Constellation Energy (CEG) 10-K16 Feb 232022 FY Annual reportFinancial data

Company Profile

Cover Page

Cover Page - USD ($)	12 Months Ended
Cover Page - USD ($)	Dec. 31, 2022	Jan. 31, 2023	Jun. 30, 2022
Document Information [Line Items]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2022
Current Fiscal Year End Date	--12-31
Document Transition Report	false
Entity File Number	001-41137
Entity Registrant Name	CONSTELLATION ENERGY CORPORATION
Entity Tax Identification Number	87-1210716
Entity Incorporation, State or Country Code	PA
Entity Address, Address Line One	1310 Point Street
Entity Address, City or Town	Baltimore
Entity Address, State or Province	MD
Entity Address, Postal Zip Code	21231-3380
City Area Code	(833)
Local Phone Number	883-0162
Title of 12(b) Security	Common Stock, without par value
Trading Symbol	CEG
Security Exchange Name	NASDAQ
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Entity Shell Company	false
Entity Public Float			$ 18,711,601,222
Entity Common Stock Shares Outstanding		327,131,082
Documents Incorporated by Reference [Text Block]	Documents Incorporated by Reference Portions of the Registrants’ Definitive Proxy Statement relating to the 2023 Annual Meeting of Shareholders are incorporated by reference into Part III of this report. The Registrants expect to file the Definitive Proxy Statement with the Securities and Exchange Commission within 120 days after December 31, 2022.
Document Fiscal Year Focus	2022
Document Fiscal Period Focus	FY
Entity Central Index Key	0001868275
Amendment Flag	false
Constellation Energy Generation, LLC
Document Information [Line Items]
Entity File Number	333-85496
Entity Registrant Name	CONSTELLATION ENERGY GENERATION, LLC
Entity Tax Identification Number	23-3064219
Entity Incorporation, State or Country Code	PA
Entity Address, Address Line One	200 Exelon Way
Entity Address, City or Town	Kennett Square
Entity Address, State or Province	PA
Entity Address, Postal Zip Code	19348-2473
City Area Code	(833)
Local Phone Number	883-0162
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Central Index Key	0001168165

Audit Information

Audit Information	12 Months Ended
Audit Information	Dec. 31, 2022
Audit Information [Abstract]
Auditor Name	PricewaterhouseCoopers LLP
Auditor Location	Baltimore, Maryland
Auditor Firm ID	238

Consolidated Statements of Oper

Consolidated Statements of Operations and Comprehensive Income, Parent - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Operating revenues
Operating revenues	$ 24,280	$ 18,461	$ 16,392
Operating revenues from affiliates	160	1,188	1,211
Total operating revenues	24,440	19,649	17,603
Operating expenses
Purchased power and fuel	17,457	12,157	9,592
Purchased power and fuel from affiliates	5	6	(7)
Operating and maintenance	4,797	3,934	4,613
Operating and maintenance from affiliates	44	621	555
Depreciation and amortization	1,091	3,003	2,123
Taxes other than income taxes	552	475	482
Total operating expenses	23,946	20,196	17,358
Gain on sales of assets and businesses	1	201	11
Operating income (loss)	495	(346)	256
Other income and (deductions)
Interest expense, net	(250)	(282)	(328)
Interest expense to affiliates	(1)	(15)	(29)
Other, net	(786)	795	937
Total other income and (deductions)	(1,037)	498	580
(Loss) income before income taxes	(542)	152	836
Income taxes	(388)	225	249
Equity in losses of unconsolidated affiliates	(13)	(10)	(8)
Net (loss) income	(167)	(83)	579
Net (loss) income attributable to noncontrolling interests	(7)	122	(10)
Net (loss) income attributable to common shareholders	(160)	(205)	589
Comprehensive income (loss), net of income taxes
Net (loss) income	(167)	(83)	579
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	(6)	0	0
Actuarial loss reclassified to periodic cost	101	0	0
Pension and non-pension postretirement benefit plans valuation adjustment	186	0	0
Unrealized loss on cash flow hedges	(1)	(1)	(2)
Unrealized (loss) gain on foreign currency translation	(3)	0	4
Other comprehensive income (loss), net of income taxes	277	(1)	2
Comprehensive income (loss)	110	(84)	581
Comprehensive (loss) income attributable to noncontrolling interests	(7)	122	(10)
Comprehensive income (loss) attributable to common shareholders	$ 117	$ (206)	$ 591
Average shares of common stock outstanding:
Basic (in shares)	328	0	0
Assumed exercise and/or distributions of stock-based awards (in shares)	1	0	0
Diluted (in shares)	329	0	0
Earnings per average common share
Basic (in dollars per share)	$ (0.49)	$ 0	$ 0
Diluted (in dollars per share)	$ (0.49)	$ 0	$ 0

Consolidated Statements of Cash

Consolidated Statements of Cash Flows, Parent - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Cash flows from operating activities
Net (loss) income	$ (167)	$ (83)	$ 579
Adjustments to reconcile net (loss) income to net cash flows (used in) provided by operating activities
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization	2,427	4,540	3,636
Asset impairments	0	545	563
Gain on sales of assets and businesses	(1)	(201)	(11)
Deferred income taxes and amortization of ITC	(643)	(205)	78
Net fair value changes related to derivatives	986	(568)	(270)
Net realized and unrealized losses (gains) on NDT funds	794	(586)	(461)
Net realized and unrealized losses (gains) on equity investments	13	160	(186)
Other non-cash operating activities	249	(605)	18
Changes in assets and liabilities:
Accounts receivable	(868)	(616)	1,125
Receivables from and payables to affiliates, net	20	14	24
Inventories	(228)	(68)	(77)
Accounts payable and accrued expenses	1,142	346	(343)
Option premiums paid, net	(177)	(338)	(139)
Collateral (posted) received, net	(351)	(130)	479
Income taxes	162	256	186
Pension and non-pension postretirement benefit contributions	(237)	(259)	(255)
Other assets and liabilities	(5,474)	(3,540)	(4,362)
Net cash flows (used in) provided by operating activities	(2,353)	(1,338)	584
Cash flows from investing activities
Capital expenditures	(1,689)	(1,329)	(1,747)
Proceeds from NDT fund sales	4,050	6,532	3,341
Investment in NDT funds	(4,271)	(6,673)	(3,464)
Collection of DPP, net	4,964	3,902	3,771
Proceeds from sales of assets and businesses	52	878	46
Other investing activities	(2)	(28)	11
Net cash flows provided by investing activities	3,104	3,282	1,958
Cash flows from financing activities
Change in short-term borrowings	257	362	20
Proceeds from short-term borrowings with maturities greater than 90 days	0	880	500
Repayments of short-term borrowings with maturities greater than 90 days	(1,180)	0	0
Issuance of long-term debt	14	152	3,155
Retirement of long-term debt	(1,162)	(105)	(4,334)
Retirement of long-term debt to affiliate	(258)	0	(550)
Change in money pool with Exelon	0	(285)	285
Acquisition of CENG noncontrolling interest	0	(885)	0
Distributions to Exelon	0	(1,832)	(1,734)
Contributions from Exelon	1,750	64	64
Dividends paid on common stock	(185)	0	0
Other financing activities	(35)	(46)	(70)
Net cash flows used in financing activities	(799)	(1,695)	(2,664)
(Decrease) increase in cash, restricted cash, and cash equivalents	(48)	249	(122)
Cash, restricted cash, and cash equivalents at beginning of period	576	327	449
Cash, restricted cash, and cash equivalents at end of period	528	576	327
Supplemental cash flow information
(Decrease) increase in capital expenditures not paid	(23)	96	(88)
Increase in DPP	5,166	3,652	4,441
Increase in PP&E related to ARO update	$ 343	$ 618	$ 850

Consolidated Balance Sheets, Pa

Consolidated Balance Sheets, Parent - USD ($) $ in Millions		Dec. 31, 2022	Dec. 31, 2021
Current assets
Cash and cash equivalents		$ 422	$ 504
Restricted cash and cash equivalents		106	72
Accounts receivable
Customer accounts receivable (net of allowance for credit losses of $46 and $55 as of December 31, 2022 and December 31, 2021, respectively)		2,585	1,669
Other accounts receivable (net of allowance for credit losses of $5 as of December 31, 2022 and December 31, 2021)		731	592
Mark-to-market derivative assets		2,368	2,169
Receivables from affiliates		0	160
Inventories, net
Natural gas, oil, and emission allowances		429	284
Materials and supplies		1,076	1,004
Renewable energy credits		617	520
Other		1,026	1,007
Total current assets		9,360	7,981
Property, plant, and equipment (net of accumulated depreciation and amortization of $16,726 and $15,873 as of December 31, 2022 and 2021, respectively)		19,822	19,612
Deferred debits and other assets
Nuclear decommissioning trust funds		14,114	15,938
Investments		202	174
Mark-to-market derivative assets		1,261	949
Prepaid pension asset		0	1,683
Deferred income taxes		44	32
Other		2,106	1,717
Total deferred debits and other assets		17,727	20,493
Total assets	[1]	46,909	48,086
Current liabilities
Short-term borrowings		1,159	2,082
Long-term debt due within one year		143	1,220
Accounts payable		2,828	1,757
Accrued expenses		906	737
Payables to affiliates		0	131
Mark-to-market derivative liabilities		1,558	981
Renewable energy credit obligation		901	777
Other		344	311
Total current liabilities		7,839	7,996
Long-term debt		4,466	4,575
Long-term debt to affiliates		0	319
Deferred credits and other liabilities
Deferred income taxes and unamortized ITCs		3,031	3,703
Asset retirement obligations		12,699	12,819
Pension obligations		605	0
Non-pension postretirement benefit obligations		609	847
Spent nuclear fuel obligation		1,230	1,210
Payables to affiliates		0	3,357
Payables related to Regulatory Agreement Units		2,897	0
Mark-to-market derivative liabilities		983	513
Other		1,178	1,133
Total deferred credits and other liabilities		23,232	23,582
Total liabilities	[1]	35,537	36,472
Commitments and contingencies (Note 19)
Member’s equity
Predecessor Member's Equity	[2]	0	11,250
Common stock (No par value, 1,000 shares authorized, 327 shares outstanding as of December 31, 2022)		13,274	0
Retained deficit		(496)	0
Accumulated other comprehensive loss, net		(1,760)	(31)
Total shareholders’ equity		11,018	11,219
Noncontrolling interests		354	395
Total equity		11,372	11,614
Total liabilities and equity		46,909	48,086
Constellation Energy Generation, LLC
Current assets
Cash and cash equivalents		403	504
Restricted cash and cash equivalents		98	72
Accounts receivable
Customer accounts receivable (net of allowance for credit losses of $46 and $55 as of December 31, 2022 and December 31, 2021, respectively)		2,585	1,669
Other accounts receivable (net of allowance for credit losses of $5 as of December 31, 2022 and December 31, 2021)		718	592
Mark-to-market derivative assets		2,368	2,169
Receivables from affiliates		0	160
Inventories, net
Natural gas, oil, and emission allowances		429	284
Materials and supplies		1,076	1,004
Renewable energy credits		617	520
Other		1,026	1,007
Total current assets		9,320	7,981
Property, plant, and equipment (net of accumulated depreciation and amortization of $16,726 and $15,873 as of December 31, 2022 and 2021, respectively)		19,822	19,612
Deferred debits and other assets
Nuclear decommissioning trust funds		14,114	15,938
Investments		202	174
Mark-to-market derivative assets		1,261	949
Prepaid pension asset		0	1,683
Deferred income taxes		44	32
Other		2,106	1,717
Total deferred debits and other assets		17,727	20,493
Total assets	[3]	46,869	48,086
Current liabilities
Short-term borrowings		1,159	2,082
Long-term debt due within one year		143	1,220
Accounts payable		2,810	1,757
Accrued expenses		869	737
Payables to affiliates		45	131
Mark-to-market derivative liabilities		1,558	981
Renewable energy credit obligation		901	777
Other		344	311
Total current liabilities		7,829	7,996
Long-term debt		4,466	4,575
Long-term debt to affiliates		0	319
Deferred credits and other liabilities
Deferred income taxes and unamortized ITCs		3,031	3,703
Asset retirement obligations		12,699	12,819
Pension obligations		605	0
Non-pension postretirement benefit obligations		609	847
Spent nuclear fuel obligation		1,230	1,210
Payables to affiliates		0	3,357
Payables related to Regulatory Agreement Units		2,897	0
Mark-to-market derivative liabilities		983	513
Other		1,106	1,133
Total deferred credits and other liabilities		23,160	23,582
Total liabilities	[3]	35,455	36,472
Commitments and contingencies (Note 19)
Member’s equity
Predecessor Member's Equity		12,408	10,482
Retained deficit		412	768
Accumulated other comprehensive loss, net		(1,760)	(31)
Total liabilities and equity		46,869	48,086
Variable Interest Entity, Primary Beneficiary
Current assets
Cash and cash equivalents		51	35
Restricted cash and cash equivalents		46	48
Accounts receivable
Customer accounts receivable (net of allowance for credit losses of $46 and $55 as of December 31, 2022 and December 31, 2021, respectively)		20	24
Other accounts receivable (net of allowance for credit losses of $5 as of December 31, 2022 and December 31, 2021)		9	6
Inventories, net
Materials and supplies		12	14
Other		549	405
Total current assets		687	532
Property, plant, and equipment (net of accumulated depreciation and amortization of $16,726 and $15,873 as of December 31, 2022 and 2021, respectively)		1,965	2,027
Deferred debits and other assets
Other		190	215
Total assets		2,842	2,774
Current liabilities
Long-term debt due within one year		60	70
Accounts payable		17	10
Accrued expenses		23	21
Other		2	1
Total current liabilities		102	102
Long-term debt		764	822
Deferred credits and other liabilities
Other		3	3
Total deferred credits and other liabilities		940	976
Total liabilities		1,042	1,078
Variable Interest Entity, Primary Beneficiary \| Nonrecourse
Deferred credits and other liabilities
Total liabilities		1,041	1,077
Variable Interest Entity, Primary Beneficiary \| Nonrecourse \| Constellation Energy Generation, LLC
Deferred credits and other liabilities
Total liabilities		1,041	1,077
Variable Interest Entity, Primary Beneficiary \| Asset Pledged as Collateral
Deferred debits and other assets
Total assets		2,641	2,549
Variable Interest Entity, Primary Beneficiary \| Asset Pledged as Collateral \| Constellation Energy Generation, LLC
Deferred debits and other assets
Total assets		$ 2,641	$ 2,549

[1]Our consolidated assets include $2,641 million and $2,549 million at December 31, 2022 and 2021, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Our consolidated liabilities include $1,041 million and $1,077 million at December 31, 2022 and 2021, respectively, of certain VIEs for which the VIE creditors do not have recourse to us. See Note 22–Variable Interest Entities for additional information.[2]Represents Constellation’s predecessor member's equity prior to the separation transaction. Upon completion of the separation, the predecessor member's equity was transferred to CEG Parent’s Common stock. See Note 1 — Basis of Presentation for additional information on the separation.[3]Our consolidated assets include $2,641 million and $2,549 million as of December 31, 2022 and 2021, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Our consolidated liabilities include $1,041 million and $1,077 million as of December 31, 2022 and 2021, respectively, of certain VIEs for which the VIE creditors do not have recourse to us. See Note 22–Variable Interest Entities for additional information.

Consolidated Balance Sheets, _2

Consolidated Balance Sheets, Parent (Parenthetical) $ in Millions	Dec. 31, 2022 USD ($) $ / shares shares
Statement of Financial Position [Abstract]
Allowance for credit losses	$ (46)
Allowance for other credit losses	(5)
Accumulated depreciation and amortization	$ 16,726
Common stock, par value (in dollars per share) \| $ / shares	$ 0
Common stock, shares authorized (in shares) \| shares	1,000,000,000
Common stock, shares outstanding (in shares) \| shares	327,000,000

Consolidated Statement of Chang

Consolidated Statement of Changes in Shareholders Equity, Parent - USD ($) $ in Millions	Total	CENG	Common Stock	Retained Deficit	Accumulated Other Comprehensive Loss, net	Noncontrolling Interests	Noncontrolling Interests CENG	Predecessor Member's Equity	[1]	Predecessor Member's Equity CENG	[1]
Beginning Balance (in shares) at Dec. 31, 2019			0
Beginning Balance at Dec. 31, 2019	$ 15,830		$ 0	$ 0	$ (32)	$ 2,346		$ 13,516
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net (loss) income	579					(10)		589
Sale of noncontrolling interest	3							3
Changes in equity of noncontrolling interest	(59)					(59)
Distribution to member of deferred taxes associated with net retirement benefit obligation	(9)							(9)
Distribution to member	(1,734)							(1,734)
Contributions from member	64							64
Other comprehensive loss, net of income taxes	2				2
Ending Balance (in shares) at Dec. 31, 2020			0
Ending Balance at Dec. 31, 2020	14,676		$ 0	0	(30)	2,277		12,429
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net (loss) income	(83)					122		(205)
Changes in equity of noncontrolling interest	(37)					(37)
Acquisition of CENG noncontrolling Interest		$ (885)					$ (1,965)			$ 1,080
Deferred tax adjustment related to acquisition of CENG noncontrolling interest	(288)							(288)
Distribution to member	(1,832)							(1,832)
Contributions from member	64							64
Acquisition of noncontrolling interest	0					(2)		2
Other comprehensive loss, net of income taxes	(1)				(1)
Ending Balance (in shares) at Dec. 31, 2021			0
Ending Balance at Dec. 31, 2021	11,614		$ 0	0	(31)	395		11,250
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net (loss) income	(167)
Separation-related adjustments	(197)				(2,006)	7		1,802
Changes in equity of noncontrolling interest	(34)					(34)
Consummation of separation (in shares)			326,664,000,000
Consummation of separation	0		$ 13,203					(13,203)
Employee incentive plans (in shares)			466,000,000
Employee incentive plans	71		$ 71
Common stock dividends ($0.14/common share)	(185)			(185)
Other comprehensive loss, net of income taxes	$ 277				277
Ending Balance (in shares) at Dec. 31, 2022	327,000,000		327,130,000,000
Ending Balance at Dec. 31, 2022	$ 11,372		$ 13,274	$ (496)	$ (1,760)	$ 354		$ 0

[1]Represents Constellation’s predecessor member's equity prior to the separation transaction. Upon completion of the separation, the predecessor member's equity was transferred to CEG Parent’s Common stock. See Note 1 — Basis of Presentation for additional information on the separation.

Consolidated Statement of Cha_2

Consolidated Statement of Changes in Equity, Parent (Parenthetical)	12 Months Ended
	Dec. 31, 2022 $ / shares
Statement of Stockholders' Equity [Abstract]
Common stock dividends (in dollars per share)	$ 0.14

Consolidated Statements of Op_2

Consolidated Statements of Operations and Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Operating revenues
Operating revenues	$ 24,280	$ 18,461	$ 16,392
Operating revenues from affiliates	160	1,188	1,211
Total operating revenues	24,440	19,649	17,603
Operating expenses
Purchased power and fuel	17,457	12,157	9,592
Purchased power and fuel from affiliates	5	6	(7)
Operating and maintenance	4,797	3,934	4,613
Operating and maintenance from affiliates	44	621	555
Depreciation and amortization	1,091	3,003	2,123
Taxes other than income taxes	552	475	482
Total operating expenses	23,946	20,196	17,358
Gain on sales of assets and businesses	1	201	11
Operating income (loss)	495	(346)	256
Other income and (deductions)
Interest expense, net	(250)	(282)	(328)
Interest expense to affiliates	(1)	(15)	(29)
Other, net	(786)	795	937
Total other income and (deductions)	(1,037)	498	580
(Loss) income before income taxes	(542)	152	836
Income taxes	(388)	225	249
Equity in losses of unconsolidated affiliates	(13)	(10)	(8)
Net (loss) income	(167)	(83)	579
Net (loss) income attributable to noncontrolling interests	(7)	122	(10)
Net (loss) income attributable to common shareholders	(160)	(205)	589
Comprehensive income (loss), net of income taxes
Net (loss) income	(167)	(83)	579
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	(6)	0	0
Actuarial loss reclassified to periodic benefit cost	101	0	0
Pension and non-pension postretirement benefit plans valuation adjustment	186	0	0
Unrealized loss on cash flow hedges	(1)	(1)	(2)
Unrealized (loss) gain on foreign currency translation	(3)	0	4
Other comprehensive income (loss), net of income taxes	277	(1)	2
Comprehensive income (loss)	110	(84)	581
Comprehensive (loss) income attributable to noncontrolling interests	(7)	122	(10)
Comprehensive income (loss) attributable to common shareholders	117	(206)	591
Constellation Energy Generation, LLC
Operating revenues
Operating revenues	24,280	18,461	16,392
Operating revenues from affiliates	160	1,188	1,211
Total operating revenues	24,440	19,649	17,603
Operating expenses
Purchased power and fuel	17,457	12,157	9,592
Purchased power and fuel from affiliates	5	6	(7)
Operating and maintenance	4,797	3,934	4,613
Operating and maintenance from affiliates	44	621	555
Depreciation and amortization	1,091	3,003	2,123
Taxes other than income taxes	552	475	482
Total operating expenses	23,946	20,196	17,358
Gain on sales of assets and businesses	1	201	11
Operating income (loss)	495	(346)	256
Other income and (deductions)
Interest expense, net	(250)	(282)	(328)
Interest expense to affiliates	(1)	(15)	(29)
Other, net	(786)	795	937
Total other income and (deductions)	(1,037)	498	580
(Loss) income before income taxes	(542)	152	836
Income taxes	(388)	225	249
Equity in losses of unconsolidated affiliates	(13)	(10)	(8)
Net (loss) income	(167)	(83)	579
Net (loss) income attributable to noncontrolling interests	(7)	122	(10)
Net (loss) income attributable to common shareholders	(160)	(205)	589
Comprehensive income (loss), net of income taxes
Net (loss) income	(167)	(83)	579
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	(6)	0	0
Actuarial loss reclassified to periodic benefit cost	101	0	0
Pension and non-pension postretirement benefit plans valuation adjustment	186	0	0
Unrealized loss on cash flow hedges	(1)	(1)	(2)
Unrealized (loss) gain on foreign currency translation	(3)	0	4
Other comprehensive income (loss), net of income taxes	277	(1)	2
Comprehensive income (loss)	110	(84)	581
Comprehensive (loss) income attributable to noncontrolling interests	(7)	122	(10)
Comprehensive income (loss) attributable to common shareholders	$ 117	$ (206)	$ 591

Consolidated Statements of Ca_2

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Cash flows from operating activities
Net (loss) income	$ (167)	$ (83)	$ 579
Adjustments to reconcile net (loss) income to net cash flows (used in) provided by operating activities
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization	2,427	4,540	3,636
Asset impairments	0	545	563
Gain on sales of assets and businesses	(1)	(201)	(11)
Deferred income taxes and amortization of ITCs	(643)	(205)	78
Net fair value changes related to derivatives	986	(568)	(270)
Net realized and unrealized losses (gains) on NDT funds	794	(586)	(461)
Net realized and unrealized losses (gains) on equity investments	13	160	(186)
Other non-cash operating activities	249	(605)	18
Changes in assets and liabilities:
Accounts receivable	(868)	(616)	1,125
Receivables from and payables to affiliates, net	20	14	24
Inventories	(228)	(68)	(77)
Accounts payable and accrued expenses	1,142	346	(343)
Option premiums paid, net	(177)	(338)	(139)
Collateral (posted) received, net	(351)	(130)	479
Income taxes	162	256	186
Pension and non-pension postretirement benefit contributions	(237)	(259)	(255)
Other assets and liabilities	(5,474)	(3,540)	(4,362)
Net cash flows (used in) provided by operating activities	(2,353)	(1,338)	584
Cash flows from investing activities
Capital expenditures	(1,689)	(1,329)	(1,747)
Proceeds from NDT fund sales	4,050	6,532	3,341
Investment in NDT funds	(4,271)	(6,673)	(3,464)
Collection of DPP, net	4,964	3,902	3,771
Proceeds from sales of assets and businesses	52	878	46
Other investing activities	(2)	(28)	11
Net cash flows provided by investing activities	3,104	3,282	1,958
Cash flows from financing activities
Change in short-term borrowings	257	362	20
Proceeds from short-term borrowings with maturities greater than 90 days	0	880	500
Repayments of short-term borrowings with maturities greater than 90 days	(1,180)	0	0
Issuance of long-term debt	14	152	3,155
Retirement of long-term debt	(1,162)	(105)	(4,334)
Retirement of long-term debt to affiliate	(258)	0	(550)
Change in money pool with Exelon	0	(285)	285
Acquisition of CENG noncontrolling interest	0	(885)	0
Distributions to member	0	(1,832)	(1,734)
Contributions from member	1,750	64	64
Other financing activities	(35)	(46)	(70)
Net cash flows used in financing activities	(799)	(1,695)	(2,664)
(Decrease) increase in cash, restricted cash, and cash equivalents	(48)	249	(122)
Cash, restricted cash, and cash equivalents at beginning of period	576	327	449
Cash, restricted cash, and cash equivalents at end of period	528	576	327
Supplemental cash flow information
(Decrease) increase in capital expenditures not paid	(23)	96	(88)
Increase in DPP	5,166	3,652	4,441
Increase in PP&E related to ARO update	343	618	850
Constellation Energy Generation, LLC
Cash flows from operating activities
Net (loss) income	(167)	(83)	579
Adjustments to reconcile net (loss) income to net cash flows (used in) provided by operating activities
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization	2,427	4,540	3,636
Asset impairments	0	545	563
Gain on sales of assets and businesses	(1)	(201)	(11)
Deferred income taxes and amortization of ITCs	(643)	(205)	78
Net fair value changes related to derivatives	986	(568)	(270)
Net realized and unrealized losses (gains) on NDT funds	794	(586)	(461)
Net realized and unrealized losses (gains) on equity investments	13	160	(186)
Other non-cash operating activities	200	(605)	18
Changes in assets and liabilities:
Accounts receivable	(855)	(616)	1,125
Receivables from and payables to affiliates, net	65	14	24
Inventories	(228)	(68)	(77)
Accounts payable and accrued expenses	1,112	346	(343)
Option premiums paid, net	(177)	(338)	(139)
Collateral (posted) received, net	(351)	(130)	479
Income taxes	162	256	186
Pension and non-pension postretirement benefit contributions	(237)	(259)	(255)
Other assets and liabilities	(5,540)	(3,540)	(4,362)
Net cash flows (used in) provided by operating activities	(2,440)	(1,338)	584
Cash flows from investing activities
Capital expenditures	(1,689)	(1,329)	(1,747)
Proceeds from NDT fund sales	4,050	6,532	3,341
Investment in NDT funds	(4,271)	(6,673)	(3,464)
Collection of DPP, net	4,964	3,902	3,771
Proceeds from sales of assets and businesses	52	878	46
Other investing activities	(2)	(28)	11
Net cash flows provided by investing activities	3,104	3,282	1,958
Cash flows from financing activities
Change in short-term borrowings	257	362	20
Proceeds from short-term borrowings with maturities greater than 90 days	0	880	500
Repayments of short-term borrowings with maturities greater than 90 days	(1,180)	0	0
Issuance of long-term debt	14	152	3,155
Retirement of long-term debt	(1,162)	(105)	(4,334)
Retirement of long-term debt to affiliate	(258)	0	(550)
Change in money pool with Exelon	0	(285)	285
Acquisition of CENG noncontrolling interest	0	(885)	0
Distributions to Exelon	0	(1,832)	(1,734)
Distributions to member	(185)	0	0
Contributions from Exelon	1,750	64	64
Contributions from member	82	0	0
Other financing activities	(57)	(46)	(70)
Net cash flows used in financing activities	(739)	(1,695)	(2,664)
(Decrease) increase in cash, restricted cash, and cash equivalents	(75)	249	(122)
Cash, restricted cash, and cash equivalents at beginning of period	576	327	449
Cash, restricted cash, and cash equivalents at end of period	501	576	327
Supplemental cash flow information
(Decrease) increase in capital expenditures not paid	(23)	96	(88)
Increase in DPP	5,166	3,652	4,441
Increase in PP&E related to ARO update	$ 343	$ 618	$ 850

