress, the performance obligation meets the criteria to be considered a series. In exchange for the exclusive right to sell or distribute electricity in our service area, AES Indiana is subject to rate regulation by federal and state regulators. This regulation sets the framework for the prices (“tariffs”) that AES Indiana is allowed to charge customers for electric services. Since tariffs are approved by the regulator, the price that AES Indiana has the right to bill corresponds directly with the value to the customer of AES Indiana’s performance completed in each period. Therefore, revenues under these contracts are recognized using an output method measured by the MWhs delivered each month at the approved tariff. Customer payments are typically due on a monthly basis, though see Note 2, " Regulatory Matters - IURC COVID-19 Orders " for a discussion of the orders requiring expanded payment arrangements for customers. Wholesale revenues - Power produced at the generation stations in excess of our retail load is sold into the MISO market. Such sales are made at either the day-ahead or real-time hourly market price, and these sales are classified as wholesale revenues. We sell to and purchase power from MISO, and such sales and purchases are settled and accounted for on a net hourly basis. In the MISO market, wholesale revenues are recorded at the spot price based on the quantities of MWh delivered in each hour during each month. As a member of MISO, we are obligated to declare the availability of our energy production into the wholesale energy market, but we are not obligated to commit our previously declared availability. As such, contract terms end as the energy for each day is delivered to the market in the case of the day-ahead market and for each hour in the case of the real-time market. Miscellaneous revenues - Miscellaneous revenues are mainly comprised of MISO transmission revenues and capacity revenues. MISO transmission revenues are earned when AES Indiana’s power lines are used in transmission of energy by power producers other than AES Indiana. As AES Indiana owns and operates transmission lines in central and southern Indiana, demand charges collected from network customers by MISO are allocated to the appropriate transmission owners (including AES Indiana) and recognized as transmission revenues. Capacity revenues are also included in miscellaneous revenues, 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 revenues 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 revenues, 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 revenues, 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 revenues from contracts with customers was $1,760.0 million, $1,389.2 million and $1,326.6 million for the years ended December 31, 2022 , 2021 and 2020, respectively. The following table presents our revenues from contracts with customers and other revenues (in thousands): For the Years Ended December 31, 2022 2021 2020 Retail Revenues Retail revenues from contracts with customers: Residential $ 688,487 $ 595,692 $ 566,668 Small commercial and industrial 247,655 211,997 194,904 Large commercial and industrial 625,351 518,069 484,230 Public lighting 9,832 8,888 9,115 Other (1) 17,845 16,785 14,402 Total retail revenues from contracts with customers 1,589,170 1,351,431 1,269,319 Alternative revenues programs 29,171 35,248 24,781 Wholesale Revenues Wholesale revenues from contracts with customers 148,517 25,059 46,482 Miscellaneous Revenues Capacity revenues 11,750 734 1,477 Transmission and other revenues 10,534 11,480 9,317 Total miscellaneous revenues from contracts with customers 22,284 12,214 10,794 Other miscellaneous revenues (2) 2,569 2,180 1,609 Total Revenues $ 1,791,711 $ 1,426,132 $ 1,352,985 (1) Other retail revenues from contracts with customers includes miscellaneous charges to customers, including reconnection and late fee charges. (2) Other miscellaneous revenues includes lease and other miscellaneous revenues not accounted for under ASC 606. The balances of receivables from contracts with customers were $198.3 million and $163.0 million as of December 31, 2022 and 2021, 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 revenues 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 revenues based on the amount we have the right to invoice for services performed, and contracts with variable consideration allocated entirely to a wholly unsatisfied performance obligation when the consideration relates specifically to our efforts to satisfy the performance obligation and depicts the amount to which we expect to be entitled. Contract Balances — The timing of revenue recognition, billings, and cash collections results in accounts receivable and contract liabilities. There were no contract liabilities from contracts with customers as of December 31, 2022 and 2021, respectively. During the years ended December 31, 2022 and 2021, we recognized revenues of $0.0 million and $0.5 million, respectively, that was included in the corresponding contract liability balance at the beginning of the periods.
Indianapolis Power And Light Company
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer [Text Block]	Revenues are primarily earned from retail and wholesale electricity sales and electricity transmission and distribution delivery services. Revenues are 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. Revenues are recorded net of any taxes assessed on and collected from customers, which are remitted to the governmental authorities. Retail revenues - AES Indiana energy sales to utility customers are based on the reading of meters at the customer’s location that occurs on a systematic basis throughout the month. AES Indiana sells electricity directly to end-users, such as homes and businesses, and bills customers directly. Retail revenues have a single performance obligation, as the promise to transfer energy and other distribution and/or transmission services are not separately identifiable from other promises in the contracts and, therefore, are not distinct. Additionally, as the performance obligation is satisfied over time as energy is delivered, and the same method is used to measure progress, the performance obligation meets the criteria to be considered a series. In exchange for the exclusive right to sell or distribute electricity in our service area, AES Indiana is subject to rate regulation by federal and state regulators. This regulation sets the framework for the prices (“tariffs”) that AES Indiana is allowed to charge customers for electric services. Since tariffs are approved by the regulator, the price that AES Indiana has the right to bill corresponds directly with the value to the customer of AES Indiana’s performance completed in each period. Therefore, revenues under these contracts are recognized using an output method measured by the MWhs delivered each month at the approved tariff. Customer payments are typically due on a monthly basis, though see Note 2, " Regulatory Matters - IURC COVID-19 Orders " for a discussion of the orders requiring expanded payment arrangements for customers. Wholesale revenues - Power produced at the generation stations in excess of our retail load is sold into the MISO market. Such sales are made at either the day-ahead or real-time hourly market price, and these sales are classified as wholesale revenues. We sell to and purchase power from MISO, and such sales and purchases are settled and accounted for on a net hourly basis. In the MISO market, wholesale revenues are recorded at the spot price based on the quantities of MWh delivered in each hour during each month. As a member of MISO, we are obligated to declare the availability of our energy production into the wholesale energy market, but we are not obligated to commit our previously declared availability. As such, contract terms end as the energy for each day is delivered to the market in the case of the day-ahead market and for each hour in the case of the real-time market. Miscellaneous revenues - Miscellaneous revenues are mainly comprised of MISO transmission revenues and capacity revenues. MISO transmission revenues are earned when AES Indiana’s power lines are used in transmission of energy by power producers other than AES Indiana. As AES Indiana owns and operates transmission lines in central and southern Indiana, demand charges collected from network customers by MISO are allocated to the appropriate transmission owners (including AES Indiana) and recognized as transmission revenues. Capacity revenues are also included in miscellaneous revenues, 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 revenues 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 revenues, 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 revenues, 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 revenues from contracts with customers was $1,760.0 million , $1,389.2 million and $1,326.6 million for the years ended December 31, 2022 , 2021 and 2020, respectively. The following table presents AES Indiana's revenues from contracts with customers and other revenues (in thousands): For the Years Ended December 31, 2022 2021 2020 Retail Revenues Retail revenues from contracts with customers: Residential $ 688,487 $ 595,692 $ 566,668 Small commercial and industrial 247,655 211,997 194,904 Large commercial and industrial 625,351 518,069 484,230 Public lighting 9,832 8,888 9,115 Other (1) 17,845 16,785 14,402 Total retail revenues from contracts with customers 1,589,170 1,351,431 1,269,319 Alternative revenues programs 29,171 35,248 24,781 Wholesale Revenues Wholesale revenues from contracts with customers 148,517 25,059 46,482 Miscellaneous Revenues Capacity revenues 11,750 734 1,477 Transmission and other revenues 10,534 11,480 9,317 Total miscellaneous revenues from contracts with customers 22,284 12,214 10,794 Other miscellaneous revenues (2) 2,569 2,180 1,609 Total Revenues $ 1,791,711 $ 1,426,132 $ 1,352,985 (1) Other retail revenues from contracts with customers includes miscellaneous charges to customers, including reconnection and late fee charges. (2) Other miscellaneous revenues includes lease and other miscellaneous revenues not accounted for under ASC 606. The balances of receivables from contracts with customers were $198.3 million and $163.0 million as of December 31, 2022 and 2021, 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 revenues 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 revenues based on the amount we have the right to invoice for services performed, and contracts with variable consideration allocated entirely to a wholly unsatisfied performance obligation when the consideration relates specifically to our efforts to satisfy the performance obligation and depicts the amount to which AES Indiana expects to be entitled. Contract Balances — The timing of revenue recognition, billings, and cash collections results in accounts receivable and contract liabilities. There were no contract liabilities from contracts with customers as of December 31, 2022 and 2021, respectively. During the years ended December 31, 2022 and 2021, we recognized revenues of

Leases

Leases	12 Months Ended
	Dec. 31, 2022
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, 2022 December 31, 2021 Assets Right-of-use assets — finance leases Other non-current assets $ 15,819 $ 19,763 Liabilities Finance lease liabilities (current) Short-term debt — 294 Finance lease liabilities (noncurrent) Long-term debt 16,361 19,469 Total finance lease liabilities $ 16,361 $ 19,763 The following table summarizes supplemental balance sheet information related to leases as of the periods indicated: Lease Term and Discount Rate December 31, 2022 December 31, 2021 Weighted-average remaining lease term — finance leases 36 years 31 years Weighted-average discount rate — finance leases 5.650 % 4.561% 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, 2022 , 2021 and 2020, respectively (in thousands): For the Year Ended December 31, Components of Lease Cost 2022 2021 2020 Finance lease cost: Amortization of right- of-use assets $ 542 $ — $ — Interest on lease liabilities 782 — — Total lease cost $ 1,324 $ — $ — Operating cash outflows from finance leases were $0.3 million, $0.0 million and $0.0 million for the years ended December 31, 2022 , 2021 and 2020, 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, 2022 for 2023 through 2027 and thereafter (in thousands): Finance Leases 2023 $ 802 2024 818 2025 834 2026 851 2027 868 Thereafter 37,546 Total $ 41,719 Less: Imputed interest (25,358) Present value of lease payments $ 16,361 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 revenues on a straight-line basis over the lease term whereas contingent rentals are recognized when earned. The following table presents lease revenues from operating leases in which the Company is the lessor for the periods indicated (in thousands): For the Year Ended December 31, 2022 2021 2020 Total lease revenues $ 1,134 $ 1,439 $ 941 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, 2022 December 31, 2021 Gross assets $ 4,334 $ 4,403 Less: Accumulated depreciation (1,060) (979) Net assets $ 3,274 $ 3,424 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 2027 and thereafter (in thousands): Operating Leases 2023 $ 544 2024 544 2025 553 2026 554 2027 554 Thereafter 1,245 Total $ 3,994
Future Minimum Lease Receipts	The following table shows the future minimum lease receipts through 2027 and thereafter (in thousands): Operating Leases 2023 $ 544 2024 544 2025 553 2026 554 2027 554 Thereafter 1,245 Total $ 3,994
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, 2022 December 31, 2021 Assets Right-of-use assets — finance leases Other non-current assets $ 15,819 $ 19,763 Liabilities Finance lease liabilities (current) Short-term debt — 294 Finance lease liabilities (noncurrent) Long-term debt 16,361 19,469 Total finance lease liabilities $ 16,361 $ 19,763 The following table summarizes supplemental balance sheet information related to leases as of the periods indicated: Lease Term and Discount Rate December 31, 2022 December 31, 2021 Weighted-average remaining lease term — finance leases 36 years 31 years Weighted-average discount rate — finance leases 5.650% 4.561% 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, 2022 , 2021 and 2020, respectively (in thousands): For the Year Ended December 31, Components of Lease Cost 2022 2021 2020 Finance lease cost: Amortization of right- of-use assets $ 542 $ — $ — Interest on lease liabilities 782 — — Total lease cost $ 1,324 $ — $ — Operating cash outflows from finance leases were $0.3 million, $0.0 million and $0.0 million for the years ended December 31, 2022 , 2021 and 2020, 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, 2022 for 2023 through 2027 and thereafter (in thousands): Finance Leases 2023 $ 802 2024 818 2025 834 2026 851 2027 868 Thereafter 37,546 Total $ 41,719 Less: Imputed interest (25,358) Present value of lease payments $ 16,361 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 revenues on a straight-line basis over the lease term whereas contingent rentals are recognized when earned. The following table presents lease revenues from operating leases in which the Company is the lessor for the periods indicated (in thousands): For the Year Ended December 31, 2022 2021 2020 Total lease revenues $ 1,134 $ 1,439 $ 941 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, 2022 December 31, 2021 Gross assets $ 4,334 $ 4,403 Less: Accumulated depreciation (1,060) (979) Net assets $ 3,274 $ 3,424 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 2027 and thereafter (in thousands): Operating Leases 2023 $ 544 2024 544 2025 553 2026 554 2027 554 Thereafter 1,245 Total $ 3,994
Future Minimum Lease Receipts	The following table shows the future minimum lease receipts through 2027 and thereafter (in thousands): Operating Leases 2023 $ 544 2024 544 2025 553 2026 554 2027 554 Thereafter 1,245 Total $ 3,994

Risks and Uncertainties

Risks and Uncertainties	12 Months Ended
	Dec. 31, 2022
Entity Information [Line Items]
Risks and Uncertainties	RISKS AND UNCERTAINTIES COVID-19 Pandemic The COVID-19 pandemic has impacted global economic activity, including electricity and energy consumption, and caused significant volatility in financial markets. We continue to take a variety of measures in response to the spread of COVID-19 to ensure our ability to generate, transmit, distribute and sell electric energy, ensure the health and safety of our employees, contractors, customers and communities and provide essential services to the
Subsidiaries [Member]
Entity Information [Line Items]
Risks and Uncertainties	RISKS AND UNCERTAINTIES COVID-19 Pandemic The COVID-19 pandemic has impacted global economic activity, including electricity and energy consumption, and caused significant volatility in financial markets. We continue to take a variety of measures in response to the spread of COVID-19 to ensure our ability to generate, transmit, distribute and sell electric energy, ensure the health and safety of our employees, contractors, customers and communities and provide essential services to the communities in which we operate. The magnitude and duration of the COVID-19 pandemic is unknown at this time and may have material and adverse effects on our results of operations, financial condition and cash flows in future periods.

Schedule I - Condensed Financia

Schedule I - Condensed Financial Information Of Registrant	12 Months Ended
	Dec. 31, 2022
Condensed Financial Information Disclosure [Abstract]
Schedule I - Condensed Financial Information Of Registrant	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIESAccounting for Subsidiaries and Affiliates – IPALCO has accounted for the earnings of its subsidiaries on the equity method in the unconsolidated condensed financial information.FAIR VALUE The fair value of current financial assets and liabilities approximate their reported carrying amounts. The estimated fair values of the Company’s assets and liabilities have been determined using available market information. Because these amounts are estimates and based on hypothetical transactions to sell assets or transfer liabilities, the use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts. Fair Value Hierarchy and Valuation Techniques ASC 820 defined and established a framework for measuring fair value and expands disclosures about fair value measurements for financial assets and liabilities that are adjusted to fair value on a recurring basis and/or financial assets and liabilities that are measured at fair value on a nonrecurring basis, which have been adjusted to fair value during the period. In accordance with ASC 820, we have categorized our financial assets and liabilities that are adjusted to fair value, based on the priority of the inputs to the valuation technique, following the three-level fair value hierarchy prescribed by ASC 820 as follows: Level 1 - unadjusted quoted prices for identical assets or liabilities in an active market; Level 2 - inputs from quoted prices in markets where trading occurs infrequently or quoted prices of instruments with similar attributes in active markets; and Level 3 - unobservable inputs reflecting management’s own assumptions about the inputs used in pricing the asset or liability. Whenever possible, quoted prices in active markets are used to determine the fair value of our financial instruments. Our financial instruments are not held for trading or other speculative purposes. The estimated fair value of financial instruments has been determined by using available market information and appropriate valuation methodologies. However, considerable judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we could realize in a current market exchange. The use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts. Financial Assets VEBA Assets IPALCO has VEBA investments that are to be used to fund certain employee postretirement health care benefit plans. These assets are primarily comprised of open-ended mutual funds, which are valued using the net assets value per unit. These investments are recorded at fair value within " Other non-current assets " on the accompanying Unconsolidated Balance Sheets and classified as equity securities. All changes to fair value on the VEBA investments are included in income in the period that the changes occur. These changes to fair value were not material for the years ended December 31, 2022, 2021, or 2020. Any unrealized gains or losses are recorded in " Other income / (expense), net " on the accompanying Unconsolidated Statements of Operations. Financial Liabilities 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 / (AOCL). See also Note 3, " Derivative Instruments and Hedging Activities - Cash Flow Hedges " for further information. Summary The fair value of assets and liabilities at December 31, 2022 and 2021 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, 2022 Fair Value as of December 31, 2021 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total (In Thousands) Financial assets: VEBA investments: Money market funds $ 5 $ — $ — $ 5 $ 11 $ — $ — $ 11 Mutual funds 3,223 — — 3,223 — 3,594 — 3,594 Total VEBA investments 3,228 — — 3,228 11 3,594 — 3,605 Interest rate hedges — 12,172 — 12,172 — — — — Total financial assets measured at fair value $ 3,228 $ 12,172 $ — $ 15,400 $ 11 $ 3,594 $ — $ 3,605 Financial liabilities: Interest rate hedges $ — $ — $ — $ — $ — $ 49,382 $ — $ 49,382 Total financial liabilities measured at fair value $ — $ — $ — $ — $ — $ 49,382 $ — $ 49,382 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 and variable-rate indebtedness (Level 2) for the periods ending: December 31, 2022 December 31, 2021 Face Value Fair Value Face Value Fair Value (In Thousands) Fixed-rate $ 880,000 $ 816,411 $ 880,000 $ 946,346 Variable-rate — — — — Total indebtedness $ 880,000 $ 816,411 $ 880,000 $ 946,346 The difference between the face value and the carrying value of this indebtedness represents the following: • unamortized deferred financing costs of $5.9 million and $7.3 million at December 31, 2022 and 2021, respectively; and • unamortized discounts of $0.4 million and $0.5 million at December 31, 2022 and 2021, 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, 2022 , 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) 2022 2021 2020 Beginning accumulated derivative gain / (loss) in AOCL $ (29,407) $ (43,420) $ (19,750) Net gains / (losses) associated with current period hedging transactions 46,245 10,393 (27,779) Net losses reclassified to interest expense, net of tax 5,431 3,620 4,109 Ending accumulated derivative gain / (loss) in AOCI / (AOCL) $ 22,269 $ (29,407) $ (43,420) 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) 21 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, 2022 and 2021, 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 2022 2021 Interest rate hedges Cash Flow Hedge Derivative assets, non-current $ 12,172 $ — Interest rate hedges Cash Flow Hedge Derivative liabilities, non-current $ — $ 49,382 The following table presents IPALCO’s long-term indebtedness: December 31, Series Due 2022 2021 (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 (425) (527) Deferred financing costs – net (5,912) (7,319) Total long-term debt 873,663 872,154 Less: current portion of long-term debt — — Net long-term debt $ 873,663 $ 872,154 IPALCO’s Senior Secured Notes and Term Loan In April 2020, IPALCO completed the sale of $475 million aggregate principal amount of 4.25% 2030 IPALCO Notes pursuant to Rule 144A and Regulation S under the Securities Act of 1933, as amended. We used the net proceeds from this offering to retire the $65 million Term Loan on April 14, 2020. The remaining net proceeds, together with cash on hand, were used to redeem the 2020 IPALCO Notes on May 14, 2020, and to pay certain related fees, expenses and make-whole premiums. A loss on early extinguishment of debt of $2.4 million for the 2020 IPALCO Notes is included as a separate line item within " Other Income/(Expense), Net " in the accompanying Unconsolidated Statements of Operations. Pursuant to a registration rights agreement dated April 14, 2020, IPALCO agreed to register the 2030 IPALCO Notes under the Securities Act by filing an exchange offer registration statement or, under specified circumstances, a shelf registration statement with the SEC. IPALCO filed a registration statement on Form S-4 with respect to the 2030 IPALCO Notes with the SEC on March 22, 2021 in respect of its obligations under such registration rights agreement, and this registration statement was declared effective on April 7, 2021. The exchange offer closed on May 11, 2021.

Schedule II - Valuation And Qua

Schedule II - Valuation And Qualifying Accounts And Reserves	12 Months Ended
	Dec. 31, 2019
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, 2022, 2021 and 2020 (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, 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 Year ended December 31, 2020 Accumulated Provisions Deducted from Assets – Doubtful Accounts $ 2,053 $ 5,861 $ (1,132) $ 3,627 $ 3,155 Deducted from Inventories Valuation Allowance for Materials and Supplies $ 6,204 $ — $ — $ 71 $ 6,133 AES INDIANA and SUBSIDIARIES Valuation and Qualifying Accounts and Reserves For the Years Ended December 31, 2022, 2021 and 2020 (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, 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 Year ended December 31, 2020 Accumulated Provisions Deducted from Assets – Doubtful Accounts $ 2,053 $ 5,861 $ (1,132) $ 3,627 $ 3,155 Deducted from Inventories Valuation Allowance for Materials and Supplies $ 6,204 $ — $ — $ 71 $ 6,133

Overview and Summary of Signi_2

Overview and Summary of Significant Accounting Policies (Policy)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2019
Entity Information [Line Items]
Property, Plant and Equipment, Policy [Policy Text Block]	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 3.8%, 3.7% and 3.7% during 2022, 2021 and 2020, respectively. Depreciation expense was $247.5 million, $239.1 million, and $232.8 million for the years ended December 31, 2022, 2021 and 2020, 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, 2022 2021 (In Thousands) Accounts receivable, net Customer receivables $ 125,540 $ 100,952 Unbilled revenues 74,488 64,758 Amounts due from related parties 239 169 Other 17,373 13,904 Allowance for credit losses (1,117) (647) Total accounts receivable, net $ 216,523 $ 179,136
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, 2022 2021 (In Thousands) Inventories Fuel $ 60,497 $ 41,626 Materials and supplies, net 63,111 60,273 Total inventories $ 123,608 $ 101,899
Intangible Assets, Finite-Lived, Policy [Policy Text Block]	Intangible Assets Finite-lived intangible assets include capitalized software and project development intangible assets amortized over their useful lives. Capitalized software of $205.9 million and $162.0 million and its corresponding accumulated amortization of $107.2 million and $95.8 million is recorded as of December 31, 2022 and 2021, respectively. Amortization expense for capitalized software was $10.1 million, $11.2 million and $10.6 million for the years ended December 31, 2022, 2021 and 2020, respectively. These capitalized software intangible assets have a 7 year-weighted average amortization period and the estimated amortization expense is approximately $30.7 million over the next 5 years ($9.8 million in 2023, $5.3 million in 2024, $5.2 million in 2025, $5.2 million in 2026 and $5.2 million in 2027). Project development intangible assets were $39.5 million as of December 31, 2022 and 2021. These project development intangible assets have a 30 year-weighted average amortization period and the estimated amortization expense is approximately $4.9 million over the next 5 years ($0.0 million in 2023, $1.0 million in 2024, $1.3 million in 2025, $1.3 million in 2026 and $1.3 million in 2027).
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. All intercompany items have been eliminated in consolidation. Certain costs for shared resources amongst AES Indiana and IPALCO, such as labor and benefits, are allocated to each entity based on allocation methodologies that management believes to be reasonable. We have evaluated subsequent events through the date this report is issued.
Use of Management Estimates	Use of Management Estimates The preparation of financial statements in conformity with GAAP requires that management make certain estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements. The reported amounts of revenues and expenses during the reporting period may also be affected by the estimates and assumptions management is required to make. Actual results may differ from those estimates. Significant items subject to such estimates and assumptions include: recognition of revenue including unbilled revenues; 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.
Regulation	Regulatory Accounting The retail utility operations of AES Indiana are subject to the jurisdiction of the IURC. AES Indiana’s wholesale power transactions are subject to the jurisdiction of the FERC. These agencies regulate AES Indiana’s utility business operations, tariffs, accounting, depreciation allowances, services, issuances of securities and the sale and acquisition of utility properties. The financial statements of AES Indiana are based on GAAP, including the provisions of FASB ASC 980 “Regulated Operations,” which gives recognition to the ratemaking and accounting practices of these agencies. See also Note 2, “Regulatory Matters - Regulatory Assets and Liabilities” for a discussion of specific regulatory assets and liabilities.
Cash 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, 2022 2021 (In Thousands) Cash, cash equivalents and restricted cash Cash and cash equivalents $ 201,548 $ 6,912 Restricted cash (included in Prepayments and other current assets) 5 5 Total cash, cash equivalents and restricted cash $ 201,553 $ 6,917
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, 2022 2021 (In Thousands) Accounts receivable, net Customer receivables $ 125,540 $ 100,952 Unbilled revenues 74,488 64,758 Amounts due from related parties 239 169 Other 17,373 13,904 Allowance for credit losses (1,117) (647) Total accounts receivable, net $ 216,523 $ 179,136
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 AES Indiana’s actual environmental and/or legal obligations are different from our estimates, the recognition of the actual amounts may have a material impact on our results of operations, financial condition and cash flows; although that has not been the case during the periods covered by this report. As of December 31, 2022 and 2021, total loss contingencies accrued were $0.1 million and $0.2 million, respectively, which were included in “Accrued and Other Current Liabilities” and " Other Non-Current Liabilities
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 two suppliers, and substantially all of AES Indiana's coal is currently mined in the state of Indiana.
Allowance For Funds Used During Construction		Allowance For Funds Used During ConstructionIn accordance with the Uniform System of Accounts prescribed by FERC, AES Indiana capitalizes an allowance for the net cost of funds (interest on borrowed funds and a reasonable rate of return on equity funds) used for construction purposes during the period of construction with a corresponding credit to income. AES Indiana capitalized amounts using pretax composite rates of 5.4%, 5.7% and 6.9% during 2022, 2021 and 2020, respectively.
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. 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 $4.0 billion and $4.0 billion as of December 31, 2022 and 2021, respectively. As of December 31, 2022 and 2021, AES Indiana had $287.5 million and $300.1 million, respectively, of long-term regulatory assets associated with the Petersburg Unit 1 retirement and the probable Petersburg Unit 2 retirement (for further discussion, see Note 2, “Regulatory Matters - IRP 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.
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 9, " Benefit Plans " for more information.
Revenue Recognition, Revenue Reductions	Revenue Recognition Revenues related to the sale of energy are generally recognized when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to certain customers since the date of the last meter reading are estimated and the corresponding unbilled revenues is accrued. In making its estimates of unbilled revenues, AES Indiana uses complex models that consider various factors including daily generation volumes; known amounts of energy usage by nearly all residential, commercial and industrial customers; estimated line losses; and estimated customer rates based on prior period billings. Given the use of these models, and that customers are billed on a monthly cycle, we believe it is unlikely that materially different results will occur in future periods when revenue is billed. The effect on 2022 revenues and ending unbilled revenues of a one percentage point change in estimated line losses for the month of December 2022 is immaterial. An allowance for potential credit losses is maintained and amounts are written off when normal collection efforts have been exhausted. Our provision for expected credit losses included in “Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations was $5.9 million, $3.0 million and $4.8 million for the years ended December 31, 2022, 2021 and 2020, 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, " Revenues " for additional information of MISO sales and other revenue streams.
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 3.8%, 3.7% and 3.7% during 2022, 2021 and 2020, respectively. Depreciation expense was $247.5 million, $239.1 million, and $232.8 million for the years ended December 31, 2022, 2021 and 2020, 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, 2022 2021 (In Thousands) Accounts receivable, net Customer receivables $ 125,540 $ 100,952 Unbilled revenues 74,488 64,758 Amounts due from related parties 288 214 Other 17,373 13,904 Allowance for credit losses (1,117) (647) Total accounts receivable, net $ 216,572 $ 179,181
Intangible Assets, Finite-Lived, Policy [Policy Text Block]	Intangible Assets Finite-lived intangible assets include capitalized software and project development intangible assets amortized over their useful lives. Capitalized software of $205.9 million and $162.0 million and its corresponding accumulated amortization of $107.2 million and $95.8 million is recorded as of December 31, 2022 and 2021, respectively. Amortization expense for capitalized software was $10.1 million, $11.2 million and $10.6 million for the years ended December 31, 2022, 2021 and 2020, respectively. These capitalized software intangible assets have a 7 year-weighted average amortization period and the estimated amortization expense is approximately $30.7 million over the next 5 years ($9.8 million in 2023, $5.3 million in 2024, $5.2 million in 2025, $5.2 million in 2026 and $5.2 million in 2027). Project development intangible assets were $39.5 million as of December 31, 2022 and 2021. These project development intangible assets have a 30 year-weighted average amortization period and the estimated amortization expense is approximately $4.9 million over the next 5 years ($0.0 million in 2023, $1.0 million in 2024, $1.3 million in 2025, $1.3 million in 2026 and $1.3 million in 2027).
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 AES Indiana Devco Holdings 1, LLC and AES Indiana Devco Holdings 2, LLC (these entities were formed on November 18, 2020 and May 27, 2021, respectively, related to the replacement generation project for retired Petersburg units) . All intercompany items have been eliminated in consolidation. Certain costs for shared resources amongst AES Indiana and IPALCO, such as labor and benefits, are allocated to each entity based on allocation methodologies that management believes to be reasonable. We have evaluated subsequent events through the date this report is issued.
Use of Management Estimates	Use of Management Estimates The preparation of financial statements in conformity with GAAP requires that management make certain estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements. The reported amounts of revenues and expenses during the reporting period may also be affected by the estimates and assumptions management is required to make. Actual results may differ from those estimates. Significant items subject to such estimates and assumptions include: recognition of revenues including unbilled revenues; 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.
Regulation	Regulatory Accounting The retail utility operations of AES Indiana are subject to the jurisdiction of the IURC. AES Indiana’s wholesale power transactions are subject to the jurisdiction of the FERC. These agencies regulate AES Indiana’s utility business operations, tariffs, accounting, depreciation allowances, services, issuances of securities and the sale and acquisition of utility properties. The financial statements of AES Indiana are based on GAAP, including the provisions of FASB ASC 980 “Regulated Operations,” which gives recognition to the ratemaking and accounting practices of these agencies. See also Note 2, “Regulatory Matters - Regulatory Assets and Liabilities” for a discussion of specific regulatory assets and liabilities.
Cash 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, 2022 2021 (In Thousands) Cash, cash equivalents and restricted cash Cash and cash equivalents $ 199,103 $ 2,756 Restricted cash (included in Prepayments and other current assets) 5 5 Total cash, cash equivalents and restricted cash $ 199,108 $ 2,761
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, 2022 2021 (In Thousands) Accounts receivable, net Customer receivables $ 125,540 $ 100,952 Unbilled revenues 74,488 64,758 Amounts due from related parties 288 214 Other 17,373 13,904 Allowance for credit losses (1,117) (647) Total accounts receivable, net $ 216,572 $ 179,181
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. As of December 31, 2022 and 2021, total loss contingencies accrued were $0.1 million and $0.2 million, respectively, which were included in “ Accrued and Other Current Liabilities” and " Other Non-Current Liabilities ", respectively, on the accompanying Consolidated Balance Sheets.
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 two suppliers, and substantially all of AES Indiana's coal is currently mined in the state of Indiana.
Allowance For Funds Used During Construction	Allowance For Funds Used During ConstructionIn accordance with the Uniform System of Accounts prescribed by FERC, AES Indiana capitalizes an allowance for the net cost of funds (interest on borrowed funds and a reasonable rate of return on equity funds) used for construction purposes during the period of construction with a corresponding credit to income. AES Indiana capitalized amounts using pretax composite rates of 5.4%, 5.7% and 6.9% during 2022, 2021 and 2020, respectively.
Derivatives	Derivatives
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 $4.0 billion and $4.0 billion as of December 31, 2022 and 2021, respectively. As of December 31, 2022 and 2021, AES Indiana had $287.5 million and $300.1 million, respectively, of long-term regulatory assets associated with the Petersburg Unit 1 retirement and the probable Petersburg Unit 2 retirement (for further discussion, see Note 2, “Regulatory Matters - IRP 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, 2022	Dec. 31, 2021	Dec. 31, 2019
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, 2022 2021 (In Thousands) Inventories Fuel $ 60,497 $ 41,626 Materials and supplies, net 63,111 60,273 Total inventories $ 123,608 $ 101,899
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, 2022 2021 (In Thousands) Accounts receivable, net Customer receivables $ 125,540 $ 100,952 Unbilled revenues 74,488 64,758 Amounts due from related parties 239 169 Other 17,373 13,904 Allowance for credit losses (1,117) (647) Total accounts receivable, net $ 216,523 $ 179,136
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, 2022 2021 (In Thousands) Cash, cash equivalents and restricted cash Cash and cash equivalents $ 201,548 $ 6,912 Restricted cash (included in Prepayments and other current assets) 5 5 Total cash, cash equivalents and restricted cash $ 201,553 $ 6,917
Reclassification out of Accumulated Other Comprehensive Income	The amounts reclassified out of AOCI / (AOCL) by component during the years ended December 31, 2022, 2021 and 2020 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, 2022 2021 2020 Net losses on cash flow hedges (Note 5): Interest expense $ 7,229 $ 4,819 $ 5,422 Income tax effect (1,798) (1,199) (1,313) Total reclassifications for the period, net of income taxes $ 5,431 $ 3,620 $ 4,109
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 (in Thousands): Year Ended December 31, 2022 Beginning Allowance Balance at January 1, 2022 Current Period Provision Write-offs Charged Against Allowances Recoveries Collected Ending Allowance Balance at Allowance for credit losses $ 647 $ 5,851 $ (7,008) $ 1,627 $ 1,117 Year Ended December 31, 2021 Beginning Allowance Balance at January 1, 2021 Current Period Provision Write-offs Charged Against Allowances Recoveries Collected Ending Allowance Balance at Allowance for credit losses $ 3,155 $ 2,035 $ (6,448) $ 1,905 $ 647
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, 2022 2021 (In Thousands) Inventories Fuel $ 60,497 $ 41,626 Materials and supplies, net 63,111 60,273 Total inventories $ 123,608 $ 101,899
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, 2022 2021 (In Thousands) Accounts receivable, net Customer receivables $ 125,540 $ 100,952 Unbilled revenues 74,488 64,758 Amounts due from related parties 288 214 Other 17,373 13,904 Allowance for credit losses (1,117) (647) Total accounts receivable, net $ 216,572 $ 179,181
Schedule of Cash and Cash Equivalents [Table Text Block]		As of December 31, 2022 2021 (In Thousands) Cash, cash equivalents and restricted cash Cash and cash equivalents $ 199,103 $ 2,756 Restricted cash (included in Prepayments and other current assets) 5 5 Total cash, cash equivalents and restricted cash $ 199,108 $ 2,761
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 (in Thousands): Year Ended December 31, 2022 Beginning Allowance Balance at January 1, 2022 Current Period Provision Write-offs Charged Against Allowances Recoveries Collected Ending Allowance Balance at Allowance for credit losses $ 647 $ 5,851 $ (7,008) $ 1,627 $ 1,117

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2019
Entity Information [Line Items]
Schedule Of Original Cost Of Utility Plant In Service	As of December 31, 2022 2021 (In Thousands) Production $ 4,164,416 $ 4,099,110 Transmission 461,245 436,257 Distribution 2,045,579 1,831,029 General plant 311,074 277,533 Total property, plant and equipment $ 6,982,314 $ 6,643,929
Reconciliation Of Asset Retirement Obligation Liability	The following is a roll forward of the ARO legal liability year end balances: 2022 2021 (In Thousands) Balance as of January 1 $ 189,509 $ 195,236 Liabilities incurred 1,159 — Liabilities settled (24,699) (13,692) Revisions to cash flow and timing estimates 44,679 — Accretion 8,081 7,965 Balance as of December 31 $ 218,729 $ 189,509
Indianapolis Power And Light Company
Entity Information [Line Items]
Schedule Of Original Cost Of Utility Plant In Service	As of December 31, 2022 2021 (In Thousands) Production $ 4,164,416 $ 4,099,110 Transmission 461,245 436,257 Distribution 2,045,579 1,831,029 General plant 311,074 277,533 Total property, plant and equipment $ 6,982,314 $ 6,643,929
Reconciliation Of Asset Retirement Obligation Liability	The following is a roll forward of the ARO legal liability year end balances: 2022 2021 (In Thousands) Balance as of January 1 $ 189,509 $ 195,236 Liabilities incurred 1,159 — Liabilities settled (24,699) (13,692) Revisions to cash flow and timing estimates 44,679 — Accretion 8,081 7,965 Balance as of December 31 $ 218,729 $ 189,509

Fair Value (Tables)

Fair Value (Tables)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2019
Entity Information [Line Items]
Summary of Fair Value Assets and Liabilities Measured on a Recurring Basis, Level 3	The fair value of assets and liabilities at December 31, 2022 and 2021 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, 2022 Fair Value as of December 31, 2021 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total (In Thousands) Financial assets: VEBA investments: Money market funds $ 5 $ — $ — $ 5 $ 11 $ — $ — $ 11 Mutual funds 3,223 — — 3,223 — 3,594 — 3,594 Total VEBA investments 3,228 — — 3,228 11 3,594 — 3,605 FTRs — — 7,545 7,545 — — 1,235 1,235 Interest rate hedges — 12,172 — 12,172 — — — — Total financial assets measured at fair value $ 3,228 $ 12,172 $ 7,545 $ 22,945 $ 11 $ 3,594 $ 1,235 $ 4,840 Financial liabilities: Interest rate hedges $ — $ — $ — $ — $ — $ 49,382 $ — $ 49,382 Total financial liabilities measured at fair value $ — $ — $ — $ — $ — $ 49,382 $ — $ 49,382
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, 2021 $ 543 Issuances 2,971 Settlements (2,279) Balance at December 31, 2021 $ 1,235 Issuances 15,338 Settlements (9,028) Balance at December 31, 2022 $ 7,545
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, 2022 December 31, 2021 Face Value Fair Value Face Value Fair Value (In Thousands) Fixed-rate $ 3,033,800 $ 2,775,644 $ 2,683,800 $ 3,169,118 Variable-rate — — 60,000 60,000 Total indebtedness $ 3,033,800 $ 2,775,644 $ 2,743,800 $ 3,229,118
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 and liabilities at December 31, 2022 and 2021 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, 2022 Fair Value as of December 31, 2021 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total (In Thousands) Financial assets: FTRs $ — $ — $ 7,545 $ 7,545 $ — $ — $ 1,235 $ 1,235 Total financial assets measured at fair value $ — $ — $ 7,545 $ 7,545 $ — $ — $ 1,235 $ 1,235
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, 2021 $ 543 Issuances 2,971 Settlements (2,279) Balance at December 31, 2021 $ 1,235 Issuances 15,338 Settlements (9,028) Balance at December 31, 2022 $ 7,545
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, 2022 December 31, 2021 Face Value Fair Value Face Value Fair Value (In Thousands) Fixed-rate $ 2,153,800 $ 1,959,233 $ 1,803,800 $ 2,222,772 Variable-rate — — 60,000 60,000 Total indebtedness $ 2,153,800 $ 1,959,233 $ 1,863,800 $ 2,282,772

Regulatory Matters (Tables)