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions		Dec. 31, 2022	Dec. 31, 2021
Current assets
Cash and cash equivalents		$ 422	$ 504
Restricted cash and cash equivalents		106	72
Accounts receivable
Customer accounts receivable (net of allowance for credit losses of $46 and $55 as of December 31, 2022 and December 31, 2021, respectively)		2,585	1,669
Other accounts receivable (net of allowance for credit losses of $5 as of December 31, 2022 and December 31, 2021)		731	592
Mark-to-market derivative assets		2,368	2,169
Receivables from affiliates		0	160
Inventories, net
Natural gas, oil, and emission allowance		429	284
Materials and supplies		1,076	1,004
Renewable energy credits		617	520
Other		1,026	1,007
Total current assets		9,360	7,981
Property, plant, and equipment (net of accumulated depreciation and amortization of $16,726 and $15,873 as of December 31, 2022 and 2021, respectively)		19,822	19,612
Deferred debits and other assets
Nuclear decommissioning trust funds		14,114	15,938
Investments		202	174
Mark-to-market derivative assets		1,261	949
Prepaid pension asset		0	1,683
Deferred income taxes		44	32
Other		2,106	1,717
Total deferred debits and other assets		17,727	20,493
Total assets	[1]	46,909	48,086
Current liabilities
Short-term borrowings		1,159	2,082
Long-term debt due within one year		143	1,220
Accounts payable		2,828	1,757
Accrued expenses		906	737
Payables to affiliates		0	131
Mark-to-market derivative liabilities		1,558	981
Renewable energy credit obligation		901	777
Other current liabilities		344	311
Total current liabilities		7,839	7,996
Long-term debt		4,466	4,575
Long-term debt to affiliates		0	319
Deferred credits and other liabilities
Deferred income taxes and unamortized ITCs		3,031	3,703
Asset retirement obligations		12,699	12,819
Pension obligations		605	0
Non-pension postretirement benefit obligations		609	847
Spent nuclear fuel obligation		1,230	1,210
Payables to affiliates		0	3,357
Payables related to Regulatory Agreement Units		2,897	0
Mark-to-market derivative liabilities		983	513
Other		1,178	1,133
Total deferred credits and other liabilities		23,232	23,582
Total liabilities	[1]	35,537	36,472
Commitments and contingencies (Note 19)
Member’s equity
Membership interest	[2]	0	11,250
Undistributed earnings		(496)	0
Accumulated other comprehensive loss, net		(1,760)	(31)
Total liabilities and equity		46,909	48,086
Variable Interest Entity, Primary Beneficiary
Current assets
Cash and cash equivalents		51	35
Restricted cash and cash equivalents		46	48
Accounts receivable
Customer accounts receivable (net of allowance for credit losses of $46 and $55 as of December 31, 2022 and December 31, 2021, respectively)		20	24
Other accounts receivable (net of allowance for credit losses of $5 as of December 31, 2022 and December 31, 2021)		9	6
Inventories, net
Materials and supplies		12	14
Other		549	405
Total current assets		687	532
Property, plant, and equipment (net of accumulated depreciation and amortization of $16,726 and $15,873 as of December 31, 2022 and 2021, respectively)		1,965	2,027
Deferred debits and other assets
Other		190	215
Total assets		2,842	2,774
Current liabilities
Long-term debt due within one year		60	70
Accounts payable		17	10
Accrued expenses		23	21
Other current liabilities		2	1
Total current liabilities		102	102
Long-term debt		764	822
Deferred credits and other liabilities
Other		3	3
Total deferred credits and other liabilities		940	976
Total liabilities		1,042	1,078
Variable Interest Entity, Primary Beneficiary \| Nonrecourse
Deferred credits and other liabilities
Total liabilities		1,041	1,077
Variable Interest Entity, Primary Beneficiary \| Asset Pledged as Collateral
Deferred debits and other assets
Total assets		2,641	2,549
Constellation Energy Generation, LLC
Current assets
Cash and cash equivalents		403	504
Restricted cash and cash equivalents		98	72
Accounts receivable
Customer accounts receivable (net of allowance for credit losses of $46 and $55 as of December 31, 2022 and December 31, 2021, respectively)		2,585	1,669
Other accounts receivable (net of allowance for credit losses of $5 as of December 31, 2022 and December 31, 2021)		718	592
Mark-to-market derivative assets		2,368	2,169
Receivables from affiliates		0	160
Inventories, net
Natural gas, oil, and emission allowance		429	284
Materials and supplies		1,076	1,004
Renewable energy credits		617	520
Other		1,026	1,007
Total current assets		9,320	7,981
Property, plant, and equipment (net of accumulated depreciation and amortization of $16,726 and $15,873 as of December 31, 2022 and 2021, respectively)		19,822	19,612
Deferred debits and other assets
Nuclear decommissioning trust funds		14,114	15,938
Investments		202	174
Mark-to-market derivative assets		1,261	949
Prepaid pension asset		0	1,683
Deferred income taxes		44	32
Other		2,106	1,717
Total deferred debits and other assets		17,727	20,493
Total assets	[3]	46,869	48,086
Current liabilities
Short-term borrowings		1,159	2,082
Long-term debt due within one year		143	1,220
Accounts payable		2,810	1,757
Accrued expenses		869	737
Payables to affiliates		45	131
Mark-to-market derivative liabilities		1,558	981
Renewable energy credit obligation		901	777
Other current liabilities		344	311
Total current liabilities		7,829	7,996
Long-term debt		4,466	4,575
Long-term debt to affiliates		0	319
Deferred credits and other liabilities
Deferred income taxes and unamortized ITCs		3,031	3,703
Asset retirement obligations		12,699	12,819
Pension obligations		605	0
Non-pension postretirement benefit obligations		609	847
Spent nuclear fuel obligation		1,230	1,210
Payables to affiliates		0	3,357
Payables related to Regulatory Agreement Units		2,897	0
Mark-to-market derivative liabilities		983	513
Other		1,106	1,133
Total deferred credits and other liabilities		23,160	23,582
Total liabilities	[3]	35,455	36,472
Commitments and contingencies (Note 19)
Member’s equity
Membership interest		12,408	10,482
Undistributed earnings		412	768
Accumulated other comprehensive loss, net		(1,760)	(31)
Total member’s equity		11,060	11,219
Noncontrolling interests		354	395
Total equity		11,414	11,614
Total liabilities and equity		46,869	48,086
Constellation Energy Generation, LLC \| Variable Interest Entity, Primary Beneficiary \| Nonrecourse
Deferred credits and other liabilities
Total liabilities		1,041	1,077
Constellation Energy Generation, LLC \| Variable Interest Entity, Primary Beneficiary \| Asset Pledged as Collateral
Deferred debits and other assets
Total assets		$ 2,641	$ 2,549

[1]Our consolidated assets include $2,641 million and $2,549 million at December 31, 2022 and 2021, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Our consolidated liabilities include $1,041 million and $1,077 million at December 31, 2022 and 2021, respectively, of certain VIEs for which the VIE creditors do not have recourse to us. See Note 22–Variable Interest Entities for additional information.[2]Represents Constellation’s predecessor member's equity prior to the separation transaction. Upon completion of the separation, the predecessor member's equity was transferred to CEG Parent’s Common stock. See Note 1 — Basis of Presentation for additional information on the separation.[3]Our consolidated assets include $2,641 million and $2,549 million as of December 31, 2022 and 2021, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Our consolidated liabilities include $1,041 million and $1,077 million as of December 31, 2022 and 2021, respectively, of certain VIEs for which the VIE creditors do not have recourse to us. See Note 22–Variable Interest Entities for additional information.

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Allowance for credit losses	$ (46)	$ (55)
Allowance for other credit losses	(5)	(5)
Accumulated depreciation and amortization	16,726	15,873
Constellation Energy Generation, LLC
Allowance for credit losses	(46)	(55)
Allowance for other credit losses	(5)	(5)
Accumulated depreciation and amortization	$ 16,726	$ 15,873

Consolidated Statement of Cha_3

Consolidated Statement of Changes in Equity - USD ($) $ in Millions	Total	CENG	Accumulated Other Comprehensive Loss, net	Noncontrolling Interests	Noncontrolling Interests CENG	Constellation Energy Generation, LLC	Constellation Energy Generation, LLC CENG	Constellation Energy Generation, LLC Membership Interest	Constellation Energy Generation, LLC Membership Interest CENG	Constellation Energy Generation, LLC Retained Deficit	Constellation Energy Generation, LLC Accumulated Other Comprehensive Loss, net	Constellation Energy Generation, LLC Noncontrolling Interests	Constellation Energy Generation, LLC Noncontrolling Interests CENG
Beginning Balance at Dec. 31, 2019						$ 15,830		$ 9,566		$ 3,950	$ (32)	$ 2,346
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net (loss) income	$ 579			$ (10)		579				589		(10)
Sale of noncontrolling interests	3					3		3
Changes in equity of noncontrolling interests	(59)			(59)		(59)						(59)
Distribution to member of deferred taxes associated with net retirement benefit obligation	(9)					(9)		(9)
Distribution to member	(1,734)					(1,734)				(1,734)
Contribution from member	64					64		64
Other comprehensive loss, net of income taxes	2		$ 2			2					2	0
Ending Balance at Dec. 31, 2020						14,676		9,624		2,805	(30)	2,277
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net (loss) income	(83)			122		(83)				(205)		122
Changes in equity of noncontrolling interests	(37)			(37)		(37)						(37)
Acquisition of CENG noncontrolling Interest		$ (885)			$ (1,965)		$ (885)		$ 1,080				$ (1,965)
Distribution to member	(1,832)					(1,832)				(1,832)
Deferred tax adjustment related to acquisition of CENG noncontrolling interest	(288)					(288)		(288)
Contribution from member	64					64		64
Acquisition of noncontrolling interest	0			(2)		0		2				(2)
Other comprehensive loss, net of income taxes	(1)		(1)			(1)					(1)
Ending Balance at Dec. 31, 2021						11,614		10,482		768	(31)	395
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net (loss) income	(167)					(167)				(160)		(7)
Separation-related adjustments	(197)		(2,006)	7		(166)		1,844		(11)	(2,006)	7
Changes in equity of noncontrolling interests	(34)			$ (34)		(41)						(41)
Distribution to member						(185)				(185)
Contribution from member						82		82
Other comprehensive loss, net of income taxes	$ 277		$ 277			277					277
Ending Balance at Dec. 31, 2022						$ 11,414		$ 12,408		$ 412	$ (1,760)	$ 354

Basis of Presentation

Basis of Presentation	12 Months Ended
Basis of Presentation	Dec. 31, 2022
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation Description of Business We are a producer of clean energy and a supplier of energy products and services. Our generating capacity includes primarily nuclear, wind, solar, natural gas and hydroelectric assets. Through our integrated business operations, we sell electricity, natural gas, and other energy-related products and sustainable solutions to various types of customers, including distribution utilities, municipalities, cooperatives, and commercial, industrial, governmental, and residential customers in markets across multiple geographic regions. We have five reportable segments: Mid-Atlantic, Midwest, New York, ERCOT and Other Power Regions. Basis of Presentation On February 21, 2021, the Board of Directors of Exelon authorized management to pursue a plan to separate its competitive generation and customer-facing energy businesses, conducted through Constellation Energy Generation, LLC ( “ Constellation ” , formerly Exelon Generation Company, LLC) and its subsidiaries, into an independent, publicly-traded company. CEG Parent, a direct, wholly owned subsidiary of Exelon, was newly formed for the purpose of separation and had not engaged in any business activities nor had any assets or liabilities prior to the separation. On February 1, 2022, the separation was completed and CEG Parent holds all the interests in Constellation previously held by Exelon. As an individual registrant, Constellation has historically filed consolidated financial statements to reflect its financial position and operating results as a stand-alone, wholly owned subsidiary of Exelon. The accompanying Consolidated Financial Statements have been prepared in accordance with GAAP for annual financial statements and in accordance with the instructions to Form 10-K and Regulation S-X promulgated by the SEC. The Consolidated Financial Statements include the accounts of our subsidiaries and all intercompany transactions have been eliminated. CEG Parent's prior period financial statements have been adjusted to reflect the balances of Constellation in accordance with applicable guidance. Amounts disclosed relate to CEG Parent and Constellation unless specifically noted as relating to CEG Parent only. Unless otherwise indicated or the context otherwise requires, references herein to the terms “we,” “us,” and “our” refer collectively to CEG Parent and Constellation. We own 100% of our significant consolidated subsidiaries, either directly or indirectly, except for certain consolidated VIEs, including CRP, of which we hold a 51% interest. The remaining interests in the consolidated VIEs are included in noncontrolling interests on the Consolidated Balance Sheets. See Note 22 — Variable Interest Entities for additional information on consolidated VIEs. We consolidate the accounts of entities in which we have a controlling financial interest, after the elimination of intercompany transactions. Where we do not have a controlling financial interest in an entity, proportionate consolidation, equity method accounting or accounting for investments in equity securities with or without readily determinable fair value is applied. We apply proportionate consolidation when we have an undivided interest in an asset and are proportionately liable for our share of each liability associated with the asset. We proportionately consolidate our undivided ownership interest in jointly owned electric plants. Under proportionate consolidation, we separately record our proportionate share of the assets, liabilities, revenues and expenses related to the undivided interest in the asset. We apply equity method accounting when we have a significant influence over an investee through an ownership in equity, which generally approximates a 20% to 50% voting interest. We apply equity method accounting to certain investments and joint ventures. Under equity method accounting, we report our interest in the entity as an investment and our percentage share of the earnings from the entity as single line items in our consolidated financial statements. We use accounting for investments in equity securities with or without readily determinable fair values if we lack a significant influence, which generally results when we hold less than 20% of the common stock of an entity. Under accounting for investments in equity securities with readily determinable fair values, the investments are reported based on quoted prices in active markets and realized and unrealized gains and losses are included in earnings. Under accounting for investments in equity securities without readily determinable fair values, the investments are reported at cost adjusted for changes from observable transactions for identical or similar investments of the same issuer, less impairment, and changes in measurement are reported in earnings. Separation from Exelon On February 1, 2022, Exelon completed the separation through a pro-rata distribution of all of the outstanding shares of our common stock, no par value, on the basis of one such share for every three shares of Exelon common stock held on January 20, 2022, the record date of the distribution. We are an independent, publicly traded company listed on the Nasdaq Stock Market under the symbol “CEG”, and regular-way trading began on February 2, 2022. Exelon no longer retains any ownership interest in CEG Parent or Constellation. Prior to completion of the separation, our financial statements include certain transactions with affiliates of Exelon, which are disclosed as related party transactions. After February 1, 2022, all transactions with Exelon or its affiliates are no longer related party transactions. In order to govern the ongoing relationships with Exelon after the separation, and to facilitate an orderly transition, we entered into several agreements with Exelon, including the following: • Separation Agreement – sets forth the principal actions to be taken in connection with the separation, including the transfer of assets and assumption of liabilities and establishes certain rights and obligations between us following the distribution • Transition Services Agreement (TSA) – governs all matters relating to the provision of services between us and Exelon on a transitional basis, in addition to providing us with certain services for an expected period of two-years, provided that certain services may be longer than the term and services may be extended with approval from both parties; the services include support for information technology, accounting, finance, human resources, security, and various other administrative and operational services • Employee Matters Agreement (EMA) – addresses certain employment, compensation and benefits matters, including the allocation of employees between us and Exelon and the allocation and treatment of certain assets and liabilities relating to our employees and former employees • Tax Matters Agreement (TMA) - governs the respective rights, responsibilities, and obligations between us and Exelon with respect to all tax matters (excluding employee-related taxes covered under EMA), in addition to certain restrictions which generally prohibit us from taking or failing to take any action in the two-year period following the distribution that would prevent the distribution from qualifying as tax-free for U.S. federal income tax purposes, including limitations on our ability to pursue certain equity issuances, strategic transactions, repurchases or other transactions Pursuant to the Separation Agreement, we received a cash contribution of $1.75 billion from Exelon on January 31, 2022, the proceeds of which were used to settle $258 million of an intercompany loan from Exelon and $200 million of short-term debt outstanding prior to separation, in addition to a $192 million contribution to our pension plans. We also entered into two new five-year credit Beginning on February 1, 2022, the amounts Exelon billed us for services pursuant to the TSA were $266 million for the year ended December 31, 2022, and the amounts we billed Exelon for services pursuant to the TSA were $43 million for the year ended December 31, 2022. Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Areas in which significant estimates have been made include, but are not limited to, the accounting for nuclear decommissioning costs and other AROs, pension and OPEB plans, inventory reserves, allowance for credit losses, long-lived asset impairment assessments, derivative instruments, unamortized energy contracts, fixed asset depreciation, environmental costs and other loss contingencies, taxes and unbilled energy revenues. Actual results could differ from those estimates. Revenues Operating Revenues. Our operating revenues generally consist of revenues from contracts with customers involving the sale and delivery of energy commodities and related products and services and realized and unrealized revenues recognized under mark-to-market energy commodity derivative contracts. We recognize revenue from contracts with customers to depict the transfer of goods or services to customers in an amount that we expect to be entitled to in exchange for those goods or services. Our primary source of revenue includes competitive sales of power, natural gas, and other energy-related products and services. At the end of each reporting period, we accrue an estimate for the unbilled amount of energy delivered or services provided to customers. Option Contracts, Swaps and Commodity Derivatives. Certain option contracts and swap arrangements that meet the definition of derivative instruments are recorded at fair value with subsequent changes in fair value recognized as revenue or expense. The classification of revenue or expense is based on the intent of the transaction. See Note 16 — Derivative Financial Instruments for additional information. Taxes Directly Imposed on Revenue-Producing Transactions. We collect certain taxes from customers such as sales and gross receipts taxes, along with other taxes, surcharges and fees, that are levied by state or local governments on the sale or distribution of electricity and natural gas. Some of these taxes are imposed on the customer, but paid by us, while others are imposed on us. Where these taxes are imposed on the customer, such as sales taxes, they are reported on a net basis in revenues. However, where these taxes are imposed on us, such as gross receipts taxes, they are reported on a gross basis. Accordingly, revenues are recognized for the taxes collected from customers along with an offsetting expense. Se e Note 23 — Supplemental Financial Information for the taxes that are presented on a gross basis. Leases We recognize a ROU asset and lease liability for operating leases with a term of greater than one year. Operating lease ROU assets are included in Other deferred debits and other assets and operating lease liabilities are included in Other current liabilities and Other deferred credits and other liabilities on the Consolidated Balance Sheets. The ROU asset is measured as the sum of (1) the present value of all remaining fixed and in-substance fixed payments using the rate implicit in the lease whenever that is readily determinable or our incremental borrowing rate, (2) any lease payments made at or before the commencement date (less any lease incentives received) and (3) any initial direct costs incurred. The lease liability is measured the same as the ROU asset, but excludes any payments made before the commencement date and initial direct costs incurred. Lease terms include options to extend or terminate the lease if it is reasonably certain they will be exercised. We include non-lease components for most asset classes, which are service-related costs that are not integral to the use of the asset, in the measurement of the ROU asset and lease liability. Expense for operating leases and leases with a term of one year or less is recognized on a straight-line basis over the term of the lease, unless another systematic and rational basis is more representative of the derivation of benefit from use of the leased property. Variable lease payments are recognized in the period in which the related obligation is incurred and consist primarily of payments for purchases of electricity under contracted generation that are based on the electricity produced by those generating assets. Operating lease expense and variable lease payments are recorded to Purchased power and fuel expense for contracted generation or Operating and maintenance expense for all other lease agreements in the Consolidated Statements of Operations and Comprehensive Income. Income from operating leases, including subleases, is recognized on a straight-line basis over the term of the lease, unless another systematic and rational basis is more representative of the pattern in which income is earned over the term of the lease. Variable lease payments are recognized in the period in which the related obligation is performed and consist primarily of payments received from sales of electricity under contracted generation that are based on the electricity produced by those generating assets. Operating lease income and variable lease payments are recorded to Operating revenues in the Consolidated Statements of Operations and Comprehensive Income. Our operating leases consist primarily of contracted generation, real estate including office buildings, and vehicles and equipment. We generally account for contracted generation in which the generating asset is not renewable as a lease if the customer has dispatch rights and obtains substantially all the economic benefits. We generally do not account for contracted generation in which the generating asset is renewable as a lease if the customer does not design the generating asset. We account for land right arrangements that provide for exclusive use as leases while shared use land arrangements are generally not leases. See Note 11 — Leases for additional information. Income Taxes Deferred federal and state income taxes are recorded on temporary differences between the book and tax basis of assets and liabilities and for tax benefits carried forward. ITCs have been deferred in the Consolidated Balance Sheets and are recognized in book income over the life of the related property. We account for uncertain income tax positions using a benefit recognition model with a two-step approach; a more-likely-than-not recognition criterion; and a measurement approach that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. If it is not more-likely-than-not that the benefit of the tax position will be sustained on its technical merits, no benefit is recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. We recognize accrued interest related to unrecognized tax benefits in Interest expense, net or Other, net (interest income) and recognize penalties related to unrecognized tax benefits in Other, net in the Consolidated Statements of Operations and Comprehensive Income. Cash and Cash Equivalents We consider investments purchased with an original maturity of three months or less to be cash equivalents. Restricted Cash and Cash Equivalents Restricted cash and cash equivalents represent funds that are restricted to satisfy designated current liabilities. As of December 31, 2022 and 2021, restricted cash and cash equivalents primarily represented the payment of medical, dental, vision, and long-term disability benefits and project-specific nonrecourse financing structures for debt service and financing of operations of the underlying entities. See Note 17 — Debt and Credit Agreements and Note 23 — Supplemental Financial Information for additional information. Allowance for Credit Losses on Accounts Receivables The allowance for credit losses reflects our best estimate of losses on the customers' accounts receivable balances based on historical experience, current information, and reasonable and supportable forecasts. The allowance for credit losses for our retail customers is based on accounts receivable aging historical experience coupled with specific identification through a credit monitoring process, which considers current conditions and forward-looking information such as industry trends, macroeconomic factors, changes in the regulatory environment, external credit ratings, publicly available news, payment status, payment history, and the exercise of collateral calls. The allowance for credit losses for our wholesale customers is developed using a credit monitoring process, like that used for retail customers. When a wholesale customer’s risk characteristics are no longer aligned with the pooled population, we use specific identification to develop an allowance for credit losses. Adjustments to the allowance for credit losses are recorded in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. We have certain non-customer receivables in Other deferred debits and other assets which primarily are with governmental agencies and other high-quality counterparties. As such, the allowance for credit losses related to these receivables is not material. We monitor these balances and will record an allowance if there are indicators of a decline in credit quality. Variable Interest Entities We account for our investments in and arrangements with VIEs based on the following specific requirements: • qualitative assessment of factors determinant in whether we have a controlling financial interest, • ongoing reconsideration of this assessment, and • where we consolidate a VIE (as primary beneficiary), disclosure of (1) the assets of the consolidated VIE, if they can be used to only settle specific obligations of the consolidated VIE, and (2) the liabilities of a consolidated VIE for which creditors do not have recourse to the general credit of the primary beneficiary. See Note 22 — Variable Interest Entities for additional information. Inventories Inventory is recorded at the lower of weighted average cost or net realizable value. Provisions are recorded for excess and obsolete inventory. Natural gas, oil, materials and supplies, and emissions allowances are generally included in inventory when purchased. Natural gas, oil, and emissions allowances are expensed to Purchased power and fuel expense. Materials and supplies generally include items utilized within our generating plants and are expensed to Operating and maintenance or capitalized to Property, plant and equipment, as appropriate, when installed or used. Debt and Equity Security Investments Debt and Equity Investments within NDT funds. We have debt and equity securities held in our NDT funds which are measured and recorded at fair value. Realized and unrealized gains and losses, net of tax, on our NDT funds associated with the Regulatory Agreement Units are included in Noncurrent payables related to Regulatory Agreement Units. Realized and unrealized gains and losses, net of tax, on our NDT funds associated with the Non-Regulatory Agreement Units are included in Other, net in the Consolidated Statements of Operations and Comprehensive Income. For equity securities without readily determinable fair values, we have elected to use the measurement alternative to measure these investments, defined as cost adjusted for changes from observable transactions for identical or similar investments of the same issuer, less impairment. Our NDT funds are classified as current or noncurrent assets, depending on the timing of the decommissioning activities and income taxes on trust earnings. See Note 18 — Fair Value of Financial Assets and Liabilities and Note 10 — Asset Retirement Obligations for additional information. Equity Security Investments without Readily Determinable Fair Values. We have certain equity securities without readily determinable fair values. We have elected to use the measurement alternative to measure these investments, defined as cost adjusted for changes from observable transactions for identical or similar investments of the same issuer, less impairment. Changes in measurement are reported in Other, net in the Consolidated Statements of Operations and Comprehensive Income. See Note 18 — Fair Value of Financial Assets for additional information. Equity Security Investments with Readily Determinable Fair Values. We have certain equity securities with readily determinable fair values. Realized and unrealized gains and losses are included in Other, net in the Consolidated Statements of Operations and Comprehensive Income. See Note 18 — Fair Value of Financial Assets and Liabilities for additional information. Property, Plant and Equipment Property, plant and equipment is recorded at original cost. Original cost includes construction-related direct labor and material costs. When appropriate, original cost also includes capitalized interest. Costs associated with nuclear outages and planned major maintenance activities, are expensed to Operating and maintenance expense or capitalized to Property, plant, and equipment based on the nature of the activities in the period incurred. The cost of repairs and maintenance and minor replacements of property, is charged to Operating and maintenance expense as incurred. Upon retirement, the cost of property is generally charged to accumulated depreciation in accordance with the composite and group methods of depreciation. Upon replacement of an asset, the costs to remove the asset, net of salvage, are capitalized to gross plant when incurred as part of the cost of the newly-installed asset and recorded to depreciation expense over the life of the new asset. Removal costs, net of salvage, incurred for property that will not be replaced is charged to Operating and maintenance expense as incurred. Certain assets follow the unitary method of depreciation and recognize gains and losses in the period of replacement or retirement. These gains and losses are recorded in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. Capitalized Software. Certain costs, such as design, coding, and testing incurred during the application development stage of software projects that are internally developed or purchased for operational use are capitalized in Property, plant and equipment in the Consolidated Balance Sheets. Similar costs incurred for cloud-based solutions treated as service arrangements are capitalized in Other current assets and Deferred debits and other assets in the Consolidated Balance Sheets. Such capitalized amounts are amortized ratably over the expected lives of the projects when they become operational, generally not to exceed five years. Certain other capitalized software costs are being amortized over longer lives based on the expected life. Capitalized Interest. During construction, we capitalize the costs of debt funds. Most projects will use a debt rate calculated using the general corporate debt pool. In some cases, projects are specifically financed and use a project specific debt rate, which is excluded from the general corporate debt pool. Capitalization of debt funds is recorded as a charge to construction work in progress and as a non-cash credit to interest expense. See Note 8 — Property, Plant, and Equipment, Note 9 — Jointly Owned Electric Utility Plant and Note 23 — Supplemental Financial Information for additional information. Nuclear Fuel The cost of nuclear fuel is capitalized in Property, plant and equipment and charged to Purchased power and fuel using the unit-of-production method. Any potential future SNF disposal fees will also be expensed through Purchased power and fuel expense. Additionally, certain on-site SNF storage costs are being reimbursed by the DOE since a DOE (or government-owned) long-term storage facility has not been completed. See Note 19 — Commitments and Contingencies for additional information regarding the cost of SNF storage and disposal. Depreciation and Amortization Except for the amortization of nuclear fuel, depreciation, inclusive of ARC, is generally recorded over the estimated service lives of property, plant and equipment on a straight-line basis using the group, composite or unitary methods of depreciation. The group approach is typically for groups of similar assets that have approximately the same useful lives and the composite approach is used for dissimilar assets that have different lives. Under both methods, a reporting entity depreciates the assets over the average life of the assets in the group. The estimated service lives are based on a combination of depreciation studies, historical retirements, site licenses and management estimates of operating costs and expected future energy market conditions. See Note 7 — Early Plant Retirements for additional information on the impacts of early plant retirements, Note 8 — Property, Plant, and Equipment for additional information regarding depreciation, and Note 23 — Supplemental Financial Information for additional information regarding nuclear fuel. Asset Retirement Obligations We estimate and recognize a liability for our legal obligation to perform asset retirement activities even though the timing and/or methods of settlement may be conditional on future events. We generally update our nuclear decommissioning ARO annually, unless circumstances warrant more frequent updates, based on our annual evaluation of cost escalation factors and probabilities assigned to the multiple outcome scenarios within our probability-weighted discounted cash flow models. Our multiple outcome scenarios are generally based on decommissioning cost studies which are updated, on a rotational basis, for each of our nuclear units at least every five years, unless circumstances warrant more frequent updates. AROs are accreted throughout each year to reflect the time value of money for these present value obligations through a charge to Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income for Non-Regulatory Agreement Units and through a decrease in noncurrent payables related to Regulatory Agreement Units. See Note 10 — Asset Retirement Obligations for additional information. Accounting Implications of the Regulatory Agreement Units with ComEd and PECO Based on the regulatory agreements with the ICC and PAPUC that dictate our obligations related to the shortfall or excess of NDT funds necessary for decommissioning the former ComEd units on a unit-by-unit basis and the former PECO units in total, decommissioning-related activities net of applicable taxes, including realized and unrealized gains and losses on the NDT funds, depreciation of the ARC, and accretion of the decommissioning obligation are generally offset in the Consolidated Statements of Operations and Comprehensive Income and are recorded as noncurrent payables in the Consolidated Balance Sheets (within Payables related to Regulatory Agreement Units). See Note 10 — Asset Retirement Obligations for additional information. Asset Impairments Long-Lived Assets. We regularly monitor and evaluate the carrying value of long-lived assets or asset groups for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the asset, or plans to dispose of a long-lived asset significantly before the end of its useful life. We determine if long-lived assets or asset groups are potentially impaired by comparing the undiscounted expected future cash flows to the carrying value when indicators of impairment exist. When the undiscounted cash flow analysis indicates a long-lived asset or asset group may not be recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. Generally, pre-tax impairment losses are recorded in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. See Note 12 — Asset Impairments for additional information. Equity Method Investments. We regularly monitor and evaluate equity method investments to determine whether they are impaired. An impairment is recorded when the investment has experienced a decline in value that is other-than-temporary in nature. Additionally, if the entity in which we hold an investment recognizes an impairment loss, we would record their proportionate share of that impairment loss and evaluate the investment for an other-than-temporary decline in value. These impairment losses are recorded in Equity in (losses) earnings of unconsolidated affiliates in the Consolidated Statements of Operations and Comprehensive Income. Equity Security Investments. Equity investments with readily determinable fair values are measured and recorded at fair value with any changes in fair value recorded in Other, net in the Consolidated Statements of Operations and Comprehensive Income. Investments in equity securities without readily determinable fair values are qualitatively assessed for impairment each reporting period. If it is determined that the equity security is impaired, an impairment loss will be recognized in Other, net in the Consolidated Statements of Operations and Comprehensive Income to the amount by which the security’s carrying amount exceeds its fair value. Derivative Financial Instruments All derivatives are recognized on the balance sheet at their fair value unless they qualify for certain exceptions, including NPNS. For derivatives intended to serve as economic hedges, changes in fair value are recognized in earnings each period. Amounts classified in earnings are included in Operating revenues, Purchased power and fuel, or Interest expense in the Consolidated Statements of Operations and Comprehensive Income based on the activity the transaction is economically hedging. While most of the derivatives serve as economic hedges, there are also derivatives entered into for proprietary trading purposes, subject to our RMP, and changes in the fair value of those derivatives are recorded in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income. Cash inflows and outflows related to derivative instruments are included as a component of operating, investing, or financing cash flows in the Consolidated Statements of Cash Flows, depending on the nature of each transaction. As part of the energy marketing business, we enter contracts to buy and sell energy to meet the requirements of our customers. These contracts include short-term and long-term commitments to purchase and sell energy and energy-related products in the energy markets with the intent and ability to deliver or take delivery of the underlying physical commodity. NPNS are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period and will not be financially settled. Revenues and expenses on derivative contracts that qualify, and are designated, as NPNS are recognized when the underlying physical transaction is completed. While these contracts are considered derivative financial instruments, they are not required to be recorded at fair value. See Note 16 — Derivative Financial Instruments for additional information. Retirement Benefits Prior to separation, Exelon sponsored defined benefit pension plans and OPEB plans as described in Note 15 — Retirement Benefits . The plan obligations and costs of providing benefits under these plans were measured as of December 31, 2021. We accounted for our participation in Exelon’s pension and OPEB plans by applying multi-employer accounting. Exelon allocated costs related to its pension and OPEB plans to its subsidiaries based on both active and retired employee participation in each plan. We included the service cost and non- service cost components in Operating and maintenance expense and Property, plant, and equipment, net in the consolidated financial statements. Effective upon separation, we sponsor defined benefit pension and OPEB plans as described in Note 15 — Retirement Benefits. The plan obligations and costs o