Regulatory Matters (Tables)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2019
Entity Information [Line Items]
Schedule Of Regulatory Assets And Liabilities [Table Text Block]		2022 2021 Recovery Period (In Thousands) Regulatory Assets Current: Undercollections of rate riders $ 26,047 $ 41,108 Approximately 1 year (1) Fuel costs 79,861 8,890 Approximately 1 year (1) Costs being recovered through basic rates and charges 13,815 13,815 Approximately 1 year (1) Total current regulatory assets 119,723 63,813 Long-term: Unrecognized pension and other postretirement benefit plan costs 131,907 114,887 Various (2) Deferred MISO costs 34,483 47,875 Through 2026 (1) Unamortized Petersburg Unit 4 carrying charges and certain other costs 3,866 4,921 Through 2026 (1)(3) Unamortized reacquisition premium on debt 14,429 15,703 Over remaining life of debt Environmental costs 68,947 71,201 Through 2046 (1)(3) COVID-19 costs 5,426 5,426 To be determined TDSIC costs 18,547 8,540 36.3 years (1)(3) Petersburg Unit 1 and 2 retirement costs 287,463 300,067 Through 2034 (1)(3) Hardy Hills Solar Project costs 5,744 2,907 To be determined (3) Petersburg Solar Project costs 1,582 881 To be determined Fuel costs 20,518 83,513 Through 2025 (1) Other miscellaneous 1,027 1,056 Various (4) Total long-term regulatory assets 593,939 656,977 Total regulatory assets $ 713,662 $ 720,790 Regulatory Liabilities Current: Overcollections and other credits being passed to customers through rate riders $ 15,803 $ 3,006 Approximately 1 year (1) FTRs 7,545 1,235 Approximately 1 year (1) Total current regulatory liabilities 23,348 4,241 Long-term: ARO and accrued asset removal costs 518,797 722,774 Not applicable Deferred income taxes payable to customers through rates 88,662 100,171 Various Major storm damage 5,126 3,764 To be determined Total long-term regulatory liabilities 612,585 826,709 Total regulatory liabilities $ 635,933 $ 830,950 (1) Recovered (credited) per specific rate orders (2) AES Indiana receives a return on its discretionary funding (3) Recovered with a current return (4) The majority of these costs are being recovered in basic rates and charges through 2026. For the remainder, recovery is probable, but the
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 revenues. Our basic rates and charges are determined after giving consideration, on a pro-forma basis, to all allowable costs for ratemaking purposes including a fair return on the fair value of the utility property used and useful in providing service to customers. These basic rates and charges are set and approved by the IURC after public hearings. Such proceedings, which have occurred at irregular intervals, involve AES Indiana, the IURC, the Indiana Office of Utility Consumer Counselor, and other interested stakeholders. Pursuant to statute, the IURC is to conduct a periodic review of the basic rates and charges of all Indiana utilities at least once every four years, but the IURC has the authority to review the rates of any Indiana utility at any time. Once set, the basic rates and charges authorized do not assure the realization of a fair return on the fair value of property. Our declining block rate structure generally provides for residential and commercial customers to be charged a lower per kWh rate at higher consumption levels. Therefore, as volumes increase, the weighted average price per kWh decreases. Numerous factors including, but not limited to, weather, inflation, customer growth and usage, the level of actual operating and maintenance expenditures, fuel costs, generating unit availability, and capital expenditures including those required by environmental regulations can affect the return realized. Base Rate Orders On October 31, 2018, the IURC issued an order approving an uncontested settlement agreement previously filed with the IURC by AES Indiana for a $43.9 million, or 3.2%, increase to annual revenues (the "2018 Base Rate Order"). The 2018 Base Rate Order includes recovery through rates of the CCGT at Eagle Valley completed in the first half of 2018, as well as other construction projects and changes to operating income since the 2016 Base Rate Order. New basic rates and charges became effective on December 5, 2018. The 2018 Base Rate Order also provides customers approximately $50 million in benefits, which flowed to customers over the two-year period that began March 2019, via the ECCRA rate adjustment mechanism. As of December 31, 2022 and 2021, these credits have been fully returned to customers. In addition, the 2018 Base Rate Order provides that annual wholesale margins earned above (or below) the benchmark of $16.3 million shall be passed back (or charged) to customer rates through a rate adjustment mechanism. Prior to the 2018 Base Rate Order, wholesale sales margins were shared with customers 50% above and below an established benchmark of $6.3 million. Similarly, the 2018 Base Rate Order provides that all capacity sales above (or below) a benchmark of $11.3 million shall be passed back (or charged) to customer rates through a rate adjustment mechanism. The 2018 Base Rate Order also approved changes to AES Indiana's depreciation and amortization rates (including no longer deferring depreciation on the CCGT at Eagle Valley) which altogether represent a net expense increase of approximately $28.7 million annually. FAC and Authorized Annual Jurisdictional Net Operating Income AES Indiana may apply to the IURC for a change in AES Indiana’s fuel charge every three months to recover AES Indiana’s estimated fuel costs, including the energy portion of purchased power costs, which may be above or below the levels included in AES Indiana’s basic rates and charges. AES Indiana must present evidence in each FAC proceeding that it has made every reasonable effort to acquire fuel and generate or purchase power or both so as to provide electricity to its retail customers at the lowest fuel cost reasonably possible. Independent of the IURC’s ability to review basic rates and charges, Indiana law requires electric utilities under the jurisdiction of the IURC to meet operating expense and income test requirements as a condition for approval of requested changes in the FAC. A utility may be unable to recover all of its fuel costs if its rolling twelve-month operating income, determined at quarterly measurement dates, exceeds its authorized annual jurisdictional net operating income and there are not sufficient applicable cumulative net operating income deficiencies (“Cumulative Deficiencies”) to offset it. The Cumulative Deficiencies calculation provides that only five years’ worth of historical earnings deficiencies or surpluses are included, unless it has been greater than five years since the most recent rate case. In each of the last three calendar years, AES Indiana has reported earnings in excess of the authorized level for each of the four quarterly reporting periods in those years. AES Indiana was not required to reduce its fuel cost recovery in 2019 because of its Cumulative Deficiencies. During 2020, AES Indiana's Cumulative Deficiencies dropped to zero and thus AES Indiana recorded a reduction to revenues of $0.3 million, $5.5 million and $10.0 million in 2022, 2021 and 2020, respectively. AES Indiana's regulatory liability attributed to the Cumulative Deficiencies calculation was $0.0 million and $0.5 million as of December 31, 2022 and 2021, respectively, which is recorded within " Regulatory liabilities, current " on the accompanying Consolidated Balance Sheets. ECCRA AES Indiana may apply to the IURC for approval of a rate adjustment known as the ECCRA periodically to recover costs (including a return) to comply with certain environmental regulations applicable to AES Indiana’s generating stations. The total amount of AES Indiana’s environmental equipment approved for ECCRA recovery as of December 31, 2022 was $22.8 million. The jurisdictional revenue requirement approved by the IURC to be included in AES Indiana’s rates for the twelve-month period ending February 2023 is a net cost to customers of $1.6 million. The only environmental equipment still remaining in the ECCRA as of December 31, 2022 are certain projects associated with NAAQS compliance. DSM Through various rate orders from the IURC, AES Indiana has been able to recover its costs of implementing various DSM programs throughout the periods covered by this report. In 2022, 2021 and 2020, 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, 2022, 2021 and 2020 were $8.3 million, $7.2 million and $6.0 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 revenues, consistent with the provisions of the settlement agreement. Wind and Solar Power Purchase Agreements We are committed under a power purchase agreement to purchase all wind-generated electricity through 2029 from a wind project in Indiana. We are also committed under another agreement to purchase all wind-generated electricity through 2031 from a project in Minnesota. The Indiana project has a maximum output capacity of approximately 100 MW and the Minnesota project has a maximum output capacity of approximately 200 MW. In addition, we have 94.5 MW of solar-generated electricity in our service territory under long-term contracts (these long-term contracts have expiration dates ranging from 2026 to 2033), of which 94.0 MW was in operation as of December 31, 2022. We have authority from the IURC to recover the costs for all of these agreements through an adjustment mechanism administered within the FAC. If and when AES Indiana sells the renewable energy attributes (in the form of renewable energy credits) generated from these facilities, the proceeds would pass back to benefit AES Indiana’s retail customers through the FAC. TDSIC In 2013, Senate Enrolled Act 560, the Transmission, Distribution, and Storage System Improvement Charge ("TDSIC") statute, was signed into law. The TDSIC statute was revised in 2019. Among other provisions, this legislation provides for cost recovery outside of a base rate proceeding for new or replacement electric and gas transmission, distribution, and storage projects that a public utility undertakes for the purposes of safety, reliability, system modernization, or economic development. Provisions of the TDSIC statute require that, among other things, requests for recovery include a plan of at least five years and not more than seven for eligible investments. The first eighty percent of eligible costs can be recovered using a periodic rate adjustment mechanism. The cost recovery mechanism is referred to as a TDSIC mechanism. Recoverable costs include a return on, and of, the investment, including AFUDC, post-in-service carrying charges, operation and maintenance expenses, depreciation and property taxes. The remaining twenty percent of recoverable costs are to be deferred for future recovery in the public utility’s next base rate case. The periodic rate adjustment mechanism is capped at an annual increase of no more than two percent of total retail revenues. On March 4, 2020, the IURC issued an order approving the projects in a seven-year TDSIC Plan for eligible transmission, distribution and storage system improvements totaling $1.2 billion from 2020 through 2026. Beginning in June 2020, AES Indiana files an annual TDSIC rate adjustment for a return on and of investments through March 31 with rates requested to be effective each November. Annual TDSIC plan update filings are required to be staggered by six months as ordered by the IURC and are filed each December. The total amount of AES Indiana’s equipment approved for TDSIC recovery as of December 31, 2022 was $324.0 million. The jurisdictional revenues requirement approved by the IURC to be included in AES Indiana’s rates for the twelve-month period ending October 2023 is a net cost to customers of $34.3 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 by the end of 2025. AES Indiana has not yet filed for the necessary regulatory approvals from the IURC to convert Petersburg units 3 and 4; however, AES Indiana expects to do so at the appropriate time. 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 has determined that the cost of operating Petersburg Units 1 and 2 exceeds the value customers receive compared to alternative resources. Retirement of these units allows the company to cost-effectively diversify the portfolio and transition to lower cost and cleaner resources while maintaining a reliable system. AES Indiana issued an all-source Request for Proposal on December 20, 2019, in order to competitively procure replacement capacity by June 1, 2023, which 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 $2.1 million, $0.8 million, and $0.0 million of obsolescence losses, during the periods ended December 31, 2022, 2021, and 2020, respectively, for materials and supplies inventory AES Indiana does not believe will be utilized by the planned retirement dates, which is recorded in " Operating expenses - Operation and maintenance " on the accompanying Consolidated Statements of Operations. 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 on May 31, 2021 and expects to retire Unit 2 in 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. AES Indiana had $60.1 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, 2021. Hardy Hills Solar Project In January 2021, AES Indiana, through its wholly-owned subsidiary AES Indiana Devco Holdings 1, LLC, executed an agreement for the acquisition and construction of the 195 MW Hardy Hills Solar Project to be developed in Clinton County, Indiana. As amended in December 2022 and subject to IURC approval, the Hardy Hills Solar Project is now expected to be completed in 2024. 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. Petersburg Solar Project In July 2021, AES Indiana, through its wholly-owned subsidiary AES Indiana Devco Holdings 2, LLC, executed an agreement for the acquisition and construction of a 250 MW solar and 180 MWh energy storage facility to be developed in Pike County, Indiana. As amended in October 2022 and subject to IURC approval, the Petersburg Solar Project is now expected to be completed in 2025. On July 30, 2021, AES Indiana filed a petition and case-in-chief with the IURC seeking a CPCN for this solar project and on November 24, 2021, AES Indiana received an order from the IURC approving the project, including a joint venture structure between an AES Indiana subsidiary and one or more tax equity partners upon completion and approval for recovery of project development costs and carrying costs on AES Indiana's investment in the project. 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. Additionally, the clean energy statute provides for a 120-day procedural schedule for the IURC to issue a determination of a project's eligibility. 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 Hardy Hills and Petersburg Energy Center under this statute (and other applicable statutes) and currently has a related request for IURC approval of contract amendments pending before the IURC. 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 through August 14, 2020, which has lapsed. Additionally, the IURC authorized Indiana utilities to use regulatory accounting for any impacts associated with prohibiting utility disconnections, waiver or exclusion of certain utility fees (i.e., late fees, convenience fees, deposits, and reconnection fees), and also required utilities to use expanded payment arrangements to aid customers. The IURC also authorized regulatory accounting treatment for COVID-19 related uncollectible and incremental bad debt expense. On August 12, 2020, the IURC required all jurisdictional utilities to continue offering extended payment arrangements for a minimum of six months to all customers for an additional 60 days, until October 12, 2020, which the IURC again extended through December 31, 2020 for residential customers on October 27, 2020. The IURC also continued to suspend the collection of certain utility fees (late fees, deposits, and disconnection/reconnection fees) from residential customers for an additional 60 days, until October 12, 2020, after which utilities were allowed to resume charging convenience fees as set forth in the rate and charges established in their Commission-approved tariffs. As a result of the IURC's COVID-19 related orders issued in 2020, AES Indiana has recorded a regulatory asset of $5.4 million as of December 31, 2022 and 2021. On August 25, 2021, the IURC closed the investigation to consider and address the impacts of the COVID-19 pandemic. For further discussion on the COVID-19 pandemic, see Note 15, " Risks and Uncertainties - COVID-19 Pandemic ." Excess Distributed Generation Rates On March 1, 2021, AES Indiana filed a petition with the IURC for approval of its proposed rate for the procurement of excess distributed generation ("EDG") and related consumer EDG credit issues. The EDG rate 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 remains subject to the pending appeal filed by the other parties on February 22, 2022, which is currently being 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 and currently remains in effect. 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. Electric Vehicle Portfolio Program On January 27, 2023, AES Indiana filed with the IURC a request to approve its Electric Vehicle (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. 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 Utility Receipts Tax ("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 revenues 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: 2022 2021 Recovery Period (In Thousands) Regulatory Assets Current: Undercollections of rate riders $ 26,047 $ 41,108 Approximately 1 year (1) Fuel costs 79,861 8,890 Approximately 1 year (1) Costs being recovered through basic rates and charges 13,815 13,815 Approximately 1 year (1) Total current regulatory assets 119,723 63,813 Long-term: Unrecognized pension and other postretirement benefit plan costs 131,907 114,887 Various (2) Deferred MISO costs 34,483 47,875 Through 2026 (1) Unamortized Petersburg Unit 4 carrying charges and certain other costs 3,866 4,921 Through 2026 (1)(3) Unamortized reacquisition premium on debt 14,429 15,703 Over remaining life of debt Environmental costs 68,947 71,201 Through 2046 (1)(3) COVID-19 costs 5,426 5,426 To be determined TDSIC costs 18,547 8,540 36.3 years (1)(3) Petersburg Unit 1 and 2 retirement costs 287,463 300,067 Through 2034 (1)(3) Hardy Hills Solar Project costs 5,744 2,907 To be determined (3) Petersburg Solar Project costs 1,582 881 To be determined Fuel costs 20,518 83,513 Through 2025 (1) Other miscellaneous 1,027 1,056 Various (4) Total long-term regulatory assets 593,939 656,977 Total regulatory assets $ 713,662 $ 720,790 Regulatory Liabilities Current: Overcollections and other credits being passed to customers through rate riders $ 15,803 $ 3,006 Approximately 1 year (1) FTRs 7,545 1,235 Approximately 1 year (1) Total current regulatory liabilities 23,348 4,241 Long-term: ARO and accrued asset removal costs 518,797 722,774 Not applicable Deferred income taxes payable to customers through rates 88,662 100,171 Various Major storm damage 5,126 3,764 To be determined Total long-term regulatory liabilities 612,585 826,709 Total regulatory liabilities $ 635,933 $ 830,950 (1) Recovered (credited) per specific rate orders (2) AES Indiana receives a return on its discretionary funding (3) Recovered with a current return (4) The majority of these costs are being recovered in basic rates and charges through 2026. For the remainder, recovery is probable, but the timing is not yet determined. 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) Green Power, (iii) Deferred Fuel Costs and (iv) 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) ECCRA costs, (iii) Off System Sales Margin Sharing, (iv) Capacity rider costs, (v) FAC 133 sub-docket costs and (vi) the NOI liability that is credited to customers in the FAC filing. Deferred Fuel Deferred fuel costs are a component of current and long-term regulatory assets or liabilities (which is a result of AES Indiana charging either more or less for fuel than our actual costs to our jurisdictional customers) and are expected to be recovered through future FAC proceedings. AES Indiana records deferred fuel in accordance with standards prescribed by the FERC. The deferred fuel adjustment is the result of variances between estimated fuel and purchased power costs in AES Indiana’s FAC and actual fuel and purchased power costs. AES Indiana is generally permitted to recover underestimated fuel and purchased power costs in future rates through the FAC proceedings and therefore the costs are deferred when incurred and amortized into fuel expense in the same period that AES Indiana’s rates are adjusted to reflect these costs. The Eagle Valley CCGT was on unplanned outage from late April 2021 until mid-March 2022, impacting several FAC periods. The FAC 133 IURC Order issued on November 24, 2021 approved the FAC 133 fuel cost factor on an interim basis subject to refund pending the outcome of a sub-docket created to examine the Eagle Valley CCGT extended outage. A procedural schedule for the sub-docket was established by the IURC. AES Indiana filed testimony in the FAC sub-docket in May 2022. AES Indiana's subsequent FAC filings have included a reduced FAC factor requested by AES Indiana in order to mitigate the rate impact on customers, primarily caused by rising commodity pricing and the Eagle Valley extended outage, that deferred the collection of certain variances estimated to be due to the Eagle Valley unplanned outage until a future FAC filing or the resolution in the FAC sub-docket for the Eagle Valley outage. Such FAC deferrals are recorded in long-term regulatory assets until the timing of collection is known. This treatment ceased with the FAC 138 filing in December 2022. On October 25, 2022, AES Indiana and various intervening parties reached a unanimous settlement regarding the Eagle Valley CCGT unplanned outage. This settlement resolves all issues related to the FAC sub-docket and all outage related costs including energy purchases, Off-System Sales margins, Capacity trackers and base rate proceedings. As part of this comprehensive settlement, AES Indiana agreed not to recover $21.0 million of previously deferred costs and to credit an additional $6.8 million to customers in future rates. As such, AES Indiana recorded a $27.8 million charge to " Power purchased " in the Consolidated Statements of Operations during the third quarter of 2022. On January 18, 2023, AES Indiana received an order from the IURC approving the settlement. Unrecognized Pension and Postretirement Benefit Plan Costs In accordance with ASC 715 “Compensation – Retirement Benefits” and ASC 980, we recognize a regulatory asset equal to the unrecognized actuarial gains and losses and prior service costs. Pension expenses or income are recorded based on the benefit plan’s actuarially determined pension liability or asset and associated level of annual expenses or income to be recognized. The other postretirement benefit plan’s deferred benefit cost is the excess of the other postretirement benefit liability over the amount previously recognized. Deferred MISO Costs These consist of administrative costs for transmission services, transmission expansion cost sharing, and certain other operational and administrative costs from the MISO market. These costs are being recovered per specific rate order. Unamortized Petersburg Unit 4 Carrying Charges and Certain Other Costs These consist of deferred debt carrying costs, depreciation, and post-in-service Allowance for Funds Used During Construction ("AFUDC") on Petersburg Unit 4. These costs are being recovered per specific rate order. Unamortized Reacquisition Premium on Debt This regulatory asset represents losses on long-term debt reacquired or redeemed in prior periods that have been deferred. These deferred losses are being amortized over the lives of the original issues in accordance with the rules of the FERC and the IURC. Environmental Costs These consist of various costs incurred to comply with environmental regulations. These costs were approved for recovery either through AES Indiana's ECCRA proceedings or in the 2018 Base Rate Order. Amortization periods vary, ranging from 3 to 43 years. COVID-19 Costs These consist of deferred fees (foregone late fees, reconnection fees a
Indianapolis Power And Light Company
Entity Information [Line Items]
Schedule Of Regulatory Assets And Liabilities [Table Text Block]		2022 2021 Recovery Period (In Thousands) Regulatory Assets Current: Undercollections of rate riders $ 26,047 $ 41,108 Approximately 1 year (1) Fuel costs 79,861 8,890 Approximately 1 year (1) Costs being recovered through basic rates and charges 13,815 13,815 Approximately 1 year (1) Total current regulatory assets 119,723 63,813 Long-term: Unrecognized pension and other postretirement benefit plan costs 131,907 114,887 Various (2) Deferred MISO costs 34,483 47,875 Through 2026 (1) Unamortized Petersburg Unit 4 carrying charges and certain other costs 3,866 4,921 Through 2026 (1)(3) Unamortized reacquisition premium on debt 14,429 15,703 Over remaining life of debt Environmental costs 68,947 71,201 Through 2046 (1)(3) COVID-19 costs 5,426 5,426 To be determined TDSIC costs 18,547 8,540 36.3 years (1)(3) Petersburg Unit 1 and 2 retirement costs 287,463 300,067 Through 2034 (1)(3) Hardy Hills Solar Project costs 5,744 2,907 To be determined (3) Petersburg Solar Project costs 1,582 881 To be determined Fuel costs 20,518 83,513 Through 2025 (1) Other miscellaneous 1,027 1,056 Various (4) Total long-term regulatory assets 593,939 656,977 Total regulatory assets $ 713,662 $ 720,790 Regulatory Liabilities Current: Overcollections and other credits being passed to customers through rate riders $ 15,803 $ 3,006 Approximately 1 year (1) FTRs 7,545 1,235 Approximately 1 year (1) Total current regulatory liabilities 23,348 4,241 Long-term: ARO and accrued asset removal costs 518,797 722,774 Not applicable Deferred income taxes payable to customers through rates 88,662 100,171 Various Major storm damage 5,126 3,764 To be determined Total long-term regulatory liabilities 612,585 826,709 Total regulatory liabilities $ 635,933 $ 830,950 (1) Recovered (credited) per specific rate orders (2) AES Indiana receives a return on its discretionary funding (3) Recovered with a current return (4) The majority of these costs are being recovered in basic rates and charges through 2026. For the remainder, recovery is probable, but the timing is not yet determined.

Derivative Instruments and He_2

Derivative Instruments and Hedging Activities (Tables)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2019
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 Year Ended December 31, $ in thousands (net of tax) 2022 2021 2020 Beginning accumulated derivative losses in AOCL $ (29,407) $ (43,420) $ (19,750) Net gains / (losses) associated with current period hedging transactions 46,245 10,393 (27,779) Net losses reclassified to interest expense, net of tax 5,431 3,620 4,109 Ending accumulated derivative gains / (losses) in AOCI / (AOCL) $ 22,269 $ (29,407) $ (43,420) Losses 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) 21
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]		December 31, Commodity Hedging Designation Balance sheet classification 2022 2021 FTRs Not a Cash Flow Hedge Prepayments and other current assets $ 7,545 $ 1,235 Interest rate hedges Cash Flow Hedge Derivative assets, non-current $ 12,172 $ — Interest rate hedges Cash Flow Hedge Derivative liabilities, non-current $ — $ 49,382
Schedule of Derivative Instruments [Table Text Block]	At December 31, 2022 , 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 5,388 — 5,388 (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 2022 2021 FTRs Not a Cash Flow Hedge Prepayments and other current assets $ 7,545 $ 1,235
Schedule of Derivative Instruments [Table Text Block]	At December 31, 2022 , AES Indiana's outstanding derivative instruments were as follows: Commodity Accounting Treatment (a) Unit Notional Sales Net Notional FTRs Not Designated MWh 5,388 — 5,388 (a) Refers to whether the derivative instruments have been designated as a cash flow hedge.

Equity (Tables)

Equity (Tables)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Entity Information [Line Items]
Schedule Of Preferred Stock	At December 31, 2022 and 2021, preferred stock consisted of the following: December 31, Shares Call Price 2022 2021 Par Value, plus premium, if applicable (In Thousands) Cumulative $100 par value, authorized 2,000,000 shares 4% Series 47,611 $ 118.00 $ — $ 5,410 4.2% Series 19,331 $ 103.00 — 1,933 4.6% Series 2,481 $ 103.00 — 248 4.8% Series 21,930 $ 101.00 — 2,193 5.65% Series 500,000 $ 100.00 — 50,000 Total cumulative preferred stock 591,353 $ — $ 59,784
Indianapolis Power And Light Company
Entity Information [Line Items]
Schedule Of Preferred Stock		At December 31, 2022 and 2021, preferred stock consisted of the following: December 31, Shares Call Price 2022 2021 Par Value, plus premium, if applicable (In Thousands) Cumulative $100 par value, authorized 2,000,000 shares 4% Series 47,611 $ 118.00 $ — $ 5,410 4.2% Series 19,331 $ 103.00 — 1,933 4.6% Series 2,481 $ 103.00 — 248 4.8% Series 21,930 $ 101.00 — 2,193 5.65% Series 500,000 $ 100.00 — 50,000 Total cumulative preferred stock 591,353 $ — $ 59,784 (a) AES Indiana's preferred stock was redeemed on December 30, 2022.

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2019
Entity Information [Line Items]
Schedule Long-Term Indebtedness	The following table presents our long-term debt: December 31, Series Due 2022 2021 (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 — 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 (6,651) (5,855) Deferred financing costs (20,362) (17,913) Total AES Indiana first mortgage bonds 2,126,787 1,780,032 Total long-term debt – AES Indiana 2,126,787 1,780,032 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 (425) (527) Deferred financing costs (5,912) (7,319) Total long-term debt – IPALCO 873,663 872,154 Total consolidated IPALCO long-term debt 3,000,450 2,652,186 Less: current portion of long-term debt — — Net consolidated IPALCO long-term debt $ 3,000,450 $ 2,652,186 (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.
Schedule Of Maturities On Long-Term Indebtedness		Maturities on long-term indebtedness subsequent to December 31, 2022, are as follows: Year Amount (In Thousands) 2023 $ — 2024 445,000 2025 40,000 2026 90,000 2027 — Thereafter 2,458,800 Total $ 3,033,800
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 2022 2021 (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 — 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 (6,651) (5,855) Deferred financing costs (20,362) (17,913) Total AES Indiana first mortgage bonds 2,126,787 1,780,032 Total consolidated AES Indiana long-term debt 2,126,787 1,780,032 Less: current portion of long-term debt — — Net consolidated AES Indiana long-term debt $ 2,126,787 $ 1,780,032 (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.
Schedule Of Maturities On Long-Term Indebtedness		Maturities on long-term indebtedness subsequent to December 31, 2022, are as follows: Year Amount (In Thousands) 2023 $ — 2024 40,000 2025 40,000 2026 90,000 2027 — Thereafter 1,983,800 Total $ 2,153,800

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2019
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: 2022 2021 2020 (In Thousands) Components of income tax expense: Current income taxes: Federal $ 22,539 $ 28,100 $ 19,489 State 6,026 8,218 6,249 Total current income taxes 28,565 36,318 25,738 Deferred income taxes: Federal (6,920) (7,286) 323 State 214 (91) 2,531 Total deferred income taxes (6,706) (7,377) 2,854 Net amortization of investment credit — — — Total income tax expense $ 21,859 $ 28,941 $ 28,592
Schedule Of Effective Income Tax Rate	The reasons for the difference, stated as a percentage of pretax income, are as follows: 2022 2021 2020 Federal statutory tax rate 21.0 % 21.0 % 21.0 % State income tax, net of federal tax benefit 3.9 % 4.0 % 4.2 % Depreciation flow through and amortization (7.8) % (6.3) % (6.8) % Additional funds used during construction - equity 0.9 % 0.4 % 1.0 % Other – net 0.4 % 0.4 % 1.2 % Effective tax rate 18.4 % 19.5 % 20.6 %
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, 2022 and 2021 are as follows: 2022 2021 (In Thousands) Deferred tax liabilities: Relating to utility property, net $ 341,473 $ 369,783 Regulatory assets recoverable through future rates 123,669 126,531 Other 17,953 14,326 Total deferred tax liabilities 483,095 510,640 Deferred tax assets: Investment tax credit 6 7 Regulatory liabilities including ARO 167,725 200,948 Employee benefit plans — — Other 2,723 18,958 Total deferred tax assets 170,454 219,913 Deferred income tax liability – net $ 312,641 $ 290,727
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, 2022, 2021 and 2020: 2022 2021 2020 (In Thousands) Unrecognized tax benefits at January 1 $ — $ 7,368 $ 7,056 Gross increases – current period tax positions — — 312 Gross decreases – prior period tax positions — (7,368) — Unrecognized tax benefits at December 31 $ — $ — $ 7,368
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: 2022 2021 2020 (In Thousands) Components of income tax expense: Current income taxes: Federal $ 31,286 $ 36,353 $ 28,395 State 8,185 10,325 8,661 Total current income taxes 39,471 46,678 37,056 Deferred income taxes: Federal (6,822) (7,283) 503 State 238 (90) 2,576 Total deferred income taxes (6,584) (7,373) 3,079 Net amortization of investment credit — — — Total income tax expense $ 32,887 $ 39,305 $ 40,135
Schedule Of Effective Income Tax Rate	The reasons for the difference, stated as a percentage of pretax income, are as follows: 2022 2021 2020 Federal statutory tax rate 21.0 % 21.0 % 21.0 % State income tax, net of federal tax benefit 3.9 % 4.0 % 4.2 % Depreciation flow through and amortization (5.7) % (4.9) % (5.1) % Additional funds used during construction - equity 0.7 % 0.3 % 0.7 % Other – net 0.3 % 0.3 % 1.0 % Effective tax rate 20.2 % 20.7 % 21.8 %
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, 2022 and 2021 are as follows: 2022 2021 (In Thousands) Deferred tax liabilities: Relating to utility property, net $ 341,473 $ 369,783 Regulatory assets recoverable through future rates 123,669 126,531 Other 22,717 18,283 Total deferred tax liabilities 487,859 514,597 Deferred tax assets: Investment tax credit 6 7 Regulatory liabilities including ARO 167,726 205,099 Employee benefit plans — — Other 15,020 9,313 Total deferred tax assets 182,752 214,419 Deferred income tax liability – net $ 305,107 $ 300,178
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, 2022, 2021 and 2020: 2022 2021 2020 (In Thousands) Unrecognized tax benefits at January 1 $ — $ 7,368 $ 7,056 Gross increases – current period tax positions — — 312 Gross decreases – prior period tax positions — (7,368) — Unrecognized tax benefits at December 31 $ — $ — $ 7,368

Benefit Plans (Tables)

Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2019
Entity Information [Line Items]
Schedule Of Defined Benefit Plans Disclosures	The following table presents information relating to the Pension Plans: Pension benefits 2022 2021 (In Thousands) Change in benefit obligation: Projected benefit obligation at January 1 $ 772,040 $ 842,525 Service cost 8,949 9,339 Interest cost 18,099 15,660 Actuarial gain (182,590) (37,858) Amendments (primarily increases in pension bands) — 5,575 Settlements (394) — Benefits paid (38,575) (63,201) Projected benefit obligation at December 31 577,529 772,040 Change in plan assets: Fair value of plan assets at January 1 820,684 850,020 Actual (loss)/return on plan assets (171,002) 33,841 Employer contributions 412 24 Settlements (394) — Benefits paid (38,575) (63,201) Fair value of plan assets at December 31 611,125 820,684 Funded status $ 33,596 $ 48,644 Amounts recognized in the statement of financial position: Non-current assets $ 33,611 $ 49,182 Non-current liabilities (15) (538) Net amount recognized at end of year $ 33,596 $ 48,644 Sources of change in regulatory assets (1) : Prior service cost arising during period $ — $ 5,575 Net loss/(gain) arising during period 24,069 (29,884) Amortization of prior service cost (2,589) (2,944) Amortization of loss (2,622) (5,529) Total recognized in regulatory assets $ 18,858 $ (32,782) Amounts included in regulatory assets: Net loss $ 131,559 $ 110,113 Prior service cost 11,655 14,244 Total amounts included in regulatory assets $ 143,214 $ 124,357
Schedule Of Net Periodic Benefit Costs	Pension benefits for 2022 2021 2020 (In Thousands) Components of net periodic benefit (credit) / cost: Service cost $ 8,949 $ 9,339 $ 8,272 Interest cost 18,099 15,660 22,151 Expected return on plan assets (35,656) (41,815) (37,779) Amortization of prior service cost 2,589 2,944 3,677 Amortization of actuarial loss 2,424 5,529 8,115 Amortization of settlement loss 199 — — Net periodic benefit (credit) / cost (3,396) (8,343) 4,436 Less: amounts capitalized 316 771 372 Amount charged to expense $ (3,080) $ (7,572) $ 4,064 Rates relevant to each year’s expense calculations: Discount rate – defined benefit pension plan 2.83 % 2.46 % 3.33 % Discount rate – supplemental retirement plan 2.62 % 2.31 % 3.05 % Expected return on defined benefit pension plan assets 4.45 % 5.05 % 5.05 % Expected return on supplemental retirement plan assets 5.50 % 3.60 % 4.45 %
Schedule Of Asset Allocation Guidelines	The following table summarizes the Company’s target pension plan allocation for 2022: 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, 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. Fair Value Measurements at December 31, 2021 (in thousands) Quoted Prices in Active Markets for Identical Assets Significant Observable Inputs Asset Category Total (Level 1) (Level 2) % Common collective trusts: Equities (a) $ 183,203 $ 2,778 $ 180,425 22 % Debt securities (b) 481,077 1,637 479,440 59 % Government debt securities (c) 154,051 324 153,727 19 % Total common collective trusts 818,331 4,739 813,592 100 % Cash and cash equivalents (d) 2,353 2,490 — — % Total pension plan assets $ 820,684 $ 7,229 $ 813,592 100 %
Schedule Of Expected Benefit Payments	Expected benefit payments are expected to be paid out of the Pension Plans as follows: Year Pension Benefits (In Thousands) 2023 $ 40,922 2024 41,855 2025 42,433 2026 43,191 2027 43,446 2028 through 2032 216,734
Indianapolis Power And Light Company
Entity Information [Line Items]
Schedule Of Defined Benefit Plans Disclosures	Pension benefits 2022 2021 (In Thousands) Change in benefit obligation: Projected benefit obligation at January 1 $ 772,040 $ 842,525 Service cost 8,949 9,339 Interest cost 18,099 15,660 Actuarial gain (182,590) (37,858) Amendments (primarily increases in pension bands) — 5,575 Settlements (394) — Benefits paid (38,575) (63,201) Projected benefit obligation at December 31 577,529 772,040 Change in plan assets: Fair value of plan assets at January 1 820,684 850,020 Actual (loss)/return on plan assets (171,002) 33,841 Employer contributions 412 24 Settlements (394) — Benefits paid (38,575) (63,201) Fair value of plan assets at December 31 611,125 820,684 Funded status $ 33,596 $ 48,644 Amounts recognized in the statement of financial position: Non-current assets $ 33,611 $ 49,182 Non-current liabilities (15) (538) Net amount recognized at end of year $ 33,596 $ 48,644 Sources of change in regulatory assets (1) : Prior service cost arising during period $ — $ 5,575 Net loss/(gain) arising during period 24,069 (29,884) Amortization of prior service cost (2,589) (2,944) Amortization of loss (2,622) (5,529) Total recognized in regulatory assets $ 18,858 $ (32,782) Amounts included in regulatory assets: Net loss $ 131,559 $ 110,113 Prior service cost 11,655 14,244 Total amounts included in regulatory assets $ 143,214 $ 124,357
Schedule Of Net Periodic Benefit Costs	Pension benefits for 2022 2021 2020 (In Thousands) Components of net periodic benefit (credit) / cost: Service cost $ 8,949 $ 9,339 $ 8,272 Interest cost 18,099 15,660 22,151 Expected return on plan assets (35,656) (41,815) (37,779) Amortization of prior service cost 2,589 2,944 3,677 Amortization of actuarial loss 2,424 5,529 8,115 Amortization of settlement loss 199 — — Net periodic benefit (credit) / cost (3,396) (8,343) 4,436 Less: amounts capitalized 316 771 372 Amount charged to expense $ (3,080) $ (7,572) $ 4,064 Rates relevant to each year’s expense calculations: Discount rate – defined benefit pension plan 2.83 % 2.46 % 3.33 % Discount rate – supplemental retirement plan 2.62 % 2.31 % 3.05 % Expected return on defined benefit pension plan assets 4.45 % 5.05 % 5.05 % Expected return on supplemental retirement plan assets 5.50 % 3.60 % 4.45 %
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, 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. Fair Value Measurements at December 31, 2021 (in thousands) Quoted Prices in Active Markets for Identical Assets Significant Observable Inputs Asset Category Total (Level 1) (Level 2) % Common collective trusts: Equities (a) $ 183,203 $ 2,778 $ 180,425 22 % Debt securities (b) 481,077 1,637 479,440 59 % Government debt securities (c) 154,051 324 153,727 19 % Total common collective trusts 818,331 4,739 813,592 100 % Cash and cash equivalents (d) 2,353 2,490 — — % Total pension plan assets $ 820,684 $ 7,229 $ 813,592 100 %
Schedule Of Expected Benefit Payments	Year Pension Benefits (In Thousands) 2023 $ 40,922 2024 41,855 2025 42,433 2026 43,191 2027 43,446 2028 through 2032 216,734