Mergers, Acquisitions, and Disp

Mergers, Acquisitions, and Dispositions	12 Months Ended
Mergers, Acquisitions, and Dispositions	Dec. 31, 2022
Mergers, Acquisitions, and Dispositions [Abstract]
Mergers, Acquisitions, and Dispositions	Mergers, Acquisitions, and Dispositions CENG Put Option Prior to August 6, 2021, we owned a 50.01% membership interest in CENG, a joint venture with EDF, which wholly owned the Calvert Cliffs and Ginna nuclear stations and Nine Mile Point Unit 1, in addition to an 82% undivided ownership interest in Nine Mile Point Unit 2. CENG is 100% consolidated in our financial statements. On April 1, 2014, we entered into various agreements with EDF including a NOSA, an amended LLC Operating Agreement, an Employee Matters Agreement, and a Put Option Agreement, among others. Under the amended LLC Operating Agreement, CENG made a $400 million special distribution to EDF and committed to make preferred distributions to us until we had received aggregate distributions of $400 million plus a return of 8.50% per annum. Under the terms of the Put Option Agreement, EDF had the option to sell its 49.99% equity interest in CENG exercisable beginning on January 1, 2016 and thereafter until June 30, 2022. On November 20, 2019, we received notice of EDF’s intention to exercise the put option, and the put automatically exercised on January 19, 2020 at the end of the sixty-day advance notice period. The transaction required approval by FERC and the NYPSC, which approvals were received on July 30, 2020 and April 15, 2021, respectively. On August 6, 2021, we entered into a settlement agreement pursuant to which we purchased EDF's equity interest in CENG for a net purchase price of $885 million, which included, among other things, an adjustment for EDF's share of the outstanding balance of the preferred distribution payable to us by CENG. The difference between the net purchase price and EDF's noncontrolling interest as of August 6, 2021 was recorded to Membership interest in the Consolidated Balance Sheet. As a result of the transaction, we also recorded deferred tax liabilities of $288 million in Membership interest in the Consolidated Balance Sheet. See Note 14 — Income Taxes for additional information. The following table summarizes the effects of the changes in our ownership interest in CENG in Member's Equity: For the Year Ended December 31, 2021 Net loss attributable to membership interest $ (205) Pre-tax increase in membership interest for purchase of EDF's 49.99% equity interest (a) 1,080 Decrease in membership interest due to deferred tax liabilities resulting from purchase of EDF's equity interest (a) (288) Change from net loss attributable to membership interest and transfers from noncontrolling interest $ 587 __________ (a) Represents non-cash activity in the consolidated financial statements. Agreement for Sale of Our Solar Business On December 8, 2020, we entered into an agreement with an affiliate of Brookfield Renewable, for the sale of a significant portion of our solar business, including 360 MWs of generation in operation or under construction across more than 600 sites across the United States. We retained certain solar assets not included in this agreement, primarily Antelope Valley. Completion of the transaction contemplated by the sale agreement was subject to the satisfaction of several closing conditions that were satisfied in the first quarter of 2021. The sale was completed on March 31, 2021 for a purchase price of $810 million. We received cash proceeds of $675 million, net of $125 million long-term debt assumed by the buyer and certain working capital and other post-closing adjustments. We recognized a pre-tax gain of $68 million which is included in Gain on sales of assets and businesses in the Consolidated Statement of Operations and Comprehensive Income. Agreement for Sale of Our Biomass Facility

Regulatory Matters

Regulatory Matters	12 Months Ended
Regulatory Matters	Dec. 31, 2022
Regulated Operations [Abstract]
Regulatory Matters	Regulatory Matters The following matters below discuss the status of our material regulatory and legislative proceedings. Impacts of the February 2021 Extreme Cold Weather Event and Texas-based Generating Assets Outages In February 2021, our Texas-based generating assets within the ERCOT market, specifically Colorado Bend II, Wolf Hollow II, and Handley, experienced outages because of extreme cold weather conditions. In addition, those weather conditions drove increased demand for service, dramatically increased wholesale power prices, and increased gas prices in certain regions. As a result of the event and outages, we incurred a loss of approximately $800 million for the year ended December 31, 2021. The estimated impact reduced our overall Net loss by approximately $50 million for the year ended December 31, 2022, attributable to a payment to ERCOT from a defaulting market participant, the bankruptcy settlement of a defaulting ERCOT market participant, and the settlement of a dispute related to gas penalties. In response to the high demand and significantly reduced total generation on the system during the event, the PUCT directed ERCOT to use an administrative price cap of $9,000/MWh during firm load shedding. We intervened in a third-party notice of appeal in the Court of Appeals for the Third District of Texas challenging the validity of the PUCT’s action administratively setting prices at $9,000/MWh. Additionally, we filed a request for declaratory judgment in Texas district court. Our request is being stayed at our request pending the outcome of the third party’s direct appeal to the Third Court of Appeals on similar grounds, in which briefing is complete, oral argument was held on April 27, 2022. We cannot reasonably predict the outcome of these proceedings or the potential financial statement impact. Due to the event, several ERCOT market participants experienced bankruptcies or defaulted on payments to ERCOT. As of December 31, 2021, there were approximately $2.5 billion of outstanding defaults. Under ERCOT rules, defaults are allocated to the remaining market participants. Accordingly, we recorded our estimated obligation of the outstanding defaults, net of legislative solutions, and on a discounted basis, of approximately $17 million as of December 31, 2021, which was expected to be paid over a term of 83 years. As of result of a market participant paying off their debt to ERCOT and a bankruptcy settlement, there were no outstanding defaults to be allocated to market participants as of December 31, 2022, as further discussed below. Additionally, several legislative proposals were introduced in the Texas legislature during February and March 2021 concerning the amount, timing and allocation of recovery of the defaults, as well as recovery of other costs associated with the PUCT's directive to set prices at $9,000 per MWh. Two of these proposals were enacted into law in June 2021 and establish financing mechanisms that ERCOT and certain market participants can utilize to fund amounts owed to ERCOT. Securitization of defaults of competitive retail providers has been completed and a market participant securitized its debt and repaid amounts owed to ERCOT, both of which reduced our obligation . We participated in proceedings before the PUCT addressing the proposed allocation of the $2.1 billion in securitized funds for reliability and ancillary service charges over $9,000 per MWh. In September 2021, we entered into a settlement agreement and stipulation to resolve the allocation issues. The PUCT approved the settlement agreement and stipulation on October 13, 2021, and in June 2022, we collected our outstanding receivable. In the first quarter of 2022, a hearing began on ERCOT’s $1.9 billion claim in another market participant’s bankruptcy for the entire outstanding default owed to ERCOT. The ERCOT claim was resolved through a settlement included in the Chapter 11 Plan of Reorganization filed by the Debtor (market participant) on September 1, 2022 and approved by the bankruptcy court, which became effective on December 15, 2022. The settlement avoids ERCOT allocating outstanding default charges to remaining market participants. In February 2021, more than 70 local distribution companies (LDCs) and natural gas pipelines in multiple states throughout the mid-continent region, where we serve natural gas customers, issued operational flow orders (OFOs), curtailments or other limitations on natural gas transportation or use to manage the operational integrity of the applicable LDC or pipeline system. When in effect, gas transportation or use above these limitations is subject to significant penalties according to the applicable LDCs’ and natural gas pipelines’ tariffs. Gas transportation and supply in many states became restricted due to wells freezing and pipeline compression disruption, while demand was increasing due to the extreme cold temperatures, resulting in extremely high natural gas prices. Due to the extraordinary circumstances, many LDCs and natural gas pipelines either voluntarily waived or sought applicable regulatory approvals to waive the tariff penalties associated with the extreme weather event. During May 2021, an LDC filed a motion with the Kansas Corporation Commission (KCC) requesting the KCC to grant a waiver from the tariff and allow the LDC to reduce the amounts assessed by permitting the removal of a multiplier from the penalty calculation. On March 3, 2022, the KCC approved a unanimous settlement, resolving this matter. Illinois Regulatory Matters Clean Energy Law. On September 15, 2021, the Illinois Public Act 102-0662 was signed into law by the Governor of Illinois ("Clean Energy Law"). The Clean Energy Law establishes decarbonization requirements for Illinois as well as programs to support the retention and development of emissions-free sources of electricity. Among other things, the Clean Energy Law authorized the IPA to procure up to 54.5 million CMCs from qualifying nuclear plants for a five-year period beginning on June 1, 2022 through May 31, 2027. CMCs are credits for the carbon-free attributes of eligible nuclear power plants in PJM. Our Byron, Dresden, and Braidwood nuclear plants located in Illinois participated in the CMC procurement process and were awarded contracts that commit each plant to operate through May 31, 2027. Pursuant to these contracts, ComEd will procure CMCs based upon the number of MWhs produced annually by each plant, subject to minimum performance requirements. The price to be paid for each CMC was established through a competitive bidding process that included consumer-protection measures that capped the maximum acceptable bid amount and reduces CMC prices by an energy price index, the base residual auction capacity price in the ComEd zone of PJM, and the monetized value of any federal tax credit or other subsidy, if applicable. The consumer protection measures contained in the new law will result in net payments to ComEd ratepayers if the energy index, the capacity price and applicable federal tax credits or subsidy exceed the CMC contract price. Regulatory or legal challenges regarding the validity or implementation of the Clean Energy Law are possible and we cannot reasonably predict the outcome of any such challenges. See Note 7 – Early Plant Retirements for the impacts of the provisions above on the Illinois nuclear plants and the consolidated financial statements. New Jersey Regulatory Matters New Jersey Clean Energy Legislation. On May 23, 2018, New Jersey enacted legislation that established a ZEC program that provides compensation for nuclear plants that demonstrate to the NJBPU that they meet certain requirements, including that they make a significant contribution to air quality in the state and that their revenues are insufficient to cover their costs and risks. Under the legislation, the NJBPU will issue ZECs to qualifying nuclear power plants and the electric distribution utilities in New Jersey will be required to purchase those ZECs. On April 18, 2019, the NJBPU approved the award of ZECs to Salem 1 and Salem 2. Upon approval, we began recognizing revenue for the sale of New Jersey ZECs in the month they are generated. On March 19, 2021, a three-judge panel of the Superior Court of New Jersey Appellate Division unanimously affirmed the NJBPU’s April 2019 order awarding ZECs for the first eligibility period. On April 8, 2021, New Jersey Rate Counsel filed a notice asking the New Jersey Supreme Court to hear the appeal of the Superior Court’s order. On July 9, 2021, the New Jersey Supreme Court declined to hear the appeal. On October 1, 2020, we and PSEG filed applications seeking ZECs for the second eligibility period (June 2022 through May 2025). On April 27, 2021, the NJBPU approved the award of ZECs to Salem 1 and Salem 2 for the second eligibility period. On May 11, 2021, the New Jersey Rate Counsel appealed the April 27, 2021 decision to the Superior Court of New Jersey Appellate Division. Briefing on the appeal has concluded, and we are awaiting the scheduling of oral argument. We cannot reasonably predict the outcome of this proceeding. New England Regulatory Matters Mystic Units 8 and 9 Cost of Service Agreement. On March 29, 2018, we notified grid operator ISO-NE of our plans to early retire Mystic Units 8 and 9 absent regulatory reforms on June 1, 2022. On May 16, 2018, we made a filing with FERC to establish cost-of-service compensation and terms and conditions of service for Mystic Units 8 and 9 for the period between June 1, 2022 to May 31, 2024. On December 20, 2018, FERC issued an order accepting the cost of service compensation, reflecting a number of adjustments to the annual fixed revenue requirement and allowing for recovery of a substantial portion of the costs associated with the adjacent EMT we acquired in October 2018. Those adjustments were reflected in a compliance filing made on March 1, 2019. In the December 20, 2018 order, FERC also directed a paper hearing on Return on Equity (“ROE”) using a new methodology. The ROE impacts the return Mystic collects on its rate base under the agreement. On January 22, 2019, we and several other parties filed requests for rehearing of certain findings in the order. On July 15, 2021, FERC issued an order establishing the ROE to be used in the cost of service agreement for Mystic 8 and 9 at 9.33%. On August 16, 2021, we and several other parties filed requests for rehearing of certain aspects of the July 15, 2021 order. In November 2021, FERC issued an order directing a decrease to the ROE used in the Mystic Cost of Service Agreement (the “Mystic COS”) from 9.33% to 9.19%. Several parties, including us, have filed petitions for review with the U.S. Court of Appeals for the D.C. Circuit challenging the FERC orders establishing the ROE. These petitions are pending. We do not expect the outcome of this appeal to have a material financial statement impact. On July 17, 2020, FERC issued three orders, which together affirmed the recovery of key elements of Mystic's cost of service compensation, including recovery of costs associated with the operation of the EMT. FERC directed a downward adjustment to the rate base for Mystic Units 8 and 9, the effect of which will be partially offset by elimination of a crediting mechanism for third-party gas sales during the term of the cost of service agreement. In addition, several parties filed protests to a compliance filing by us on September 15, 2020, taking issue with how gross plant in-service was calculated, and we filed an answer to the protests on October 21, 2020. On December 21, 2020, FERC issued an order on rehearing of the three July 17, 2020 orders, clarifying several cost of service provisions. Several parties appealed the December 21, 2020 order to the U.S. Court of Appeals for the D.C. Circuit and that appeal was consolidated with appeals of orders issued December 20, 2018 and July 17, 2020 in the Mystic proceeding. On August 23, 2022, court issued its opinion and remanded several issues back to FERC, which include: (1) the amount of the EMT’s fixed costs that can be recovered via the Mystic COS, (2) whether some or all of EMT capital expenditures recovered during the term of the Mystic COS will have to be returned if EMT continues operating after the Mystic COS terminates, and (3) the historical rate base for Mystic upon which we earn a return. We await FERC’s order on remand and cannot reasonably predict the outcome of this proceeding, which could have a material financial impact over the term of the Mystic COS. The Mystic COS requires an annual process whereby we identify and support our projected costs under the agreement and/or true-up previous projections to the actual costs incurred. The first annual process resulted in a filing at FERC on September 15, 2021 and included our projection of capital expenditures to be recovered under the Mystic COS between June 1, 2022 and December 31, 2022. On April 28, 2022, FERC issued an order setting for settlement and/or hearing the issue of whether our projected 2022 capital expenditures can be recovered. Settlement negotiations are currently ongoing. We cannot reasonably predict the outcome of the settlement and/or hearing. On September 15, 2022, we made our second annual filing at FERC, which included (1) our projection of capital expenditures to be recovered under the Mystic COS between January 1, 2023 and December 31, 2023, and (2) an updated projection of the Annual Fixed Revenue Requirement, the Maximum Monthly Fixed Cost Payment, and the Fixed Operating and Maintenance/Return on Investment component of the Monthly Fuel Cost Charge, including an update to rate base for the period between January 1, 2018 and December 31, 2021. That filing is currently pending at FERC. Following our separation from Exelon, we submitted a filing at FERC to update the capital structure and cost of debt used in the Mystic COS. The Mystic COS had previously used the Exelon capital structure and cost of debt in the rate, and we proposed post-separation to instead use Constellation's capital structure and cost of debt. On May 2, 2022, FERC accepted our filing, subject to refund, and set the matter for settlement and/or hearing. An unopposed offer of settlement was filed at FERC on September 8, 2022 and was approved by FERC on November 2, 2022. The settlement does not have a material financial impact. See Note 7 — Early Plant Retirements and Note 12 — Asset Impairments for additional information on the impacts of our August 2020 decision to retire Mystic Units 8 and 9 upon expiration of the cost of service agreement. Federal Regulatory Matters Inflation Reduction Act of 2022. On August 16, 2022, Congress passed and President Biden signed into law the IRA, which, among other things, includes federal tax credits, certain of which are transferable or fully refundable, for a number of clean energy technologies including existing nuclear plants and hydrogen production facilities. The Nuclear PTC recognizes the contributions of carbon-free nuclear power by providing a federal tax credit of up to $15/MWh, subject to phase-out, beginning in 2024 and continuing through 2032. The Hydrogen PTC provides a 10-year federal tax credit of up to $3/kilogram for clean hydrogen produced after 2022 from facilities that begin construction prior to 2033. Both the Nuclear and Hydrogen PTCs include adjustments for inflation. The Hydrogen PTC creates additional opportunities for our nuclear fleet to enable decarbonization of other industries through the production of clean hydrogen. With this policy support, we expect that many of our nuclear assets will operate through the end of the Nuclear PTC period. Further, the IRA includes a 15% book-minimum tax on applicable corporations that we do not expect to have a material impact to our consolidated financial statements. Complaint at FERC Seeking to Alter Capacity Market Default Offer Caps. On February 21, 2019, PJM's Independent Market Monitor (IMM) filed a complaint alleging that the number of performance assessment intervals used to calculate the default offer cap for bids to supply capacity in PJM is too high, resulting in an overstated default offer cap that obviates the need for most sellers to seek unit-specific approval of their offers. The IMM argued that this allows for the exercise of market power. The IMM asked FERC to require PJM to reduce the number of performance assessment intervals used to calculate the opportunity costs of a capacity supplier assuming a capacity obligation. This would, in turn, lower the default offer cap and allow the IMM to review more offers on a unit-specific basis. Several consumer advocates filed a complaint seeking similar relief several months after the IMM’s complaint. On March 18, 2021, FERC granted the complaints, finding the current estimate of performance assessment intervals to be excessive compared to the reasonably expected number of performance assessment intervals which results in an unjust and unreasonable default offer cap. FERC did not establish the number of performance assessment intervals that should be used to calculate the default offer cap and instead requested briefs on the matter, including alternative approaches to mitigation in the capacity market. On September 2, 2021, FERC issued an order adopting the IMM's unit-specific avoidable cost offer review methodology and directed PJM to submit a compliance filing establishing new deadlines for offer review and related other activities leading up to the base residual auction for the 2023-2024 planning year and an additional compliance filing revising the PJM Tariff to comply with FERC's order. Requests for rehearing of FERC’s September 2021 order were deemed denied on November 4, 2021. A number of parties, including us, have filed petitions for review of FERC's orders in this proceeding, which remain pending before the Court of Appeals for the District of Columbia Circuit. We cannot predict the outcome of these proceedings. PJM MOPR Proceedings. The PJM capacity market includes a MOPR. If a resource is subjected to a MOPR, its offer is adjusted to effectively remove the revenues it receives through a state government-provided financial support program - resulting in a higher offer that may not clear in capacity auctions. Prior to December 19, 2019, the MOPR in PJM applied only to certain new gas-fired resources. On December 19, 2019, FERC required PJM to broadly apply the MOPR to all new and existing resources including nuclear, renewables, demand response, energy efficiency, storage, and all resources owned by vertically-integrated utilities. This greatly expanded the breadth and scope of PJM’s MOPR, which became effective as of PJM’s capacity auction for the 2022-23 planning year. While FERC included some limited exemptions, no exemptions were available to state-supported nuclear resources. FERC denied rehearing of that order on April 16, 2020. A number of parties, including us, have filed petitions for review of FERC's orders in this proceeding, which are being held in abeyance before the Court of Appeals for the Seventh Circuit. We cannot reasonably predict the outcome of this proceeding. While this litigation remains pending, the MOPR applied in the capacity auction for the 2022-23 planning year to our owned or jointly owned nuclear plants in those states receiving a benefit under the Illinois ZES, and the New Jersey ZEC program. The MOPR prevented Quad Cities from clearing in that capacity auction. At the direction of the PJM Board of Managers, PJM and its stakeholders developed further MOPR reforms to ensure that the capacity market rules respect and accommodate state resource preferences such as the ZEC programs. PJM filed related tariff revisions at FERC on July 30, 2021 and, on September 29, 2021, PJM's proposed MOPR reforms became effective by operation of law. Under the new tariff provisions, the MOPR applied in the capacity auction for the 2023-2024 delivery year and did not restrict the offers of any of our state-supported owned or jointly owned nuclear plants. All of our nuclear units receiving state support cleared in the 2023-24 auction. Requests for rehearing of FERC’s notice establishing the effective date for PJM’s proposed market reforms were filed in October 2021 and denied by operation of law on November 4, 2021. Several parties have filed petitions for review of FERC's orders in this proceeding, which remain pending before the Court of Appeals for the Third Circuit. We cannot reasonably predict the outcome of this proceeding. If our state-supported nuclear plants in PJM are subjected to a MOPR or equivalent without compensation under an FRR or similar program, it could have a material adverse impact on our consolidated financial statements, which we cannot reasonably estimate at this time. Operating License Renewals Conowingo Hydroelectric Project. On August 29, 2012, we submitted an application to FERC for a new license for the Conowingo Hydroelectric Project (Conowingo). In connection with our efforts to obtain a water quality certification pursuant to Section 401 of the Clean Water Act (401 Certification) from MDE for Conowingo, we had been working with MDE and other stakeholders to resolve water quality licensing issues, including: (1) water quality, (2) fish habitat, and (3) sediment. On April 21, 2016, we and the U.S. Fish and Wildlife Service of the U.S. Department of the Interior executed a settlement agreement (DOI Settlement) resolving all fish passage issues between the parties. On April 27, 2018, MDE issued its 401 Certification for Conowingo. As issued, the 401 Certification contained numerous conditions, including those relating to reduction of nutrients from upstream sources, removal of all visible trash and debris from upstream sources, and implementation of measures relating to fish passage. On October 29, 2019, we and MDE filed with FERC a Joint Offer of Settlement (Offer of Settlement) that would resolve all outstanding issues relating to the 401 Certification. Pursuant to the Offer of Settlement, the parties submitted Proposed License Articles to FERC to be incorporated by FERC into the new license in accordance with FERC’s discretionary authority under the Federal Power Act. Among the Proposed License Articles were modifications to river flows to improve aquatic habitat, eel passage improvements, and initiatives to support rare, threatened and endangered wildlife. On March 19, 2021, FERC issued a new 50-year license for Conowingo, effective March 1, 2021. FERC adopted the Proposed License Articles into the new license, only making modifications it deemed necessary to allow FERC to enforce the Proposed License Articles. Consistent with the Offer of Settlement, FERC found that MDE waived its 401 Certification and pursuant to a separate agreement with MDE (MDE Settlement), we agreed to implement additional environmental protection, mitigation, and enhancement measures over the 50-year term of the new license. These measures address mussel restoration and other ecological and water quality matters, among other commitments. On April 19, 2021, a few environmental groups filed with FERC a petition for rehearing requesting that FERC reconsider the issuance of the new Conowingo license, which was denied by operation of law on May 20, 2021. On June 17, 2021, the petitioners appealed FERC’s ruling to the U.S. Court of Appeals for the D.C. Circuit. On December 20, 2022, the U.S. Court of Appeals for the D.C. Circuit issued a decision vacating FERC’s decision to grant Conowingo its 50-year license renewal and sending the matter back to FERC for further proceedings. The court found that the Clean Water Act prohibits FERC from issuing the new Conowingo license because the process under which MDE provided a waiver of its right to issue a 401 certification was invalid. Upon issuance of the mandate from the U.S. Court of Appeals for the D.C. Circuit, we expect FERC will issue an annual license, which renews automatically, containing the same terms as the license that was in effect prior to the March 19, 2021 FERC order and Conowingo will continue to operate pursuant to that license. We are unable to further predict the outcome of this proceeding at this time. Depreciation provisions continue to assume operation through 2071 given our expectation that a 50-year license will be issued. Peach Bottom Units 2 and 3. On March 6, 2020, the NRC approved a second 20-year license renewal for Peach Bottom Units 2 and 3. As a result, Peach Bottom Units 2 and 3 were granted the authority to operate through 2053 and 2054, respectively. Notwithstanding its 2020 approval, on February 24, 2022, the NRC took action to modify Peach Bottom's subsequently renewed licenses in response to a request for hearing that the NRC had not previously adjudicated. In its February 2022 decision, the NRC reversed itself and concluded that the previous environmental review required by the National Environmental Policy Act (NEPA) for the Peach Bottom subsequently renewed licenses was incomplete because it did not adequately address environmental impacts resulting from renewing the units’ licenses for an additional 20 years. As a result, the NRC has undertaken an effort to modify its regulations and guidance to specifically address environmental impacts during the period of subsequent license renewal, which it expects to complete in 2024. In addition, the NRC modified the expiration dates for the Peach Bottom licenses from 2053 and 2054 to 2033 and 2034, respectively, pending the completion of the updated NEPA analysis. On March 7, 2022, we filed a petition requesting that the NRC reevaluate its decision to amend the expiration dates of the Peach Bottom licenses, which the NRC denied on June 3, 2022. In denying our petition, however, the NRC affirmed that the subsequently renewed licenses would otherwise remain in place. We expect that the license expiration dates will be restored to 2053 and 2054, respectively, once the NRC's reevaluation of environmental impacts resulting from subsequent license renewal is complete. On April 5, 2022, the NRC approved a proposed plan to complete the process by April 2024 and to date, the NRC has remained on schedule to meet the April 2024 goal. Depreciation provisions and ARO assumed retirement dates

Revenue from Contracts with Cus

Revenue from Contracts with Customers	12 Months Ended
Revenue from Contracts with Customers	Dec. 31, 2022
Revenue from Contract with Customer [Abstract]
Revenue from Contracts with Customers	Revenue from Contracts with Customers We recognize revenue from contracts with customers to depict the transfer of goods or services to customers at an amount that we expect to be entitled to in exchange for those goods or services. Our primary sources of revenue include competitive sales of power, natural gas, and other energy-related products and services. The performance obligations, revenue recognition, and payment terms associated with these sources of revenue are further discussed in the table below. There are no significant financing components for these sources of revenue. Unless otherwise noted, for each of the significant revenue categories and related performance obligations described below, we have the right to consideration from the customer in an amount that corresponds directly with the value transferred to the customer for the performance completed to date. Therefore, we generally recognize revenue in the amount for which we have the right to invoice the customer. As a result, there are generally no significant judgments used in determining or allocating the transaction price. Revenue Source Description Performance Obligation Timing of Revenue Recognition Payment Terms Competitive Power Sales Sales of power and other energy-related commodities to wholesale and retail customers across multiple geographic regions through our customer-facing business. Various, including the delivery of power (generally delivered over time) and other energy-related commodities such as capacity (generally delivered over time), CMCs, ZECs, RECs or other ancillary services (generally delivered at a point in time). Concurrently as power is generated for bundled power sale contracts. (a) Within the month following delivery to the customer. Competitive Natural Gas Sales Sales of natural gas on a full requirement basis or for an agreed upon volume to commercial and residential customers. Delivery of natural gas to the customer. Over time as the natural gas is delivered to the customer. Within the month following delivery to the customer. Other Competitive Products and Services Sales of other energy-related products and services such as long-term construction and installation of energy efficiency assets and new power generating facilities, primarily to commercial and industrial customers. Construction and/or installation of the asset for the customer. Revenues and associated costs are recognized throughout the contract term using an input method to measure progress towards completion. (b) Within 30 or 45 days from the invoice date. __________ (a) Certain contracts may contain limits on the total amount of revenue we are able to collect over the entire term of the contract. In such cases, we estimate the total consideration expected to be received over the term of the contract net of the constraint and allocate the expected consideration to the performance obligations in the contract such that revenue is recognized ratably over the term of the entire contract as the performance obligations are satisfied. (b) The method recognizes revenue based on the various inputs used to satisfy the performance obligation, such as costs incurred and total labor hours expended. The total amount of revenue that will be recognized is based on the agreed upon contractually-stated amount. The average contract term for these projects is approximately 18 months. We incur incremental costs in order to execute certain retail power and gas sales contracts. These costs, which primarily relate to retail broker fees and sales commissions, are capitalized when incurred as contract acquisition costs and were not material as of December 31, 2022 and 2021. Contract Balances Contract Assets We record contract assets for the revenue recognized on the construction and installation of energy efficiency assets and new power generating facilities before we have an unconditional right to bill for and receive the consideration from the customer. These contract assets are subsequently reclassified to receivables when the right to payment becomes unconditional. We record contract assets and contract receivables in Other current assets and Customer accounts receivable, net, respectively, in the Consolidated Balance Sheets. The following table provides a rollforward of the contract assets reflected in the Consolidated Balance Sheets: Contract Assets Balance as of December 31, 2020 $ 144 Amounts reclassified to receivables (59) Revenues recognized 52 Amounts previously held-for-sale 12 Balance as of December 31, 2021 149 Amounts reclassified to receivables (81) Revenues recognized 62 Balance as of December 31, 2022 $ 130 Contract Liabilities We record contract liabilities when consideration is received or due prior to the satisfaction of the performance obligations. We record contract liabilities in Other current liabilities and Other deferred credits and other liabilities in the Consolidated Balance Sheets. These contract liabilities primarily relate to upfront consideration received or due for equipment service plans and the Illinois ZEC program that introduces an annual cap on the total consideration to be received by us for each delivery period. The ZEC price is established on a per MWh of production basis with a maximum annual cap for total compensation to be received in a delivery period, while requiring delivery of all ZECs produced by our participating facilities during each delivery period. ZECs delivered to Illinois utilities in excess of the annual cost cap may be paid in subsequent years if the payments do not exceed the prescribed annual cost cap for that year. The following table provides a rollforward of the contract liabilities reflected in the Consolidated Balance Sheets: Contract Liabilities Balance as of December 31, 2019 $ 71 Consideration received or due 282 Revenues recognized (266) Contracts liabilities reclassified as held for sale (3) Balance as of December 31, 2020 84 Consideration received or due 251 Revenues recognized (263) Amounts previously held-for-sale 3 Balance as of December 31, 2021 75 Consideration received or due 339 Revenues recognized (367) Balance as of December 31, 2022 $ 47 The following table reflects revenues recognized in the years ended December 31, 2022, 2021 and 2020, which were included in contract liabilities at December 31, 2021, 2020, and 2019, respectively: 2022 2021 2020 Revenues recognized $ 71 $ 82 $ 64 Transaction Price Allocated to Remaining Performance Obligations The following table shows the amounts of future revenues expected to be recorded in each year for performance obligations that are unsatisfied or partially unsatisfied as of December 31, 2022. This disclosure only includes contracts for which the total consideration is fixed and determinable at contract inception. The average contract term varies by customer type and commodity but ranges from one month to several years. This disclosure excludes our power and gas sales contracts as they contain variable volumes and/or variable pricing. 2023 2024 2025 2026 2027 and thereafter Total Remaining performance obligations $ 221 $ 78 $ 35 $ 15 $ 136 $ 485 Revenue Disaggregation We disaggregate the revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. See Note 5 — Segment Information for the presentation of revenue disaggregation.

Segment Information

Segment Information	12 Months Ended
Segment Information	Dec. 31, 2022
Segment Reporting [Abstract]
Segment Information	Segment Information Operating segments are determined based on information used by the CODM in deciding how to evaluate performance and allocate resources. We have five reportable segments consisting of the Mid-Atlantic, Midwest, New York, ERCOT, and all other power regions referred to collectively as “Other Power Regions.” The basis for our reportable segments is the integrated management of our electricity business that is located in different geographic regions, and largely representative of the footprints of ISO/RTO and/or NERC regions, which utilize multiple supply sources to provide electricity through various distribution channels (wholesale and retail). Our hedging strategies and risk metrics are also aligned to these same geographic regions. Descriptions of each of our five reportable segments are as follows: • Mid-Atlantic represents operations in the eastern half of PJM, which includes New Jersey, Maryland, Virginia, West Virginia, Delaware, the District of Columbia, and parts of Pennsylvania and North Carolina. • Midwest represents operations in the western half of PJM and the United States footprint of MISO, excluding MISO’s Southern Region. • New York represents operations within NYISO. • ERCOT represents operations within Electric Reliability Council of Texas that covers a majority of the state of Texas. • Other Power Regions: • New England represents operations within ISO-NE. • South represents operations in FRCC, MISO’s Southern Region, and the remaining portions of SERC not included within MISO or PJM. • West represents operations in WECC, which includes CAISO. • Canada represents operations across the entire country of Canada and includes AESO, OIESO, and the Canadian portion of MISO. The CODM evaluates the performance of our electric business activities and allocates resources based on Operating revenues less Purchased power and fuel expense (RNF). We believe this is a useful measurement of operational performance, although it is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report. Our operating revenues include all sales to third parties and affiliated sales to Exelon's utility subsidiaries, prior to the separation. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy, and ancillary services. Fuel expense includes the fuel costs for our owned generation and fuel costs associated with tolling agreements. The results of our other business activities are not regularly reviewed by the CODM and are therefore not classified as operating segments or included in the regional reportable segment amounts. These activities include wholesale and retail sales of natural gas, as well as other miscellaneous business activities that are not significant to our overall results of operations. Further, our unrealized mark-to-market gains and losses on economic hedging activities and our amortization of certain intangible assets and liabilities relating to commodity contracts recorded at fair value from mergers and acquisitions are also excluded from the regional reportable segment amounts. The CODM does not use a measure of total assets in making decisions regarding allocating resources to or assessing the performance of these reportable segments. The following tables disaggregate the revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. The disaggregation of revenues reflects our two primary products of power sales and natural gas sales, with further disaggregation of power sales provided by geographic region. The following tables also show the reconciliation of reportable segment revenues and RNF to our total revenues and RNF for the years ended December 31, 2022, 2021, and 2020. 2022 Revenues from external customers (a) Contracts with customers Other (b) Total Intersegment Revenues Total Revenues Mid-Atlantic $ 5,264 $ (105) $ 5,159 $ 5 $ 5,164 Midwest 5,164 (507) 4,657 (7) 4,650 New York 2,004 (408) 1,596 (1) 1,595 ERCOT 954 602 1,556 (13) 1,543 Other Power Regions 5,035 1,681 6,716 16 6,732 Total Competitive Businesses Electric Revenues $ 18,421 $ 1,263 $ 19,684 $ — $ 19,684 Competitive Businesses Natural Gas Revenues 2,559 2,408 4,967 — 4,967 Competitive Businesses Other Revenues (c) 591 (802) (211) — (211) Total Consolidated Operating Revenues $ 21,571 $ 2,869 $ 24,440 $ — $ 24,440 2021 Revenues from external customers (a) Contracts with customers Other (b) Total Intersegment Revenues Total Revenues Mid-Atlantic $ 4,381 $ 183 $ 4,564 $ 20 $ 4,584 Midwest 4,265 (205) 4,060 — 4,060 New York 1,633 (57) 1,576 (1) 1,575 ERCOT 896 276 1,172 9 1,181 Other Power Regions 3,937 981 4,918 (28) 4,890 Total Competitive Businesses Electric Revenues $ 15,112 $ 1,178 $ 16,290 $ — $ 16,290 Competitive Businesses Natural Gas Revenues 1,777 1,602 3,379 — 3,379 Competitive Businesses Other Revenues (c) 365 (385) (20) — (20) Total Consolidated Operating Revenues $ 17,254 $ 2,395 $ 19,649 $ — $ 19,649 2020 Revenues from external customers (a) Contracts with customers Other (b) Total Intersegment Revenues Total Revenues Mid-Atlantic $ 4,785 $ (168) $ 4,617 $ 28 $ 4,645 Midwest 3,717 312 4,029 (5) 4,024 New York 1,444 (12) 1,432 (1) 1,431 ERCOT 735 198 933 25 958 Other Power Regions 3,586 463 4,049 (47) 4,002 Total Competitive Businesses Electric Revenues $ 14,267 $ 793 $ 15,060 $ — $ 15,060 Competitive Businesses Natural Gas Revenues 1,283 720 2,003 — 2,003 Competitive Businesses Other Revenues (c) 355 185 540 — 540 Total Consolidated Operating Revenues $ 15,905 $ 1,698 $ 17,603 $ — $ 17,603 __________ (a) Includes all wholesale and retail electric sales to third parties and affiliated sales to Exelon's utility subsidiaries prior to the separation on February 1, 2022. See Note 24 — Related Party Transactions for additional information. (b) Includes revenues from derivatives and leases. (c) Represents activities not allocated to a region. See text above for a description of included activities. Includes unrealized mark-to-market losses of $1,188 million and $633 million and gains of $110 million for the years ended December 31, 2022, 2021, and 2020, respectively. 2022 2021 2020 RNF from external (a) Intersegment Total RNF from external (a) Intersegment Total RNF from external (a) Intersegment Total Mid-Atlantic $ 2,129 $ 9 $ 2,138 $ 2,247 $ 17 $ 2,264 $ 2,174 $ 30 $ 2,204 Midwest 2,765 (1) 2,764 2,717 — 2,717 2,902 — 2,902 New York 1,061 6 1,067 1,151 10 1,161 983 14 997 ERCOT 503 (96) 407 (668) (157) (825) 407 19 426 Other Power Regions 952 (31) 921 984 (93) 891 759 (94) 665 Total RNF for Reportable Segments $ 7,410 $ (113) $ 7,297 $ 6,431 $ (223) $ 6,208 $ 7,225 $ (31) $ 7,194 Other (b) (432) 113 (319) 1,055 223 1,278 793 31 824 Total RNF $ 6,978 $ — $ 6,978 $ 7,486 $ — $ 7,486 $ 8,018 $ — $ 8,018 __________ (a) Includes purchases and sales from/to third parties and affiliated sales to Exelon's utility subsidiaries prior to the separation on February 1, 2022. See Note 24 — Related Party Transactions for additional information. (b) Other represents activities not allocated to a region. See text above for a description of included activities. Primarily includes: • Unrealized mark-to-market losses of $1,013 million, and gains of $565 million, and $295 million for the years ended December 31, 2022, 2021, and 2020, respectively; • Accelerated nuclear fuel amortization associated with the announced early plant retirements as discussed in Note 7 - Early Plant Retirements of $148 million, and $60 million for the years ended December 31, 2021, and 2020, respectively; and • The elimination of intersegment RNF.

Accounts Receivable

Accounts Receivable	12 Months Ended
Accounts Receivable	Dec. 31, 2022
Receivables [Abstract]
Accounts Receivable	Accounts Receivable Allowance for Credit Losses on Accounts Receivable The following table presents the rollforward of Allowance for Credit Losses on Customer Accounts Receivable, which does not include any allowance related to the sales of Customer Accounts Receivable disclosed below. Allowance for Credit Losses on Other Accounts Receivable was not material as of the balance sheet dates. Balance as of December 31, 2020 $ 32 Plus: Current period provision for expected credit losses 30 Less: Write-offs, net of recoveries (a) 7 Balance as of December 31, 2021 55 Plus: Current period provision for expected credit losses 9 Less: Write-offs, net of recoveries (a) 18 Balance as of December 31, 2022 $ 46 __________ (a) Recoveries were not material. Unbilled Customer Revenue We recorded $564 million and $373 million of unbilled customer revenues in Customer accounts receivables, net in the Consolidated Balance Sheets as of December 31, 2022 and 2021, respectively. Sales of Customer Accounts Receivable On April 8, 2020, NER, a bankruptcy remote, special purpose entity, which is wholly owned by us, entered into a revolving accounts receivable financing arrangement with a number of financial institutions and a commercial paper conduit (the "Purchasers") to sell certain customer accounts receivable (the "Facility"). On August 16, 2022, we entered into an amendment on the Facility, which increased the maximum funding limit of the Facility from $900 million to $1.1 billion and extended the term of the Facility through August 15, 2025, unless renewed by the mutual consent of the parties in accordance with its terms. Under the Facility, NER may sell eligible short-term customer accounts receivable to the Purchasers in exchange for cash and subordinated interest. The transfers are reported as sales of receivables in the consolidated financial statements. The subordinated interest in collections upon the receivables sold to the Purchasers is referred to as the DPP, which is reflected in Other current assets in the Consolidated Balance Sheets. The Facility requires the balance of eligible receivables to be maintained at or above the balance of cash proceeds received from the Purchasers. To the extent the eligible receivables decrease below such balance, we are required to repay cash to the Purchasers. When eligible receivables exceed cash proceeds, we have the ability to increase the cash received up to the maximum funding limit. These cash inflows and outflows impact the DPP. The following table summarizes the impact of the sale of certain receivables: As of December 31, 2022 2021 Derecognized receivables transferred at fair value $ 1,615 $ 1,265 Cash proceeds received 1,100 900 DPP 515 365 For the Years Ended December 31, 2022 2021 2020 Loss on sale of receivables (a) $ 69 $ 36 $ 30 _________ (a) Reflected in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. This represents the amount by which the accounts receivable sold into the Facility are discounted, limited to credit losses. For the Years Ended December 31, 2022 2021 2020 Proceeds from new transfers (a) $ 6,108 $ 6,095 $ 2,816 Cash collections received on DPP and reinvested in the Facility (b) 4,764 3,502 3,771 Cash collections reinvested in the Facility 10,872 9,597 6,587 _________ (a) Customer accounts receivable sold into the Facility were $11,274 million and $9,747 million for the years ended December 31, 2022 and 2021, respectively. (b) Does not include the $200 million in net cash proceeds received from the Purchasers in 2022 and $400 million in cash proceeds received from the Purchasers in 2021. Our risk of loss following the transfer of accounts receivable is limited to the DPP outstanding. Payment of DPP is not subject to significant risks other than delinquencies and credit losses on accounts receivable transferred. We continue to service the receivables sold in exchange for a servicing fee. We did not record a servicing asset or liability as the servicing fees were immaterial. We recognize the cash proceeds received upon sale in Net cash provided by operating activities in the Consolidated Statements of Cash Flows. The collection and reinvestment of DPP is recognized in Net cash provided by investing activities in the Consolidated Statements of Cash Flows. See Note 18 — Fair Value of Financial Assets and Liabilities and Note 22 — Variable Interest Entities for additional information. Other Sales of Customer Accounts Receivables We are required, under supplier tariffs, to sell customer receivables to utility companies, which included Exelon's utility subsidiaries prior to the separation. The following table presents the total receivables sold. For the Years Ended December 31, 2022 2021 2020 Total receivables sold $ 423 $ 147 $ 824 Related party transactions: Receivables sold to Exelon's utility subsidiaries prior to the separation on February 1, 2022 4 23 252

Early Plant Retirements

Early Plant Retirements	12 Months Ended
Early Plant Retirements	Dec. 31, 2022
Implications of Potential Early Plant Retirements [Abstract]
Early Plant Retirements	Early Plant Retirements We continuously evaluate factors that affect the current and expected economic value of our plants, including, but not limited to: market power prices, results of capacity auctions, potential legislative and regulatory solutions to ensure plants are fairly compensated for benefits they provide through their carbon-free emissions, reliability or fuel security, and the impact of potential rules from the EPA requiring reduction of carbon and other emissions and the efforts of states to implement those final rules. We remain committed to continued operations for our nuclear plants receiving state-supported payments under the Illinois CMC (Byron, Dresden, and Braidwood), Illinois ZES (Clinton and Quad Cities), New Jersey ZEC program (Salem), and the New York CES (FitzPatrick, Ginna, and Nine Mile Point), assuming the continued effectiveness of each program. With the passage of the IRA, we expect that many of our nuclear assets will operate at least through the end of the Nuclear PTC period, concluding at the end of 2032. To enable long term operations, we plan to file applications to extend the licenses of our Nuclear fleet to 80 years for the units that receive continued support under federal or state policies or a combination of both. We are currently seeking license renewals for our Clinton and Dresden units. We have updated our depreciation provisions and ARO assumed retirement dates for these assets in the third quarter of 2022 to reflect an additional 20 years of operation. We continuously evaluate factors that affect the current and expected economic value of our plants including current and projected market conditions and policy support. Nuclear Generation On August 27, 2020, we announced our intention to permanently cease our operations at Byron in September 2021 and at Dresden in November 2021. On September 15, 2021, we announced that we have reversed our previous decision to retire Byron and Dresden given the opportunity for additional revenue under the Illinois Clean Energy Law. Our Byron, Dresden, and Braidwood nuclear plants participated in the CMC procurement process and were awarded contracts that commit each plant to operate through May 31, 2027. See Note 3 — Regulatory Matters for additional information. In the third quarter of 2021, we reversed $81 million of severance benefit costs and $13 million of other one-time charges initially recorded in Operating and maintenance expense in the third and fourth quarters of 2020 associated with the early retirements. In addition, we updated the expected economic useful life for both facilities to 2044 and 2046, for Byron Units 1 and 2, respectively, and to 2029 and 2031 for Dresden Units 2 and 3, respectively, the end of the respective NRC operating license for each unit. Depreciation was therefore adjusted beginning September 15, 2021, to reflect these extended useful life estimates. See Note 10 — Asset Retirement Obligations for additional detail on changes to the nuclear decommissioning ARO balances resulting from the initial decision and subsequent reversal of the decision to early retire Byron and Dresden. The total impact for the years ended December 31, 2021 and 2020 in the Consolidated Statements of Operations and Comprehensive Income resulting from the initial decision and subsequent reversal of the decision to early retire Byron and Dresden is summarized in the table below. Income statement expense (pre-tax) 2021 2020 Depreciation and amortization Accelerated depreciation (a) $ 1,805 $ 895 Accelerated nuclear fuel amortization 148 60 Operating and maintenance One-time charges (94) 255 Other charges (b) 9 34 Contractual offset (c) (451) (364) Total $ 1,417 $ 880 _________ (a) Includes the accelerated depreciation of plant assets including any ARC. (b) For 2020, reflects the net impacts associated with the remeasurement of the ARO. See Note 10 - Asset Retirement Obligations for additional information. (c) Reflects contractual offset for ARO accretion, ARC depreciation, ARO remeasurement, and excludes any changes in earnings in the NDT funds. Decommissioning-related impacts were not offset for the Byron units starting in the second quarter of 2021 due to the inability to recognize a regulatory asset at ComEd. With our September 15, 2021 reversal of the previous decision to retire Byron, we resumed contractual offset for Byron as of that date. Based on the regulatory agreement with the ICC, decommissioning-related activities are offset in the Consolidated Statements of Operations and Comprehensive Income as long as the net cumulative decommissioning-related activity result in a regulatory liability at ComEd. The offset resulted in an equal adjustment to the noncurrent payables to ComEd. See Note 10 - Asset Retirement Obligations for additional information. Other Generation In March 2018, we notified ISO-NE of our plans to early retire, among other assets, the Mystic Generating Station's units 8 and 9 ("Mystic 8 and 9") absent regulatory reforms to properly value reliability and regional fuel security. Thereafter, ISO-NE identified Mystic 8 and 9 as being needed to ensure fuel security for the region and entered into a cost of service agreement with these two units for the period between June 1, 2022 to May 31, 2024. The agreement was approved by FERC in December 2018. On June 10, 2020, we filed a complaint with FERC against ISO-NE stating that ISO-NE failed to follow its tariff with respect to its evaluation of Mystic 8 and 9 for transmission security for the 2024 to 2025 Capacity Commitment Period and that the modifications that ISO-NE made to its unfiled planning procedures to avoid retaining Mystic 8 and 9 should have been filed with FERC for approval. On August 17, 2020, FERC issued an order denying the complaint. As a result, on August 20, 2020, we announced we will permanently cease generation operations at Mystic 8 and 9 at the expiration of the cost of service commitment in May 2024. See Note 3 — Regulatory Matters for additional discussion of Mystic’s cost of service agreement. As a result of the decision to early retire Mystic 8 and 9, we recognized $22 million of one-time charges for the year ended December 31, 2020, related to materials and supplies inventory reserve adjustments, among other items. In addition, there are annual financial impacts stemming from shortening the expected economic useful life of Mystic 8 and 9 primarily related to accelerated depreciation of plant assets. We recorded an immaterial amount of incremental Depreciation and amortization expense for the year ended December 31, 2022. We recorded incremental Depreciation and amortization expense of $41 million and $26 million for the years ended December 31, 2021 and 2020, respectively. See Note 12 — Asset Impairments for impairment assessment considerations of the New England Asset Group.

Property, Plant, and Equipment

Property, Plant, and Equipment	12 Months Ended
Property, Plant, and Equipment	Dec. 31, 2022
Property, Plant and Equipment [Abstract]
Property, Plant, and Equipment	Property, Plant, and Equipment The following table presents a summary of property, plant, and equipment by asset category as of December 31, 2022 and 2021: Asset Category December 31, 2022 December 31, 2021 Electric $ 30,804 $ 29,910 Nuclear fuel (a) 5,106 5,166 Construction work in progress 630 399 Other property, plant, and equipment 8 10 Total property, plant, and equipment 36,548 35,485 Less: accumulated depreciation (b) 16,726 15,873 Property, plant, and equipment, net $ 19,822 $ 19,612 __________ (a) Includes nuclear fuel that is in the fabrication and installation phase of $937 million and $859 million as of December 31, 2022 and 2021, respectively. (b) Includes accumulated amortization of nuclear fuel in the reactor core of $2,657 million and $2,765 million as of December 31, 2022 and 2021, respectively. The following table presents the average service life for each asset category in number of years: Asset Category Average Service Life (years) Electric 1-52 Nuclear fuel 1-8 Other property, plant, and equipment 1-10 Depreciation provisions are based on the estimated useful lives of the stations, which generally correspond with the term of the operating licenses, except for Peach Bottom, Conowingo, Clinton, and Dresden. Peach Bottom Units 2 and 3 depreciation provisions are based on an estimated useful life through 2053 and 2054, respectively. Conowingo depreciation provisions are based on an estimated useful life through 2071. These depreciation provisions are in anticipation of the license expiration dates being restored. We are currently seeking license renewals for our Clinton and Dresden units. Clinton depreciation provisions are based on an estimated useful life through 2047. Dresden Units 2 and 3 depreciation provisions are based on an estimated useful life through 2049 and 2051, respectively, in anticipation of the license renewals. Beginning August 2020, Byron, Dresden, and Mystic depreciation provisions were based on their announced shutdown dates of September 2021, November 2021, and May 2024, respectively. On September 15, 2021, we updated the expected useful lives for Byron and Dresden to reflect the end of the available NRC operating license for each unit. See Note 3 — Regulatory Matters for additional information regarding license renewals for Peach Bottom, Conowingo, Clinton, and Dresden. See Note 7 — Early Plant Retirements for additional information on the impacts related to Byron, Dresden and Mystic. Annual depreciation rates for electric generation were 3.46%, 8.67%, and 6.11% for the years ended December 31, 2022, 2021, and 2020, respectively. Nuclear fuel amortization is charged to fuel expense using the unit-of-production method and not included in the annual depreciation rates. Capitalized Interest Capitalized interest was $25 million, $15 million, and $22 million for the years ended December 31, 2022, 2021, and 2020, respectively.