Commitment and Contingencies (T

Commitment and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2022
Commitments and Contingencies Disclosure [Abstract]
Oil and Gas, Delivery Commitment	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 $ 1,188.8 $ 323.3 $ 331.1 $ 232.4 $ 302.0 Other $ 422.4 349.1 59.5 8.8 5.0

Business Segment Information (T

Business Segment Information (Tables)	12 Months Ended
	Dec. 31, 2019
Segment Reporting [Abstract]
Summary Of Company's Reporting Segments	The following table provides information about IPALCO’s business segments (in thousands): 2022 2021 2020 Utility All Other Total Utility All Other Total Utility All Other Total Revenues $ 1,791,711 $ — $ 1,791,711 $ 1,426,132 $ — $ 1,426,132 $ 1,352,985 $ — $ 1,352,985 Depreciation and amortization $ 266,504 $ — $ 266,504 $ 256,085 $ — $ 256,085 $ 246,896 $ — $ 246,896 Interest expense $ 87,428 $ 43,804 $ 131,232 $ 84,256 $ 41,370 $ 125,626 $ 87,281 $ 42,212 $ 129,493 Income/(loss) from operations before income tax $ 162,862 $ (44,377) $ 118,485 $ 189,548 $ (41,425) $ 148,123 $ 184,174 $ (45,615) $ 138,559 Capital expenditures (1) $ 496,510 $ — $ 496,510 $ 291,546 $ — $ 291,546 $ 235,736 $ — $ 235,736 (1) Capital expenditures includes $0 thousand, $36 thousand and $36 thousand of payments for financed capital expenditures in 2022, 2021 and 2020, respectively. As of December 31, 2022 As of December 31, 2021 As of December 31, 2020 Total assets $ 5,559,977 $ 29,237 $ 5,589,214 $ 5,222,987 $ 16,780 $ 5,239,767 $ 4,952,408 $ 17,511 $ 4,969,919

Revenue (Tables)

Revenue (Tables)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2019
Disaggregation of Revenue [Line Items]
Disaggregation of Revenue [Table Text Block]		’s revenues from contracts with customers was $1,760.0 million, $1,389.2 million and $1,326.6 million for the years ended December 31, 2022 , 2021 and 2020, respectively. The following table presents our revenues from contracts with customers and other revenues (in thousands): For the Years Ended December 31, 2022 2021 2020 Retail Revenues Retail revenues from contracts with customers: Residential $ 688,487 $ 595,692 $ 566,668 Small commercial and industrial 247,655 211,997 194,904 Large commercial and industrial 625,351 518,069 484,230 Public lighting 9,832 8,888 9,115 Other (1) 17,845 16,785 14,402 Total retail revenues from contracts with customers 1,589,170 1,351,431 1,269,319 Alternative revenues programs 29,171 35,248 24,781 Wholesale Revenues Wholesale revenues from contracts with customers 148,517 25,059 46,482 Miscellaneous Revenues Capacity revenues 11,750 734 1,477 Transmission and other revenues 10,534 11,480 9,317 Total miscellaneous revenues from contracts with customers 22,284 12,214 10,794 Other miscellaneous revenues (2) 2,569 2,180 1,609 Total Revenues $ 1,791,711 $ 1,426,132 $ 1,352,985
Revenue from Contract with Customer [Text Block]	REVENUES Revenues are primarily earned from retail and wholesale electricity sales and electricity transmission and distribution delivery services. Revenues are 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. Revenues are recorded net of any taxes assessed on and collected from customers, which are remitted to the governmental authorities. Retail revenues - AES Indiana energy sales to utility customers are based on the reading of meters at the customer’s location that occurs on a systematic basis throughout the month. AES Indiana sells electricity directly to end-users, such as homes and businesses, and bills customers directly. Retail revenues have a single performance obligation, as the promise to transfer energy and other distribution and/or transmission services are not separately identifiable from other promises in the contracts and, therefore, are not distinct. Additionally, as the performance obligation is satisfied over time as energy is delivered, and the same method is used to measure progress, the performance obligation meets the criteria to be considered a series. In exchange for the exclusive right to sell or distribute electricity in our service area, AES Indiana is subject to rate regulation by federal and state regulators. This regulation sets the framework for the prices (“tariffs”) that AES Indiana is allowed to charge customers for electric services. Since tariffs are approved by the regulator, the price that AES Indiana has the right to bill corresponds directly with the value to the customer of AES Indiana’s performance completed in each period. Therefore, revenues under these contracts are recognized using an output method measured by the MWhs delivered each month at the approved tariff. Customer payments are typically due on a monthly basis, though see Note 2, " Regulatory Matters - IURC COVID-19 Orders " for a discussion of the orders requiring expanded payment arrangements for customers. Wholesale revenues - Power produced at the generation stations in excess of our retail load is sold into the MISO market. Such sales are made at either the day-ahead or real-time hourly market price, and these sales are classified as wholesale revenues. We sell to and purchase power from MISO, and such sales and purchases are settled and accounted for on a net hourly basis. In the MISO market, wholesale revenues are recorded at the spot price based on the quantities of MWh delivered in each hour during each month. As a member of MISO, we are obligated to declare the availability of our energy production into the wholesale energy market, but we are not obligated to commit our previously declared availability. As such, contract terms end as the energy for each day is delivered to the market in the case of the day-ahead market and for each hour in the case of the real-time market. Miscellaneous revenues - Miscellaneous revenues are mainly comprised of MISO transmission revenues and capacity revenues. MISO transmission revenues are earned when AES Indiana’s power lines are used in transmission of energy by power producers other than AES Indiana. As AES Indiana owns and operates transmission lines in central and southern Indiana, demand charges collected from network customers by MISO are allocated to the appropriate transmission owners (including AES Indiana) and recognized as transmission revenues. Capacity revenues are also included in miscellaneous revenues, 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 revenues 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 revenues, 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 revenues, 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 revenues from contracts with customers was $1,760.0 million, $1,389.2 million and $1,326.6 million for the years ended December 31, 2022 , 2021 and 2020, respectively. The following table presents our revenues from contracts with customers and other revenues (in thousands): For the Years Ended December 31, 2022 2021 2020 Retail Revenues Retail revenues from contracts with customers: Residential $ 688,487 $ 595,692 $ 566,668 Small commercial and industrial 247,655 211,997 194,904 Large commercial and industrial 625,351 518,069 484,230 Public lighting 9,832 8,888 9,115 Other (1) 17,845 16,785 14,402 Total retail revenues from contracts with customers 1,589,170 1,351,431 1,269,319 Alternative revenues programs 29,171 35,248 24,781 Wholesale Revenues Wholesale revenues from contracts with customers 148,517 25,059 46,482 Miscellaneous Revenues Capacity revenues 11,750 734 1,477 Transmission and other revenues 10,534 11,480 9,317 Total miscellaneous revenues from contracts with customers 22,284 12,214 10,794 Other miscellaneous revenues (2) 2,569 2,180 1,609 Total Revenues $ 1,791,711 $ 1,426,132 $ 1,352,985 (1) Other retail revenues from contracts with customers includes miscellaneous charges to customers, including reconnection and late fee charges. (2) Other miscellaneous revenues includes lease and other miscellaneous revenues not accounted for under ASC 606. The balances of receivables from contracts with customers were $198.3 million and $163.0 million as of December 31, 2022 and 2021, 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 revenues 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 revenues based on the amount we have the right to invoice for services performed, and contracts with variable consideration allocated entirely to a wholly unsatisfied performance obligation when the consideration relates specifically to our efforts to satisfy the performance obligation and depicts the amount to which we expect to be entitled. Contract Balances — The timing of revenue recognition, billings, and cash collections results in accounts receivable and contract liabilities. There were no contract liabilities from contracts with customers as of December 31, 2022 and 2021, respectively. During the years ended December 31, 2022 and 2021, we recognized revenues of $0.0 million and $0.5 million, respectively, that was included in the corresponding contract liability balance at the beginning of the periods.
Indianapolis Power And Light Company
Disaggregation of Revenue [Line Items]
Disaggregation of Revenue [Table Text Block]		he following table presents AES Indiana's revenues from contracts with customers and other revenues (in thousands): For the Years Ended December 31, 2022 2021 2020 Retail Revenues Retail revenues from contracts with customers: Residential $ 688,487 $ 595,692 $ 566,668 Small commercial and industrial 247,655 211,997 194,904 Large commercial and industrial 625,351 518,069 484,230 Public lighting 9,832 8,888 9,115 Other (1) 17,845 16,785 14,402 Total retail revenues from contracts with customers 1,589,170 1,351,431 1,269,319 Alternative revenues programs 29,171 35,248 24,781 Wholesale Revenues Wholesale revenues from contracts with customers 148,517 25,059 46,482 Miscellaneous Revenues Capacity revenues 11,750 734 1,477 Transmission and other revenues 10,534 11,480 9,317 Total miscellaneous revenues from contracts with customers 22,284 12,214 10,794 Other miscellaneous revenues (2) 2,569 2,180 1,609 Total Revenues $ 1,791,711 $ 1,426,132 $ 1,352,985 (1) Other retail revenues from contracts with customers includes miscellaneous charges to customers, including reconnection and late fee charges. (2) Other miscellaneous revenues includes lease and other miscellaneous revenues not accounted for under ASC 606.
Revenue from Contract with Customer [Text Block]	Revenues are primarily earned from retail and wholesale electricity sales and electricity transmission and distribution delivery services. Revenues are 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. Revenues are recorded net of any taxes assessed on and collected from customers, which are remitted to the governmental authorities. Retail revenues - AES Indiana energy sales to utility customers are based on the reading of meters at the customer’s location that occurs on a systematic basis throughout the month. AES Indiana sells electricity directly to end-users, such as homes and businesses, and bills customers directly. Retail revenues have a single performance obligation, as the promise to transfer energy and other distribution and/or transmission services are not separately identifiable from other promises in the contracts and, therefore, are not distinct. Additionally, as the performance obligation is satisfied over time as energy is delivered, and the same method is used to measure progress, the performance obligation meets the criteria to be considered a series. In exchange for the exclusive right to sell or distribute electricity in our service area, AES Indiana is subject to rate regulation by federal and state regulators. This regulation sets the framework for the prices (“tariffs”) that AES Indiana is allowed to charge customers for electric services. Since tariffs are approved by the regulator, the price that AES Indiana has the right to bill corresponds directly with the value to the customer of AES Indiana’s performance completed in each period. Therefore, revenues under these contracts are recognized using an output method measured by the MWhs delivered each month at the approved tariff. Customer payments are typically due on a monthly basis, though see Note 2, " Regulatory Matters - IURC COVID-19 Orders " for a discussion of the orders requiring expanded payment arrangements for customers. Wholesale revenues - Power produced at the generation stations in excess of our retail load is sold into the MISO market. Such sales are made at either the day-ahead or real-time hourly market price, and these sales are classified as wholesale revenues. We sell to and purchase power from MISO, and such sales and purchases are settled and accounted for on a net hourly basis. In the MISO market, wholesale revenues are recorded at the spot price based on the quantities of MWh delivered in each hour during each month. As a member of MISO, we are obligated to declare the availability of our energy production into the wholesale energy market, but we are not obligated to commit our previously declared availability. As such, contract terms end as the energy for each day is delivered to the market in the case of the day-ahead market and for each hour in the case of the real-time market. Miscellaneous revenues - Miscellaneous revenues are mainly comprised of MISO transmission revenues and capacity revenues. MISO transmission revenues are earned when AES Indiana’s power lines are used in transmission of energy by power producers other than AES Indiana. As AES Indiana owns and operates transmission lines in central and southern Indiana, demand charges collected from network customers by MISO are allocated to the appropriate transmission owners (including AES Indiana) and recognized as transmission revenues. Capacity revenues are also included in miscellaneous revenues, 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 revenues 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 revenues, 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 revenues, 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 revenues from contracts with customers was $1,760.0 million , $1,389.2 million and $1,326.6 million for the years ended December 31, 2022 , 2021 and 2020, respectively. The following table presents AES Indiana's revenues from contracts with customers and other revenues (in thousands): For the Years Ended December 31, 2022 2021 2020 Retail Revenues Retail revenues from contracts with customers: Residential $ 688,487 $ 595,692 $ 566,668 Small commercial and industrial 247,655 211,997 194,904 Large commercial and industrial 625,351 518,069 484,230 Public lighting 9,832 8,888 9,115 Other (1) 17,845 16,785 14,402 Total retail revenues from contracts with customers 1,589,170 1,351,431 1,269,319 Alternative revenues programs 29,171 35,248 24,781 Wholesale Revenues Wholesale revenues from contracts with customers 148,517 25,059 46,482 Miscellaneous Revenues Capacity revenues 11,750 734 1,477 Transmission and other revenues 10,534 11,480 9,317 Total miscellaneous revenues from contracts with customers 22,284 12,214 10,794 Other miscellaneous revenues (2) 2,569 2,180 1,609 Total Revenues $ 1,791,711 $ 1,426,132 $ 1,352,985 (1) Other retail revenues from contracts with customers includes miscellaneous charges to customers, including reconnection and late fee charges. (2) Other miscellaneous revenues includes lease and other miscellaneous revenues not accounted for under ASC 606. The balances of receivables from contracts with customers were $198.3 million and $163.0 million as of December 31, 2022 and 2021, 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 revenues 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 revenues based on the amount we have the right to invoice for services performed, and contracts with variable consideration allocated entirely to a wholly unsatisfied performance obligation when the consideration relates specifically to our efforts to satisfy the performance obligation and depicts the amount to which AES Indiana expects to be entitled. Contract Balances — The timing of revenue recognition, billings, and cash collections results in accounts receivable and contract liabilities. There were no contract liabilities from contracts with customers as of December 31, 2022 and 2021, respectively. During the years ended December 31, 2022 and 2021, we recognized revenues of

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2022
Leases [Abstract]
Schedule of Capital Leased Assets	Property, Plant and Equipment, Net December 31, 2022 December 31, 2021 Gross assets $ 4,334 $ 4,403 Less: Accumulated depreciation (1,060) (979) Net assets $ 3,274 $ 3,424
Operating Lease, Lease Income	For the Year Ended December 31, 2022 2021 2020 Total lease revenues $ 1,134 $ 1,439 $ 941
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, 2022 for 2023 through 2027 and thereafter (in thousands): Finance Leases 2023 $ 802 2024 818 2025 834 2026 851 2027 868 Thereafter 37,546 Total $ 41,719 Less: Imputed interest (25,358) Present value of lease payments $ 16,361
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, 2022 , 2021 and 2020, respectively (in thousands): For the Year Ended December 31, Components of Lease Cost 2022 2021 2020 Finance lease cost: Amortization of right- of-use assets $ 542 $ — $ — Interest on lease liabilities 782 — — Total lease cost $ 1,324 $ — $ —
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, 2022 December 31, 2021 Weighted-average remaining lease term — finance leases 36 years 31 years Weighted-average discount rate — finance leases 5.650 % 4.561%
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, 2022 December 31, 2021 Assets Right-of-use assets — finance leases Other non-current assets $ 15,819 $ 19,763 Liabilities Finance lease liabilities (current) Short-term debt — 294 Finance lease liabilities (noncurrent) Long-term debt 16,361 19,469 Total finance lease liabilities $ 16,361 $ 19,763

Overview and Summary of Signi_4

Overview and Summary of Significant Accounting Policies (Details) $ in Thousands				12 Months Ended
	Feb. 13, 2023	Dec. 06, 2021	Oct. 31, 2018 USD ($)	Dec. 31, 2022 USD ($) generating_station item customer MW	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($) segment MW	May 31, 2021
Significant Accounting Policies [Line Items]
Accumulated Other Comprehensive Income (Loss), Net of Tax				$ 22,269	$ (29,407)	$ (43,420)	$ (19,750)
Other Comprehensive Income (Loss), Net of Tax				51,676	14,013	(23,670)
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax				46,245	10,393	(27,779)
Public Utilities, Approved Rate Increase (Decrease), Amount			$ 43,900
Public Utilities, Inventory				60,497	41,626
Receivables from Customers				125,540	100,952
Cash and Cash Equivalents, at Carrying Value				201,548	6,912
Capitalized Computer Software, Gross				205,900	162,000
Service cost				8,949	9,339	8,272
Interest cost				$ 18,099	15,660	$ 22,151
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				519,000
Number of generating stations | generating_station				4
Electric generation capability for winter, megawatts | MW				3,475
Electric generation capability for summer, megawatts | MW				3,330
Total other non-current assets				$ 849,054	873,923
Unbilled energy revenues				74,488	64,758
Provision for doubtful accounts				$ 5,851	2,035
Loss contingencies accrued					$ 200
Number of suppliers | item				2
Capitalized amount, rate				5.40%	5.70%	6.90%
Depreciation rate				3.80%
Depreciation expense				$ 247,500	$ 239,100	$ 232,800
Utility plant assets				4,000,000	4,000,000
Number of segments | segment							2
Capitalized Computer Software, Accumulated Amortization				107,200	95,800
Capitalized Computer Software, Amortization				10,100	11,200	10,600
Capitalized software, estimated amortization expense in year two				30,700
Capitalized Software, estimated amortization expense for the next 12 months				9,800
capitalized software, estimated amortization expense for year two				5,300
Capitalized software, estimated amortization expense for year three				5,200
Capitalized software, estimated amortization expense year four				5,200
Restricted Cash and Cash Equivalents				5	5
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents				201,553	6,917	26,622	$ 48,552
Accounts Receivable, Related Parties				239	169
Other Receivables				17,373	13,904
Accounts Receivable, Allowance for Credit Loss				(1,117)	(647)
Receivables, Net, Current				216,523	179,136
Materials and Supplies, Average Cost				63,111	60,273
Inventory, Net				123,608	101,899
capitalized software, estimated amortization expense year five				5,200
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax				46,245	10,393	(27,779)
Reclassification from AOCI, Current Period, Net of Tax, Attributable to Parent				5,431	3,620	4,109
Accounts receivable and unbilled revenue, allowance for doubtful accounts				1,117	647	3,155
Accounts Receivable, Allowance for Credit Loss, Writeoff				$ (7,008)	(6,448)
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 (in Thousands): Year Ended December 31, 2022 Beginning Allowance Balance at January 1, 2022 Current Period Provision Write-offs Charged Against Allowances Recoveries Collected Ending Allowance Balance at Allowance for credit losses $ 647 $ 5,851 $ (7,008) $ 1,627 $ 1,117 Year Ended December 31, 2021 Beginning Allowance Balance at January 1, 2021 Current Period Provision Write-offs Charged Against Allowances Recoveries Collected Ending Allowance Balance at Allowance for credit losses $ 3,155 $ 2,035 $ (6,448) $ 1,905 $ 647
Accounts Receivable, Allowance for Credit Loss, Recovery				$ 1,627	1,905
Income Tax Expense (Benefit)				(21,859)	(28,941)	(28,592)
Regulatory assets, non-current				593,939	656,977
Provision for Expected Credit Losses				$ 5,900	3,000	4,800
Preferred Resource Portfolio Coal-Fired Generation Retirement MW by 2023				630
Hardy Hills Solar Project MW				195
Petersburg Solar Project MW				250
Petersburg Solar Project MWh energy storage facility				180
Public Utilities, Property, Plant and Equipment, Net				$ 4,000,000	4,000,000
Project Development Intangible Assets				39,500
Other Assets, Noncurrent				849,054	873,923
Project Development, Estimated Amortization Expense Over the Next 5 Years				4,900
Project Development Intangible Assets, Estimated Amortization Expense for the Next Twelve Months				0
Project Development Intangible Assets, Estimated Amortization Expense for Year After Next				1,000
Project Development Intangible Assets, Estimated Amortization Expense for Three Years in the Future				1,300
Project Development Intangible Assets, Estimated Amortization Expense for Four Years in the Future				1,300
Project Development Intangible Assets, Estimated Amortization Expense for Five Year in the Future				1,300
Gain on acquisition				0	5,630	0
Loss Contingency Accrual at Carrying Value				$ 100	200
Petersburg Unit 1 Retired MW								230
Petersburg Unit 2 Planned Retirement MW in 2023				415
Gain on remeasurement of contingent consideration				$ 3,200
Prepaid Implementation Costs for Software as a Service
Significant Accounting Policies [Line Items]
Total other non-current assets				8,200	9,100
Other Assets, Noncurrent				$ 8,200	9,100
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				$ 22,269	(29,407)	(43,420)	(19,750)
Other Comprehensive Income (Loss), Net of Tax				51,676	14,013	(23,670)
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax				46,245	10,393	(27,779)
Cash and Cash Equivalents, at Carrying Value				191	1,902
Total other non-current assets				1,960,939	1,706,408
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents				191	1,902	6,417	3,709
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax				46,245	10,393	(27,779)
Reclassification from AOCI, Current Period, Net of Tax, Attributable to Parent				5,431	3,620	4,109
Income Tax Expense (Benefit)				11,027	10,364	11,278
Other Assets, Noncurrent				1,960,939	1,706,408
Indianapolis Power And Light Company
Significant Accounting Policies [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount			43,900
Public Utilities, Inventory				60,497	41,626
Receivables from Customers				125,540	100,952
Cash and Cash Equivalents, at Carrying Value				199,103	2,756
Capitalized Computer Software, Gross				205,900	162,000
Service cost				8,949	9,339	8,272
Interest cost				$ 18,099	15,660	$ 22,151
Number of customers | customer				519,000
Electric generation capability for winter, megawatts | MW				3,475
Electric generation capability for summer, megawatts | MW				3,330
Total other non-current assets				$ 833,536	870,212
Unbilled energy revenues				74,488	64,758
Provision for doubtful accounts				5,851	2,035
Loss contingencies accrued				$ 100	$ 200
Capitalized amount, rate				5.40%	5.70%	6.90%
Depreciation rate				3.80%
Depreciation expense				$ 247,500	$ 239,100	$ 232,800
Utility plant assets				4,000,000	4,000,000
Capitalized Computer Software, Accumulated Amortization				107,200	95,800
Capitalized Computer Software, Amortization				10,100	11,200	10,600
Capitalized software, estimated amortization expense in year two				30,700
Capitalized Software, estimated amortization expense for the next 12 months				9,800
capitalized software, estimated amortization expense for year two				5,300
Capitalized software, estimated amortization expense for year three				5,200
Capitalized software, estimated amortization expense year four				5,200
Restricted Cash and Cash Equivalents				5	5
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents				199,108	2,761	17,951	$ 42,589
Accounts Receivable, Related Parties				288	214
Other Receivables				17,373	13,904
Accounts Receivable, Allowance for Credit Loss				(1,117)	(647)
Receivables, Net, Current				216,572	179,181
Materials and Supplies, Average Cost				63,111	60,273
Inventory, Net				123,608	101,899
capitalized software, estimated amortization expense year five				5,200
Accounts receivable and unbilled revenue, allowance for doubtful accounts				1,117	647	3,155
Accounts Receivable, Allowance for Credit Loss, Writeoff				$ (7,008)	(6,448)
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 (in Thousands): Year Ended December 31, 2022 Beginning Allowance Balance at January 1, 2022 Current Period Provision Write-offs Charged Against Allowances Recoveries Collected Ending Allowance Balance at Allowance for credit losses $ 647 $ 5,851 $ (7,008) $ 1,627 $ 1,117
Accounts Receivable, Allowance for Credit Loss, Recovery				$ 1,627	1,905
Income Tax Expense (Benefit)				(32,887)	(39,305)	(40,134)
Regulatory assets, non-current				593,939	656,977
Provision for Expected Credit Losses				$ 5,900	3,000	4,800
Preferred Resource Portfolio Coal-Fired Generation Retirement MW by 2023				630
Hardy Hills Solar Project MW				195
Public Utilities, Property, Plant and Equipment, Net				$ 4,000,000	4,000,000
Project Development Intangible Assets				39,500
Other Assets, Noncurrent				833,536	870,212
Project Development, Estimated Amortization Expense Over the Next 5 Years				4,900
Project Development Intangible Assets, Estimated Amortization Expense for the Next Twelve Months				0
Project Development Intangible Assets, Estimated Amortization Expense for Year After Next				1,000
Project Development Intangible Assets, Estimated Amortization Expense for Three Years in the Future				1,300
Project Development Intangible Assets, Estimated Amortization Expense for Four Years in the Future				1,300
Project Development Intangible Assets, Estimated Amortization Expense for Five Year in the Future				1,300
Gain on acquisition				0	5,630	0
Indianapolis Power And Light Company | Prepaid Implementation Costs for Software as a Service
Significant Accounting Policies [Line Items]
Total other non-current assets				8,200	9,100
Other Assets, Noncurrent				$ 8,200	9,100
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
Increase to Annual Depreciation Rate [Member]
Significant Accounting Policies [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount			28,700
Increase to Annual Depreciation Rate [Member] | Indianapolis Power And Light Company
Significant Accounting Policies [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount			$ 28,700
Petersburg Unit 1 retirement
Significant Accounting Policies [Line Items]
Regulatory assets, non-current				$ 47,600
Petersburg Unit 1 retirement | Indianapolis Power And Light Company
Significant Accounting Policies [Line Items]
Regulatory assets, non-current					300,067
Petersburg Unit 1 retirement and 2 retirement costs
Significant Accounting Policies [Line Items]
Regulatory assets, non-current				287,463	300,067
Petersburg Unit 1 retirement and 2 retirement costs | Indianapolis Power And Light Company
Significant Accounting Policies [Line Items]
Regulatory assets, non-current				287,463
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	4,819	5,422
Income Tax Expense (Benefit)				(1,798)	(1,199)	(1,313)
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest				$ 5,431	$ 3,620	$ 4,109