Jointly Owned Electric Utility

Jointly Owned Electric Utility Plant	12 Months Ended
Jointly Owned Electric Utility Plant	Dec. 31, 2022
Public Utilities, Property, Plant and Equipment [Abstract]
Jointly Owned Electric Utility Plant	Jointly Owned Electric Utility Plant Our material undivided ownership interests in jointly owned nuclear plants as of December 31, 2022 and 2021 were as follows: Nuclear Generation Quad Cities Peach Salem Nine Mile Point Unit 2 Operator Constellation Constellation PSEG Nuclear Constellation Ownership interest 75.00 % 50.00 % 42.59 % 82.00 % Our share as of December 31, 2022 Plant in service $ 1,243 $ 1,534 $ 772 $ 1,063 Accumulated depreciation 761 659 328 256 Construction work in progress 7 12 23 26 Our share as of December 31, 2021 Plant in service $ 1,211 $ 1,515 $ 756 $ 1,002 Accumulated depreciation 715 628 299 222 Construction work in progress 11 12 20 41 Our undivided ownership interests are financed with our funds and all operations are proportionately consolidated consistent with our ownership interest. Our share of direct expenses of the jointly owned plants are included in Purchased power and fuel and Operating and maintenance expenses in the Consolidated Statements of Operations and Comprehensive Income.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
Asset Retirement Obligations	Dec. 31, 2022
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Asset Retirement Obligations Nuclear Decommissioning Asset Retirement Obligations We have a legal obligation to decommission our nuclear power plants following the permanent cessation of operations. To estimate our nuclear decommissioning obligations we use a probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models, and discount rates. We update our AROs annually, unless circumstances warrant more frequent updates, based on our review of updated cost studies and our annual evaluation of cost escalation factors and probabilities assigned to various scenarios. We began decommissioning the TMI nuclear plant upon permanently ceasing operations in 2019. See below section for decommissioning of Zion Station. The financial statement impact for changes in the ARO, on an individual unit basis, due to the changes in and timing of estimated cash flows generally result in a corresponding change in the unit’s ARC in Property, plant, and equipment in the Consolidated Balance Sheets. If the ARO decreases for a Non-Regulatory Agreement unit without any remaining ARC, the corresponding change is recorded as a decrease in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. The following table provides a rollforward of the nuclear decommissioning AROs reflected in the Consolidated Balance Sheets from December 31, 2020 to December 31, 2022: Balance as of December 31, 2020 $ 11,922 Net increase due to changes in, and timing of, estimated future cash flows 324 Accretion expense 503 Costs incurred related to decommissioning plants (73) Balance as of December 31, 2021 (a) 12,676 Net decrease due to changes in, and timing of, estimated future cash flows (648) Accretion expense 532 Costs incurred related to decommissioning plants (60) Balance as of December 31, 2022 (a) $ 12,500 __________ (a) Includes $40 million and $72 million as the current portion of the ARO as of December 31, 2022 and 2021, respectively, which is included in Other current liabilities in the Consolidated Balance Sheets. The net $648 million decrease in the ARO during 2022 for changes in the amounts and timing of estimated decommissioning cash flows was driven by multiple adjustments, including the following: • A net decrease of approximately $790 million due to an increase in discount rates partly offset by an increase in cost escalation rates, primarily labor and energy. • A decrease of approximately $235 million due to changes in assumed retirement dates as a result of the passage of the IRA and useful life extension for Clinton and Dresden plants. See Note 3 - Regulatory Matters and Note 7 - Early Plant Retirements for additional information. • A increase of approximately $320 million due to revisions to the projected decommissioning schedule for our New York nuclear plants in connection with our separation from Exelon as discussed further below. • A net increase of approximately $75 million due to higher estimated decommissioning costs resulting from the completion of updated cost studies for our New York nuclear plants, Quad Cities, Calvert Cliffs, and Three Mile Island. The 2022 ARO updates resulted in a decrease of $226 million in Operating and maintenance expense for the year ended December 31, 2022 in the Consolidated Statement of Operations and Comprehensive Income. The net $324 million increase in the ARO during 2021 for changes in the amounts and timing of estimated decommissioning cash flows was driven by multiple adjustments throughout the year, including the following: • An increase of approximately $550 million for updated cost escalation rates, primarily for labor and energy, and a decrease in discount rates. • An increase of approximately $90 million due to revisions to assumed retirement dates for several nuclear plants. • A net decrease of approximately $170 million was driven by updates to Byron and Dresden reflecting changes in assumed retirement dates and assumed methods of decommissioning as a result of the reversal of the decision to early retire the plants. See Note 7 — Early Plant Retirements for additional information. • A net decrease of approximately $150 million due to lower estimated decommissioning costs resulting from the completion of updated cost studies for seven nuclear plants. The 2021 ARO updates resulted in an increase of $51 million in Operating and maintenance expense for the year ended December 31, 2021 in the Consolidated Statement of Operations and Comprehensive Income. NDT Funds NDT funds have been established for each of our nuclear units to satisfy our nuclear decommissioning obligations, as required by the NRC, and withdrawals from these funds for reasons other than to pay for decommissioning are restricted pursuant to NRC requirements until all decommissioning activities have been completed. Generally, NDT funds established for a particular unit may not be used to fund the decommissioning obligations of any other unit. The NDT funds associated with our nuclear units have been funded with amounts collected from the previous owners and their respective utility customers. PECO is authorized to collect funds, in revenues, through regulated rates for decommissioning the former PECO nuclear plants, and these collections are scheduled through the operating lives of these former PECO plants. The amounts collected from PECO customers are remitted to us and deposited into the NDT funds for the unit for which funds are collected. Every five years, PECO files a rate adjustment with the PAPUC that reflects PECO’s calculations of the estimated amount needed to decommission each of the former PECO units based on updated fund balances and estimated decommissioning costs. The rate adjustment is used to determine the amount collectible from PECO customers. On March 31, 2022, PECO filed its Nuclear Decommissioning Cost Adjustment with the PAPUC proposing an annual recovery from customers of approximately $4 million. On August 19, 2022, the PAPUC approved the filing, and the new rates became effective January 1, 2023. Any shortfall of funds necessary for decommissioning, determined for each generating station unit, are generally required to be funded by us, with the exception of a shortfall for the current decommissioning activities at Zion Station, where certain decommissioning activities have been transferred to a third-party (see Zion Station Decommissioning below) and the former PECO nuclear plants where, through PECO, we have recourse to collect additional amounts from PECO customers related to a shortfall of NDT funds for those units, subject to certain limitations and thresholds, as prescribed by an order from the PAPUC that limits collection of amounts associated with the first $50 million of any shortfall of trust funds compared to decommissioning costs, as well as 5% of any additional shortfalls, on an aggregate basis for all former PECO units. The initial $50 million and up to 5% of any additional shortfalls would be borne by us. No recourse exists to collect additional amounts from utility customers for any of our other nuclear units. With respect to the former ComEd and former PECO units, any funds remaining in the NDTs after all decommissioning has been completed are required to be refunded to ComEd’s or PECO’s customers, subject to certain limitations that allow sharing of excess funds with us related to the former PECO units. With respect to our other nuclear units, we retain any funds remaining after decommissioning. However, in connection with CENG's acquisition of the Nine Mile Point and Ginna plants and settlements with certain regulatory agencies, certain conditions pertaining to NDT funds apply that, if met, could possibly result in obligations to make payments to certain third parties (clawbacks). For Nine Mile Point and Ginna, the clawback provisions are triggered only in the event that the required decommissioning activities are discontinued or not started or completed in a timely manner. In the event that the clawback provisions are triggered for Nine Mile Point, then, depending upon the triggering event, an amount equal to 50% of the total amount withdrawn from the funds for non-decommissioning activities as defined in the agreement or 50% of any excess funds in the trust funds above the amounts required for decommissioning (including SNF management and site restoration) is to be paid to the Nine Mile Point sellers. In the event that the clawback provisions are triggered for Ginna, then an amount equal to any estimated cost savings realized by not completing any of the required decommissioning activities is to be paid to the Ginna sellers. We expect to comply with applicable regulations and timely commence and complete all required decommissioning activities. We had NDT funds totaling $14,127 million and $16,064 million as of December 31, 2022 and 2021, respectively. The NDT funds also include $13 million and $126 million for the current portion of the NDT funds as of December 31, 2022 and 2021, respectively, which are included in Other current assets in the Consolidated Balance Sheets. See Note 23 — Supplemental Financial Information for additional information on activities of the NDT funds. Accounting Implications of the Regulatory Agreements with ComEd and PECO See Note 1 — Basis of Presentation for additional information on the accounting policy for Regulatory Agreement Units with ComEd and PECO. For the former PECO units, given the symmetric settlement provisions that allow for continued recovery of decommissioning costs from PECO customers in the event of a shortfall and the obligation for us to ultimately return excess funds to PECO customers (on an aggregate basis for all seven units), decommissioning-related activities are generally offset in the Consolidated Statements of Operations and Comprehensive Income regardless of whether the NDT funds are expected to exceed or fall short of the total estimated decommissioning obligation. The offset of decommissioning-related activities in the Consolidated Statements of Operations and Comprehensive Income results in an equal adjustment to noncurrent payables or noncurrent receivables. Any changes to the existing PECO regulatory agreements could impact our ability to offset decommissioning-related activities in the Consolidated Statements of Operations and Comprehensive Income, and the potential impact to our consolidated financial statements could be material. For the former ComEd units, given no further recovery from ComEd customers is permitted and we retain an obligation to ultimately return any unused NDTs to ComEd customers (on a unit-by-unit basis), to the extent the related NDT investment balances are expected to exceed the total estimated decommissioning obligation for each unit, decommissioning-related activities are offset in the Consolidated Statements of Operations and Comprehensive Income which results in us recognizing a noncurrent payable. However, given the asymmetric settlement provision that does not allow for continued recovery from ComEd customers in the event of a shortfall, recognition of a regulatory asset at ComEd is not permissible and accounting for decommissioning-related activities for that unit would not be offset, and the impact to the Consolidated Statements of Operations and Comprehensive Income could be material during such periods. During the second and third quarter of 2021, a pre-tax charge of $53 million and $140 million, respectively, was recorded in the Consolidated Statement of Operations and Comprehensive Income for decommissioning-related activities that were not offset for the Byron units due to contractual offset being temporarily suspended. With our September 15, 2021 reversal of the previous decision to retire Byron and the corresponding adjustment to the ARO for Byron discussed previously, we resumed contractual offset for Byron as of that date. The following table presents our noncurrent payables to ComEd and PECO which are recorded as Payables related to Regulatory Agreement Units as of December 31, 2022 and noncurrent Payables to affiliates as of December 31, 2021: December 31, 2022 December 31, 2021 ComEd $ 2,660 $ 2,760 PECO 237 597 As of December 31, 2022, decommissioning-related activities for all of the former ComEd units, except for Zion (see Zion Station Decommissioning below), are currently offset in the Consolidated Statements of Operations and Comprehensive Income. The decommissioning-related activities for the Non-Regulatory Agreement Units are reflected in the Consolidated Statements of Operations and Comprehensive Income within Operating and maintenance expense, Depreciation and amortization expense, and in Other, net. Zion Station Decommissioning In 2010, we completed an ASA under which ZionSolutions assumed responsibility for decommissioning Zion Station and we transferred to ZionSolutions substantially all the Zion Station’s assets, including the related NDT funds. Following ZionSolutions' completion of its contractual obligations and transfer of the NRC license back to us, we will store the SNF at Zion Station until it is transferred to the DOE for ultimate disposal, and complete all remaining decommissioning activities associated with the SNF dry storage facility. We had retained our obligation for the SNF upon transfer of the NRC license to us as well as certain NDT assets to fund the obligation to maintain the SNF at Zion Station until transfer to the DOE and to complete all remaining decommissioning activities for the SNF storage facility. Any shortage of funds necessary to maintain the SNF and decommission the SNF storage facility is ultimately required to be funded by us. As of December 31, 2022, the ARO associated with Zion's SNF storage facility is $138 million and the NDT funds available to fund this obligation are $58 million. NRC Minimum Funding Requirements NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts to decommission the facility at the end of its life. The estimated decommissioning obligations are calculated using an NRC methodology that is different from the ARO recorded in the Consolidated Balance Sheets primarily due to differences in the type of costs included in the estimates, the basis for estimating such costs, and assumptions regarding the decommissioning alternatives to be used, potential license renewals, decommissioning cost escalation, and the growth rate in the NDT funds. Under NRC regulations, if the minimum funding requirements for radiological decommissioning calculated under the NRC methodology are greater than the future value of the NDT funds, also calculated under the NRC methodology, then the NRC requires resolution of the shortfalls which could include further funding or other financial guarantees. Key assumptions used in the minimum funding calculation for radiological decommissioning costs using the NRC methodology at December 31, 2022 include: (1) consideration of costs only for the removal of radiological contamination at each unit; (2) the option on a unit-by-unit basis to use generic, non-site specific cost estimates; (3) consideration of only one decommissioning scenario for each unit; (4) the plants cease operation at the end of their current license lives (with no assumed license renewals for those units that have not already received renewals); (5) the assumption of current nominal dollar cost estimates that are neither escalated through the anticipated period of decommissioning, nor discounted using the CARFR; and (6) assumed annual after-tax returns on the NDT funds of 2% (3% for the former PECO units, as specified by the PAPUC). In contrast, the key criteria and assumptions used by us to determine the ARO and to forecast the target growth in the NDT funds as of December 31, 2022 include: (1) the use of site specific cost estimates that are updated at least once every five years; (2) the inclusion in the ARO estimate of all legally unavoidable costs required to decommission the unit (e.g., radiological decommissioning and full site restoration for certain units, on-site SNF maintenance and storage subsequent to ceasing operations and until DOE acceptance, and disposal of certain LLRW); (3) as applicable, the consideration of multiple scenarios where decommissioning and site restoration activities, as applicable, are completed under possible scenarios ranging from 10 to 70 years after the cessation of plant operations or the end of the current licensed operating life; (4) the consideration of multiple end of life scenarios; (5) the measurement of the obligation at the present value of the future estimated costs and an annual average accretion of the ARO of approximately 4% through a period of approximately 30 years after the end of the extended lives of the units; and (6) an estimated targeted annual pre-tax return on the NDT funds of 6.2% to 6.9% (as compared to a historical 5-year annual average pre-tax return of approximately 5.3%). We are required to provide to the NRC a biennial report by unit (annually for units that have been retired or are within five years of license expiration), based on values as of December 31, addressing our ability to meet the NRC minimum funding levels. Depending on the value of the trust funds, we may be required to take steps, such as providing financial guarantees through surety bonds, letters of credit, or parent company guarantees or making additional contributions to the trusts, which could be significant, to ensure that the trusts are adequately funded and that NRC minimum funding requirements are met. As a result, our cash flows and financial position may be significantly adversely affected. We filed our biennial decommissioning funding status report with the NRC on February 24, 2021 for all units, including our shutdown units, except for Zion Station which is included in a separate report to the NRC submitted by ZionSolutions, LLC. The status report demonstrated adequate decommissioning funding assurance as of December 31, 2020 for all units except for Byron Units 1 and 2. We filed an updated decommissioning funding status report for Byron Units 1 and 2 and Dresden Units 2 and 3 on September 28, 2021 based on their current license expiration dates consistent with our announcements regarding the continued operations of these units. This report demonstrated adequate decommissioning funding assurance as of December 31, 2020 for Byron Units 1 and 2 and Dresden Units 2 and 3. On March 23, 2022, we filed our annual decommissioning funding status report with the NRC for our shutdown units (excluding Zion station for the reason noted above). The annual status report demonstrated adequate decommissioning funding assurance, based on the value of the trust funds as of December 31, 2021 for all of our shutdown reactors except for Peach Bottom Unit 1. As a former PECO plant, financial assurance for decommissioning Peach Bottom Unit 1 is provided by the NDT fund, collections from PECO customers, and the ability to adjust those collections in accordance with the approved PAPUC tariff. See NDT Funds section above for additional information. We will file the next decommissioning funding status report with the NRC by March 31, 2023. This report will also reflect the status of decommissioning funding as of December 31, 2022 for all units. We expect the annual status report to demonstrate adequate decommissioning funding assurance, based on the value of trust funds as of December 31, 2022 for all reactors except for Peach Bottom Unit 1 and Clinton. We are currently seeking to renew Clinton’s operating license for an additional 20 years and anticipate NRC approval by 2026. Once approved, we expect that Clinton will demonstrate adequate funding assurance. In the event that Clinton remains underfunded by April 2024, additional financial assurance may be required. Financial assurance for decommissioning of Peach Bottom Unit 1 is provided by the collections from PECO customers as noted above. As the future values of trust funds change due to market conditions, the NRC minimum funding status of our units will change. In addition, if changes occur to the regulatory agreement with the PAPUC that currently allows amounts to be collected from PECO customers for decommissioning the former PECO units, the NRC minimum funding status of those plants could change at subsequent NRC filing dates. Impact of Separation from Exelon Satisfying a condition precedent, on December 16, 2021, the NYPSC authorized our separation from Exelon and accepted the terms of a Joint Proposal that became binding upon closing of the separation on February 1, 2022. As part of the Joint Proposal, among other items, we have projected completion of radiological decommissioning and site restoration activities necessary to achieve a partial site release from the NRC (release of the site for unrestricted use, except for any on-site dry cask storage) within 20 years from the end of licensed life for each of our Ginna and FitzPatrick units and from the end of licensed life for the last of the NMP operating units. While there is flexibility under the Joint Proposal, there was an increase to the AROs, as noted above, associated with our New York nuclear plants during the first quarter of 2022. The Joint Proposal also required a contribution of $15 million to the NDT for NMP Unit 2 in January 2022 and requires various financial assurance mechanisms through the duration of decommissioning and site restoration, including a minimum NDT balance for each unit, adjusted for specific stages of decommissioning, and a parent guaranty for site restoration costs updated annually as site restoration progresses, which must be replaced with a third-party surety bond or equivalent financial instrument in the event we were to fall below investment grade. See Note 1 — Basis of Presentation for additional information. Non-Nuclear Asset Retirement Obligations We have AROs for plant closure costs associated with our natural gas, oil, and renewable generating facilities, including asbestos abatement, removal of certain storage tanks, restoring leased land to the condition it was in prior to construction of renewable generating stations, and other decommissioning-related activities. See Note 1 — Basis of Presentation for additional information on the accounting policy for AROs. The following table provides a rollforward of the non-nuclear AROs reflected in the Consolidated Balance Sheets from December 31, 2020 to December 31, 2022: Balance as of December 31, 2020 $ 212 Net increase due to changes in, and timing of, estimated future cash flows 5 Accretion expense 11 Asset divestitures (19) Payments (3) AROs previously held for sale 10 Balance as of December 31, 2021 216 Net increase due to changes in, and timing of, estimated future cash flows 18 Accretion expense 11 Asset divestitures (1) Payments (5) Balance as of December 31, 2022 $ 239 .

Leases

Leases	12 Months Ended
Leases	Dec. 31, 2022
Leases [Abstract]
Leases	Leases Lessee We have operating leases for which we are the lessee. The significant types of leases are contracted generation, real estate, and vehicles and equipment. The following table outlines other terms and conditions of the lease agreements as of December 31, 2022. We did not have material finance leases in 2022, 2021, or in 2020. In Years Remaining lease terms 1-33 Options to extend the term 2-30 Options to terminate within 1-2 The components of operating lease costs were as follows: For the Years Ended December 31, 2022 2021 2020 Operating lease costs $ 109 $ 161 $ 194 Variable lease costs 169 168 234 __________ (a) Excludes $49 million, $44 million, $44 million of sublease income recorded for each of the years ended December 31, 2022, 2021, and 2020 respectively. The following table provides additional information regarding the presentation of operating lease ROU assets and lease liabilities in the Consolidated Balance Sheets: As of December 31, 2022 2021 Operating lease ROU assets (a) Other deferred debits and other assets $ 545 $ 604 Operating lease liabilities (a) Other current liabilities 67 72 Other deferred credits and other liabilities 643 705 Total operating lease liabilities $ 710 $ 777 __________ (a) The operating ROU assets and lease liabilities include $248 million and $377 million, respectively, related to contracted generation as of December 31, 2022, and $293 million and $429 million, respectively, as of December 31, 2021. The weighted average remaining lease terms, in years, and the weighted average discount rates for operating leases as of December 31, 2022 were as follows: As of December 31, 2022 2021 2020 Weighted average remaining lease term 9.3 10.1 10.5 Weighted average discount rate 5.0 % 5.0 % 4.9 % The following table reconciles the undiscounted cash flows for our operating leases to the operating lease liabilities recorded on our consolidated balance sheet as of December 31, 2022: Year Amount 2023 $ 101 2024 99 2025 102 2026 102 2027 100 Thereafter 421 Total lease payments 925 Less: Imputed interest 215 Operating lease liabilities $ 710 Supplemental cash flow information related to operating leases was as follows: For the Years Ended December 31, 2022 2021 2020 Cash paid for amounts included in the measurement of operating lease liabilities $ 114 $ 162 $ 204 ROU assets obtained in exchange for operating lease obligations 14 2 3 Lessor We have operating leases for which we are the lessor. The significant types of leases are contracted generation and real estate. The following table outlines other terms and conditions of the lease agreements as of December 31, 2022. In Years Remaining lease terms 1-18 Options to extend the term 1-20 The components of lease income were as follows: For the Years Ended December 31, 2022 2021 2020 Operating lease income $ 51 $ 47 $ 47 Variable lease income 258 261 282 The following table presents maturity analysis of the lease payments we expect to receive as of December 31, 2022: Year Amount 2023 $ 48 2024 48 2025 48 2026 49 2027 49 Thereafter 133 Total $ 375
Leases	Leases Lessee We have operating leases for which we are the lessee. The significant types of leases are contracted generation, real estate, and vehicles and equipment. The following table outlines other terms and conditions of the lease agreements as of December 31, 2022. We did not have material finance leases in 2022, 2021, or in 2020. In Years Remaining lease terms 1-33 Options to extend the term 2-30 Options to terminate within 1-2 The components of operating lease costs were as follows: For the Years Ended December 31, 2022 2021 2020 Operating lease costs $ 109 $ 161 $ 194 Variable lease costs 169 168 234 __________ (a) Excludes $49 million, $44 million, $44 million of sublease income recorded for each of the years ended December 31, 2022, 2021, and 2020 respectively. The following table provides additional information regarding the presentation of operating lease ROU assets and lease liabilities in the Consolidated Balance Sheets: As of December 31, 2022 2021 Operating lease ROU assets (a) Other deferred debits and other assets $ 545 $ 604 Operating lease liabilities (a) Other current liabilities 67 72 Other deferred credits and other liabilities 643 705 Total operating lease liabilities $ 710 $ 777 __________ (a) The operating ROU assets and lease liabilities include $248 million and $377 million, respectively, related to contracted generation as of December 31, 2022, and $293 million and $429 million, respectively, as of December 31, 2021. The weighted average remaining lease terms, in years, and the weighted average discount rates for operating leases as of December 31, 2022 were as follows: As of December 31, 2022 2021 2020 Weighted average remaining lease term 9.3 10.1 10.5 Weighted average discount rate 5.0 % 5.0 % 4.9 % The following table reconciles the undiscounted cash flows for our operating leases to the operating lease liabilities recorded on our consolidated balance sheet as of December 31, 2022: Year Amount 2023 $ 101 2024 99 2025 102 2026 102 2027 100 Thereafter 421 Total lease payments 925 Less: Imputed interest 215 Operating lease liabilities $ 710 Supplemental cash flow information related to operating leases was as follows: For the Years Ended December 31, 2022 2021 2020 Cash paid for amounts included in the measurement of operating lease liabilities $ 114 $ 162 $ 204 ROU assets obtained in exchange for operating lease obligations 14 2 3 Lessor We have operating leases for which we are the lessor. The significant types of leases are contracted generation and real estate. The following table outlines other terms and conditions of the lease agreements as of December 31, 2022. In Years Remaining lease terms 1-18 Options to extend the term 1-20 The components of lease income were as follows: For the Years Ended December 31, 2022 2021 2020 Operating lease income $ 51 $ 47 $ 47 Variable lease income 258 261 282 The following table presents maturity analysis of the lease payments we expect to receive as of December 31, 2022: Year Amount 2023 $ 48 2024 48 2025 48 2026 49 2027 49 Thereafter 133 Total $ 375

Asset Impairments

Asset Impairments	12 Months Ended
Asset Impairments	Dec. 31, 2022
Impairment or Disposal of Tangible Assets Disclosure [Abstract]
Asset Impairments	Asset Impairments We evaluate the carrying value of long-lived assets or asset groups for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the asset, or plans to dispose of a long-lived asset significantly before the end of its useful life. We determine if long-lived assets or asset groups are potentially impaired by comparing the undiscounted expected future cash flows to the carrying value when indicators of impairment exist. When the undiscounted cash flow analysis indicates a long-lived asset or asset group may not be recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. The fair value analysis is primarily based on the income approach using significant unobservable inputs (Level 3) including revenue and generation forecasts, projected capital and maintenance expenditures and discount rates. A variation in the assumptions used could lead to a different conclusion regarding the recoverability of an asset or asset group and, thus, could potentially result in material future impairments of our long-lived assets. Generally, pre-tax impairment losses on long-lived assets or asset groups are recorded in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. New England Asset Group In the third quarter of 2020, in conjunction with the retirement announcement of Mystic Units 8 and 9, we completed a comprehensive review of the estimated undiscounted future cash flows of the New England asset group and concluded that the estimated undiscounted future cash flows and fair value of the New England asset group were less than their carrying values. As a result, a pre-tax impairment charge of $500 million was recorded in the third quarter of 2020 in Operating and maintenance expense in the Consolidated Statement of Operations and Comprehensive Income. See Note 7 - Early Plant Retirements for additional information. In the second quarter of 2021, an overall decline in the asset group's portfolio value suggested that the carrying value of the New England asset group may be impaired. We completed a comprehensive review of the estimated undiscounted future cash flows of the New England asset group and concluded that the carrying value was not recoverable and that its fair value was less than its carrying value. As a result, a pre-tax impairment charge of $350 million was recorded in the second quarter of 2021 in Operating and maintenance expense in the Consolidated Statement of Operations and Comprehensive Income. Contracted Wind Project In the third quarter of 2021, significant long-term operational issues anticipated for a specific wind turbine technology suggested that the carrying value of a contracted wind asset, located in Maryland and part of the CRP joint venture, may be impaired. We completed a comprehensive review of the estimated undiscounted future cash flows and concluded that the carrying value of this contracted wind project was not recoverable and that its fair value was less than its carrying value. As a result, in the third quarter of 2021, a pre-tax impairment charge of $45 million was recorded in Operating and maintenance expense, $21 million of which was offset in Net income attributable to noncontrolling interests in the Consolidated Statement of Operations and Comprehensive Income.

Intangible Assets

Intangible Assets	12 Months Ended
Intangible Assets	Dec. 31, 2022
Goodwill and Intangible Assets Disclosure [Abstract]
Intangible Assets	Intangible Assets Our intangible assets and liabilities, included in Other current assets, Other deferred debits and other assets, Other current liabilities, Other deferred credits and other liabilities in the Consolidated Balance Sheets, consisted of the following as of December 31, 2022 and 2021. The intangible assets and liabilities shown below are generally amortized on a straight line basis, except for unamortized energy contracts which are amortized in relation to the expected realization of the underlying cash flows: December 31, 2022 December 31, 2021 Gross Accumulated Amortization Net Gross Accumulated Amortization Net Unamortized Energy Contracts $ 1,960 $ (1,708) $ 252 $ 1,963 $ (1,673) $ 290 Customer Relationships 356 (265) 91 330 (243) 87 Trade Name 222 (222) — 222 (218) 4 Total $ 2,538 $ (2,195) $ 343 $ 2,515 $ (2,134) $ 381 The following table summarizes the amortization expense related to intangible assets and liabilities for each of the years ended December 31, 2022, 2021, and 2020: For the Years Ended December 31, Amortization Expense (a) 2022 $ 61 2021 80 2020 81 __________ (a) See Note 23 — Supplemental Financial Information for additional information related to the amortization of unamortized energy contracts. The following table summarizes the estimated future amortization expense related to intangible assets and liabilities as of December 31, 2022: For the Years Ending December 31, Estimated Future Amortization Expense 2023 $ 59 2024 56 2025 47 2026 40 2027 27 Renewable Energy Credits RECs are included in Renewable energy credits in the Consolidated Balance Sheets. Purchased RECs are recorded at cost on the date they are purchased. The cost of RECs purchased on a stand-alone basis is based on the transaction price, while the cost of RECs acquired through PPAs represents the difference between the total contract price and the market price of energy at contract inception. Generally, revenue for RECs that are sold to a counterparty under a contract that specifically identifies a power plant is recognized at a point in time when the power is produced. This includes both bundled and unbundled REC sales. Otherwise, the revenue is recognized upon physical transfer of the REC to the customer. The following table presents current RECs as of December 31, 2022 and 2021: December 31, 2022 December 31, 2021 Current REC's $ 617 $ 520

Income Taxes

Income Taxes	12 Months Ended
Income Taxes	Dec. 31, 2022
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes Components of Income Tax Expense or Benefit Income taxes are comprised of the following components: For the Years Ended December 31, 2022 (a) 2021 (a) 2020 (a) Federal Current $ 219 $ 394 $ 130 Deferred (655) (153) 150 ITC amortization (15) (15) (25) State Current 34 36 40 Deferred 29 (37) (46) Total $ (388) $ 225 $ 249 _________ (a) Negative amounts represent income tax benefit. Positive amounts represent income tax expense. Rate Reconciliation The effective income tax rate varies from the U.S. federal statutory rate principally due to the following: For the Years Ended December 31, 2022 (a) 2021 2020 U.S. federal statutory rate 21.0 % 21.0 % 21.0 % (Decrease) increase due to: State income taxes, net of federal income tax benefit (c) (9.2) — 0.5 Qualified NDT fund income and losses 46.3 165.1 23.5 Amortization of investment tax credit, including deferred taxes on basis differences 2.2 (9.0) (2.6) Production tax credits and other credits 7.7 (28.7) (5.4) Noncontrolling interests (0.3) (3.0) 3.2 Tax Settlements — — (10.3) Other (d) 3.9 2.6 (0.1) Effective income tax rate (b) 71.6 % 148.0 % 29.8 % _________ (a) Positive percentages represent income tax benefit. Negative percentages represent income tax expense. (b) The change in effective tax rate in 2022 is primarily due to the impacts of higher unrealized NDT losses on Income before income taxes and one-time income tax adjustments. (c) Includes $30 million related to state rate changes and certain state tax positions. (d) Primarily related to a $32 million prior period income tax adjustment recorded in 2022. Tax Differences and Carryforwards The tax effects of temporary differences and carryforwards, which give rise to significant portions of the deferred tax (liabilities) assets, as of December 31, 2022 and 2021 are presented below: December 31, 2022 December 31, 2021 Plant basis differences $ (3,005) $ (2,812) Accrual based contracts (35) (38) Derivatives and other financial instruments 43 (172) Deferred pension and postretirement obligation 287 (274) Nuclear decommissioning activities (371) (912) Deferred debt refinancing costs — 15 Tax loss carryforward, net of valuation allowances 67 53 Tax credit carryforward 179 778 Investment in partnerships (205) (252) Other, net 407 312 Deferred income tax liabilities (net) $ (2,633) $ (3,302) Unamortized ITCs (354) (369) Total deferred income tax liabilities (net) and $ (2,987) $ (3,671) The following table provides our carryforwards, of which the state related items are presented on a post-apportioned basis, and any corresponding valuation allowances as of December 31, 2022: Federal December 31, 2022 Federal general business credits carryforwards and other carryforwards $ 178 State State net operating losses and other carryforwards 939 Deferred taxes on state tax attributes (net) 78 Valuation allowance on state tax attributes 11 Year in which net operating loss or credit carryforwards will begin to expire 2035 Tabular Reconciliation of Unrecognized Tax Benefits The following table presents changes in unrecognized tax benefits: Unrecognized tax benefits Balance as of December 31, 2019 $ 441 Increases based on tax positions related to 2020 1 Increases based on tax positions prior to 2020 23 Decreases based on tax positions prior to 2020 (a) (346) Decrease from settlements with taxing authorities (a) (69) Balance as of December 31, 2020 50 Change to positions that only affect timing (1) Increases based on tax positions related to 2021 1 Increases based on tax positions prior to 2021 1 Decreases based on tax positions prior to 2021 (2) Balance as of December 31, 2021 49 Change to positions that only affect timing (5) Increases based on tax positions related to 2022 29 Increases based on tax positions prior to 2022 (b) 6 Decreases based on tax positions prior to 2022 (b) (55) Balance as of December 31, 2022 $ 24 __________ (a) Our unrecognized federal and state tax benefits decreased in the first quarter of 2020 by approximately $411 million due to the settlement of a federal refund claim with IRS Appeals. The recognition of these tax benefits resulted in an increase in net income of $73 million in the first quarter of 2020, reflecting a decrease to income tax expense of $67 million. (b) Tax positions prior to 2022 remained with Exelon and are not reflected in this table as of December 31, 2022. See discussion below under the Tax Matters Agreement for responsibility of taxes for this period. Recognition of unrecognized tax benefits The following table presents the unrecognized tax benefits that, if recognized, would decrease the effe ctive tax rate: December 31, 2022 $ 29 December 31, 2021 39 December 31, 2020 39 Reasonably possible the total amount of unrecognized tax benefits could significantly increase or decrease within 12 months after the reporting date No amounts are expected to significantly increase or decrease within 12 months after the reporting date. Total amounts of interest and penalties recognized We did not record material interest and penalty expense related to tax positions reflected in the Consolidated Balance Sheets. Interest expense and penalty expense are recorded in Interest expense, net and Other, net, respectively, in Other income and deductions in the Consolidated Statements of Operations and Comprehensive Income. Description of tax years open to assessment by major jurisdiction Major Jurisdiction Open Years (a) Federal consolidated income tax returns 2010-2021 Illinois unitary corporate income tax returns 2012-2021 New Jersey separate corporate income tax returns 2017-2018 New Jersey combined corporate income tax returns 2019-2021 New York combined corporate income tax returns 2015-2021 Pennsylvania separate corporate income tax returns 2019-2021 __________ (a) Tax years open to assessment include years when we were consolidated by Exelon. See discussion below under the Tax Matters Agreement for responsibility of taxes of these open years. Other Tax Matters CENG Put Option On August 6, 2021, we entered into a settlement agreement with EDF pursuant to which we purchased EDF’s equity interest in CENG. We recorded deferred tax liabilities of $288 million against Membership interest in the Consolidated Balance Sheet. The deferred tax liabilities represent the tax effect on the difference between the net purchase price and EDF’s noncontrolling interest as of August 6, 2021. The deferred tax liabilities will reverse during the remaining operating lives and during decommissioning of the CENG nuclear plants. See Note 2 – Mergers, Acquisitions, and Dispositions for additional information. Allocation of Tax Benefits Prior to separation, we were a party to an agreement with Exelon and other subsidiaries of Exelon that provided for the allocation of consolidated tax liabilities and benefits (Tax Sharing Agreement). The Tax Sharing Agreement provided that each party was allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. In addition, any net federal and state benefits attributable to Exelon were reallocated to the parties. That allocation was treated as a contribution from Exelon to the party receiving the benefit. The following table presents the allocation of tax benefits from Exelon to us under the Tax Sharing Agreement: December 31, 2021 64 December 31, 2020 64 Tax Matters Agreement In connection with the separation, we entered into a Tax Matters Agreement (“TMA”) with Exelon. The TMA governs the respective rights, responsibilities, and obligations between us and Exelon after the separation with respect to tax liabilities and benefits, tax attributes, tax returns, tax contests and other tax sharing regarding U.S. federal, state, local and foreign income taxes, other tax matters and related tax returns. Responsibility and Indemnification for Taxes . As a former subsidiary of Exelon, we have joint and several liability with Exelon to the IRS and certain state jurisdictions relating to the taxable periods that we were included in federal and state filings. However, the TMA specifies the portion of this tax liability for which we will bear contractual responsibility, and we and Exelon each agreed to indemnify each other against any amounts for which such indemnified party is not responsible. Specifically, we will be liable for taxes due and payable in connection with tax returns that we are required to file. We will also be liable for our share of certain taxes required to be paid by Exelon with respect to taxable years or periods (or portions thereof) ending on or prior to the separation to the extent that we would have been responsible for such taxes under the Exelon tax sharing agreement then existing. As such, our Consolidated Balance Sheets at separation reflected a payable of $103 million for tax liabilities where we maintain contractual responsibility to Exelon, with $53 million recognized in Accounts payable and $50 million in Noncurrent other liabilities. As of December 31, 2022, we had $18 million in Other accounts receivable, no payables in Accounts payable and $50 million in Noncurrent other liabilities. Tax Refunds and Attributes . The TMA provides for the allocation of certain pre-closing tax attributes between us and Exelon. Tax attributes will be allocated in accordance with the principles set forth in the existing Exelon tax sharing agreement, unless otherwise required by law. Under the TMA, we will be entitled to refunds for taxes for which we are responsible. In addition, it is expected that Exelon will have tax attributes that may be used to offset Exelon’s future tax liabilities. A significant portion of such attributes were generated by our business. Upon separation we reclassified $508 million from Deferred income taxes to reflect receivables of $11 million and $497 million in Other accounts receivable and Other deferred debits and other assets, respectively, in the Consolidated Balance Sheets for the tax attributes expected to be utilized by Exelon after separation in accordance with the terms of the TMA. As of December 31, 2022, we ha d $168 million in Other accounts receivable and $362 million in Other deferred debits and other assets for the reclassified tax attributes .