Property, Plant and Equipment_2

Property, Plant and Equipment (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2019
Public Utility, Property, Plant and Equipment [Line Items]
Revisions to cash flow and timing estimates	$ 44,679	$ 0	$ 0
Direct first mortgage lien	2,153,800
Non-contractually required removal costs of utility plant in service	694,000	846,100
Contractually required removal costs of utility plant in service	218,700	189,500
Regulatory assets, non-current	593,939	656,977
Regulatory assets, non-current	593,939	656,977
Entity Information [Line Items]
Regulatory assets, non-current	593,939	656,977
Contractually required removal costs of utility plant in service	218,700	189,500
Non-contractually required removal costs of utility plant in service	694,000	846,100
Direct first mortgage lien	2,153,800
Petersburg Unit 1 retirement
Public Utility, Property, Plant and Equipment [Line Items]
Regulatory assets, non-current	47,600
Regulatory assets, non-current	47,600
Entity Information [Line Items]
Regulatory assets, non-current	47,600
Petersburg Unit 1 retirement and 2 retirement costs
Public Utility, Property, Plant and Equipment [Line Items]
Regulatory assets, non-current	287,463	300,067
Regulatory assets, non-current	287,463	300,067
Entity Information [Line Items]
Regulatory assets, non-current	287,463	300,067
Subsidiaries [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Revisions to cash flow and timing estimates	44,679	0	$ 0
Direct first mortgage lien	2,153,800
Non-contractually required removal costs of utility plant in service	694,000	846,100
Contractually required removal costs of utility plant in service	218,700	189,500
Regulatory assets, non-current	593,939	656,977
Regulatory assets, non-current	593,939	656,977
Entity Information [Line Items]
Regulatory assets, non-current	593,939	656,977
Contractually required removal costs of utility plant in service	218,700	189,500
Non-contractually required removal costs of utility plant in service	694,000	846,100
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		300,067
Regulatory assets, non-current		300,067
Entity Information [Line Items]
Regulatory assets, non-current		$ 300,067
Subsidiaries [Member] | Petersburg Unit 1 retirement and 2 retirement costs
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

Property, Plant and Equipment_3

Property, Plant and Equipment (Schedule Of Original Cost Of Utility Plant In Service) (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Entity Information [Line Items]
Production	$ 4,164,416	$ 4,099,110
Transmission	461,245	436,257
Distribution	2,045,579	1,831,029
General plant	311,074	277,533
Total utility plant in service	6,982,314	6,643,929
Indianapolis Power And Light Company
Entity Information [Line Items]
Production	4,164,416	4,099,110
Transmission	461,245	436,257
Distribution	2,045,579	1,831,029
General plant	311,074	277,533
Total utility plant in service	$ 6,982,314	$ 6,643,929

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, 2022	Dec. 31, 2021	Dec. 31, 2019
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance as of January 1	$ 189,509	$ 195,236
Liabilities settled	(24,699)	(13,692)
Revisions to cash flow and timing estimates	44,679	0	$ 0
Accretion expense	8,081	7,965
Balance as of December 31	218,729	189,509
Asset Retirement Obligation, Liabilities Incurred	1,159	0
Indianapolis Power And Light Company
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance as of January 1	189,509	195,236
Liabilities settled	24,699	13,692
Revisions to cash flow and timing estimates	44,679	0	$ 0
Accretion expense	8,081	7,965
Balance as of December 31	$ 218,729	$ 189,509

Fair Value (Narrative) (Details

Fair Value (Narrative) (Details) MWh in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2022 USD ($) MWh	Dec. 31, 2021 USD ($)	Dec. 31, 2019 USD ($)
Entity Information [Line Items]
Investments, Fair Value Disclosure	$ 3,228	$ 3,605
Revisions to cash flow and timing estimates	44,679	0	$ 0
Debt Issuance Costs, Net	26,300	25,200
Unamortized debt discount	7,100	6,400
Asset retirement obligations	218,729	189,509
Regulatory assets, non-current	593,939	656,977
Financial transmission rights	7,545	1,235
Total financial assets measured at fair value	22,945	4,840
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	$ 47,600
Indianapolis Power And Light Company
Entity Information [Line Items]
Revisions to cash flow and timing estimates	44,679	0	$ 0
Debt Issuance Costs, Net	20,400	17,900
Unamortized debt discount	6,651	5,855
Asset retirement obligations	218,729	189,509
Regulatory assets, non-current	593,939	656,977
Financial transmission rights	7,545	1,235
Total financial assets measured at fair value	$ 7,545	1,235
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		300,067
Money Market Funds [Member]
Entity Information [Line Items]
Investments, Fair Value Disclosure	$ 5	11
Mutual Fund [Member]
Entity Information [Line Items]
Investments, Fair Value Disclosure	3,223	3,594
Fair Value, Inputs, Level 1 [Member]
Entity Information [Line Items]
Investments, Fair Value Disclosure	3,228	11
Financial transmission rights	0	0
Total financial assets measured at fair value	3,228	11
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	3,594
Financial transmission rights	0	0
Total financial assets measured at fair value	12,172	3,594
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	7,545	1,235
Total financial assets measured at fair value	7,545	1,235
Fair Value, Inputs, Level 3 [Member] | Indianapolis Power And Light Company
Entity Information [Line Items]
Financial transmission rights	7,545	1,235
Total financial assets measured at fair value	$ 7,545	$ 1,235

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, 2022	Dec. 31, 2021
Entity Information [Line Items]
Investments, Fair Value Disclosure	$ 3,228	$ 3,605
Financial transmission rights	7,545	1,235
Total financial assets measured at fair value	22,945	4,840
Total financial liabilities measured at fair value	0	49,382
Indianapolis Power And Light Company
Entity Information [Line Items]
Financial transmission rights	7,545	1,235
Total financial assets measured at fair value	7,545	1,235
Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Entity Information [Line Items]
Investments, Fair Value Disclosure	3,228	11
Financial transmission rights	0	0
Total financial assets measured at fair value	3,228	11
Total financial liabilities measured at fair value	0	0
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	3,594
Financial transmission rights	0	0
Total financial assets measured at fair value	12,172	3,594
Total financial liabilities measured at fair value	0	49,382
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	7,545	1,235
Total financial assets measured at fair value	7,545	1,235
Total financial liabilities measured at fair value	0	0
Unobservable Inputs (Level 3) [Member] | Indianapolis Power And Light Company
Entity Information [Line Items]
Financial transmission rights	7,545	1,235
Total financial assets measured at fair value	7,545	1,235
Money Market Funds [Member]
Entity Information [Line Items]
Investments, Fair Value Disclosure	5	11
Mutual Fund [Member]
Entity Information [Line Items]
Investments, Fair Value Disclosure	$ 3,223	$ 3,594

Fair Value (Reconciliation Of F

Fair Value (Reconciliation Of Financial Instruments Classified As Level 3) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Forward Power Contracts Fair Value Disclosure	$ 12,172	$ 0
Total financial assets measured at fair value	22,945	4,840
Derivative Liability, Noncurrent	0	49,382
Financial transmission rights	7,545	1,235
Investments, Fair Value Disclosure	3,228	3,605
Total financial liabilities measured at fair value	0	49,382
Mutual Fund [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Investments, Fair Value Disclosure	3,223	3,594
Money Market Funds [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Investments, Fair Value Disclosure	5	11
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	3,228	11
Financial transmission rights	0	0
Investments, Fair Value Disclosure	3,228	11
Total financial liabilities measured at fair value	0	0
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	12,172	3,594
Financial transmission rights	0	0
Investments, Fair Value Disclosure	0	3,594
Total financial liabilities measured at fair value	0	49,382
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	7,545	1,235
Financial transmission rights	7,545	1,235
Investments, Fair Value Disclosure	0	0
Total financial liabilities measured at fair value	0	0
Derivative Financial Instruments, net Liabilities [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	1,235	543
Issuances	15,338	2,971
Settlements	(9,028)	(2,279)
Ending balance	7,545	1,235
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	7,545	1,235
Financial transmission rights	7,545	1,235
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	7,545	1,235
Financial transmission rights	7,545	1,235
Parent Company [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Forward Power Contracts Fair Value Disclosure	12,172	0
Total financial assets measured at fair value	15,400	3,605
Derivative Liability, Noncurrent	0	49,382
Investments, Fair Value Disclosure	3,228	3,605
Total financial liabilities measured at fair value	0	49,382
Parent Company [Member] | Mutual Fund [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Investments, Fair Value Disclosure	3,223	3,594
Parent Company [Member] | Money Market Funds [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Investments, Fair Value Disclosure	5	11
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	3,228	11
Derivative Liability, Noncurrent	0	0
Investments, Fair Value Disclosure	3,228	11
Total financial liabilities measured at fair value	0	0
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	3,223	0
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	5	11
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	12,172	0
Total financial assets measured at fair value	12,172	3,594
Derivative Liability, Noncurrent	0	49,382
Investments, Fair Value Disclosure	0	3,594
Total financial liabilities measured at fair value	0	49,382
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	3,594
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
Derivative Liability, Noncurrent	0	0
Investments, Fair Value Disclosure		0
Total financial liabilities measured at fair value	0	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, 2022	Dec. 31, 2021
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount	$ 7,100	$ 6,400
Face Value	3,033,800	2,743,800
Fair Value	2,775,644	3,229,118
Indianapolis Power And Light Company
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount	6,651	5,855
Face Value	2,153,800	1,863,800
Fair Value	1,959,233	2,282,772
Fixed Rate [Member]
Debt Instrument [Line Items]
Face Value	3,033,800	2,683,800
Fair Value	2,775,644	3,169,118
Fixed Rate [Member] | Indianapolis Power And Light Company
Debt Instrument [Line Items]
Face Value	2,153,800	1,803,800
Fair Value	1,959,233	2,222,772
Variable Rate [Member]
Debt Instrument [Line Items]
Face Value	0	60,000
Fair Value	0	60,000
Variable Rate [Member] | Indianapolis Power And Light Company
Debt Instrument [Line Items]
Face Value	0	60,000
Fair Value	$ 0	$ 60,000

Regulatory Matters (Narrative)

Regulatory Matters (Narrative) (Details) $ in Thousands		1 Months Ended	3 Months Ended	12 Months Ended
	Oct. 31, 2018 USD ($)	Mar. 31, 2016 USD ($)	Mar. 31, 2020 MW	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($) MW	Dec. 31, 2018 USD ($)	May 31, 2021	Jul. 24, 2019 USD ($)
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities, current				$ 23,348	$ 4,241
Regulatory assets, current				119,723	63,813
Regulatory assets, non-current				$ 593,939	$ 656,977
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent				21%	21%	21%
Equipment recovery approved amount							$ 22,800
Revenue requirement to be included in rate							1,600
Public Utlities, Approved Shareholder Incentives				$ 8,300			$ 7,200	$ 6,000
Regulatory Assets				713,662	$ 720,790
Regulatory assets				$ 119,723	63,813
Public Utilities, Approved Rate Increase (Decrease), Amount	$ 43,900
Public Utilities, Approved Rate Increase (Decrease), Percentage	3.20%
Wholesale Sales Margins, Percent Shared with Customers		50%
Benchmark for Wholesale Sales Margin		$ 6,300
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				$ 2,100	800
Regulatory Liability Attributable to the Cumulative Deficiencies Calculation				0
Reduction to Revenue				300	5,500	$ 10,000
Regulatory Liability, Noncurrent				612,585	826,709
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				635,933	830,950
Regulatory liabilities				612,585	826,709
Jurisdictional Revenue Requirement Approved by the IURC to be included in AES Indiana’s rates for the twelve-month period ending October 2022				$ 34,300
Retired MW Petersburg Unit 1									230
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				3,200
Estimated Projected Costs to Successfully Implement the Services Proposed in the EV Portfolio				$ 16,200
Time Period of Estimated Projected Costs to Successfully Implement the Services Proposed in the EV Portfolio				3
AES Indiana’s equipment approved for TDSIC recovery				$ 324,000
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
Overcollection and other credits passed to customers through rate riders [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities, current				15,803	3,006
Financial Transmission Rights [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities, current				7,545	1,235
Asset Retirement Obligation Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability, Noncurrent				518,797	722,774
Regulatory liabilities				518,797	722,774
Other Regulatory Assets (Liabilities) [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability, Noncurrent				5,126	3,764
Regulatory liabilities				5,126	3,764
Current
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability Attributable to the Cumulative Deficiencies Calculation				500
Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities, current				23,348	4,241
Regulatory assets, current				119,723	63,813
Regulatory assets, non-current				$ 593,939	$ 656,977
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent				21%	21%	21%
Equipment recovery approved amount							$ 22,800
Revenue requirement to be included in rate							1,600
Public Utlities, Approved Shareholder Incentives				$ 8,300			$ 7,200	$ 6,000
Regulatory Assets				713,662	$ 720,790
Regulatory assets				$ 119,723	63,813
Public Utilities, Approved Rate Increase (Decrease), Amount	$ 43,900
Public Utilities, Approved Rate Increase (Decrease), Percentage	3.20%
Wholesale Sales Margins, Percent Shared with Customers		50%
Benchmark for Wholesale Sales Margin		$ 6,300
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						$ 0
Reduction to Revenue				$ 5,500	10,000
Regulatory Liability, Noncurrent				612,585	826,709
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				635,933	830,950
Regulatory liabilities				612,585	826,709
Jurisdictional Revenue Requirement Approved by the IURC to be included in AES Indiana’s rates for the twelve-month period ending October 2022				$ 34,300
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				3,200
AES Indiana’s equipment approved for TDSIC recovery				324,000
Subsidiaries [Member] | Overcollection and other credits passed to customers through rate riders [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities, current				15,803	3,006
Subsidiaries [Member] | Financial Transmission Rights [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities, current				7,545	1,235
Subsidiaries [Member] | Asset Retirement Obligation Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability, Noncurrent				518,797	722,774
Regulatory liabilities				518,797	722,774
Subsidiaries [Member] | Deferred Income Tax Charge [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability, Noncurrent				88,700	100,171
Regulatory liabilities				88,700	100,171
Subsidiaries [Member] | Other Regulatory Assets (Liabilities) [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability, Noncurrent				5,126	3,764
Regulatory liabilities				5,126	3,764
Subsidiaries [Member] | Current
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability Attributable to the Cumulative Deficiencies Calculation				$ 0	500
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				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
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				$ 88,662	100,171
Regulatory liabilities				88,662	100,171
Deferred Income Tax Charge [Member] | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability, Noncurrent				88,662
Regulatory liabilities				88,662
Undercollections of rate riders [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, current				26,047	41,108
Regulatory assets				26,047	41,108
Undercollections of rate riders [Member] | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, current				26,047	41,108
Regulatory assets				26,047	41,108
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				131,907	114,887
Pension Costs [Member] | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current				131,907	114,887
Deferred Project Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current					47,875
Deferred Project Costs [Member] | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current					47,875
Unamortized Carrying Charges And Certain Other Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current				3,866	4,921
Unamortized Carrying Charges And Certain Other Costs [Member] | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current				3,866	4,921
Loss on Reacquired Debt [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current				14,429	15,703
Loss on Reacquired Debt [Member] | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current				14,429	15,703
Environmental Restoration Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current				68,947	71,201
Environmental Restoration Costs [Member] | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current				68,947	71,201
Other Miscellaneous [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current				1,027	1,056
Other Miscellaneous [Member] | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current				1,027	1,056
Deferred MISO Non-fuel Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current				34,483
Deferred MISO Non-fuel Costs [Member] | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current				34,483
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				18,547	8,540
TDSIC projects | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current				18,547	8,540
Petersburg Unit 1 retirement
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current				47,600
Petersburg Unit 1 retirement | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current					300,067
Petersburg Unit 2 retirement
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current				239,900
Hardy Hills Solar Project
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current				5,744	2,907
Hardy Hills Solar Project | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current				5,744	2,907
Petersburg Solar Project
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current				1,582	881
Petersburg Solar Project | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current				1,582	881
Fuel Costs
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, current				79,861	8,890
Regulatory assets, non-current				20,518	83,513
Regulatory assets				79,861	8,890
Fuel Costs | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current				20,518	83,513
Petersburg Unit 1 retirement and 2 retirement costs
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current				287,463	$ 300,067
Petersburg Unit 1 retirement and 2 retirement costs | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current				$ 287,463
Rate Order total benefits to customers [Member]
Regulatory Assets And Liabilities [Line Items]
Approved Rate Order Benefits to Customers	$ 50,000
Rate Order total benefits to customers [Member] | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Approved Rate Order Benefits to Customers	50,000
Benchmark for annual wholesale margins [Member]
Regulatory Assets And Liabilities [Line Items]
Approved Rate Order Benefits to Customers	16,300
Benchmark for annual wholesale margins [Member] | Subsidiaries [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
Benchmark for annual capacity sales [Member] | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Approved Rate Order Benefits to Customers	11,300
Increase to Annual Depreciation Rate [Member]
Regulatory Assets And Liabilities [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount	28,700
Increase to Annual Depreciation Rate [Member] | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount	$ 28,700

Regulatory Matters (Schedule Of

Regulatory Matters (Schedule Of Regulatory Assets And Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, current	$ 119,723	$ 63,813
Regulatory assets, noncurrent	593,939	656,977
Total regulatory assets	713,662	720,790
Regulatory liabilities, current	23,348	4,241
Regulatory Liability, Noncurrent	612,585	826,709
Total regulatory liabilities	635,933	830,950
Overcollection and other credits passed to customers through rate riders [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities, current	15,803	3,006
Financial Transmission Rights [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities, current	7,545	1,235
Asset Retirement Obligation Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability, Noncurrent	518,797	722,774
Other Regulatory Assets (Liabilities) [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability, Noncurrent	5,126	3,764
Undercollections of rate riders [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, current	26,047	41,108
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	131,907	114,887
Deferred Income Tax Charge [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability, Noncurrent	88,662	100,171
Deferred MISO Non-fuel Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	34,483
Unamortized Petersburg Unit 4 Carrying Charges And Certain Other Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	3,866	4,921
Unamortized Reacquisition Premium On Debt [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	14,429	15,703
Environmental Projects [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	68,947	71,201
Other Miscellaneous [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	1,027	1,056
Hardy Hills Solar Project
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	5,744	2,907
Petersburg Solar Project
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	1,582	881
Fuel Costs
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, current	79,861	8,890
Regulatory assets, noncurrent	20,518	83,513
Petersburg Unit 1 retirement and 2 retirement costs
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	287,463	300,067
Indianapolis Power And Light Company
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, current	119,723	63,813
Regulatory assets, noncurrent	593,939	656,977
Total regulatory assets	713,662	720,790
Regulatory liabilities, current	23,348	4,241
Regulatory Liability, Noncurrent	612,585	826,709
Total regulatory liabilities	635,933	830,950
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	15,803	3,006
Indianapolis Power And Light Company | Financial Transmission Rights [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities, current	7,545	1,235
Indianapolis Power And Light Company | Asset Retirement Obligation Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability, Noncurrent	518,797	722,774
Indianapolis Power And Light Company | Deferred Income Tax Charge [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability, Noncurrent	88,700	100,171
Indianapolis Power And Light Company | Other Regulatory Assets (Liabilities) [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability, Noncurrent	5,126	3,764
Indianapolis Power And Light Company | Undercollections of rate riders [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, current	26,047	41,108
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	131,907	114,887
Indianapolis Power And Light Company | Deferred Income Tax Charge [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability, Noncurrent	88,662
Indianapolis Power And Light Company | Deferred MISO Non-fuel Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	34,483
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	3,866	4,921
Indianapolis Power And Light Company | Unamortized Reacquisition Premium On Debt [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	14,429	15,703
Indianapolis Power And Light Company | Environmental Projects [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	68,947	71,201
Indianapolis Power And Light Company | Other Miscellaneous [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	1,027	1,056
Indianapolis Power And Light Company | Hardy Hills Solar Project
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	5,744	2,907
Indianapolis Power And Light Company | Petersburg Solar Project
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	1,582	881
Indianapolis Power And Light Company | Fuel Costs
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	20,518	$ 83,513
Indianapolis Power And Light Company | Petersburg Unit 1 retirement and 2 retirement costs
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	$ 287,463

Derivative Instruments and He_3

Derivative Instruments and Hedging Activities (Details) MWh in Thousands	12 Months Ended
	Dec. 31, 2022 USD ($) MWh	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Apr. 08, 2020 USD ($)	Dec. 31, 2019 USD ($)
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax	$ (15,309,000)	$ (3,441,000)	$ 8,876,000
Number of Interest Rate Swaps	3
Other Comprehensive Income (Loss), Net of Tax	$ 46,245,000	10,393,000	(27,779,000)
Accumulated Other Comprehensive Income (Loss), Net of Tax	22,269,000	(29,407,000)	(43,420,000)		$ (19,750,000)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	46,245,000	10,393,000	(27,779,000)
Reclassification from AOCI, Current Period, Net of Tax, Attributable to Parent	5,431,000	3,620,000	4,109,000
Interest Rate Contract [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax	22,269,000	(29,407,000)	(43,420,000)
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	21 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	5,388
Sale of Units Derivative Instruments Financial Transmission Rights | MWh	0
Derivative, Nonmonetary Notional Amount, Purchase (Sales), Net | MWh	5,388
Not Designated as Hedging Instrument [Member] | Realized Gains Forward Power Contracts
Derivative Instruments Not Designated as Hedging Instruments, Gain	$ 1,300,000	6,000,000
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	7,545,000	1,235,000
Other Current Assets [Member] | Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative Liability, Fair Value, Gross Liability	0	49,382,000
Derivative Liability, Current | Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative Liability, Fair Value, Gross Liability	12,172,000,000	0
Parent Company [Member]
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax	(15,309,000)	(3,441,000)	8,876,000
Other Comprehensive Income (Loss), Net of Tax	46,245,000	10,393,000	(27,779,000)
Accumulated Other Comprehensive Income (Loss), Net of Tax	22,269,000	(29,407,000)	(43,420,000)		$ (19,750,000)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	46,245,000	10,393,000	(27,779,000)
Reclassification from AOCI, Current Period, Net of Tax, Attributable to Parent	5,431,000	3,620,000	4,109,000
Parent Company [Member] | Interest Rate Contract [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax	22,269,000	(29,407,000)	$ (43,420,000)
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	21 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] | Other Current Assets [Member] | Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative Liability, Fair Value, Gross Liability	0	49,382,000,000
Parent Company [Member] | Derivative Liability, Current | Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative Liability, Fair Value, Gross Liability	$ 12,172,000,000	0
Subsidiaries [Member] | Not Designated as Hedging Instrument [Member] | FTR [Member]
Purchase of Units Derivative Instruments Financial Transmission Rights | MWh	5,388
Sale of Units Derivative Instruments Financial Transmission Rights | MWh	0
Derivative, Nonmonetary Notional Amount, Purchase (Sales), Net | MWh	5,388
Subsidiaries [Member] | Other Current Assets [Member] | Not Designated as Hedging Instrument [Member] | FTR [Member]
Derivative Asset, Fair Value, Gross Asset	$ 7,545,000,000	$ 1,235,000,000

Equity (Narrative) (Details)

Equity (Narrative) (Details) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2022 USD ($) $ / shares shares	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2019 $ / shares shares
Class of Stock [Line Items]
Preferred Stock, Par or Stated Value Per Share | $ / shares	$ 100
Preferred Stock, Shares Authorized | shares	2,000,000
Ownership percentage by parent	82.35%
Equity contributions from shareholders	$ 253,000	$ 275,000	$ 0
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	$ 101,986	131,476	108,739
Number of separate series of cumulative preferred stock	5
Preferred Stock, Voting Rights	2
Preferred stock outstanding | shares	591,353
Equity Capital Contributions	$ 208,300	226,500
Series A Preferred Stock [Member]
Class of Stock [Line Items]
Dividend rate on preferred stock				4%
Preferred stock outstanding | shares	47,611
5.65% Series Preferred Stock [Member]
Class of Stock [Line Items]
Dividend rate on preferred stock				5.65%
Preferred stock outstanding | shares	500,000
Series B Preferred Stock [Member]
Class of Stock [Line Items]
Dividend rate on preferred stock				4.20%
Preferred stock outstanding | shares	19,331
Series C Preferred Stock [Member]
Class of Stock [Line Items]
Dividend rate on preferred stock				4.60%
Preferred stock outstanding | shares	2,481
Series D Preferred Stock [Member]
Class of Stock [Line Items]
Dividend rate on preferred stock				4.80%
Preferred stock outstanding | shares	21,930
Indianapolis Power And Light Company
Class of Stock [Line Items]
Preferred Stock, Par or Stated Value Per Share | $ / shares				$ 100
Preferred Stock, Shares Authorized | shares				2,000,000
Equity contributions from AES	$ 253,000	275,000	0
Debt to capitalization ratio	0.67
Debt to Capitalization Ratio, Maximum	1
Dividends, Common Stock, Cash	$ 127,200	155,700	140,600
Payments of Ordinary Dividends, Common Stock	$ 127,200	155,700	147,600
Number of separate series of cumulative preferred stock	5
Total preferred stock dividends declared	$ 3,200
Preferred Stock, Voting Rights				2
Preferred stock outstanding | shares	591,353
Equity Capital Contributions	$ 253,000	275,000
Indianapolis Power And Light Company | Series A Preferred Stock [Member]
Class of Stock [Line Items]
Dividend rate on preferred stock				4%
Preferred stock outstanding | shares	47,611
Indianapolis Power And Light Company | 5.65% Series Preferred Stock [Member]
Class of Stock [Line Items]
Dividend rate on preferred stock				5.65%
Preferred stock outstanding | shares	500,000
Indianapolis Power And Light Company | Series B Preferred Stock [Member]
Class of Stock [Line Items]
Dividend rate on preferred stock				4.20%
Preferred stock outstanding | shares	19,331
Indianapolis Power And Light Company | Series C Preferred Stock [Member]
Class of Stock [Line Items]
Dividend rate on preferred stock				4.60%
Preferred stock outstanding | shares	2,481
Indianapolis Power And Light Company | Series D Preferred Stock [Member]
Class of Stock [Line Items]
Dividend rate on preferred stock				4.80%
Preferred stock outstanding | shares	21,930
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 shareholders	$ 253,000	275,000
Additional Paid-in Capital [Member] | Indianapolis Power And Light Company
Class of Stock [Line Items]
Equity contributions from AES	253,000	275,000	0
Retained Earnings [Member] | Indianapolis Power And Light Company
Class of Stock [Line Items]
Dividends, Common Stock, Cash	127,200	155,700	140,600
Total preferred stock dividends declared	$ 3,213	$ 3,213	$ 3,213

Equity (Summary Of Preferred St

Equity (Summary Of Preferred Stock) (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2022	Dec. 31, 2021
Class of Stock [Line Items]
Shares Outstanding		591,353
Par value, plus premium, if applicable		$ 0	$ 59,784
Preferred stock par value		$ 100
Preferred stock authorized		2,000,000
4% Series Preferred Stock [Member]
Class of Stock [Line Items]
Shares Outstanding		47,611
Call Price		$ 118
Par value, plus premium, if applicable		$ 0	5,410
Dividend rate on preferred stock	4%
4.2% Series Preferred Stock [Member]
Class of Stock [Line Items]
Shares Outstanding		19,331
Call Price		$ 103
Par value, plus premium, if applicable		$ 0	1,933
Dividend rate on preferred stock	4.20%
4.6% Series Preferred Stock [Member]
Class of Stock [Line Items]
Shares Outstanding		2,481
Call Price		$ 103
Par value, plus premium, if applicable		$ 0	248
Dividend rate on preferred stock	4.60%
4.8% Series Preferred Stock [Member]
Class of Stock [Line Items]
Shares Outstanding		21,930
Call Price		$ 101
Par value, plus premium, if applicable		$ 0	2,193
Dividend rate on preferred stock	4.80%
5.65% Series Preferred Stock [Member]
Class of Stock [Line Items]
Shares Outstanding		500,000
Call Price		$ 100
Par value, plus premium, if applicable		$ 0	50,000
Dividend rate on preferred stock	5.65%
Indianapolis Power And Light Company
Class of Stock [Line Items]
Shares Outstanding		591,353
Par value, plus premium, if applicable		$ 0	59,784
Preferred stock par value	$ 100
Preferred stock authorized	2,000,000
Indianapolis Power And Light Company | 4% Series Preferred Stock [Member]
Class of Stock [Line Items]
Shares Outstanding		47,611
Call Price		$ 118
Par value, plus premium, if applicable		$ 0	5,410
Dividend rate on preferred stock	4%
Indianapolis Power And Light Company | 4.2% Series Preferred Stock [Member]
Class of Stock [Line Items]
Shares Outstanding		19,331
Call Price		$ 103
Par value, plus premium, if applicable		$ 0	1,933
Dividend rate on preferred stock	4.20%
Indianapolis Power And Light Company | 4.6% Series Preferred Stock [Member]
Class of Stock [Line Items]
Shares Outstanding		2,481
Call Price		$ 103
Par value, plus premium, if applicable		$ 0	248
Dividend rate on preferred stock	4.60%
Indianapolis Power And Light Company | 4.8% Series Preferred Stock [Member]
Class of Stock [Line Items]
Shares Outstanding		21,930
Call Price		$ 101
Par value, plus premium, if applicable		$ 0	2,193
Dividend rate on preferred stock	4.80%
Indianapolis Power And Light Company | 5.65% Series Preferred Stock [Member]
Class of Stock [Line Items]
Shares Outstanding		500,000
Call Price		$ 100
Par value, plus premium, if applicable		$ 0	$ 50,000
Dividend rate on preferred stock	5.65%

Debt (Narrative) (Details)

Debt (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	May 31, 2014
Debt Instrument [Line Items]
Secured debt gross	$ 3,033,800,000
Aggregate principal amount	3,033,800,000	$ 2,743,800,000
Net proceeds from debt issuance	350,000,000	95,000,000	$ 565,000,000
Long-term debt	3,000,450,000	2,652,186,000
Loss on early extinguishment of debt	237,000	0	2,424,000
Maximum borrowing capacity	750,000,000				$ 350,000,000
Line of Credit Facility, Remaining Borrowing Capacity	400,000,000
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	2,153,800,000
Aggregate principal amount	2,153,800,000	1,863,800,000
Net proceeds from debt issuance	350,000,000	95,000,000	90,000,000
Long-term debt	2,126,787,000	1,780,032,000
Loss on early extinguishment of debt			2,415,000
Maximum borrowing capacity	750,000,000				350,000,000
Line of Credit Facility, Remaining Borrowing Capacity	400,000,000
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	$ 2,126,787,000	1,780,032,000
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed	100%
Debt Instrument, Unused Borrowing Capacity, Amount	$ 390,000,000
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	0	60,000,000
Ipalco Enterprises, Inc. [Member]
Debt Instrument [Line Items]
Aggregate principal amount	880,000,000	880,000,000
Net proceeds from debt issuance	0	0	474,568,000
Early tender premium	(237,000)	0	(2,415,000)
Long-term debt	873,663,000	872,154,000
Loss on early extinguishment of debt	0	0	2,400,000
First Mortgage Bonds [Member] | Indianapolis Power And Light Company
Debt Instrument [Line Items]
Secured debt gross	$ 2,153,800,000			$ 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	65,000,000
FMB Twenty - three | Ipalco Enterprises, Inc. [Member]
Debt Instrument [Line Items]
First mortgage bonds			$ 65,000,000
Three Point Eight Seven Five Percent First Mortgage Bonds | Indianapolis Power And Light Company
Debt Instrument [Line Items]
Debt instrument, stated interest rate	9,500,000,000%
Aggregated Principal Amount of First Mortgage Bonds to the Indiana Finance Authority in Two Series | Indianapolis Power And Light Company
Debt Instrument [Line Items]
First mortgage bonds	$ 95,000,000
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	0
Four Point Two Five Percent Senior Secured Notes | Indianapolis Power And Light Company
Debt Instrument [Line Items]
Debt instrument, stated interest rate	4.25%
Long-term debt	$ 475,000,000
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
Line of Credit [Member] | Committed Line of Credit
Debt Instrument [Line Items]
Long-term Line of Credit	$ 0	$ 60,000,000

Debt (Schedule Long-Term Indebt

Debt (Schedule Long-Term Indebtedness) (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Debt Instrument [Line Items]
Unamortized discount - net	$ (7,100)	$ (6,400)
Debt Issuance Costs, Net	(26,300)	(25,200)
Long-term debt	3,000,450	2,652,186
Current portion of long-term debt	0	0
Long-term debt	3,000,450	2,652,186
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	(425)	(527)
Debt Issuance Costs, Net	(5,912)	(7,319)
Long-term debt	873,663	872,154
Current portion of long-term debt	0	0
Long-term debt	873,663	872,154
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] | FMB Twenty - three
Debt Instrument [Line Items]
First mortgage bonds			$ 65,000
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	$ 2,126,787	1,780,032
Unamortized discount - net	(6,651)	(5,855)
Debt Issuance Costs, Net	(20,400)	(17,900)
Long-term debt	2,126,787	1,780,032
Current portion of long-term debt	0	0
Long-term debt	2,126,787	1,780,032
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	$ 65,000
Debt, stated interest rate	0.95%
Indianapolis Power And Light Company | Four Point Two Five Percent Senior Secured Notes
Debt Instrument [Line Items]
Long-term debt	$ 475,000
Debt, stated interest rate	4.25%
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	0
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	$ (6,651)
Debt Issuance Costs, Net	$ (20,362)	$ (17,913)

Debt (Schedule Of Maturities On

Debt (Schedule Of Maturities On Long-Term Indebtedness) (Details) $ in Thousands	Dec. 31, 2022 USD ($)
Entity Information [Line Items]
2016	$ 0
2017	445,000
2018	40,000
2019	90,000
2020	0
Thereafter	2,458,800
Total	3,033,800
Indianapolis Power And Light Company
Entity Information [Line Items]
2016	0
2017	40,000
2018	40,000
2019	90,000
2020	0
Thereafter	1,983,800
Total	$ 2,153,800

Income Taxes (Narrative) (Detai

Income Taxes (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Entity Information [Line Items]
Income taxes	$ 31,000,000	$ 27,500,000	$ 27,000,000
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21%	21%	21%
Unrecognized Tax Benefits	$ 0	$ 0	$ 7,368,000	$ 7,056,000
Indianapolis Power And Light Company
Entity Information [Line Items]
Income taxes	$ 39,500,000	$ 40,800,000	$ 27,000,000
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21%	21%	21%
Unrecognized Tax Benefits	$ 0	$ 0	$ 7,368,000	$ 7,056,000

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, 2022	Dec. 31, 2021	Dec. 31, 2020
Income Taxes [Line Items]
Less: income tax expense	$ 21,859	$ 28,941	$ 28,592
Charged To Utility Operating Expense [Member]
Income Taxes [Line Items]
Current income taxes, Federal	22,539	28,100	19,489
Current income taxes, State	6,026	8,218	6,249
Total current income taxes	28,565	36,318	25,738
Deferred income taxes, Federal	(6,920)	(7,286)	323
Deferred income taxes, State	214	(91)	2,531
Total deferred income taxes	(6,706)	(7,377)	2,854
Net amortization of investment credit	0	0	0
Less: income tax expense	21,859	28,941	28,592
Indianapolis Power And Light Company
Income Taxes [Line Items]
Less: income tax expense	32,887	39,305	40,134
Indianapolis Power And Light Company | Charged To Utility Operating Expense [Member]
Income Taxes [Line Items]
Current income taxes, Federal	31,286	36,353	28,395
Current income taxes, State	8,185	10,325	8,661
Total current income taxes	39,471	46,678	37,056
Deferred income taxes, Federal	(6,822)	(7,283)	503
Deferred income taxes, State	238	(90)	2,576
Total deferred income taxes	(6,584)	(7,373)	3,079
Net amortization of investment credit	0	0	0
Less: income tax expense	$ 32,887	$ 39,305	$ 40,135

Income Taxes (Schedule Of Effec

Income Taxes (Schedule Of Effective Income Tax Rate) (Details)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
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%	4%	4.20%
Depreciation flow through and amortization	(7.80%)	(6.30%)	(6.80%)
Effective Income Tax Rate Reconciliation, Funds Used during Construction, Equity	0.90%	0.40%	1%
Other - net	0.40%	0.40%	1.20%
Effective tax rate	18.40%	19.50%	20.60%
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%	4%	4.20%
Depreciation flow through and amortization	(5.70%)	(4.90%)	(5.10%)
Effective Income Tax Rate Reconciliation, Funds Used during Construction, Equity	0.70%	0.30%	0.70%
Other - net	0.30%	0.30%	1%
Effective tax rate	20.20%	20.70%	21.80%

Income Taxes (Schedule Of Defer

Income Taxes (Schedule Of Deferred Tax Assets And Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Entity Information [Line Items]
Relating to utility property, net	$ 341,473	$ 369,783
Regulatory assets recoverable through future rates	123,669	126,531
Other	17,953	14,326
Total deferred tax liabilities	483,095	510,640
Investment tax credit	6	7
Regulatory liabilities including ARO	167,725	200,948
Employee benefit plans	0	0
Other	2,723	18,958
Total deferred tax assets	170,454	219,913
Deferred Income Tax Liabilities, Net	312,641	290,727
Indianapolis Power And Light Company
Entity Information [Line Items]
Relating to utility property, net	341,473	369,783
Regulatory assets recoverable through future rates	123,669	126,531
Other	22,717	18,283
Total deferred tax liabilities	487,859	514,597
Investment tax credit	6	7
Regulatory liabilities including ARO	167,726	205,099
Employee benefit plans	0	0
Other	15,020	9,313
Total deferred tax assets	182,752	214,419
Deferred Income Tax Liabilities, Net	$ 305,107	$ 300,178

Income Taxes (Reconciliation Of

Income Taxes (Reconciliation Of Unrecognized Tax Benefits) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits at January 1	$ 0	$ 7,368,000	$ 7,056,000
Gross increases - current period tax positions	0	0	312,000
Gross decreases - prior period tax positions	0	(7,368,000)	0
Unrecognized tax benefits at December 31	0	0	7,368,000
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	7,368,000	7,056,000
Gross increases - current period tax positions	0	0	312,000
Gross decreases - prior period tax positions	0	(7,368,000)	0
Unrecognized tax benefits at December 31	$ 0	$ 0	$ 7,368,000

Benefit Plans (Narrative) (Deta

Benefit Plans (Narrative) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($) employee	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($) employee	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)
Defined Benefit Plan Disclosure [Line Items]
Noncurrent liabilities		$ 15	$ 538
Benefit obligation in excess of plan assets		33,596	48,644
Asset, Defined Benefit Pension Plan, Noncurrent		33,611	49,182
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		(182,590)	(37,858)
Net loss (gain) arising during period		24,069	29,884
Pension liability actuarial loss, change in discount rate			(37,900)
Amount included in regulatory assets and liabilities		131,559	110,113
Defined Benefit Plan, Pension Plan with Projected Benefit Obligation in Excess of Plan Assets, Plan Assets		$ 611,100
Expected return on plan assets		4.45%			4.45%
Effect of 25 basis point increase in discount rate on pension expense					$ (200)
Effect of 25 basis point decrease in discount rate on pension expense					200
Employer contributions during quarter		$ 412	24	$ 100
Funded target liability (percent)		99%
Pension expense					$ 38,600	$ 63,200	$ 38,500
Service cost		$ 8,949	9,339	8,272
Interest cost		18,099	15,660	22,151
Deferred Compensation Arrangement with Individual, Compensation Expense		200	200	300
Defined Benefit Plan, Benefit Obligation		577,529	$ 772,040	$ 842,525
Pension Liability Actuarial Gain, Change in Discount Rate		(182,600)
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, Tax		$ 24,100
Pension Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Percentage of employees covered by the plan		68%
Discount rate		2.83%	2.46%	3.33%
Expected return on plan assets		4.45%	5.05%	5.05%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate		5.41%	2.83%
Supplemental Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Number of plan participants | employee		20
Discount rate		2.62%	2.31%	3.05%
Expected return on plan assets		5.50%	3.60%	4.45%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate		5.32%	2.62%
Postretirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Number of plan participants, active | employee		130
Number of plan participants, retired | employee		24
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		$ 577,500
Defined Benefit Plan, Plan with Accumulated Benefit Obligation in Excess of Plan Assets, Plan Assets		611,100
Noncurrent liabilities		15	$ 538
Benefit obligation in excess of plan assets		33,596	48,644
Asset, Defined Benefit Pension Plan, Noncurrent		33,611	49,182
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		(182,590)	37,858
Net loss (gain) arising during period		24,100	29,884
Pension liability actuarial loss		206,700
Amount included in regulatory assets and liabilities		$ 131,559	110,113
Minimum percentage of unrecognized net loss over benefit obligation or assets in order to be amortized		10%
Amortization period of unrecognized loss					11 years 5 months 15 days
Unfunded status of plan		$ 33,600
Expected return on plan assets		5.60%			4.45%
Effect of 25 basis point increase in discount rate on pension expense		$ (200)
Effect of 25 basis point decrease in discount rate on pension expense		200
Employer contributions during quarter		$ 412	24	$ 100
Funded target liability (percent)		99%
Pension expense					$ 38,600	63,200	38,500
Service cost		$ 8,949	9,339	8,272
Interest cost		18,099	15,660	22,151
Deferred Compensation Arrangement with Individual, Compensation Expense		200	200	300
Defined Benefit Plan, Benefit Obligation		577,529	$ 772,040	$ 842,525
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, Tax		$ 24,069
Indianapolis Power And Light Company | Pension Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Percentage of employees covered by the plan					68%
Discount rate		2.83%	2.46%	3.33%
Expected return on plan assets		4.45%	5.05%	5.05%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate		5.41%	2.83%
Indianapolis Power And Light Company | Supplemental Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Number of plan participants | employee					20
Discount rate		2.62%	2.31%	3.05%
Expected return on plan assets		5.50%	3.60%	4.45%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate		5.32%	2.62%
Indianapolis Power And Light Company | Postretirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Number of plan participants, active | employee		130
Number of plan participants, retired | employee		24
Indianapolis Power And Light Company | Postretirement Health Coverage [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Benefit Obligation		$ 3,200	$ 3,900
Subsequent Event [Member] | Indianapolis Power And Light Company
Defined Benefit Plan Disclosure [Line Items]
Normal service cost	$ 6,200
Plan expenses	$ 400
Thrift Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Percentage of employees covered by the plan		78%
Defined contripution plan contributions					$ 3,600	3,400	3,400
Thrift Plan [Member] | Indianapolis Power And Light Company
Defined Benefit Plan Disclosure [Line Items]
Percentage of employees covered by the plan		78%
Defined contripution plan contributions					$ 3,600	3,400	3,400
Retirement Savings Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Percentage of employees covered by the plan		22%
Percentage of employee's base compensation matched		5%
Defined Contribution, Employer Matching Contribution, Non-discretionary, percent of match					4%
Defined contripution plan contributions		$ 2,100	1,900	$ 1,800
Retirement Savings Plan [Member] | Indianapolis Power And Light Company
Defined Benefit Plan Disclosure [Line Items]
Percentage of employees covered by the plan		22%			22%
Percentage of employee's base compensation matched		5%
Defined Contribution, Employer Matching Contribution, Non-discretionary, percent of match		4%
Defined contripution plan contributions			$ 2,100			$ 1,900	$ 1,800
Union Employees [Member] | Thrift Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Percentage of employees covered by the plan		10%
Union Employees [Member] | Thrift Plan [Member] | Indianapolis Power And Light Company
Defined Benefit Plan Disclosure [Line Items]
Percentage of employees covered by the plan					10%
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		5.60%
Forecast [Member] | Supplemental Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected return on plan assets	6.45%
Forecast [Member] | Indianapolis Power And Light Company | Supplemental Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected return on plan assets	6.45%