Retirement Benefits

Retirement Benefits	12 Months Ended
Retirement Benefits	Dec. 31, 2022
Retirement Benefits [Abstract]
Retirement Benefits	Retirement Benefits Defined Benefit Pension and OPEB Effective February 1, 2022, in connection with the separation, pension and OPEB obligations and the related plan assets for participants (inclusive of employees and certain former employees and their beneficiaries assigned to us from Exelon upon separation) were transferred to pension and OPEB plans established by us as the plan sponsor. Most current employees participate in the defined benefit pension and OPEB plans that we sponsor. Newly hired employees are generally not eligible for either pension or OPEB benefits; instead, these employees are eligible to receive an enhanced non-discretionary fixed employer contribution under our sponsored defined contribution savings plan. As the plan sponsor, effective February 1, 2022, our Consolidated Balance Sheets reflect underfunded pension and OPEB liabilities equal to an excess of either the PBO or APBO over the fair value of the plan assets, consistent with a single employer benefit plan. We no longer account for our interest in Exelon sponsored pension and OPEB plans under the multi-employer benefit plan guidance as we are no longer participants. That previous approach historically resulted in the recognition of a net prepaid pension asset in our Consolidated Balance Sheets representing an excess of contributions over cumulative costs. Benefit Obligations, Plan Assets, and Funded Status As of February 1, 2022, we assumed from Exelon the PBO, APBO, and plan assets for our plan participants in connection with the separation. The defined benefit pension and OPEB plans were remeasured to determine the obligations and related plan assets to be transferred to us as of that date. The pension assets allocated to us were based on the rules prescribed by ERISA for transfers of assets in connection with a pension plan separation. A portion of the Exelon OPEB plan assets, which are held in VEBA trusts, were also allocated to us separately for each funding vehicle based on the ratio of the APBO assumed by us to the total APBO attributed to each funding vehicle. The remeasurement completed at separation is reflected in the table below as a separation-related adjustment and resulted in the recognition of pension obligations of $953 million, net of pension plan assets of $8,267 million, and OPEB obligations of $876 million, net of OPEB plan assets of $904 million. Additionally, we recognized $2,006 million (after-tax) in Accumulated other comprehensive loss for actuarial losses and prior service costs that had accrued over the lives of the plans prior to separation, primarily based on our proportionate share of the total projected pension and OPEB obligations at Exelon prior to separation. We use a December 31 measurement date for our pension and OPEB obligations and the related plan assets. The actuarial gains experienced upon remeasurement as of December 31, 2022 were offset against AOCI and attributable to increases in the discount rates used to measure the benefit obligations net of actual investment performance that was less than expected. The following tables provide a rollforward of the changes in the benefit obligations and plan assets for the year ended December 31, 2022 for all plans combined: Pension Benefits OPEB Change in benefit obligation: Benefit obligation as of the beginning of the year $ — $ 847 Separation-related adjustment 9,220 933 Benefit obligation as of February 1, 2022 9,220 1,780 Service cost 115 23 Interest cost 269 52 Plan participants' contributions — 20 Actuarial gain, net (1,756) (401) Settlements (15) — Gross benefits paid (558) (114) Benefit obligation as of the end of year $ 7,275 $ 1,360 Pension Benefits OPEB Change in plan assets: Prepaid pension asset as of the beginning of year $ 1,683 $ — Separation-related adjustment 6,584 904 Fair value of net plan assets as of February 1, 2022 8,267 904 Actual return on plan assets (1,245) (99) Employer contributions 211 — Plan participants' contributions — 15 Gross benefits paid (558) (86) Settlements (15) — Fair value of net plan assets as of the end of year $ 6,660 $ 734 We present our benefit obligations net of plan assets on our Consolidated Balance Sheets within the following line items: Pension Benefits OPEB 2022 2021 2022 2021 Prepaid pension asset $ — $ 1,683 $ — $ — Other current liabilities (10) — (17) — Pension obligations (605) — — — Non-pension postretirement benefit — — (609) (847) (Unfunded) funded status (net benefit obligation less plan assets) $ (615) $ 1,683 $ (626) $ (847) The following table provides the ABO and fair value of plan assets for all pension plans with an ABO in excess of plan assets. Information for pension and OPEB plans with projected PBO and APBO, respectively, in excess of plan assets has been disclosed in the Obligations and Plan Assets table above as all pension and OPEB plans are underfunded. ABO in Excess of Plan Assets December 31, 2022 ABO $ (7,121) Fair value of net plan assets 6,660 Components of Net Periodic Benefit Costs (Credits) We report the service cost and other non-service cost (credit) components of net periodic benefit costs (credits) for all plans separately in our Consolidated Statements of Operations and Comprehensive Income. Effective February 1, 2022, the service cost component will continue to be included in Operating and maintenance expense and Property, plant, and equipment, net (where criteria for capitalization of direct labor has been met) while the non-service cost (credit) components will now be included in Other, net Historically, we were allocated our portion of pension and OPEB service and non-service costs (credits) from Exelon, which was included in Operating and maintenance expense. Our portion of the total net periodic benefit costs allocated to us from Exelon in 2022 prior to separation was not material and remains in total Operating and maintenance expense. The majority of the 2022 pension benefit cost for the plan is calculated using an expected long-term rate of return on plan assets of 7.00% and a discount rate of 3.23%. The majority of the 2022 OPEB cost is calculated using an expected long-term rate of return on plan assets of 6.39% for funded plans and a discount rate of 3.21%. The following table presents the components of our net periodic benefit costs (credits), prior to capitalization and co-owner allocations, for the years ended December 31, 2022, 2021 and 2020: Pension Benefits OPEB Total Pension Benefits and OPEB 2022 2021 (a) 2020 (a) 2022 2021 (a) 2020 (a) 2022 2021 (a) 2020 (a) Components of net periodic benefit cost (credit): Service cost $ 126 $ 145 $ 137 $ 25 $ 29 $ 34 $ 151 $ 174 $ 171 Non-service components of pension benefits & OPEB cost (credit): Interest cost 290 235 280 55 45 61 345 280 341 Expected return on assets (565) (493) (474) (55) (58) (62) (620) (551) (536) Amortization of: Prior service cost (credit) 1 1 1 (7) (9) (49) (6) (8) (48) Actuarial loss (gain) 148 199 164 (1) 10 15 147 209 179 Settlement charges 6 20 9 — — (1) 6 20 8 Non-service components of pension benefits & OPEB credit (b) (120) (38) (20) (8) (12) (36) (128) (50) (56) Net periodic benefit cost (credit) (c)(d)(e) $ 6 $ 107 $ 117 $ 17 $ 17 $ (2) $ 23 $ 124 $ 115 __________ (a) Costs recognized for the years ended December 31, 2021 and 2020 were allocated to us by Exelon under the Exelon sponsored pension and OPEB plans prior to separation. (b) Effective February 1, 2022, these non-service costs (credits) are reflected in Other, net in the Consolidated Statements of Operations and Comprehensive Income. (c) The pension benefit and OPEB service costs reflected in the Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2022 totaled $131 million. The pension benefit and OPEB non-service credits reflected in the Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2022 totaled ($116) million. (d) The pension benefit and OPEB service costs reflected in the Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2021 totaled $144 million. The pension benefit and OPEB non-service credits reflected in the Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2021 totaled ($50) million. (e) The pension benefit and OPEB service costs reflected in the Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2020 totaled $140 million. The pension benefit and OPEB non-service credits reflected in the Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2020 totaled ($43) million. Components of AOCI We recognize the overfunded or underfunded status of defined benefit pension and OPEB plans as an asset or liability on our balance sheet, with offsetting entries to AOCI. An updated measurement was performed as of December 31, 2022, the impact of which was recognized in AOCI as an actuarial gain. The following tables provide the pre-tax components of AOCI for the year ended December 31, 2022, for all plans combined: Pension Benefits OPEB Changes in plan assets and benefit obligations recognized in AOCI: Separation related adjustment $ 2,664 $ 22 Current year actuarial (gain) loss 11 (253) Amortization of actuarial (loss) gain (134) 1 Amortization of prior service (cost) credit (1) 7 Settlements (6) — Total recognized in AOCI $ 2,534 $ (223) The following table provides the components of gross accumulated other comprehensive loss that have not been recognized as components of periodic benefit cost as of December 31, 2022, for all plans combined: Pension Benefits OPEB Prior service cost (credit) $ 10 $ (30) Actuarial loss (gain) 2,524 (193) Total $ 2,534 $ (223) Average Remaining Service Period For pension benefits, we amortize the unrecognized prior service costs (credits) and certain actuarial gains and losses reflected in AOCI, as applicable, based on participants’ average remaining service periods. For OPEB, we amortize the unrecognized prior service costs (credits) reflected in AOCI over participants’ average remaining service period to benefit eligibility age, and amortize certain actuarial gains and losses reflected in AOCI over participants’ average remaining service period to expected retirement. The resulting average remaining service periods for pension and OPEB were as follows as of December 31, 2022: December 31, 2022 Pension plans 12.2 OPEB plans: Benefit Eligibility Age 7.4 Expected Retirement 8.3 Assumptions The measurement of the plan obligations and costs of providing benefits under our defined benefit pension and OPEB plans involves various factors, including the development of valuation assumptions and inputs and accounting policy elections. The measurement of benefit obligations and costs is impacted by several assumptions and inputs, as shown below, among other factors. When developing the required assumptions, we consider historical information as well as future expectations. Expected Rate of Return. In determining the EROA, we consider historical economic indicators (including inflation and GDP growth) that impact asset returns, as well as expectation regarding future long-term capital market performance, weighted by our target asset class allocations. Discount Rate. The discount rates are determined by developing a spot rate curve based on the yield to maturity of a universe of high-quality non-callable (or callable with make whole provisions) bonds with similar maturities to the related pension and OPEB obligations. The spot rates are used to discount the estimated future benefit distribution amounts under the pension and OPEB plans. The discount rate is the single level rate that produces the same result as the spot rate curve. We utilize an analytical tool developed by our actuaries to determine the discount rates. Mortality. The mortality assumption is composed of a base table that represents the current expectation of life expectancy of the population adjusted by an improvement scale that attempts to anticipate future improvements in life expectancy. At separation and upon remeasurement as of December 31, 2022, we utilized the mortality tables and projection scales released by the SOA. The following assumptions were used to determine the benefit obligations for the plans as of December 31, 2022 and at separation. Assumptions used to determine year-end benefit obligations are the assumptions used to estimate the subsequent year’s net periodic benefit costs. Pension Benefits OPEB December 31, 2022 February 1, 2022 December 31, 2022 February 1, 2022 Discount rate (a) 5.52 % 3.23 % 5.50 % 3.21 % Investment crediting rate (b) 5.15 % 3.86 % N/A N/A Rate of compensation increase 3.75 % 3.75 % 3.75 % 3.75 % Mortality table Pri-2012 table with MP-2021 improvement scale (adjusted) Pri-2012 table with MP-2021 improvement scale (adjusted) Pri-2012 table with MP-2021 improvement scale (adjusted) Pri-2012 table with MP-2021 improvement scale (adjusted) Healthcare cost trend on covered charges N/A N/A Initial and ultimate rate of 5.00% Initial and ultimate rate of 5.00% __________ (a) The discount rates above represent the blended rates used to establish the majority of Constellation's pension and OPEB costs. (b) The investment crediting rate above represents a weighted average rate. Contributions We consider various factors when making qualified pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act, and management of the pension obligation. The Pension Protection Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). The projected contributions below reflect a funding strategy to make levelized annual contributions with the objective of achieving 100% funded status over time. This level funding strategy helps minimize the volatility of future period required pension contributions. Based on this funding strategy and current market conditions, which are both subject to change, we made our annual qualified pension contribution totaling $192 million in February 2022. Prior to separation, Exelon allocated contributions related to its legacy Exelon sponsored pension and OPEB plans to its subsidiaries based on accounting cost or employee participation (both active and retired). The following tables provide our contributions to the pension and OPEB plans: Pension benefits OPEB 2021 2020 2021 2020 $ 231 $ 236 $ 28 $ 19 Our non-qualified pension plans are not funded given that they are not subject to statutory minimum contribution requirements. OPEB plans are also not subject to statutory minimum contribution requirements, though we have funded certain plans. For our funded OPEB plans, we consider several factors in determining the level of contributions to these plans, including liabilities management and levels of benefit claims paid. The benefit payments to the non-qualified pension plans in 2022 were $20 million and the contributions to the OPEB plans, including benefit payments to unfunded plans were $26 million. The following table provides our planned contributions to our qualified pension plans, non-qualified pension plans, and OPEB plans in 2023 (including our benefit payments related to unfunded plans): Qualified Pension Plans Non-Qualified Pension Plans OPEB Planned contributions $ 21 $ 10 $ 17 Estimated Future Benefit Payments Estimated future benefit payments to participants over the next ten years in all pension and OPEB plans as of December 31, 2022 are as follows: Pension Benefits OPEB 2023 $ 525 $ 105 2024 531 105 2025 544 105 2026 541 105 2027 547 106 2028 through 2032 2,792 525 Total estimated future benefits payments through 2032 $ 5,480 $ 1,051 Plan Assets On a regular basis, we evaluate our investment strategy to ensure that plan assets will be sufficient to pay plan benefits when due. We have developed and implemented a liability hedging investment strategy for our qualified pension plans that has reduced the volatility of these pension assets relative to the associated pension obligations. We are likely to continue to gradually increase the liability hedging portfolio as the funded status of the plans improve. The overall objective is to achieve attractive risk-adjusted returns that will balance with the liquidity requirements of the plans’ liabilities while striving to minimize the risk of significant losses. Trust assets for our OPEB plans are managed in a diversified investment strategy that prioritizes maximizing liquidity and returns while minimizing asset volatility. Actual asset returns have an impact on the costs reported for the pension and OPEB plans. The actual asset returns across our pension and OPEB plans for the year ended December 31, 2022 were (18.40)% and (11.20)%, respectively, compared to an expected long-term return assumption of 7.00% and 6.39%, respectively. We used an EROA of 6.50% to estimate both our 2023 pension and OPEB costs. Our pension and OPEB plan target asset allocations as of December 31, 2022 were as follows: Asset Category Pension Benefits OPEB Equity securities 21 % 43 % Fixed income securities 54 % 45 % Alternative investments (a) 25 % 12 % Total 100 % 100 % __________ (a)Alternative investments include private equity, hedge funds, real estate, and private credit. We evaluated our pension and OPEB plans’ asset portfolios for the existence of significant concentrations of credit risk as of December 31, 2022. Types of concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, and individual fund. As of December 31, 2022, our pension and OPEB plans held no credit risk concentrations surpassing 10% of plan assets. Fair Value Measurements The following table presents pension and OPEB plan assets measured and recorded at fair value in our Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2022: December 31. 2022 Level 1 Level 2 Level 3 Not subject to leveling Total Pension plan assets (a) Cash equivalents $ 216 $ — $ — $ — $ 216 Equities (b) 776 — — 368 1,144 Fixed income: U.S. Treasury and agencies 693 128 — — 821 State and municipal debt — 44 — — 44 Corporate debt — 1,736 8 — 1,744 Other (b) — 43 — 470 513 Fixed income subtotal 693 1,951 8 470 3,122 Private equity — — 180 585 765 Hedge funds — — — 429 429 Real estate — — — 547 547 Private credit — — — 480 480 Pension plan assets subtotal 1,685 1,951 188 2,879 6,703 OPEB plan assets (a) Cash equivalents 40 — — — 40 Equities 152 — — 146 298 Fixed income: U.S. Treasury and agencies 10 27 — — 37 State and municipal debt — 4 — — 4 Corporate debt — 27 — — 27 Other 57 3 — 111 171 Fixed income subtotal 67 61 — 111 239 Hedge funds — — — 59 59 Real estate — — — 62 62 Private credit — — — 36 36 OPEB plan assets subtotal 259 61 — 414 734 Total pension and OPEB plan assets (c) $ 1,944 $ 2,012 $ 188 $ 3,293 $ 7,437 __________ (a) See Note 18 — Fair Value of Financial Assets and Liabilities for a description of levels within the fair value hierarchy. (b) Includes derivative instruments of $6 million for the year ended December 31, 2022, which have total notional amounts of $1,879 million as of December 31, 2022. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not represent the amount of the company’s exposure to credit or market loss. (c) Excludes net liabilities of $43 million as of December 31, 2022, which include certain derivative assets that have notional amounts of $41 million as of December 31, 2022. These items are required to reconcile to the fair value of net plan assets and consist primarily of receivables or payables related to pending securities sales and purchases, and interest and dividends receivable. The following table presents the reconciliation of Level 3 assets and liabilities measured at fair value for pension and OPEB plans for the year ended December 31, 2022: Pension Assets Fixed Income Equities Private Equity Total Balance as of January 1, 2022 $ — $ — $ — $ — Separation related adjustment 9 — — 9 Actual return on plan assets: Relating to assets still held as of the reporting date (1) — (54) (55) Purchases and settlements: Purchases — — 18 18 Settlements (a) — — (4) (4) Transfers into Level 3 (b) — — 220 220 Balance as of December 31, 2022 $ 8 $ — $ 180 $ 188 __________ (a) Represents cash settlements only. (b) Includes certain private equity investments previously measured at fair value using NAV or its equivalent as a practical expedient at separation transferred to Level 3 primarily due to changes in market liquidity or data. Valuation Techniques Used to Determine Fair Value The techniques used to fair value the pension and OPEB assets invested in cash equivalents, equities, fixed income, derivatives, private equity, real estate, and private credit investments are the same as the valuation techniques for these types of investments in NDT funds. See Cash Equivalents and NDT Fund Investments in Note 18 — Fair Value of Financial Assets and Liabilities for further information. Pension and OPEB assets also include investments in hedge funds. Hedge fund investments include those that employ a broad range of strategies to enhance returns and provide additional diversification. The fair value of hedge funds is determined using NAV or its equivalent as a practical expedient, and therefore, hedge funds are not classified within the fair value hierarchy. We have the ability to redeem these investments at NAV or its equivalent subject to certain restrictions which may include a lock-up period or a gate. Defined Contribution Savings Plan We sponsor the Constellation Employee Savings Plan, a 401(k) defined contribution savings plan consistent with those previously sponsored by Exelon. The plan allows employees to contribute a portion of their pre-tax and/or after-tax income in accordance with specified guidelines. We match a percentage of the employee contributions up to certain limits. In addition, certain employees are eligible for a fixed non-discretionary employer contribution in lieu of a pension benefit. The matching contributions to the savings plan were $90 million, $53 million and $63 million for the years ended December 31, 2022, December 31, 2021, and 2020, respectively.

Derivative Financial Instrument

Derivative Financial Instruments	12 Months Ended
Derivative Financial Instruments	Dec. 31, 2022
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Financial Instruments	Derivative Financial Instruments We use derivative instruments to manage commodity price risk, interest rate risk, and foreign exchange risk related to ongoing business operations. Authoritative guidance requires that derivative instruments be recognized as either assets or liabilities at fair value, with changes in fair value of the derivative recognized in earnings immediately. Other accounting treatments are available through special election and designation, provided they meet specific, restrictive criteria both at the time of designation and on an ongoing basis. These alternative permissible accounting treatments include NPNS, cash flow hedges, and fair value hedges. All derivative economic hedges related to commodities, referred to as economic hedges, are recorded at fair value through earnings. For all NPNS derivative instruments, accounts receivable or accounts payable are recorded when derivatives settle and revenue or expense is recognized in earnings as the underlying physical commodity is sold or delivered. Authoritative guidance about offsetting assets and liabilities requires the fair value of derivative instruments to be shown in the Combined Notes to Consolidated Financial Statements on a gross basis, even when the derivative instruments are subject to legally enforceable master netting agreements and qualify for net presentation in the Consolidated Balance Sheets. A master netting agreement is an agreement between two counterparties that may have derivative and non-derivative contracts with each other providing for the net settlement of all referenced contracts via one payment stream, which takes place as the contracts deliver, when collateral is requested or in the event of default. In the tables below, which present fair value balances, our energy-related economic hedges and proprietary trading derivatives are shown gross. The impact of the netting of fair value balances with the same counterparty that are subject to legally enforceable master netting agreements, as well as netting of cash collateral, including margin on exchange positions, is aggregated in the collateral and netting columns. Our use of cash collateral is generally unrestricted unless we are downgraded below investment grade. Commodity Price Risk We employ established policies and procedures to manage our risks associated with market fluctuations in commodity prices by entering into physical and financial derivative contracts, including swaps, futures, forwards, options, and short-term and long-term commitments to purchase and sell energy and commodity products. We believe these instruments, which are either determined to be non-derivative or classified as economic hedges, mitigate exposure to fluctuations in commodity prices. To the extent the amount of energy we produce or procure differs from the amount of energy we have contracted to sell, we are exposed to market fluctuations in the prices of electricity, natural gas and oil, and other commodities. We use a variety of derivative and non-derivative instruments to manage the commodity price risk of our electric generation facilities, including power and gas sales, fuel and power purchases, natural gas transportation and pipeline capacity agreements, and other energy-related products marketed and purchased. To manage these risks, we may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from expected sales of power and gas and purchases of power and fuel. The objectives for executing such hedges include fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return. We are also exposed to differences between the locational settlement prices of certain economic hedges and the hedged generating units. This price difference is actively managed through other instruments which include derivative congestion products, whose changes in fair value are recognized in earnings each period, and auction revenue rights, which are accounted for on an accrual basis. Additionally, we are exposed to certain market risks through our proprietary trading activities. The proprietary trading activities are a complement to our energy marketing portfolio but represent a small portion of our overall energy marketing activities and are subject to limits established by our RMC. The following tables provide a summary of the derivative fair value balances recorded as of December 31, 2022 and 2021: December 31, 2022 Economic Proprietary Collateral (a)(b) Netting (a) Total Mark-to-market derivative assets (current assets) $ 15,296 $ 10 $ 161 $ (13,123) $ 2,344 Mark-to-market derivative assets (noncurrent assets) 5,100 — 217 (4,074) 1,243 Total mark-to-market derivative assets 20,396 10 378 (17,197) 3,587 Mark-to-market derivative liabilities (current liabilities) (15,049) (6) 374 13,123 (1,558) Mark-to-market derivative liabilities (noncurrent liabilities) (5,203) — 146 4,074 (983) Total mark-to-market derivative liabilities (20,252) (6) 520 17,197 (2,541) Total mark-to-market derivative net assets $ 144 $ 4 $ 898 $ — $ 1,046 December 31, 2021 Mark-to-market derivative assets (current assets) $ 10,915 $ 25 $ 152 $ (8,923) $ 2,169 Mark-to-market derivative assets (noncurrent assets) 3,224 2 15 (2,298) 943 Total mark-to-market derivative assets 14,139 27 167 (11,221) 3,112 Mark-to-market derivative liabilities (current liabilities) (10,143) (19) 262 8,923 (977) Mark-to-market derivative liabilities (noncurrent liabilities) (2,893) (1) 83 2,298 (513) Total mark-to-market derivative liabilities (13,036) (20) 345 11,221 (1,490) Total mark-to-market derivative net assets $ 1,103 $ 7 $ 512 $ — $ 1,622 _________ (a) We net all available amounts allowed in our Consolidated Balance Sheets in accordance with authoritative guidance for derivatives. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases we may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, letters of credit and other forms of non-cash collateral. These amounts are not material as of December 31, 2022 and 2021 and not reflected in the table above. (b) Includes $836 million and $897 million of variation margin held from the exchanges as of December 31, 2022 and 2021, respectively. Economic Hedges (Commodity Price Risk) For the years ended December 31, 2022, 2021, and 2020, we recognized the following net pre-tax commodity mark-to-market gains (losses) which are also located in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows. Gains (Losses) Income Statement Location 2022 2021 2020 Operating revenues $ (1,193) $ (635) $ 112 Purchased power and fuel 167 1,206 168 Total $ (1,026) $ 571 $ 280 In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on owned and contracted generation positions that have not been hedged. For merchant revenues not already hedged via comprehensive state programs, such as the CMC in Illinois, we typically utilize a three-year ratable sales plan to align our hedging strategy with our financial objectives. The prompt three-year merchant revenues are hedged on an approximate rolling 90%/60%/30% basis. We may also enter into transactions that are outside of this ratable hedging program. As of December 31, 2022, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York, and ERCOT reportable segments is 94%-97% and 75%-78% for 2023 and 2024, respectively. Proprietary Trading (Commodity Price Risk) We also execute commodity derivatives for proprietary trading purposes. Proprietary trading includes all contracts executed with the intent of benefiting from shifts or changes in market prices as opposed to those executed with the intent of hedging or managing risk. Gains and losses associated with proprietary trading are reported as Operating revenues in the Consolidated Statements of Operations and Comprehensive Income and are included in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows. For the years ended December 31, 2022, 2021, and 2020, net pre-tax commodity mark-to-market gains and losses were not material. Interest Rate and Foreign Exchange Risk We utilize interest rate swaps to manage our interest rate exposure and foreign currency derivatives to manage foreign exchange rate exposure associated with international commodity purchases in currencies other than U.S. dollars, both of which are treated as economic hedges. The notional amounts were $524 million and $486 million as of December 31, 2022 and 2021, respectively. The following table provides the mark-to-market derivative assets and liabilities as of December 31, 2022: December 31, 2022 Economic Netting (a) Total Mark-to-market derivative assets (current assets) $ 29 $ (5) $ 24 Mark-to-market derivative assets (noncurrent assets) 18 — 18 Total mark-to-market derivative assets 47 (5) 42 Mark-to-market derivative liabilities (current liabilities) (5) 5 — Mark-to-market derivative liabilities (noncurrent liabilities) — — — Total mark-to-market derivative liabilities (5) 5 — Total mark-to-market derivative net assets $ 42 $ — $ 42 _________ (a) We net all available amounts in our Consolidated Balance Sheets in accordance with authoritative guidance for derivatives. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements. The mark-to-market derivative assets and liabilities as of December 31, 2021 were not material. The mark-to-market gains and losses associated with management of interest rate and foreign currency exchange rate risk for the years ended December 31, 2022, 2021, and 2020 were not material. Credit Risk We would be exposed to credit-related losses in the event of non-performance by counterparties on executed derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts as of the reporting date. For commodity derivatives, we enter into enabling agreements that allow for payment netting with our counterparties, which reduces our exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. Typically, each enabling agreement is for a specific commodity and, with respect to each individual counterparty, netting is limited to t ransactions involving that specific commodity product, except where master netting agreements exist with a counterparty that allows for cross product netting. In addition to payment netting language in the enabling agreement, our credit department establishes credit limits, margining thresholds and collateral requirements for each counterparty, which are defined in the derivative contracts. Counterparty credit limits are based on an internal credit review process that considers a variety of factors, including the results of a scoring model, leverage, liquidity, profitability, credit ratings by credit rating agencies, and risk management capabilities. To the extent that a counterparty’s margining thresholds are exceeded, the counterparty is required to post collateral with us as specified in each enabling agreement. Our credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis. The following tables provide information on the credit exposure for all derivative instruments, NPNS and payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of December 31, 2022. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties. The amounts in the tables below exclude credit risk exposure from individual retail counterparties, nuclear fuel procurement contracts, and exposure through RTOs, ISOs, NYMEX, ICE, NASDAQ, NGX, and Nodal commodity exchanges. Rating as of December 31, 2022 Total Credit Collateral (a) Net Number of Net Exposure of Investment grade $ 1,304 $ 135 $ 1,169 — $ — Non-investment grade 110 88 22 — — No external ratings Internally rated — investment grade 106 — 106 — — Internally rated — non-investment grade 374 40 334 — — Total $ 1,894 $ 263 $ 1,631 — $ — Net Credit Exposure by Type of Counterparty As of December 31, 2022 Investor-owned utilities, marketers, power producers $ 1,311 Energy cooperatives and municipalities 112 Financial Institutions 9 Other 199 Total $ 1,631 __________ (a) As of December 31, 2022, credit collateral held from counterparties where we had credit exposure included $152 million of cash and $111 million of letters of credit. The credit collateral does not include non-liquid collateral. Credit-Risk-Related Contingent Features As part of the normal course of business, we routinely enter into physically or financially settled contracts for the purchase and sale of electric capacity, electricity, fuels, emissions allowances, and other energy-related products. Certain of our derivative instruments contain provisions that require us to post collateral. We also enter into commodity transactions on exchanges where the exchanges act as the counterparty to each trade. Transactions on the exchanges must adhere to comprehensive collateral and margining requirements. This collateral may be posted in the form of cash or credit support with thresholds contingent upon our credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit-risk related contingent features stipulate that if we were to be downgraded or lose our investment grade credit rating (based on our senior unsecured debt rating), we would be required to provide additional collateral. This incremental collateral requirement allows for the offsetting of derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. In this case, we believe an amount of several months of future payments (i.e., capacity payments) rather than a calculation of fair value is the best estimate for the contingent collateral obligation, which has been factored into the disclosure below. The aggregate fair value of all derivative instruments with credit-risk-related contingent features in a liability position that are not fully collateralized (excluding transactions on the exchanges that are fully collateralized) is detailed in the table below: As of December 31, Credit-Risk-Related Contingent Features 2022 2021 Gross fair value of derivative contracts containing this feature (a) $ (4,736) $ (3,872) Offsetting fair value of in-the-money contracts under master netting arrangements (b) 2,048 2,424 Net fair value of derivative contracts containing this feature (c) $ (2,688) $ (1,448) __________ (a) Amount represents the gross fair value of out-of-the-money derivative contracts containing credit-risk-related contingent features ignoring the effects of master netting agreements. (b) Amount represents the offsetting fair value of in-the-money derivative contracts under legally enforceable master netting agreements with the same counterparty, which reduces the amount of any liability for which we could potentially be required to post collateral. (c) Amount represents the net fair value of out-of-the-money derivative contracts containing credit-risk-related contingent features after considering the mitigating effects of offsetting positions under master netting arrangements and reflects the actual net liability upon which any potential contingent collateral obligations would be based. As of December 31, 2022 and 2021, we posted or held the following amounts of cash collateral and letters of credit on derivative contracts with external counterparties, after giving consideration to offsetting derivative and non-derivative positions under master netting agreements. As of December 31, 2022 2021 Cash collateral posted (a) $ 1,636 $ 713 Letters of credit posted (a) 947 755 Cash collateral held (a) 765 182 Letters of credit held (a) 115 124 Additional collateral required in the event of a credit downgrade below investment grade (at BB+/Ba1) (b)(c) 3,337 2,113 _________ (a) The cash collateral and letters of credit amounts are inclusive of NPNS contracts. (b) Certain of our contracts contain provisions that allow a counterparty to request additional collateral when there has been a subjective determination that our credit quality has deteriorated, generally termed “adequate assurance.” Due to the subjective nature of these provisions, we estimate the amount of collateral that we may ultimately be required to post in relation to the maximum exposure with the counterparty. (c) The downgrade collateral is inclusive of all contracts in a liability position regardless of accounting treatment. We entered into supply forward contracts with certain utilities with one-sided collateral postings only from us. If market prices fall below the benchmark price levels in these contracts, the utilities are not required to post collateral. However, when market prices rise above the benchmark price levels, counterparty suppliers, including us, are required to post collateral once certain unsecured credit limits are exceeded.