Benefit Plans (Schedule Of Defi

Benefit Plans (Schedule Of Defined Benefit Plans Disclosures) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Change in benefit obligation:
Projected benefit obligation at beginning Measurement Date (see below)	$ 772,040	$ 842,525
Service cost	8,949	9,339	$ 8,272
Interest cost	18,099	15,660	22,151
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)	182,590	37,858
Amendments (primarily increases in pension bands)	0	5,575
Defined Benefit Plan, Benefit Obligation, Payment for Settlement	(394)	0
Benefits paid	38,575	63,201
Projected benefit obligation at ending Measurement Date	577,529	772,040	842,525
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	820,684	850,020
Actual return on plan assets	(171,002)	33,841
Employer contributions during quarter	412	24	100
Defined Benefit Plan, Plan Assets, Payment for Settlement	(394)	0
Benefits paid	(38,575)	(63,201)
Defined Benefit Plan Fair Value of plan assets	611,125	820,684
Fair value of plan assets at ending Measurement Date	611,125	820,684	850,020
Unfunded status	33,596	48,644
Asset, Defined Benefit Pension Plan, Noncurrent	(33,611)	(49,182)
Amounts recognized in the statement of financial position under ASC 715:
Noncurrent liabilities	(15)	(538)
Asset, Defined Benefit Plan, Noncurrent, Net	33,596	48,644
Sources of change in regulatory assets(1):
Prior service cost (credit) arising during period	0	5,575
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, Tax	24,100
Net loss (gain) arising during period	24,069	29,884
Amortization of prior service cost	(2,589)	(2,944)
Amortization of gain (loss)	(2,622)	(5,529)
Total recognized in regulatory assets	18,858	(32,782)
Net loss (gain)	131,559	110,113
Prior service cost (credit)	11,655	14,244
Total amounts included in regulatory assets (liabilities)	$ 143,214	$ 124,357
Percentage by asset category	100%	100%
Assets for Plan Benefits, Defined Benefit Plan	$ 33,611	$ 49,182
Expected return on plan assets	4.45%			4.45%
Fair Value, Inputs, Level 1 [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	$ 7,229
Fair value of plan assets at ending Measurement Date	6,480	7,229
Significant Observable Inputs (Level 2) [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	813,592
Fair value of plan assets at ending Measurement Date	604,645	813,592
Indianapolis Power And Light Company
Change in benefit obligation:
Projected benefit obligation at beginning Measurement Date (see below)	772,040	842,525
Service cost	8,949	9,339	8,272
Interest cost	18,099	15,660	22,151
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)	182,590	(37,858)
Amendments (primarily increases in pension bands)	0	5,575
Defined Benefit Plan, Benefit Obligation, Payment for Settlement	(394)	0
Benefits paid	(38,575)	63,201
Projected benefit obligation at ending Measurement Date	577,529	772,040	842,525
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	820,684	850,020
Actual return on plan assets	(171,002)	33,841
Employer contributions during quarter	412	24	100
Defined Benefit Plan, Plan Assets, Payment for Settlement	394	0
Benefits paid	(38,575)	(63,201)
Fair value of plan assets at ending Measurement Date	611,125	820,684	$ 850,020
Unfunded status	33,596	48,644
Asset, Defined Benefit Pension Plan, Noncurrent	(33,611)	(49,182)
Amounts recognized in the statement of financial position under ASC 715:
Noncurrent liabilities	(15)	(538)
Asset, Defined Benefit Plan, Noncurrent, Net	33,596	48,644
Sources of change in regulatory assets(1):
Prior service cost (credit) arising during period	0	5,575
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, Tax	24,069
Net loss (gain) arising during period	24,100	29,884
Amortization of prior service cost	(2,589)	(2,944)
Amortization of gain (loss)	(2,622)	(5,529)
Total recognized in regulatory assets	18,858	(32,782)
Net loss (gain)	131,559	110,113
Prior service cost (credit)	11,655	14,244
Total amounts included in regulatory assets (liabilities)	$ 143,214	$ 124,357
Percentage by asset category	100%	100%
Assets for Plan Benefits, Defined Benefit Plan	$ 33,611	$ 49,182
Expected return on plan assets	5.60%			4.45%
Indianapolis Power And Light Company | Fair Value, Inputs, Level 1 [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	$ 7,229
Fair value of plan assets at ending Measurement Date	6,480	7,229
Indianapolis Power And Light Company | Significant Observable Inputs (Level 2) [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	813,592
Fair value of plan assets at ending Measurement Date	604,645	813,592
US Government Debt Securities [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	154,051
Fair value of plan assets at ending Measurement Date	$ 122,704	$ 154,051
Sources of change in regulatory assets(1):
Percentage by asset category	20%	19%
US Government Debt Securities [Member] | Fair Value, Inputs, Level 1 [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	$ 324
Fair value of plan assets at ending Measurement Date	420	$ 324
US Government Debt Securities [Member] | Significant Observable Inputs (Level 2) [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	153,727
Fair value of plan assets at ending Measurement Date	122,284	153,727
US Government Debt Securities [Member] | Indianapolis Power And Light Company
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	154,051
Fair value of plan assets at ending Measurement Date	$ 122,704	$ 154,051
Sources of change in regulatory assets(1):
Percentage by asset category	20%	19%
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	$ 324
Fair value of plan assets at ending Measurement Date	420	$ 324
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	153,727
Fair value of plan assets at ending Measurement Date	122,284	153,727
Defined Benefit Plan, Common Collective Trust
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	818,331
Fair value of plan assets at ending Measurement Date	$ 608,336	$ 818,331
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	$ 4,739
Fair value of plan assets at ending Measurement Date	3,691	$ 4,739
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	813,592
Fair value of plan assets at ending Measurement Date	604,645	813,592
Defined Benefit Plan, Common Collective Trust | Indianapolis Power And Light Company
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	818,331
Fair value of plan assets at ending Measurement Date	$ 608,336	$ 818,331
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	$ 4,739
Fair value of plan assets at ending Measurement Date	3,691	$ 4,739
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	813,592
Fair value of plan assets at ending Measurement Date	604,645	813,592
Short-Term Investments [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	2,353
Fair value of plan assets at ending Measurement Date	$ 2,789	$ 2,353
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	$ 2,490
Fair value of plan assets at ending Measurement Date	2,789	$ 2,490
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	2,353
Fair value of plan assets at ending Measurement Date	$ 2,789	$ 2,353
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	$ 2,490
Fair value of plan assets at ending Measurement Date	2,789	$ 2,490
Equity Securities | Indianapolis Power And Light Company
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	183,203
Fair value of plan assets at ending Measurement Date		$ 183,203
Sources of change in regulatory assets(1):
Percentage by asset category		22%
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	2,778
Fair value of plan assets at ending Measurement Date		$ 2,778
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	180,425
Fair value of plan assets at ending Measurement Date		180,425
Fixed Income [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	481,077
Fair value of plan assets at ending Measurement Date	$ 400,291	$ 481,077
Sources of change in regulatory assets(1):
Percentage by asset category	66%	59%
Fixed Income [Member] | Fair Value, Inputs, Level 1 [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	$ 1,637
Fair value of plan assets at ending Measurement Date	1,254	$ 1,637
Fixed Income [Member] | Significant Observable Inputs (Level 2) [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	479,440
Fair value of plan assets at ending Measurement Date	399,037	479,440
Fixed Income [Member] | Indianapolis Power And Light Company
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	481,077
Fair value of plan assets at ending Measurement Date	$ 400,291	$ 481,077
Sources of change in regulatory assets(1):
Percentage by asset category	66%	59%
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	$ 1,637
Fair value of plan assets at ending Measurement Date	1,254	$ 1,637
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	479,440
Fair value of plan assets at ending Measurement Date	399,037	479,440
Equity Funds [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	183,203
Fair value of plan assets at ending Measurement Date	$ 85,341	$ 183,203
Sources of change in regulatory assets(1):
Percentage by asset category	14%	22%
Equity Funds [Member] | Fair Value, Inputs, Level 1 [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	$ 2,778
Fair value of plan assets at ending Measurement Date	2,017	$ 2,778
Equity Funds [Member] | Significant Observable Inputs (Level 2) [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	180,425
Fair value of plan assets at ending Measurement Date	83,324	$ 180,425
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	$ 85,341
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	$ 2,017
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	$ 83,324

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, 2022	Dec. 31, 2021
Entity Information [Line Items]
Defined Benefit Plan, Pension Plan with Projected Benefit Obligation in Excess of Plan Assets, Plan Assets	$ 611,100
Benefit obligation in excess of plan assets	(33,596)	$ (48,644)
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	577,500
Benefit obligation in excess of plan assets	$ (33,596)	$ (48,644)

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, 2022 USD ($)
Indianapolis Power And Light Company
Entity Information [Line Items]
Plan assets	$ 611.1

Benefit Plans (Schedule Of Net

Benefit Plans (Schedule Of Net Periodic Benefit Costs) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 8,949	$ 9,339	$ 8,272
Interest cost	18,099	15,660	22,151
Expected return on assets	(35,656)	(41,815)	(37,779)
Defined Benefit Plan Amortization of prior service cost net of acceleration component of curtailment charge	2,589	2,944	3,677
Amortization of actuarial loss	2,424	5,529	8,115
Amortization of settlement loss	199	0	0
Net periodic benefit cost	(3,396)	(8,343)	4,436
Less: amounts capitalized	316	(771)	(372)
Amount charged to expense	$ (3,080)	(7,572)	4,064
Expected return on plan assets	4.45%			4.45%
Asset, Defined Benefit Pension Plan, Noncurrent	$ 33,611	49,182
Indianapolis Power And Light Company
Defined Benefit Plan Disclosure [Line Items]
Service cost	8,949	9,339	8,272
Interest cost	18,099	15,660	22,151
Expected return on assets	(35,656)	(41,815)	(37,779)
Defined Benefit Plan Amortization of prior service cost net of acceleration component of curtailment charge	2,589	2,944	3,677
Amortization of actuarial loss	2,424	5,529	8,115
Amortization of settlement loss	199	0	0
Net periodic benefit cost	(3,396)	(8,343)	4,436
Less: amounts capitalized	316	(771)	(372)
Amount charged to expense	$ (3,080)	(7,572)	$ 4,064
Expected return on plan assets	5.60%			4.45%
Asset, Defined Benefit Pension Plan, Noncurrent	$ 33,611	$ 49,182
Pension Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	2.83%	2.46%	3.33%
Expected return on plan assets	4.45%	5.05%	5.05%
Pension Benefit [Member] | Indianapolis Power And Light Company
Defined Benefit Plan Disclosure [Line Items]
Discount rate	2.83%	2.46%	3.33%
Expected return on plan assets	4.45%	5.05%	5.05%
Supplemental Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	2.62%	2.31%	3.05%
Expected return on plan assets	5.50%	3.60%	4.45%
Supplemental Retirement Plan [Member] | Indianapolis Power And Light Company
Defined Benefit Plan Disclosure [Line Items]
Discount rate	2.62%	2.31%	3.05%
Expected return on plan assets	5.50%	3.60%	4.45%

Benefit Plans (Schedule Of Asse

Benefit Plans (Schedule Of Asset Allocation Guidelines) (Details)	Dec. 31, 2022
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, 2022	Dec. 31, 2021	Dec. 31, 2020
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 611,125	$ 820,684	$ 850,020
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	$ 6,480	$ 7,229
Significant Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	604,645	813,592
Short-Term Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 2,789	$ 2,353
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	$ 2,789	$ 2,490
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	$ 122,704	$ 154,051
Percentage by asset category	20%	19%
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	$ 420	$ 324
US Government Debt Securities [Member] | Significant Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	122,284	153,727
Equity Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 85,341	$ 183,203
Percentage by asset category	14%	22%
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	$ 2,017	$ 2,778
Equity Funds [Member] | Significant Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	83,324	180,425
Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 400,291	$ 481,077
Percentage by asset category	66%	59%
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	$ 1,254	$ 1,637
Fixed Income [Member] | Significant Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	399,037	479,440
Defined Benefit Plan, Common Collective Trust
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 608,336	$ 818,331
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	$ 3,691	$ 4,739
Defined Benefit Plan, Common Collective Trust | Significant Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	604,645	813,592
Indianapolis Power And Light Company
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 611,125	$ 820,684	$ 850,020
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	$ 6,480	$ 7,229
Indianapolis Power And Light Company | Significant Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	604,645	813,592
Indianapolis Power And Light Company | Short-Term Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 2,789	$ 2,353
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	$ 2,789	$ 2,490
Indianapolis Power And Light Company | US Government Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 122,704	$ 154,051
Percentage by asset category	20%	19%
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	$ 420	$ 324
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	122,284	153,727
Indianapolis Power And Light Company | Equity Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 85,341
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	$ 2,017
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	83,324
Indianapolis Power And Light Company | Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 400,291	$ 481,077
Percentage by asset category	66%	59%
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	$ 1,254	$ 1,637
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	399,037	479,440
Indianapolis Power And Light Company | Defined Benefit Plan, Common Collective Trust
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 608,336	$ 818,331
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	$ 3,691	$ 4,739
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	$ 604,645	$ 813,592

Benefit Plans (Schedule Of Expe

Benefit Plans (Schedule Of Expected Benefit Payments) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Entity Information [Line Items]
2016	$ 40,922
2017	41,855
2018	42,433
2019	43,191
2020	43,446
2021 through 2025 (in total)	$ 216,734
Expected return on plan assets	4.45%			4.45%
Pension Benefit [Member]
Entity Information [Line Items]
Expected return on plan assets	4.45%	5.05%	5.05%
Indianapolis Power And Light Company
Entity Information [Line Items]
2016	$ 40,922
2017	41,855
2018	42,433
2019	43,191
2020	43,446
2021 through 2025 (in total)	$ 216,734
Expected return on plan assets	5.60%			4.45%
Indianapolis Power And Light Company | Pension Benefit [Member]
Entity Information [Line Items]
Expected return on plan assets	4.45%	5.05%	5.05%

Commitments and Contingencies (

Commitments and Contingencies (Narrative) (Details)	1 Months Ended
	Oct. 31, 2009 coal_fired_electric_generating_facility	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)
Entity Information [Line Items]
Coal, Gas, Purchased Power and Related Transportation Purchase Obligations, Net		$ 1,188,800
Other Purchase Obligations, Net		422,400
Coal, Gas, Purchased Power and Related Transportation Purchase Obligations Less Than 1 Year		323,300
Coal, Gas, Purchased Power and Related Transportation Purchase Obligations in Years 1 through 3		331,100
Coal, Gas, Purchased Power and Related Transportation Purchase Obligations Years 3 through 5		232,400
Coal, Gas, Purchased Power and Related Transportation Purchase Obligations After Year 5		302,000
Other Purchase Obligations, After Year 5		5,000
Other Purchase Obligations Years 3 through 5		8,800
Other Purchase Obligations Years 1 through 3		59,500
Other Purchase Obligations Less than 1 Year		349,100
Loss contingencies accrued			$ 200,000
Probable Insurance Recoveries Receivables		0	12,500,000
Other Assets, Noncurrent		849,054,000	873,923,000
Prepaid Implementation Costs for Software as a Service
Entity Information [Line Items]
Other Assets, Noncurrent		8,200,000	9,100,000
Indianapolis Power And Light Company
Entity Information [Line Items]
Number of facilities with violations of Federal Clean Air Act | coal_fired_electric_generating_facility	3
Coal, Gas, Purchased Power and Related Transportation Purchase Obligations, Net		1,188,800
Other Purchase Obligations, Net		422,400
Coal, Gas, Purchased Power and Related Transportation Purchase Obligations Less Than 1 Year		323,300
Coal, Gas, Purchased Power and Related Transportation Purchase Obligations in Years 1 through 3		331,100
Coal, Gas, Purchased Power and Related Transportation Purchase Obligations Years 3 through 5		232,400
Coal, Gas, Purchased Power and Related Transportation Purchase Obligations After Year 5		302,000
Other Purchase Obligations, After Year 5		5,000
Other Purchase Obligations Years 3 through 5		8,800
Other Purchase Obligations Years 1 through 3		59,500
Other Purchase Obligations Less than 1 Year		349,100
Loss contingencies accrued		100,000	200,000
Probable Insurance Recoveries Receivables		0	12,500,000
Other Assets, Noncurrent		833,536,000	870,212,000
Indianapolis Power And Light Company | Prepaid Implementation Costs for Software as a Service
Entity Information [Line Items]
Other Assets, Noncurrent		$ 8,200,000	$ 9,100,000

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Related Party Transaction [Line Items]
Self-insured retention per occurrence	$ 5
Insurance expense	9.5	$ 7	$ 5.6
Prepaid insurance				$ 3.4	$ 2.3
Health coverage expense	25.2	23.7	21
Income taxes receivable	18	15.6
Deferred Compensation Arrangement with Individual, Compensation Expense	0.2	0.2	0.3
Billings from related party				5.7	4.3	$ 6.5
Parent Loan Repayment	6.1
Service Company [Member]
Related Party Transaction [Line Items]
Costs incurred by related party	60.3	58.4	55.7
Prepaid balance to related party		5.9
Receivables from Related Party	2.1
Ipalco Enterprises, Inc. [Member]
Related Party Transaction [Line Items]
Costs incurred by related party	10	10.4	10.6
Indianapolis Power And Light Company
Related Party Transaction [Line Items]
Self-insured retention per occurrence	5
Insurance expense	9.5	7	5.6
Prepaid insurance				$ 3.4	$ 2.3
Health coverage expense	25.2	23.7	21
Income taxes receivable	6.7	6.7
Deferred Compensation Arrangement with Individual, Compensation Expense	0.2	0.2	0.3
Costs incurred by related party	10	10.4	10.6
Prepaid balance to related party		5.9
Billings from related party	5.7	4.3	6.5
Loans to Parent, net of repayments	6.1
Loans to Parent, net of repayments	6.1
Indianapolis Power And Light Company | Service Company [Member]
Related Party Transaction [Line Items]
Costs incurred by related party	$ 60.1	$ 58.2	$ 55.5

Business Segment Information (D

Business Segment Information (Details)	12 Months Ended
	Dec. 31, 2022 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, 2022	Dec. 31, 2021	Dec. 31, 2020
Segment Reporting Information [Line Items]
REVENUES	$ 1,791,711	$ 1,426,132	$ 1,352,985
Depreciation and amortization	266,504	256,085	246,896
Interest Expense	131,232	125,626	129,493
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest	118,485	148,123	138,559
Property, Plant and Equipment, Additions	496,510	291,546	235,736
Tax benefit	21,859	28,941	28,592
Net income	96,626	119,182	109,967
TOTAL ASSETS	5,589,214	5,239,767	4,969,919
Accruals for capital expenditures	66,949	81,325	54,360
Financed Capital Expenditures	0	36	36
Electric [Member]
Segment Reporting Information [Line Items]
REVENUES	1,791,711	1,426,132	1,352,985
Depreciation and amortization	266,504	256,085	246,896
Interest Expense	87,428	84,256	87,281
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest	162,862	189,548	184,174
Property, Plant and Equipment, Additions		291,546	235,736
TOTAL ASSETS	5,559,977	5,222,987	4,952,408
Other Segments [Member]
Segment Reporting Information [Line Items]
Depreciation and amortization	0	0	0
Interest Expense	43,804	41,370	42,212
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest	(44,377)	(41,425)	(45,615)
Property, Plant and Equipment, Additions	0	0	0
TOTAL ASSETS	$ 29,237	$ 16,780	$ 17,511

Revenue (Details)

Revenue (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Jan. 31, 2018
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	$ 1,760,000			$ 1,389,200	$ 1,326,600
REVENUES	1,791,711	$ 1,426,132	$ 1,352,985
Contract with Customer, Asset, before Allowance for Credit Loss				198,300		$ 163,000
Contract with Customer, Liability, Revenue Recognized	0	500
Contract with Customer, Liability, Revenue Recognized	0	500
Retail Revenue [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	1,589,170	1,351,431	1,269,319
Other non-606 revenue	29,171	35,248	24,781
Retail Revenue [Member] | Utility
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	17,845	16,785	14,402
Retail Revenue [Member] | Residential Revenue | Utility
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	688,487	595,692	566,668
Retail Revenue [Member] | Small Commercial and Industrial | Utility
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	247,655	211,997	194,904
Retail Revenue [Member] | Large Commercial and Industrial | Utility
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	625,351	518,069	484,230
Retail Revenue [Member] | Public Lighting | Utility
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	9,832	8,888	9,115
Wholesale Revenue [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	148,517	25,059	46,482
Miscellaneous revenue [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	22,284	12,214	10,794
RTO Capacity Revenue	11,750	734	1,477
Other non-606 revenue	2,569	2,180	1,609
Miscellaneous revenue [Member] | Transmission revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	10,534	11,480	9,317
Electricity [Member]
Disaggregation of Revenue [Line Items]
REVENUES	1,791,711	1,426,132	1,352,985
Indianapolis Power And Light Company
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	1,760,000	1,389,200	1,326,600
REVENUES	1,791,711	1,426,132	1,352,985
Contract with Customer, Asset, before Allowance for Credit Loss				$ 198,300		$ 163,000
Contract with Customer, Liability, Revenue Recognized	0	500
Contract with Customer, Liability, Revenue Recognized	0	500
Indianapolis Power And Light Company | Retail Revenue [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	1,589,170	1,351,431	1,269,319
Other non-606 revenue	29,171	35,248	24,781
Indianapolis Power And Light Company | Retail Revenue [Member] | Utility
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	17,845	16,785	14,402
Indianapolis Power And Light Company | Retail Revenue [Member] | Residential Revenue | Utility
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	688,487	595,692	566,668
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	247,655	211,997	194,904
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	625,351	518,069	484,230
Indianapolis Power And Light Company | Retail Revenue [Member] | Public Lighting | Utility
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	9,832	8,888	9,115
Indianapolis Power And Light Company | Wholesale Revenue [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	148,517	25,059	46,482
Indianapolis Power And Light Company | Miscellaneous revenue [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	22,284	12,214	10,794
RTO Capacity Revenue	11,750	734	1,477
Other non-606 revenue	2,569	2,180	1,609
Indianapolis Power And Light Company | Miscellaneous revenue [Member] | Transmission revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	10,534	11,480	9,317
Indianapolis Power And Light Company | Electricity [Member]
Disaggregation of Revenue [Line Items]
REVENUES	$ 1,791,711	$ 1,426,132	$ 1,352,985

Leases (Details)

Leases (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Lessee, Lease, Description [Line Items]
Property Subject to or Available for Operating Lease, Accumulated Depreciation	$ (1,060)	$ (979)
Property, Plant, and Equipment, Lessor Asset under Operating Lease, after Accumulated Depreciation	3,274	3,424
Property Subject to or Available for Operating Lease, Gross	4,334	4,403
Lessor, Operating Lease, Payment to be Received, Year One	544
Lessor, Operating Lease, Payment to be Received, Year Two	544
Lessor, Operating Lease, Payment to be Received, Year Three	553
Lessor, Operating Lease, Payment to be Received, Year Four	554
Lessor, Operating Lease, Payment to be Received, Year Five	554
Lessor, Operating Lease, Payment to be Received, after Year Five	$ 1,245
Future Minimum Lease Receipts	The following table shows the future minimum lease receipts through 2027 and thereafter (in thousands): Operating Leases 2023 $ 544 2024 544 2025 553 2026 554 2027 554 Thereafter 1,245 Total $ 3,994
Operating Lease, Lease Income	$ 1,134	1,439	$ 941
Lessor, Operating Lease, Payments to be Received	3,994
Right-of-Use Asset Obtained in Exchange for Finance Lease Liability	(3,402)	19,763	0
Finance Lease, Liability, Current	0	294
Finance Lease, Liability, Noncurrent	16,361	19,469
Finance Lease, Liability	$ 16,361	$ 19,763
Finance Lease, Weighted Average Remaining Lease Term	36 years	31 years
Finance Lease, Weighted Average Discount Rate, Percent	5.65%	4.561%
Finance Lease, Liability, to be Paid, Remainder of Fiscal Year	$ 802
Finance Lease, Liability, Payments, Due in Rolling Year Two	818
Finance Lease, Liability, to be Paid, Year Three	834
Finance Lease, Liability, to be Paid, Year Four	851
Finance Lease, Liability, to be Paid, Year Five	868
Finance Lease, Liability, to be Paid, after Year Five	37,546
Total Future Lease Payments	41,719
Imputed interest	(25,358)
Finance Lease, Right-of-Use Asset, Amortization	542	$ 0	0
Finance Lease, Interest Expense	782	0	0
Lease, Cost	1,324	0	0
Operating Lease, Payments, Use	300	0	0
Finance Lease, Right-of-Use Asset, before Accumulated Amortization	15,819	19,763
Subsidiaries [Member]
Lessee, Lease, Description [Line Items]
Property Subject to or Available for Operating Lease, Accumulated Depreciation	1,060	979
Property, Plant, and Equipment, Lessor Asset under Operating Lease, after Accumulated Depreciation	3,274	3,424
Property Subject to or Available for Operating Lease, Gross	4,334	4,403
Lessor, Operating Lease, Payment to be Received, Year One	544
Lessor, Operating Lease, Payment to be Received, Year Two	544
Lessor, Operating Lease, Payment to be Received, Year Three	553
Lessor, Operating Lease, Payment to be Received, Year Four	554
Lessor, Operating Lease, Payment to be Received, Year Five	554
Lessor, Operating Lease, Payment to be Received, after Year Five	$ 1,245
Future Minimum Lease Receipts	The following table shows the future minimum lease receipts through 2027 and thereafter (in thousands): Operating Leases 2023 $ 544 2024 544 2025 553 2026 554 2027 554 Thereafter 1,245 Total $ 3,994
Operating Lease, Lease Income	$ 1,134	1,439	941
Lessor, Operating Lease, Payments to be Received	3,994
Right-of-Use Asset Obtained in Exchange for Finance Lease Liability	15,819	19,763
Finance Lease, Liability, Current	0	294
Finance Lease, Liability, Noncurrent	16,361	19,469
Finance Lease, Liability	$ 16,361	$ 19,763
Finance Lease, Weighted Average Remaining Lease Term	36 years	31 years
Finance Lease, Weighted Average Discount Rate, Percent	565%	4.561%
Finance Lease, Liability, to be Paid, Remainder of Fiscal Year	$ 802
Finance Lease, Liability, Payments, Due in Rolling Year Two	818
Finance Lease, Liability, to be Paid, Year Three	834
Finance Lease, Liability, to be Paid, Year Four	851
Finance Lease, Liability, to be Paid, Year Five	868
Finance Lease, Liability, to be Paid, after Year Five	37,546
Total Future Lease Payments	41,719
Imputed interest	(25,358)
Finance Lease, Right-of-Use Asset, Amortization	542	$ 0	0
Finance Lease, Interest Expense	782	0	0
Lease, Cost	1,324	$ 0	$ 0
Operating Lease, Payments, Use	$ 300

Risks and Uncertainties (Detail

Risks and Uncertainties (Details)	12 Months Ended
	Dec. 31, 2022
Unusual Risk or Uncertainty [Line Items]
Unusual Risks and Uncertainties

Schedule I - Condensed Financ_2

Schedule I - Condensed Financial Information Of Registrant (Narrative) (Details) MWh in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2022 USD ($) MWh	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)
Condensed Financial Statements, Captions [Line Items]
Ownership percentage by parent	82.35%
Equity contributions from shareholders	$ 253,000	$ 275,000	$ 0
Investments, Fair Value Disclosure	3,228	3,605
Forward Power Contracts Fair Value Disclosure	12,172	0
Total financial assets measured at fair value	22,945	4,840
Total financial liabilities measured at fair value	0	49,382
Unobservable Inputs (Level 3) [Member]
Condensed Financial Statements, Captions [Line Items]
Investments, Fair Value Disclosure	0	0
Total financial assets measured at fair value	7,545	1,235
Total financial liabilities measured at fair value	0	0
Fair Value, Inputs, Level 1 [Member]
Condensed Financial Statements, Captions [Line Items]
Investments, Fair Value Disclosure	3,228	11
Total financial assets measured at fair value	3,228	11
Total financial liabilities measured at fair value	0	0
Significant Observable Inputs (Level 2) [Member]
Condensed Financial Statements, Captions [Line Items]
Investments, Fair Value Disclosure	0	3,594
Total financial assets measured at fair value	12,172	3,594
Total financial liabilities measured at fair value	0	49,382
Mutual Fund [Member]
Condensed Financial Statements, Captions [Line Items]
Investments, Fair Value Disclosure	3,223	3,594
Money Market Funds [Member]
Condensed Financial Statements, Captions [Line Items]
Investments, Fair Value Disclosure	5	11
Ipalco Enterprises, Inc. [Member]
Condensed Financial Statements, Captions [Line Items]
Equity contributions from shareholders	253,000	275,000	0
Investments, Fair Value Disclosure	3,228	3,605
Forward Power Contracts Fair Value Disclosure	12,172	0
Total financial assets measured at fair value	15,400	3,605
Interest Rate Cash Flow Hedge Liability at Fair Value	0	49,382
Total financial liabilities measured at fair value	0	49,382
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
Total financial liabilities 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	3,228	11
Forward Power Contracts Fair Value Disclosure	0	0
Total financial assets measured at fair value	3,228	11
Total financial liabilities measured at fair value	0	0
Ipalco Enterprises, Inc. [Member] | Significant Observable Inputs (Level 2) [Member]
Condensed Financial Statements, Captions [Line Items]
Investments, Fair Value Disclosure	0	3,594
Forward Power Contracts Fair Value Disclosure	12,172	0
Total financial assets measured at fair value	12,172	3,594
Total financial liabilities measured at fair value	0	49,382
Ipalco Enterprises, Inc. [Member] | Mutual Fund [Member]
Condensed Financial Statements, Captions [Line Items]
Investments, Fair Value Disclosure	3,223	3,594
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	3,223	0
Ipalco Enterprises, Inc. [Member] | Mutual Fund [Member] | Significant Observable Inputs (Level 2) [Member]
Condensed Financial Statements, Captions [Line Items]
Investments, Fair Value Disclosure	0	3,594
Ipalco Enterprises, Inc. [Member] | Money Market Funds [Member]
Condensed Financial Statements, Captions [Line Items]
Investments, Fair Value Disclosure	5	11
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	5	11
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	253,000	275,000	$ 0
Total financial assets measured at fair value	7,545	1,235
Subsidiaries [Member] | Unobservable Inputs (Level 3) [Member]
Condensed Financial Statements, Captions [Line Items]
Total financial assets measured at fair value	7,545	1,235
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	5,388
Sale of Units Derivative Instruments Financial Transmission Rights | MWh	0
Derivative, Nonmonetary Notional Amount, Purchase (Sales), Net | MWh	5,388
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	5,388
Sale of Units Derivative Instruments Financial Transmission Rights | MWh	0
Derivative, Nonmonetary Notional Amount, Purchase (Sales), Net | MWh	5,388

Schedule I - Condensed Financ_3

Schedule I - Condensed Financial Information Of Registrant (Unconsolidated Balance Sheet) (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Condensed Financial Statements, Captions [Line Items]
Cash and cash equivalents	$ 201,548	$ 6,912
Total current assets	706,829	407,499
Derivative Asset, Noncurrent	12,172	0
Total other non-current assets	849,054	873,923
TOTAL ASSETS	5,589,214	5,239,767	$ 4,969,919
Short-term debt	0	60,294
Accounts payable	189,845	179,834
Accumulated deficit	(108)	(24,558)
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	1,090,518	794,600	520,988	$ 546,476
Long-term debt	3,000,450	2,652,186
Deferred Income Taxes and Other Tax Liabilities, Noncurrent	7,329	0
Derivative Liability, Noncurrent	0	49,382
Accrued interest	33,447	30,634
Total current liabilities	323,225	348,513
Total non-current liabilities	4,175,471	4,036,870
Liabilities	4,498,696	4,385,383
Additional Paid in Capital	1,068,357	848,565
Accumulated Other Comprehensive Income (Loss), Net of Tax	22,269	(29,407)	(43,420)	(19,750)
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	5,589,214	5,239,767
Restricted Cash and Cash Equivalents	5	5
Income Taxes Receivable, Current	18,000	15,566
Other Assets, Current	27,427	40,173
Parent Company [Member]
Condensed Financial Statements, Captions [Line Items]
Cash and cash equivalents	191	1,902
Total current assets	19,018	18,365
Investment in subsidiaries	1,945,556	1,693,176
Deferred Tax Assets, Net	0	9,655
Other Assets	3,211	3,577
Total other non-current assets	1,960,939	1,706,408
TOTAL ASSETS	1,979,957	1,724,773
Accounts payable	87	277
Accumulated deficit	(108)	(24,558)
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	1,090,518	794,600	520,988	546,476
Long-term debt	873,663	872,154
Derivative Liability, Noncurrent	0	49,382
Accrued interest	8,360	8,360
Total current liabilities	8,447	8,637
Total non-current liabilities	880,992	921,536
Liabilities	889,439	930,173
Additional Paid in Capital	1,068,357	848,565
Accumulated Other Comprehensive Income (Loss), Net of Tax	22,269	(29,407)	$ (43,420)	$ (19,750)
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	1,979,957	1,724,773
Income Taxes Receivable, Current	11,318	8,912
Other Assets, Current	$ 7,509	$ 7,551

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, 2022	Dec. 31, 2021	Dec. 31, 2020
Condensed Financial Statements, Captions [Line Items]
Interest Expense	$ (131,232)	$ (125,626)	$ (129,493)
Loss on early extinguishment of debt	(237)	0	(2,424)
Other income / (expense), net	12,020	17,667	3,370
Total other income / (expense), net	(114,665)	(102,547)	(123,973)
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest	118,485	148,123	138,559
Less: income tax expense	21,859	28,941	28,592
Net income	96,626	119,182	109,967
Parent Company [Member]
Condensed Financial Statements, Captions [Line Items]
Equity in earnings of subsidiaries	126,466	147,030	140,030
Interest Expense	(43,805)	(41,380)	(42,212)
Loss on early extinguishment of debt	0	0	(2,400)
Other income / (expense), net	(571)	(45)	73
Total other income / (expense), net	82,090	105,605	95,476
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest	82,090	105,605	95,476
Less: income tax expense	(11,027)	(10,364)	(11,278)
Net income	$ 93,117	$ 115,969	$ 106,754

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, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Condensed Financial Statements, Captions [Line Items]
Interest Paid, Excluding Capitalized Interest, Operating Activities	$ 115,277	$ 118,052	$ 122,938
Net income	96,626	119,182	109,967
Amortization of debt issuance costs and discounts	(3,914)	(3,915)	(3,942)
Increase (Decrease) in Accounts Payable	32,038	21,417	(20,322)
Accrued and other current liabilities	6,532	(13,017)	(8,214)
Other - net	5,098	(2,026)	(4,761)
Net cash provided by operating activities	346,346	225,217	295,425
Payments for (Proceeds from) Other Investing Activities	(719)	(14,380)	(18,184)
Net cash used in investing activities	(525,087)	(368,715)	(275,769)
Long-term borrowings, net of discount	350,000	95,000	565,000
Retirement of long-term debt	0	95,000	562,135
Distributions to shareholders	101,986	131,476	108,739
Other - net	35	131	153
Net cash provided by (used in) financing activities	373,377	123,793	(41,586)
Income Taxes Paid, Net	31,000	27,500	27,000
Accrued taxes payable/receivable	(5,858)	638	6,695
Accrued interest	2,813	(1,099)	(3,601)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	201,553	6,917	26,622	$ 48,552
Net change in cash, cash equivalents and restricted cash	194,636	(19,705)	(21,930)
Equity contributions from shareholders	253,000	275,000	0
Parent Company [Member]
Condensed Financial Statements, Captions [Line Items]
Interest Paid, Excluding Capitalized Interest, Operating Activities	35,173	35,172	38,069
Net income	93,117	115,969	106,754
Equity in earnings of subsidiaries	(126,466)	(147,030)	(140,030)
Cash dividends received from subsidiary companies	127,200	155,700	147,600
Amortization of debt issuance costs and discounts	(1,403)	(1,379)	(1,607)
Deferred income taxes - net	(121)	(5)	(224)
Charges related to early extinguishment of debt	237	0	2,415
Increase (Decrease) in Accounts Payable	(194)	(85)	299
Other - net	7,507	4,265	5,005
Net cash provided by operating activities	100,277	133,133	109,026
Investment in subsidiaries	(253,000)	(275,000)	0
Net cash used in investing activities	(253,000)	(275,000)	0
Long-term borrowings, net of discount	0	0	474,568
Retirement of long-term debt	0	0	(472,135)
Distributions to shareholders	101,986	131,476	(108,739)
Other - net	2	62	6,122
Net cash provided by (used in) financing activities	151,012	137,352	(106,318)
Income Taxes Paid, Net	31,000	27,500	27,000
Accrued taxes payable/receivable	(2,406)	2,940	(11,317)
Accrued interest	0	0	(3,083)
Repayments of Loans to Subsidiary	0	6,110	20,000
Loans from Subsidiary	0	0	26,110
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	191	1,902	6,417	$ 3,709
Net change in cash, cash equivalents and restricted cash	(1,711)	(4,515)	2,708
Equity contributions from shareholders	$ 253,000	$ 275,000	$ 0

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, 2022	Dec. 31, 2021	Dec. 31, 2020
Condensed Financial Statements, Captions [Line Items]
Other Comprehensive Income (Loss), Net of Tax	$ 51,676	$ 14,013	$ (23,670)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning Balance	794,600	520,988	546,476
Net income applicable to common stock	93,117	115,969	106,754
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	144,793	129,982	83,084
Distributions to AES	(101,986)	(131,476)	(108,739)
Equity contributions from shareholders	253,000	275,000	0
Other	111	106	167
Ending Balance	1,090,518	794,600	520,988
Parent Company [Member]
Condensed Financial Statements, Captions [Line Items]
Other Comprehensive Income (Loss), Net of Tax	51,676	14,013	(23,670)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning Balance	794,600	520,988	546,476
Net income applicable to common stock	93,117	115,969	106,754
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	144,793	129,982	83,084
Distributions to AES	101,986	131,476	108,739
Equity contributions from shareholders	253,000	275,000	0
Other	111	106	167
Ending Balance	1,090,518	794,600	520,988
Paid In Capital [Member]
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning Balance	848,565	588,966	590,784
Return of Capital	(33,319)	(15,507)	(1,985)
Equity contributions from shareholders	253,000	275,000
Other	111	106	167
Ending Balance	1,068,357	848,565	588,966
Paid In Capital [Member] | Parent Company [Member]
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning Balance	848,565	588,966	590,784
Return of Capital	(33,319)	(15,507)	(1,985)
Equity contributions from shareholders	253,000
Other	111	106	167
Ending Balance	1,068,357	848,565	588,966
AOCI Attributable to Parent [Member]
Condensed Financial Statements, Captions [Line Items]
Other Comprehensive Income (Loss), Net of Tax	51,676	14,013	(23,670)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning Balance	(29,407)	(43,420)	(19,750)
Ending Balance	22,269	(29,407)	(43,420)
AOCI Attributable to Parent [Member] | Parent Company [Member]
Condensed Financial Statements, Captions [Line Items]
Other Comprehensive Income (Loss), Net of Tax	51,676	14,013	(23,670)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning Balance	(29,407)	(43,420)	(19,750)
Ending Balance	22,269	(29,407)	(43,420)
Accumulated Deficit [Member]
Condensed Financial Statements, Captions [Line Items]
Other Comprehensive Income (Loss), Net of Tax		0	0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning Balance	(24,558)	(24,558)	(24,558)
Net income applicable to common stock	96,626	119,182	109,967
Distributions to AES	(68,667)	(115,969)	(106,754)
Ending Balance	(108)	(24,558)	(24,558)
Accumulated Deficit [Member] | Parent Company [Member]
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning Balance	(24,558)	(24,558)	(24,558)
Net income applicable to common stock	93,117	115,969	106,754
Distributions to AES	68,667	115,969	106,754
Ending Balance	$ (108)	$ (24,558)	$ (24,558)

Schedule I - Condensed Financ_7

Schedule I - Condensed Financial Information Of Registrant (Long-Term Indebtedness) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Condensed Financial Statements, Captions [Line Items]
Unamortized discount - net	$ (7,100)	$ (6,400)
Debt Issuance Costs, Net	(26,300)	(25,200)
Long-term debt	3,000,450	2,652,186
Current portion of long-term debt	0	0
Net Long-term Debt	3,000,450	2,652,186
Loss on early extinguishment of debt	237	0	$ 2,424
Parent Company [Member]
Condensed Financial Statements, Captions [Line Items]
Unamortized discount - net	(425)	(527)
Debt Issuance Costs, Net	(5,912)	(7,319)
Long-term debt	873,663	872,154
Current portion of long-term debt	0	0
Net Long-term Debt	873,663	872,154
Loss on early extinguishment of debt	0	0	$ 2,400
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, 2022	Dec. 31, 2021	Dec. 31, 2020
Condensed Statement of Income Captions [Line Items]
Net Income (Loss) Available to Common Stockholders, Basic	$ 93,117	$ 115,969	$ 106,754
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	46,245	10,393	(27,779)
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax	51,676	14,013	(23,670)
Other Comprehensive Income (Loss), Net of Tax	51,676	14,013	(23,670)
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	144,793	129,982	83,084
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax	(15,309)	(3,441)	8,876
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Tax	(1,798)	(1,199)	(1,313)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	5,431	3,620	4,109
Less: dividends on and redemption of preferred stock	3,509	3,213	3,213
Parent Company [Member]
Condensed Statement of Income Captions [Line Items]
Net Income (Loss) Available to Common Stockholders, Basic	93,117	115,969	106,754
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	46,245	10,393	(27,779)
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax	51,676	14,013	(23,670)
Other Comprehensive Income (Loss), Net of Tax	51,676	14,013	(23,670)
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	144,793	129,982	83,084
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax	(15,309)	(3,441)	8,876
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Tax	(1,798)	(1,199)	(1,313)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	5,431	3,620	4,109
Subsidiaries [Member]
Condensed Statement of Income Captions [Line Items]
Net Income (Loss) Available to Common Stockholders, Basic	126,466	147,030	140,827
Less: dividends on and redemption of preferred stock	$ 3,509	$ 3,213	$ 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, 2022 USD ($) MWh	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)
Number of Interest Rate Swaps	3
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	$ 46,245,000	$ 10,393,000	$ (27,779,000)
Accumulated Other Comprehensive Income (Loss), Net of Tax	22,269,000	(29,407,000)	(43,420,000)	$ (19,750,000)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	46,245,000	10,393,000	(27,779,000)
Reclassification from AOCI, Current Period, Net of Tax, Attributable to Parent	5,431,000	3,620,000	4,109,000
Interest Rate Contract [Member]
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax	22,269,000	(29,407,000)	(43,420,000)
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	21 years
Not Designated as Hedging Instrument [Member] | FTR [Member]
Purchase of Units Derivative Instruments Financial Transmission Rights | MWh	5,388
Sale of Units Derivative Instruments Financial Transmission Rights | MWh	0
Derivative, Nonmonetary Notional Amount, Purchase (Sales), Net | MWh	5,388
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	12,172,000,000	0
Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | Other Current Assets [Member]
Derivative Liability, Fair Value, Gross Liability	0	49,382,000
Parent Company [Member]
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	46,245,000	10,393,000	(27,779,000)
Accumulated Other Comprehensive Income (Loss), Net of Tax	22,269,000	(29,407,000)	(43,420,000)	$ (19,750,000)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	46,245,000	10,393,000	(27,779,000)
Reclassification from AOCI, Current Period, Net of Tax, Attributable to Parent	5,431,000	3,620,000	4,109,000
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	22,269,000	(29,407,000)	$ (43,420,000)
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	21 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	12,172,000,000	0
Parent Company [Member] | Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | Other Current Assets [Member]
Derivative Liability, Fair Value, Gross Liability	$ 0	$ 49,382,000,000

Schedule I - Condensed Finan_10

Schedule I - Condensed Financial Information Of Registrant (Fair Value) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Apr. 08, 2020
Condensed Financial Information Disclosure [Abstract]
Total financial assets measured at fair value	$ 22,945	$ 4,840
Investments, Fair Value Disclosure	3,228	3,605
Total financial assets measured at fair value	22,945	4,840
Total financial liabilities measured at fair value	0	49,382
Face Value	3,033,800	2,743,800
Fair Value	2,775,644	3,229,118
Long-term debt	3,000,450	2,652,186
Loss on early extinguishment of debt	237	0	$ 2,424
Debt Issuance Costs, Net	26,300	25,200
Debt Instrument, Unamortized Discount	7,100	6,400
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	2,683,800
Fair Value	2,775,644	3,169,118
Variable Rate [Member]
Face Value	0	60,000
Fair Value	0	60,000
Parent Company [Member]
Condensed Financial Information Disclosure [Abstract]
Total financial assets measured at fair value	15,400	3,605
Investments, Fair Value Disclosure	3,228	3,605
Total financial assets measured at fair value	15,400	3,605
Total financial liabilities measured at fair value	0	49,382
Face Value	880,000	880,000
Fair Value	816,411	946,346
Long-term debt	873,663	872,154
Loss on early extinguishment of debt	0	0	2,400
Debt Issuance Costs, Net	5,912	7,319
Debt Instrument, Unamortized Discount	425	527
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	816,411	946,346
Parent Company [Member] | Variable Rate [Member]
Face Value	0	0
Fair Value	$ 0	0
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
Parent Company [Member] | FMB Twenty - three
First mortgage bonds			65,000
Subsidiaries [Member]
Condensed Financial Information Disclosure [Abstract]
Total financial assets measured at fair value	7,545	1,235
Total financial assets measured at fair value	7,545	1,235
Face Value	2,153,800	1,863,800
Fair Value	1,959,233	2,282,772
Long-term debt	2,126,787	1,780,032
First mortgage bonds	2,126,787	1,780,032
Loss on early extinguishment of debt			2,415
Debt Issuance Costs, Net	20,400	17,900
Debt Instrument, Unamortized Discount	6,651	5,855
Subsidiaries [Member] | Fixed Rate [Member]
Face Value	2,153,800	1,803,800
Fair Value	1,959,233	2,222,772
Subsidiaries [Member] | Variable Rate [Member]
Face Value	0	60,000
Fair Value	$ 0	60,000
Subsidiaries [Member] | Four Point Two Five Percent Senior Secured Notes
Debt instrument, stated interest rate	4.25%
Long-term debt	$ 475,000
Subsidiaries [Member] | FMB Twenty - three
Debt instrument, stated interest rate	0.95%
First mortgage bonds	$ 60,000	60,000	$ 65,000
Fair Value, Inputs, Level 1 [Member]
Condensed Financial Information Disclosure [Abstract]
Total financial assets measured at fair value	3,228	11
Investments, Fair Value Disclosure	3,228	11
Total financial assets measured at fair value	3,228	11
Total financial liabilities measured at fair value	0	0
Fair Value, Inputs, Level 1 [Member] | Parent Company [Member]
Condensed Financial Information Disclosure [Abstract]
Total financial assets measured at fair value	3,228	11
Investments, Fair Value Disclosure	3,228	11
Total financial assets measured at fair value	3,228	11
Total financial liabilities measured at fair value	0	0
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	12,172	3,594
Investments, Fair Value Disclosure	0	3,594
Total financial assets measured at fair value	12,172	3,594
Total financial liabilities measured at fair value	0	49,382
Significant Observable Inputs (Level 2) [Member] | Parent Company [Member]
Condensed Financial Information Disclosure [Abstract]
Total financial assets measured at fair value	12,172	3,594
Investments, Fair Value Disclosure	0	3,594
Total financial assets measured at fair value	12,172	3,594
Total financial liabilities measured at fair value	0	49,382
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	7,545	1,235
Investments, Fair Value Disclosure	0	0
Total financial assets measured at fair value	7,545	1,235
Total financial liabilities measured at fair value	0	0
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
Total financial liabilities 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	7,545	1,235
Total financial assets measured at fair value	7,545	1,235
Money Market Funds [Member]
Investments, Fair Value Disclosure	5	11
Money Market Funds [Member] | Parent Company [Member]
Investments, Fair Value Disclosure	5	11
Money Market Funds [Member] | Fair Value, Inputs, Level 1 [Member] | Parent Company [Member]
Investments, Fair Value Disclosure	5	11
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	3,223	3,594
Mutual Fund [Member] | Parent Company [Member]
Investments, Fair Value Disclosure	3,223	3,594
Mutual Fund [Member] | Fair Value, Inputs, Level 1 [Member] | Parent Company [Member]
Investments, Fair Value Disclosure	3,223	0
Mutual Fund [Member] | Significant Observable Inputs (Level 2) [Member] | Parent Company [Member]
Investments, Fair Value Disclosure	0	3,594
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, 2022	Dec. 31, 2021	Dec. 31, 2020
SEC Schedule, 12-09, Allowance, Credit Loss [Member]
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
Balance at beginning of period	$ 647	$ 3,155	$ 2,053
Charged to Income	7,478	3,940	5,861
Net Write-offs	7,008	6,448	3,627
Balance at End of Period	1,117	647	3,155
SEC Schedule, 12-09, Valuation Allowances and Reserves, Additions, Charge to Other Account	0	0	(1,132)
SEC Schedule, 12-09, Reserve, Inventory
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
Balance at beginning of period	3,107	6,133	6,204
Charged to Income	2,053	758	0
Net Write-offs	0	3,784	71
Balance at End of Period	5,160	3,107	6,133
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	647	3,155	2,053
Charged to Income	7,478	3,940	5,861
Net Write-offs	7,008	6,448	3,627
Balance at End of Period	1,117	647	3,155
SEC Schedule, 12-09, Valuation Allowances and Reserves, Additions, Charge to Other Account	0	0	(1,132)
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	3,107	6,133	6,204
Charged to Income	2,053	758	0
Net Write-offs	0	3,784	71
Balance at End of Period	5,160	3,107	6,133
SEC Schedule, 12-09, Valuation Allowances and Reserves, Additions, Charge to Other Account	$ 0	$ 0	$ 0