Debt and Credit Agreements

Debt and Credit Agreements	12 Months Ended
Debt and Credit Agreements	Dec. 31, 2022
Debt Disclosure [Abstract]
Debt and Credit Agreements	Debt and Credit Agreements Short-Term Borrowings We meet our short-term liquidity requirements primarily through the issuance of commercial paper. We may use our credit facility for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit. Commercial Paper The following table reflects our commercial paper program supported by the revolving credit agreements as of December 31, 2022 and 2021: Maximum Outstanding Commercial Weighted Average Interest Rate on 2022 (a)(b)(c) 2021 (a)(d) 2022 2021 2022 2021 $ 3,500 $ 5,300 $ 959 $ 702 4.90 % 0.66 % __________ (a) Excludes $1,200 million in bilateral credit facilities as of December 31, 2022 and 2021, and $131 million in credit facilities for project finance as of both December 31, 2022 and 2021, respectively. These credit facilities do not back our commercial paper program. (b) Excludes the liquidity facility, which has a bank commitment of $971 million as of December 31, 2022. This credit facility does not back our commercial paper program. (c) Excludes customer accounts receivable Facility that has total capacity of $1.1 billion as of December 31, 2022. See Note 6 — Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information. (d) Excludes $44 million of credit facility agreements arranged at minority and community banks as of December 31, 2021. These facilities expired on October 7, 2022 and were solely utilized to issue letters of credit. In order to maintain our commercial paper program in the amounts indicated above, we must have a credit facility in place, at least equal to the amount of our commercial paper program. We do not issue commercial paper in an aggregate amount exceeding the then available capacity under our credit facility. Credit Agreements In connection with our separation from Exelon, we entered into two new credit agreements that replaced our $5.3 billion syndicated revolving credit facility. On February 1, 2022, we entered into a new credit agreement establishing a $3.5 billion five-year revolving credit facility at a variable interest rate of SOFR plus 1.275% and on February 9, 2022 we entered into a $1 billion five-year liquidity facility with the primary purpose of supporting our letter of credit issuances. Many of our bilateral credit agreements remain in effect. See below for additional details. As of December 31, 2022, and 2021 we had the following aggregate bank commitments, credit facility borrowings and available capacity under our respective credit facilities: Available Capacity as of December 31, 2022 Facility Type Aggregate Bank Facility Draws Outstanding Actual To Support Syndicated Revolver $ 3,500 $ — $ 765 $ 2,735 $ 1,776 Bilaterals 1,200 — 867 333 — Liquidity Facility 971 — 732 139 (a) — Project Finance 131 — 111 20 — Total $ 5,802 $ — $ 2,475 $ 3,227 $ 1,776 __________ (a) The maximum amount of the bank commitment is not to exceed $971 million. The aggregate available capacity of the facility is subject to market fluctuations based on the value of U.S Treasury Securities which determines the amount of collateral held in the trust. We may post additional collateral to borrow up to the maximum bank commitment. As of December 31, 2022, without posting additional collateral, the actual availability of facility, prior to outstanding letters of credit was $871 million. Available Capacity as of December 31, 2021 Facility Type Aggregate Bank (b) Facility Draws Outstanding Actual To Support Syndicated Revolver (a) $ 5,300 $ — $ 1,230 $ 4,070 $ 3,368 Bilaterals 1,200 — 1,029 171 — Project Finance 131 — 116 15 — Total $ 6,631 $ — $ 2,375 $ 4,256 $ 3,368 __________ (a) Our syndicated revolving credit facility was replaced by the $3.5 billion 5-year revolving credit agreement entered into on February 1, 2022 in connection with the separation. (b) Excludes $44 million of credit facility agreements arranged at minority and community banks. These facilities expired on October 7, 2022 and were solely utilized to issue letters of credit. As of December 31, 2021, letters of credit issued under these facilities totaled $5 million. Bilateral Credit Agreements The following table reflects the bilateral credit agreements at December 31, 2022: Date Initiated Latest Amendment Date Maturity Date(a) Amount January 5, 2016 (b) April 2, 2021 April 5, 2023 $ 150 October 25, 2019 (b) N/A N/A 200 November 20, 2019 (b) N/A N/A 300 November 21, 2019 (b) N/A N/A 100 November 21, 2019 (b) November 15, 2022 November 21, 2024 100 May 15, 2020 (b)(d) February 9, 2022 N/A 200 August 12, 2022 (b) N/A N/A 50 August 24, 2022 (b)(c) N/A August 23, 2024 100 __________ (a) Credit facilities that do not contain a maturity date are specific to the agreements set within each contract. In some instances, credit facilities are automatically renewed based on the contingency standards set within the specific agreement. (b) Bilateral credit agreements solely support the issuance of letters of credit and do not back our commercial paper program. (c) On January 20, 2023, the bilateral credit agreement decreased to $10 million. (d) On January 31, 2023, the bilateral credit agreement increased to $250 million. Borrowings under our revolving credit agreement bear interest at a rate based upon either the Daily Simple SOFR rate or a Term SOFR rate, plus an adder based upon our credit rating. The adders for the Daily Simple SOFR based borrowings and Term SOFR borrowings are 27.5 basis points and 127.5 basis points, respectively. If we lose our investment grade rating, the maximum adders for Daily Simple SOFR rate borrowings and Term SOFR rate borrowings would be 100 basis points and 200 basis points, respectively. The credit agreements also require us to pay facility fees based upon the aggregate commitments. The fee varies depending upon our credit rating. Short-Term Loan Agreements On March 19, 2020, we entered into a term loan agreement for $200 million. The loan agreement was renewed on March 17, 2021 with an expiration of March 16, 2022. Pursuant to the loan agreement, loans made thereunder beared interest at a variable rate equal to LIBOR plus 0.875% and all indebtedness thereunder was unsecured. In connection with the separation, we repaid the term loan on January 26, 2022. The loan agreement was reflected in Short-term borrowings in the Consolidated Balance Sheets as of December 31, 2021. On March 31, 2020, we entered into a term loan agreement for $300 million. We repaid $100 million of the term loan on March 29, 2022. The remaining $200 million from the loan agreement was renewed on March 29, 2022 and will expire on March 29, 2023. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to SOFR plus 0.80% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Short-term borrowings in the Consolidated Balance Sheets. On August 6, 2021, we entered into a 364-day term loan agreement for $880 million to fund the purchase of EDF's equity interest in CENG. Pursuant to the loan agreement, loans made thereunder beared interest at a variable rate of LIBOR plus 0.875% until March 31, 2022 and a rate of LIBOR plus 1% thereafter, and all indebtedness thereunder was unsecured. The loan agreement was amended on January 24, 2022 to change the maturity date from August 5, 2022 to June 30, 2022. We repaid the term loan on April 15, 2022. The loan was reflected in Short-term borrowings in the Consolidated Balance Sheets as of December 31, 2021. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information. On January 26, 2023, we entered into a term loan agreement for $100 million. The loan agreement has an expiration of January 24, 2024. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to SOFR plus 0.8% and all indebtedness thereunder is unsecured. On February 9, 2023, we entered into a term loan agreement for $400 million. The loan agreement has an expiration of February 8, 2024. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to SOFR plus 1.05% and all indebtedness thereunder is unsecured. Long-Term Debt The following table presents the outstanding long-term debt as of December 31, 2022 and 2021: Maturity December 31, Rates 2022 2021 Long-term debt Senior unsecured notes 3.25 % - 6.25 % 2025 - 2042 $ 2,938 $ 4,219 Notes payable and other 2.10 % - 6.96 % 2023 - 2028 68 103 Nonrecourse debt: Fixed rates 2.29 % - 6.00 % 2031 - 2037 839 909 Variable rates 2.99 % - 7.24 % 2026 - 2027 805 870 Total long-term debt 4,650 6,101 Unamortized debt discount and premium, net (5) (7) Unamortized debt issuance costs (36) (42) Fair value adjustment — 62 Long-term debt due within one year (143) (1,220) Long-term debt $ 4,466 $ 4,894 Long-term debt maturities in the periods 2023 through 2027 and thereafter are as follows: 2023 $ 143 2024 110 2025 986 2026 121 2027 735 Thereafter 2,555 Total $ 4,650 Long-Term Debt from Affiliates In connection with the debt obligations assumed by Exelon as part of the 2012 merger, Exelon and our subsidiaries assumed intercompany loan agreements that mirror the terms and amounts of the third-party debt obligations of Exelon, resulting in intercompany notes payable to Exelon. As of December 31, 2021, we had $319 million recorded to intercompany notes payable to Exelon. In connection with the separation, on January 31, 2022, we paid cash to Exelon in the amount of $258 million to settle the intercompany loan. See Note 1 — Basis of Presentation for additional information. Debt Covenants As of December 31, 2022, we are in compliance with all debt covenants. Nonrecourse Debt We have also issued nonrecourse debt, for which approximately $2 billion of generating assets have been pledged as collateral as of December 31, 2022. Borrowings under these agreements are secured by the assets and equity of each respective project. The lenders do not have recourse against us in the event of a default. If a specific project financing entity does not maintain compliance with its specific nonrecourse debt covenants, there could be a requirement to accelerate repayment of the associated debt or other borrowings earlier than the stated maturity dates. In these instances, if such repayment was not satisfied, the lenders or security holders would generally have rights to foreclose against the project-specific assets and related collateral. The potential requirement to satisfy the associated debt or other borrowings earlier than otherwise anticipated could lead to impairments due to a higher likelihood of disposing of the respective project-specific assets significantly before the end of their useful lives. Antelope Valley Solar Ranch One. In December 2011, the DOE Loan Programs Office issued a guarantee for up to $646 million for a nonrecourse loan from the Federal Financing Bank to support the financing of the construction of the Antelope Valley facility. The project became fully operational in 2014. The loan will mature on January 5, 2037. Interest rates on the loan were fixed upon each advance at a spread of 37.5 basis points above U.S. Treasuries of comparable maturity. The advances were completed as of December 31, 2015 and the outstanding loan balance bears interest at an average blended interest rate of 2.82%. As of December 31, 2022 and 2021, approximately $415 million and $435 million were outstanding, respectively. In addition, we have issued letters of credit to support the equity investment in the project, with $37 million outstanding as of December 31, 2022. In December 2017, our interests in Antelope Valley were contributed to and are pledged as collateral for the CR financing structures referenced below. Continental Wind, LLC. In September 2013, Continental Wind, our indirect subsidiary, completed the issuance and sale of $613 million senior secured notes. Continental Wind owns and operates a portfolio of wind farms in Idaho, Kansas, Michigan, Oregon, New Mexico and Texas with a total net capacity of 667 MWs. The net proceeds were distributed to us for general business purposes. The notes are scheduled to mature on February 28, 2033. The notes bear interest at a fixed rate of 6.00% with interest payable semi-annually. As of December 31, 2022 and December 31, 2021, approximately $345 million and $380 million were outstanding, respectively. In addition, Continental Wind has a $122 million letter of credit facility and $4 million working capital revolver facility. Continental Wind has issued letters of credit to satisfy certain of its credit support and security obligations. As of December 31, 2022, the Continental Wind letter of credit facility had $111 million in letters of credit outstanding related to the project. In 2017, our interests in Continental Wind were contributed to CRP. Refer to Note 22 - Variable Interest Entities for additional information on CRP. Renewable Power Generation. In March 2016, RPG, our indirect subsidiary, issued $150 million aggregate principal amount of nonrecourse senior secured notes. The net proceeds were distributed to us for paydown of long term debt obligations at Sacramento PV Energy and Constellation Solar Horizons and for general business purposes. The loan is scheduled to mature on March 31, 2035. The term loan bears interest at a fixed rate of 4.11% payable semi-annually. As of December 31, 2022 and December 31, 2021, approximately $80 million and $90 million were outstanding, respectively. In 2017, our interests in RPG were contributed to CRP. Refer to Note 22 - Variable Interest Entities for additional information on CRP. Constellation Renewables. In November 2017, CR, our indirect subsidiary, entered into an $850 million nonrecourse senior secured term loan credit facility agreement with a maturity date of November 28, 2024. In addition to the financing, CR entered into interest rate swaps with an initial notional amount of $636 million at an interest rate of 2.32% to manage a portion of the interest rate exposure in connection with the financing. In December 2020, CR entered into a financing agreement for a $750 million nonrecourse senior secured term loan credit facility, scheduled to mature on December 15, 2027. The term loan bears interest at a variable rate equal to LIBOR plus 2.50%, subject to a 1% LIBOR floor with interest payable quarterly. In addition to the financing, CR entered into interest rate swaps with an initial notional amount of $516 million at an interest rate of 1.05% to manage a portion of the interest rate exposure in connection with the financing. The proceeds were used to repay the November 2017 nonrecourse senior secured term loan credit facility of $850 million, of which $709 million was outstanding as of the retirement date in December 2020, and to settle the November 2017 interest rate swap. Our interests in CRP and Antelope Valley remain contributed to and pledged as collateral for this financing. As of December 31, 2022 and 2021, $690 million and $735 million was outstanding, respectively. See Note 22 — Variable Interest Entities for additional information on CRP and Note 16 — Derivative Financial Instruments for additional information on interest rate swaps. West Medway II, LLC. On May 13, 2021, West Medway II, LLC (West Medway II), our indirect subsidiary, entered into a financing agreement for a $150 million nonrecourse senior secured term loan credit facility with a maturity date of March 31, 2026. The term loan bears interest at an average blended interest rate of LIBOR plus 3%, paid quarterly. In addition to the financing, West Medway II, entered into interest rate swaps with an initial notional amount of $113 million at an interest rate of 0.61%, paid quarterly, to manage a portion of the interest rate exposure in connection with the financing. We used the net proceeds for general corporate purposes. Our

Fair Value of Financial Assets

Fair Value of Financial Assets and Liabilities	12 Months Ended
Fair Value of Financial Assets and Liabilities	Dec. 31, 2022
Fair Value Disclosures [Abstract]
Fair Value of Financial Assets and Liabilities	Fair Value of Financial Assets and Liabilities We measure and classify fair value measurements in accordance with the hierarchy as defined by GAAP. The hierarchy prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows: • Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that we have the ability to liquidate as of the reporting date. • Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data. • Level 3 — unobservable inputs, such as internally developed pricing models or third-party valuations for the asset or liability due to little or no market activity for the asset or liability. Fair Value of Financial Liabilities Recorded at Amortized Cost The following tables present the carrying amounts and fair values of the short-term liabilities, long-term debt, and the SNF obligation as of December 31, 2022 and 2021. We have no financial liabilities classified as Level 1. The carrying amounts of the short-term liabilities as presented in the Consolidated Balance Sheets are representative of their fair value (Level 2) because of the short-term nature of these instruments. December 31, 2022 December 31, 2021 Carrying Amount Fair Value Carrying Amount Fair Value Level 2 Level 3 Total Level 2 Level 3 Total Long-Term Debt, including amounts due within one year $ 4,609 $ 3,688 $ 859 $ 4,547 $ 6,114 $ 5,749 $ 1,093 $ 6,842 SNF Obligation 1,230 1,021 — 1,021 1,210 1,060 — 1,060 We use the following methods and assumptions to estimate fair value of financial liabilities recorded at carrying cost: Type Level Valuation Long-term Debt, including amounts due within one year Taxable Debt Securities 2 The fair value is determined by a valuation model that is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. We obtain credit spreads based on trades of our existing debt securities as well as other issuers in the utility sector with similar credit ratings. The yields are then converted into discount rates of various tenors that are used for discounting the respective cash flows of the same tenor for each bond or note. Variable Rate Financing Debt 2 Debt rates are reset on a regular basis and the carrying value approximates fair value. Government Backed Fixed Rate Project Financing Debt 3 The fair value is similar to the process for taxable debt securities. Due to the lack of market trading data on similar debt, the discount rates are derived based on the original loan interest rate spread to the applicable U.S. Treasury rate as well as a current market curve derived from government-backed securities. Non-Government Backed Fixed Rate Nonrecourse Debt 3 Fair value is based on market and quoted prices for its own and other nonrecourse debt with similar risk profiles. Given the low trading volume in the nonrecourse debt market, the price quotes used to determine fair value will reflect certain qualitative factors, such as market conditions, investor demand, new developments that might significantly impact the project cash flows or off-taker credit, and other circumstances related to the project. SNF Obligation SNF Obligation 2 The carrying amount is derived from a contract with the DOE to provide for disposal of SNF from certain of our nuclear generating stations. See Note 19 — Commitments and Contingencies for further details. When determining the fair value of the obligation, the future carrying amount of the SNF obligation is calculated by compounding the current book value of the SNF obligation at the 13-week U.S. Treasury rate. The compounded obligation amount is discounted back to present value using our discount rate, which is calculated using the same methodology as described above for the taxable debt securities, and an estimated maturity date of 2035. Recurring Fair Value Measurements The following tables present assets and liabilities measured and recorded at fair value in the Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2022 and 2021: As of December 31, 2022 As of December 31, 2021 Level 1 Level 2 Level 3 Not subject to leveling Total Level 1 Level 2 Level 3 Not subject to leveling Total Assets Cash equivalents (a) $ 41 $ — $ — $ — $ 41 $ 113 $ — $ — $ — $ 113 NDT fund investments Cash equivalents (b) 349 88 — — 437 465 116 — — 581 Equities 3,462 1,498 — 1,421 6,381 4,564 1,805 — 1,645 8,014 Fixed income Corporate debt (c) — 885 264 — 1,149 — 1,145 286 — 1,431 U.S. Treasury and agencies 1,996 46 — — 2,042 2,193 30 — — 2,223 Foreign governments — 39 — — 39 — 60 — — 60 State and municipal debt — 53 — — 53 — 26 — — 26 Other 21 21 — 1,649 1,691 29 23 — 1449 1,501 Fixed income subtotal 2,017 1,044 264 1,649 4,974 2,222 1,284 286 1,449 5,241 Private credit — — 159 643 802 — — 178 624 802 Private equity — — — 687 687 — — — 673 673 Real estate — — — 1,014 1,014 — — — 864 864 NDT fund investments subtotal (d)(e) 5,828 2,630 423 5,414 14,295 7,251 3,205 464 5,255 16,175 Rabbi trust investments Cash equivalents 1 — — — 1 3 — — — 3 Mutual funds 39 — — — 39 36 — — — 36 Life insurance contracts — 27 1 — 28 — 33 — — 33 Rabbi trust investments subtotal 40 27 1 — 68 39 33 — — 72 Investments in equities 6 — — — 6 43 — — — 43 Commodity derivative assets Economic hedges 3,505 11,353 5,585 — 20,443 3,017 7,223 3,899 — 14,139 Proprietary trading — 4 6 — 10 — 19 8 — 27 Effect of netting and allocation of (f)(g) (2,951) (10,348) (3,525) — (16,824) (2,108) (6,177) (2769) — (11,054) Commodity derivative assets subtotal 554 1,009 2,066 — 3,629 909 1,065 1,138 — 3,112 DPP consideration — 515 — — 515 — 365 — — 365 Total assets 6,469 4,181 2,490 5,414 18,554 8,355 4,668 1,602 5,255 19,880 Liabilities Commodity derivative liabilities Economic hedges (3,171) (11,498) (5,588) — (20,257) (2,201) (6,870) (3,965) — (13,036) Proprietary trading — (4) (2) — (6) — (18) (2) — (20) Effect of netting and allocation of collateral (f)(g) 3,279 10,700 3,743 — 17,722 2,189 6,642 2,735 — 11,566 Commodity derivative liabilities subtotal 108 (802) (1,847) — (2,541) (12) (246) (1,232) — (1,490) Deferred compensation obligation — (57) — — (57) — (43) — — (43) Total liabilities 108 (859) (1,847) — (2,598) (12) (289) (1,232) — (1,533) Total net assets $ 6,577 $ 3,322 $ 643 $ 5,414 $ 15,956 $ 8,343 $ 4,379 $ 370 $ 5,255 $ 18,347 __________ (a) CEG Parent has $49 million of Level 1 cash equivalents as of December 31, 2022. We exclude cash of $390 million and $417 million as of December 31, 2022 and December 31, 2021, respectively, and restricted cash of $70 million and $46 million as of December 31, 2022 and December 31, 2021, respectively. CEG Parent has excluded an additional $19 million of cash as of December 31, 2022. (b) Includes $99 million and $116 million of cash received from outstanding repurchase agreements as of December 31, 2022 and 2021, respectively, and is offset by an obligation to repay upon settlement of the agreement as discussed in (e) below. (c) Includes investments in equities sold short of ($45) million and ($55) million as of December 31, 2022 and 2021, respectively, held in an investment vehicle primarily to hedge the equity option component of convertible debt. (d) Includes net derivative assets of $1 million and net derivative liabilities of $1 million, which have total notional amounts of $494 million and $687 million as of December 31, 2022 and 2021, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the periods ended and do not represent the amount of our exposure to credit or market loss. (e) Excludes net liabilities of $168 million and $111 million as of December 31, 2022 and 2021, respectively, which include certain derivative assets that have notional amounts of $59 million and $182 million as of December 31, 2022 and 2021, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, repurchase agreement obligations, and payables related to pending securities purchases. The repurchase agreements are generally short-term in nature with durations generally of 30 days or less. (f) Net collateral posted to counterparties totaled $328 million, $352 million, and $218 million allocated to Level 1, Level 2, and Level 3 mark-to-market derivatives, respectively, as of December 31, 2022. Net collateral posted to/(received from) counterparties totaled $81 million, $465 million, and ($34) million allocated to Level 1, Level 2, and Level 3 mark-to-market derivatives, respectively, as of December 31, 2021. (g) Includes $836 million and $897 million of variation margin held from the exchanges as of December 31, 2022 and 2021, respectively. As of December 31, 2022, we have outstanding commitments to invest in private credit, private equity, and real estate investments of $235 million, $139 million, and $392 million, respectively. These commitments will be funded by our existing NDT funds. We hold investments without readily determinable fair values with carrying amounts of $46 million and $33 million as of December 31, 2022 and 2021, respectively. Changes in fair value, cumulative adjustments, and impairments were not material for the years ended December 31, 2022 and 2021. Reconciliation of Level 3 Assets and Liabilities The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2022 and 2021: For the Year Ended December 31, 2022 NDT Fund Investments Mark-to-Market Life Insurance Contracts Total Balance as of January 1, 2022 $ 464 $ (94) $ — $ 370 Total realized / unrealized losses Included in net income (2) (753) (a) (2) (757) Included in noncurrent payables to affiliates (10) — — (10) Change in collateral — 253 — 253 Impacts of separation — — 3 3 Purchases, sales, issuances and settlements Purchases 5 594 — 599 Sales — (50) — (50) Settlements (35) (102) — (137) Transfers into Level 3 2 381 (b) — 383 Transfers out of Level 3 (1) (10) (b) — (11) Balance as of December 31, 2022 $ 423 $ 219 $ 1 $ 643 The amount of total losses included in income attributed to the change in unrealized losses related to assets and liabilities as of December 31, 2022 $ (2) $ (1,265) $ (2) $ (1,269) For the Year Ended December 31, 2021 NDT Fund Investments Mark-to-Market Total Balance as of January 1, 2021 $ 497 $ 430 $ 927 Total realized / unrealized gains (losses) Included in net income 5 (812) (a) (807) Included in noncurrent payables to affiliates 19 — 19 Change in collateral — (196) (196) Purchases, sales, issuances and settlements Purchases 4 162 166 Sales — (10) (10) Settlements (61) — (61) Transfers into Level 3 — 19 (b) 19 Transfers out of Level 3 — 313 (b) 313 Balance as of December 31, 2021 $ 464 $ (94) $ 370 The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of December 31, 2021 $ 5 $ (1,222) $ (1,217) __________ (a) Includes an addition of $410 million for realized losses due to the settlement of derivative contracts for both of the years ended December 31, 2022 and 2021, respectively. (b) Transfers into and out of Level 3 generally occur when the contract tenor becomes less and more observable, respectively, primarily due to changes in market liquidity or assumptions for certain commodity contracts. The following table presents the income statement classification of the total realized and unrealized (losses) gains included in income for Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2022, 2021, and 2020: Operating Purchased Other, net 2022 2021 2020 2022 2021 2020 2022 2021 2020 Total (losses) gains included in net income $ (860) $ (1,343) $ (404) $ 5 $ 531 $ (10) $ (4) $ 5 $ 2 Total unrealized (losses) gains (1,330) (1,577) (31) 65 355 37 (2) 5 2 Cash Equivalents. Investments with original maturities of three months or less when purchased, including mutual and money market funds, are considered cash equivalents. The fair values are based on observable market prices and, therefore, are included in the recurring fair value measurements hierarchy as Level 1. NDT Fund Investments. The trust fund investments have been established to satisfy our nuclear decommissioning obligations as required by the NRC. The NDT funds hold debt and equity securities directly and indirectly through commingled funds and mutual funds, which are included in equities and fixed income. Our NDT fund investments policies outline investment guidelines for the trusts and limit the trust funds’ exposures to investments in highly illiquid markets and other alternative investments, including private credit, private equity, and real estate. Investments with maturities of three months or less when purchased, including certain short-term fixed income securities are considered cash equivalents and included in the recurring fair value measurements hierarchy as Level 1 or Level 2. Equities. These investments consist of individually held equity securities, equity mutual funds, and equity commingled funds in domestic and foreign markets. With respect to individually held equity securities, the trustees obtain prices from pricing services, whose prices are generally obtained from direct feeds from market exchanges, which we are able to independently corroborate. Equity securities held individually, including real estate investment trusts, rights, and warrants, are primarily traded on exchanges that contain only actively traded securities due to the volume trading requirements imposed by these exchanges. The equity securities that are held directly by the trust funds are valued based on quoted prices in active markets and categorized as Level 1. Certain equity securities have been categorized as Level 2 because they are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities. Certain private placement equity securities are categorized as Level 3 because they are not publicly traded and are priced using significant unobservable inputs. Equity commingled funds and mutual funds are maintained by investment companies, and fund investments are held in accordance with a stated set of fund objectives. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For equity commingled funds and mutual funds which are not publicly quoted, the fund administrators value the funds using the NAV per fund share, derived from the quoted prices in active markets on the underlying securities and are not classified within the fair value hierarchy. These investments can typically be redeemed monthly or more frequently, with 30 or less days of notice and without further restrictions. Fixed income. For fixed income securities, which consist primarily of corporate debt securities, U.S. government securities, foreign government securities, municipal bonds, asset and mortgage-backed securities, commingled funds, mutual funds, and derivative instruments, the trustees obtain multiple prices from pricing vendors whenever possible, which enables cross-provider validations in addition to checks for unusual daily movements. A primary price source is identified based on asset type, class, or issue for each security. With respect to individually held fixed income securities, the trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the portfolio managers challenge an assigned price and the trustees determine that another price source is preferable. We have obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, we selectively corroborate the fair values of securities by comparison to other market-based price sources. Investments in U.S. Treasury securities have been categorized as Level 1 because they trade in highly-liquid and transparent markets. Certain private placement fixed income securities have been categorized as Level 3 because they are priced using certain significant unobservable inputs and are typically illiquid. The remaining fixed income securities, including certain other fixed income investments, are based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences and are categorized as Level 2. Other fixed income investments primarily consist of fixed income commingled funds and mutual funds, which are maintained by investment companies and hold fund investments in accordance with a stated set of fund objectives. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For fixed income commingled funds and mutual funds which are not publicly quoted, the fund administrators value the funds using the NAV per fund share, derived from the quoted prices in active markets of the underlying securities and are not classified within the fair value hierarchy. These investments typically can be redeemed monthly or more frequently, with 30 or less days of notice and without further restrictions. Derivative instruments. These instruments, consisting primarily of futures and swaps to manage risk, are recorded at fair value. Over-the-counter derivatives are valued daily, based on quoted prices in active markets and trade in open markets, and have been categorized as Level 1. Derivative instruments other than over-the-counter derivatives are valued based on external price data of comparable securities and have been categorized as Level 2. Private credit. Private credit investments primarily consist of investments in private debt strategies. These investments are generally less liquid assets with an underlying term of 3 to 5 years and are intended to be held to maturity. The fair value of these investments is determined by the fund manager or administrator using a combination of valuation models including cost models, market models, and income models and typically cannot be redeemed until maturity of the term loan. Private credit investments held directly by us are categorized as Level 3 because they are based largely on inputs that are unobservable and utilize complex valuation models. For managed private credit funds, the fair value is determined using a combination of valuation models including cost models, market models, and income models and typically cannot be redeemed until maturity of the term loan. Managed private credit fund investments are not classified within the fair value hierarchy because their fair value is determined using NAV or its equivalent as a practical expedient. Private equity. These investments include those in limited partnerships that invest in operating companies that are not publicly traded on a stock exchange such as leveraged buyouts, growth capital, venture capital, distressed investments, and investments in natural resources. These investments typically cannot be redeemed and are generally liquidated over a period of 8 to 10 years from the initial investment date, which is based on our understanding of the investment funds. Private equity valuations are reported by the fund manager and are based on the valuation of the underlying investments, which include unobservable inputs such as cost, operating results, discounted future cash flows, and market based comparable data. These valuation inputs are unobservable. The fair value of private equity investments is determined using NAV or its equivalent as a practical expedient, and therefore, these investments are not classified within the fair value hierarchy. Real estate. These investments are funds with a direct investment in pools of real estate properties. These funds are reported by the fund manager and are generally based on independent appraisals of the underlying investments from sources with professional qualifications, typically using a combination of market based comparable data and discounted cash flows. These valuation inputs are unobservable. Certain real estate investments cannot be redeemed and are generally liquidated over a period of 8 to 10 years from the initial investment date, which is based on our understanding of the investments funds. The remaining liquid real estate investments are generally redeemable from the investment vehicle quarterly, with 30 to 90 days of notice. The fair value of real estate investments is determined using NAV or its equivalent as a practical expedient, and therefore, these investments are not classified within the fair value hierarchy. We evaluated our NDT portfolios for the existence of significant concentrations of credit risk as of December 31, 2022. Types of concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, and individual fund. As of December 31, 2022, there were no significant concentrations (generally defined as greater than 10 percent) of risk in the NDT assets. See Note 10 — Asset Retirement Obligations for additional information on the NDT fund investments. Rabbi Trust Investments. The Rabbi trusts were established to hold assets related to deferred compensation plans existing for certain active and retired members of executive management and directors. The Rabbi trusts' assets are included in investments in the Consolidated Balance Sheets and consist primarily of money market funds, mutual funds, and life insurance policies. Money market funds and mutual funds are publicly quoted and have been categorized as Level 1 given the clear observability of the prices. The life insurance policies are valued using the cash surrender value of the policies, net of loans against those policies, which is provided by a third-party. Certain life insurance policies, which consist primarily of mutual funds that are priced based on observable market data, have been categorized as Level 2 because the life insurance policies can be liquidated at the reporting date for the value of the underlying assets. Deferred Compensation Obligations. Our deferred compensation plans allow participants to defer certain cash compensation into a notional investment account. We include such plans in other current and noncurrent liabilities in the Consolidated Balance Sheets. The value of our deferred compensation obligations is based on the market value of the participants’ notional investment accounts. The underlying notional investments are comprised primarily of equities, mutual funds, commingled funds, and fixed income securities which are based on directly and indirectly observable market prices. Since the deferred compensation obligations themselves are not exchanged in an active market, they are categorized as Level 2 in the fair value hierarchy. The value of certain employment agreement obligations (which are included with the Deferred Compensation Obligation in the table above) are based on a known and certain stream of payments to be made over time and are categorized as Level 2 within the fair value hierarchy. Investments in Equities. We hold certain investments in equity securities with readily determinable fair values in addition to those held within the NDT funds. These equity securities are valued based on quoted prices in active markets and are categorized as Level 1. Deferred Purchase Price Consideration. We have DPP consideration for the sale of certain receivables of retail electricity. This amount is valued based on the sales price of the receivables net of allowance for credit losses based on accounts receivable aging historical experience coupled with specific identification through a credit monitoring process, which considers current conditions and forward-looking information such as industry trends, macroeconomic factors, changes in the regulatory environment, external credit ratings, publicly available news, payment status, payment history, and the exercise of collateral calls. Since the DPP consideration is based on the sales price of the receivables, it is categorized as Level 2 in the fair value hierarchy. See Note 6 — Accounts Receivable for additional information on the sale of certain receivables. Mark-to-Market Derivatives. Derivative contracts are traded in both exchange-based and non-exchange-based markets. Exchange-based derivatives that are valued using unadjusted quoted prices in active markets are categorized in Level 1 in the fair value hierarchy. Certain derivatives’ pricing is verified using indicative price quotations available through brokers or over-the-counter, on-line exchanges and are categorized in Level 2. These price quotations reflect the average of the bid-ask, mid-point prices and are obtained from sources that we believe provide the most liquid market for the commodity. The price quotations are reviewed and corroborated to ensure the prices are observable and representative of an orderly transaction between market participants. This includes consideration of actual transaction volumes, market delivery points, bid-ask spreads, and contract duration. The remainder of derivative contracts are valued using the Black model, an industry standard option valuation model. The Black model considers inputs such as contract terms, including maturity, and market parameters, including assumptions of the future prices of energy, interest rates, volatility, credit worthiness, and credit spread. For derivatives that trade in liquid markets, such as generic forwards, swaps, and options, model inputs are generally observable. Such instruments are categorized in Level 2. Our derivatives are predominantly at liquid trading points. For derivatives that trade in less liquid markets with limited pricing information, model inputs generally would include both observable and unobservable inputs. These valuations may include an estimated basis adjustment from an illiquid trading point to a liquid trading point for which active price quotations are available. Such instruments are categorized in Level 3. For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations whose contract tenure extends into unobservable periods. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility, and contract duration. Such instruments are categorized in Level 3 as the model inputs generally are not observable. Forward price curves for the power market utilized by the front office to manage the portfolio, are reviewed and verified by the middle office, and used for financial reporting by the back office. We consider credit and nonperformance risk in the valuation of derivative contracts categorized in Level 2 and 3, including both historical and current market data, in our assessment of credit and nonperformance risk by counterparty. Due to master netting agreements and collateral posting requirements, the impacts of credit and nonperformance risk were not material to the consolidated financial statements. Disclosed below is detail surrounding our significant Level 3 valuations. The calculated fair value includes marketability discounts for margining provisions and other attributes. The Level 3 balance generally consists of forward sales and purchases of power and natural gas and certain transmission congestion contracts. We utilize various inputs and factors including market data and assumptions that market participants would use in pricing assets or liabilities as well as assumptions about the risks inherent in the inputs to the valuation technique. The inputs and factors include forward commodity prices, commodity price volatility, contractual volumes, delivery location, interest rates, credit quality of counterparties, and credit enhancements. For commodity derivatives, the primary input to the valuation models is the forward commodity price curve for each instrument. Forward commodity price curves are derived by risk management for liquid locations and by the traders and portfolio managers for illiquid locations. All locations are reviewed and verified by risk management considering published exchange transaction prices, executed bilateral transactions, broker quotes, and other observable or public data sources. The relevant forward commodity curve used to value each of the derivatives depends on a number of factors, including commodity type, delivery location, and delivery period. Price volatility varies by commodity and location. When appropriate, we discount future cash flows using risk-free interest rates with adjustments to reflect the credit quality of each counterparty for assets and our own credit quality for liabilities. The level of observability of a forward commodity price varies generally due to the delivery location and delivery period. Certain delivery locations including PJM West Hub (for power) and Henry Hub (for natural gas) are more liquid and prices are observable for up to three years in the future. The observability period of volatility is generally shorter than the underlying power curve used in option valuations. The forward curve for a less liquid location is estimated by using the forward curve from the liquid location and applying a spread to represent the cost to transport the commodity to the delivery location. This spread does not typically represent a majority of the instrument’s market price. As a result, the change in fair value is closely tied to liquid market movements and not a change in the applied spread. The change in fair value associated with a change in the spread is generally immaterial. An average spread calculated across all Level 3 power and gas delivery locations is approximately $72.43 and $4.57 for power and natural gas, respectively. Many of the commodity derivatives are short term in nature and thus a majority of the fair value may be based on observable inputs even though the contract as a whole must be classified as Level 3. See Note 16 — Derivative Financial Instruments for additional information on mark-to-market derivatives. The following table presents the significant inputs to the forward curve used to value these positions: Type of trade Fair Value as of December 31, 2022 Fair Value as of December 31, 2021 Valuation Unobservable 2022 Range & Arithmetic Average 2021 Range & Arithmetic Average Mark-to-market derivatives—Economic hedges (a)(b) $ (3) $ (66) Discounted Cash Flow Forward power $0.63 - $283 $72 $8.86 - $481 $55 Forward gas $1.67 - $26 $4.57 $1.69 - $17 $3.50 Option Volatility 97% - 119% 111% 24% - 284% 56% __________ (a) The valuation techniques, unobservable inputs, ranges, and arithmetic averages are the same for the asset and liability positions. (b) The fair values do not include cash collateral posted (received) on level three positions of $218 million and ($34) million as of December 31, 2022 and December 31, 2021, respectively. The inputs listed above, which are as of the balance sheet date, would have a direct impact on the fair values of the above instruments if they were adjusted. The significant unobservable inputs used in the fair value measurement of our commodity derivatives are forward commodity prices and for options is price volatility.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
Commitments and Contingencies	Dec. 31, 2022
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies Commercial Commitments. Commercial commitments as of December 31, 2022, representing commitments potentially triggered by future events, were as follows: Expiration within Total 2023 2024 2025 2026 2027 2028 and beyond Letters of credit $ 2,475 $ 2,465 $ 10 $ — $ — $ — $ — Surety bonds (a) 978 977 1 — — — — Total commercial commitments $ 3,453 $ 3,442 $ 11 $ — $ — $ — $ — __________ (a) Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds. Prior Merger Commitment. Consistent with a 2012 MDPSC order approving a prior merger, certain commitments were made for the development of new generation in Maryland, 55 MW of which remains unsatisfied to date. In 2016, we terminated rights to a development project intended to satisfy the remaining commitment and recorded a pre-tax $50 million loss contingency within Operating and maintenance expense in our Consolidated Statements of Operations and Comprehensive Income, representing the potential liquidated damages payment due for the shortfall, consistent with the terms of the original MDPSC order. In September 2022, a previously executed PPA with a third party became effective upon satisfaction of all conditions precedent (including an extension of time to complete the merger commitment from the MDPSC) and will result in the construction of a wind farm project with an expected commercial operation date (“COD”) of December 31, 2024. The satisfaction of the conditions precedent to the PPA, coupled with the milestones contained in the PPA to ensure the facility is constructed, demonstrate that the merger commitment is likely to be met through support of a PPA enabling the project to be constructed rather than a liquidated damages payment. As a result, we have reversed the previously recognized loss contingency and recorded a pre-tax gain of $50 million within Operating and maintenance expense in our Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2022. Nuclear Insurance We are subject to liability, property damage and other risks associated with major incidents at any of our nuclear stations. We have mitigated our financial exposure to these risks through insurance and other industry risk-sharing provisions. The Price-Anderson Act was enacted to ensure the availability of funds for public liability claims arising from an incident at any of the U.S. licensed nuclear facilities and to limit the liability of nuclear reactor owners for such claims from any single incident. As of December 31, 2022, the current liability limit per incident is $13.7 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors at least once every five years with the last adjustment effective November 1, 2018. In accordance with the Price-Anderson Act, we maintain financial protection at levels equal to the amount of liability insurance available from private sources through the purchase of private nuclear energy liability insurance for public liability claims that could arise in the event of an incident. Effective January 1, 2017, the required amount of nuclear energy liability insurance purchased is $450 million for each operating site. Claims exceeding that amount are covered through mandatory participation in a financial protection pool, as required by the Price Anderson-Act, which provides the additional $13.2 billion per incident in funds available for public liability claims. Participation in this secondary financial protection pool requires the operator of each reactor to fund its proportionate share of costs for any single incident that exceeds the primary layer of financial protection. Our share of this secondary layer would be approximately $2.8 billion, however any amounts payable under this secondary layer would be capped at $413 million per year. In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay public liability claims exceeding the $13.7 billion limit for a single incident. As part of the execution of the NOSA on April 1, 2014, we executed an Indemnity Agreement pursuant to which we agreed to indemnify EDF and its affiliates against third-party claims that may arise from any future nuclear incident (as defined in the Price-Anderson Act) in connection with the Calvert Cliffs, Ginna, and Nine Mile Point nuclear generating units or their operations. We are required each year to report to the NRC the current levels and sources of property insurance that demonstrates we possess sufficient financial resources to stabilize and decontaminate a reactor and reactor station site in the event of an accident. The insurance maintained for each facility is currently provided through insurance policies purchased from NEIL, an industry mutual insurance company of which we are a member. NEIL may declare distributions to its members as a result of favorable operating experience. In recent years, NEIL has made distributions to its members. Our portion of the annual distribution declared by NEIL is estimated to be $30 million for 2022, and was $114 million and $75 million for 2021 and 2020, respectively. The distributions were recorded as a reduction to Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. Premiums paid to NEIL by its members are also subject to a potential assessment for adverse loss experience in the form of a retrospective premium obligation. NEIL has never assessed this retrospective premium since its formation in 1973, and we cannot predict the level of future assessments, if any. The current maximum aggregate annual retrospective premium obligation for us is approximately $252 million. NEIL requires its members to maintain an investment grade credit rating or to ensure collectability of their annual retrospective premium obligation by providing a financial guarantee, letter of credit, deposit premium, or some other means of assurance. NEIL provides “all risk” property damage, decontamination and premature decommissioning insurance for each station for losses resulting from damage to its nuclear plants, either due to accidents or acts of terrorism. If the decision is made to decommission the facility, a portion of the insurance proceeds will be allocated to a fund, which we are required by the NRC to maintain, to provide for decommissioning the facility. In the event of an insured loss, we are unable to predict the timing of the availability of insurance proceeds to us and the amount of such proceeds that would be available. In the event that one or more acts of terrorism cause accidental property damage within a twelve-month period from the first accidental property damage under one or more policies for all insured plants, the maximum recovery by us will be an aggregate of $3.2 billion plus such additional amounts as the insurer may recover for all such losses from reinsurance, indemnity and any other source, applicable to such losses. For our insured losses, we are self-insured to the extent that losses are within the policy deductible or exceed the amount of insurance maintained. Uninsured losses and other expenses, to the extent not recoverable from insurers or the nuclear industry, could also be borne by us. Any such losses could have a material adverse effect on our consolidated financial statements. Spent Nuclear Fuel Obligation Under the NWPA, the DOE is responsible for the development of a geologic repository for and the disposal of SNF and high-level radioactive waste. As required by the NWPA, we are a party to contracts with the DOE (Standard Contracts) to provide for disposal of SNF from our nuclear generating stations. In accordance with the NWPA and the Standard Contracts, we had previously paid the DOE one mill ($0.001) per kWh of net nuclear generation for the cost of SNF disposal. Due to the lack of a viable disposal program, the DOE reduced the SNF disposal fee to zero in May 2014. Until a new fee structure is in effect, we will not accrue any further costs related to SNF disposal fees. This fee may be adjusted prospectively to ensure full cost recovery. We currently assume the DOE will begin accepting SNF in 2035 and use that date for purposes of estimating the nuclear decommissioning AROs. The SNF acceptance date assumption is based on management’s estimate of the amount of time required for DOE to select a site location and develop the necessary infrastructure for long-term SNF storage. The NWPA and the Standard Contracts required the DOE to begin taking possession of SNF generated by nuclear generating units no later than January 31, 1998. The DOE, however, failed to meet that deadline and its performance has been, and is expected to remain, delayed significantly. In August 2004, we and the DOJ, in close consultation with the DOE, reached a settlement under which the government agreed to reimburse us, subject to certain damage limitations based on the extent of the government’s breach, for costs associated with storage of SNF at our nuclear stations pending the DOE’s fulfillment of its obligations. Calvert Cliffs, Ginna and Nine Mile Point each have separate settlement agreements in place with the DOE which were extended during 2020 to provide for the reimbursement of SNF storage costs through December 31, 2022. FitzPatrick also has a separate settlement agreement in place with the DOE that was established in 2021 to provide for reimbursement of SNF storage costs through December 31, 2022. We are in the process of extending the agreements for Calvert Cliffs, Ginna, Nine Mile Point, and Fitzpatrick to provide for the reimbursement of SNF storage costs through December 31, 2025. Under the settlement agreements, we received total cumulative cash reimbursements of $1,731 million through December 31, 2022 for costs incurred. After considering the amounts due to co-owners of certain nuclear stations and to the former owner of Oyster Creek, we received net cumulative cash reimbursements of $1,501 million. As of December 31, 2022 and 2021, the amount of SNF storage costs for which reimbursement has been or will be requested from the DOE under the DOE settlement agreements is as follows: December 31, 2022 December 31, 2021 DOE receivable - current (a) $ 125 $ 241 DOE receivable - noncurrent (b) 130 85 Amounts owed to co-owners (c) (12) (35) __________ (a) Recorded in Other accounts receivable. (b) Recorded in Deferred debits and other assets, other. (c) Recorde d in Other accounts receivable. Represents amounts owed to the co-owners of Peach Bottom, Quad Cities, and Nine Mile Point Unit 2 generating facilitie s. The Standard Contracts with the DOE also required the payment to the DOE of a one-time fee applicable to nuclear generation through April 6, 1983. The below table outlines the SNF liability recorded as of December 31, 2022 and 2021: December 31, 2022 December 31, 2021 Former ComEd units (a) $ 1,100 $ 1,083 Fitzpatrick (b) 130 127 Total SNF Obligation $ 1,230 $ 1,210 __________ (a) ComEd previously elected to defer payment of the one-time fee of $277 million for its units, with interest to the date of payment, until just prior to the first delivery of SNF to the DOE. The unfunded liabilities for SNF disposal costs, including the one-time fee, were transferred to us as part of Exelon’s 2001 corporate restructuring. (b) A prior owner of FitzPatrick elected to defer payment of the one-time fee of $34 million, with interest to the date of payment, for the FitzPatrick unit. As part of the FitzPatrick acquisition on March 31, 2017, we assumed a SNF liability for the DOE one-time fee obligation with interest related to FitzPatrick along with an offsetting asset, included in Other deferred debits and other assets, for the contractual right to reimbursement from NYPA, a prior owner of FitzPatrick, for amounts paid for the FitzPatrick DOE one-time fee obligation. Interest for our SNF liabilities accrues at the 13-week Treasury Rate. The 13-week Treasury Rate in effect for calculation of the interest accrual at December 31, 2022 was 4.169% for the deferred amount transferred from ComEd and 3.415% for the deferred FitzPatrick amount. The following table summarizes sites for which we do not have an outstanding SNF Obligation: Description Sites Fees have been paid Former PECO units, Clinton and Calvert Cliffs Outstanding SNF Obligation remains with former owners Nine Mile Point, Ginna and TMI Environmental Remediation Matters General. Our operations have in the past, and may in the future, require substantial expenditures to comply with environmental laws. Additionally, under Federal and state environmental laws, we are generally liable for the costs of remediating environmental contamination of property now or formerly owned by us and of property contaminated by hazardous substances generated by us. We own or lease several real estate parcels, including parcels on which our operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. In addition, we are currently involved in proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future. Unless otherwise disclosed, we cannot reasonably estimate whether we will incur significant liabilities for additional investigation and remediation costs at these or additional sites identified by us, environmental agencies or others. Additional costs could have a material, unfavorable impact on our consolidated financial statements. As of December 31, 2022 and 2021, we had accrued undiscounted amounts for environmental liabilities of $119 million and $120 million, respectively, in Accrued expenses and Other deferred credits and other liabilities in the Consolidated Balance Sheets. Cotter Corporation. The EPA has advised Cotter Corporation (N.S.L.) (Cotter), a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at two sites in Missouri. In 2000, ComEd sold Cotter to an unaffiliated third-party. As part of the sale, ComEd agreed to indemnify Cotter for any liability arising from these two Missouri superfund sites, West Lake Landfill and Latty Avenue. In connection with Exelon’s 2001 corporate restructuring, this responsibility to indemnify Cotter was transferred to us, and ultimately retained by us per the terms of our separation from Exelon. Refer to Note 1 — Basis of Presentation for additional information on the separation. West Lake Landfill. Including Cotter, there are three PRPs currently participating in the West Lake Landfill remediation proceeding. In September 2018, the EPA issued its Record of Decision Amendment (RODA) for the selection of a final remedy that requires partial excavation of the radiological materials and capping the landfill. The EPA and the PRPs have entered into a Consent Agreement to perform the Remedial Design, which is expected to be completed in the middle of 2024. In March 2019, the PRPs received Special Notice Letters from the EPA to perform the Remedial Action work. The total estimated cost of the remedy, considering the current EPA technical requirements, is approximately $295 million, including cost escalation on an undiscounted basis. Our investigation has identified several other parties who also may be PRPs and could be liable to contribute to the final remedy. We have determined that a loss associated with the EPA’s partial excavation and landfill cover remedy is probable and have recorded a liability, included in the total amount as discussed above, that reflects management’s best estimate of Cotter’s allocable share of the ultimate cost. Given the joint and several nature of this liability, the magnitude of our ultimate liability will depend on the actual costs incurred to implement the required remedy as well as on the nature and terms of any cost-sharing arrangements with the final group of PRPs. Therefore, it is reasonably possible that the ultimate cost and Cotter's associated allocable share could differ significantly once these uncertainties are resolved, which could have a material impact on our consolidated financial statements. In September 2018, the three identified PRPs, including Cotter, signed an Administrative Settlement Agreement and Order on Consent for the performance by the PRPs of the groundwater Remedial Investigation Feasibility Study (RI/FS). The purpose of this RI/FS is to define the nature and extent of any groundwater contamination from the West Lake Landfill site and evaluate remedial alternatives. We estimate the undiscounted cost for the groundwater RI/FS to be approximately $50 million. We determined a loss associated with the RI/FS is probable and have recorded a liability, included in the total amount as discussed above, that reflects management’s best estimate of Cotter’s allocable share of the cost among the PRPs. At this time we cannot predict the likelihood, or the extent to which, if any, remediation activities may be required and therefore cannot estimate a reasonably possible range of loss for response costs beyond those associated with the RI/FS component. It is reasonably possible, however, that resolution of this matter could have a material, unfavorable impact on our consolidated financial statements. Latty Avenue . In August 2011, Cotter was notified by the DOJ that Cotter is considered a PRP with respect to the government’s clean-up costs for contamination attributable to low level radioactive residues at a former storage and reprocessing facility named Latty Avenue near St. Louis, Missouri. Latty Avenue was investigated and remediated by the United States Army Corps of Engineers pursuant to funding under the Formerly Utilized Sites Remedial Action Program. On August 3, 2020, the DOJ advised Cotter that it is seeking approximately $90 million from all the PRPs. In December 2021, a good faith offer was submitted to the government. After subsequent communications with DOJ, Cotter proposed, and DOJ agreed to consider mediation to facilitate a settlement. Pursuant to a series of agreements since 2011, the DOJ and Cotter have extended the Statute of Limitations through August 31, 2023. We have determined that a loss associated with this matter is probable and have recorded an estimated liability, included in the total amount as discussed above, that reflects management's best estimate of Cotter's allocable share of the cost. It is reasonably possible that Cotter's allocable share could differ significantly, which could have a material impact on our consolidated financial statements. Litigation and Regulatory Matters Asbestos Personal Injury Claims. We maintain a reserve for claims associated with asbestos-related personal injury actions at certain facilities that are currently owned by us or were previously owned by ComEd, PECO, or BGE. The estimated liabilities are recorded on an undiscounted basis and exclude the estimated legal costs associated with handling these matters, which could be material. At December 31, 2022 and 2021, we recorded estimated liabilities of approximately $95 million and $81 million, respectively, in total for asbestos-related bodily injury claims. As of December 31, 2022, approximately $23 million of this amount related to 253 open claims presented to us, while the remaining $72 million is for estimated future asbestos-related bodily injury claims anticipated to arise through 2055, based on actuarial assumptions and analyses, which are updated on an annual basis. On a quarterly basis, we monitor actual experience against the number of forecasted claims to be received and expected claim payments and evaluate whether adjustments to the estimated liabilities are necessary. Impacts of the February 2021 Extreme Cold Weather Event and Texas-based Generating Assets Outages. Beginning on February 15, 2021, our Texas-based generating assets within the ERCOT market, specifically Colorado Bend II, Wolf Hollow II, and Handley, experienced outages as a result of extreme cold weather conditions. In addition, those weather conditions drove increased demand for service, dramatically increased wholesale power prices, and also increased gas prices in certain regions. See Note 3 — Regulatory Matters for additional information. Various lawsuits have been filed against us since March 2021 related to these events, including: • On March 5, 2021, we, along with more than 160 power generators and transmission and distribution companies, were sued by approximately 160 individually named plaintiffs, purportedly on behalf of all Texans who allegedly suffered loss of life or sustained personal injury, property damage or other losses as a result of the weather events. The plaintiffs allege that the defendants failed to properly prepare for the cold weather and failed to properly conduct their operations, seeking compensatory as well as punitive damages. On April 26, 2021, another multi-plaintiff lawsuit was filed on behalf of approximately 90 plaintiffs against more than 300 defendants, including us, involving similar allegations of liability and claims of personal injury and property damage. Since March 2021, approximately 60 additional lawsuits, naming multiple defendants including us, were filed by individual or multiple plaintiffs in different Texas counties, all arising out of the February weather events. These additional lawsuits allege wrongful death, property damage, or other losses. Co-defendants in these lawsuits include ERCOT, transmission and distribution utilities and other generators. On December 28, 2021, approximately 130 insurance companies which insured Texas homeowners and businesses filed a subrogation lawsuit against multiple defendants alleging that defendants were at fault for the energy failure that resulted from the winter storm, causing significant property damage to the insureds. Additionally, as of January 28, 2022, we have been added to approximately 80 additional wrongful death, personal injury, and property damage lawsuits through the Multi-District-Litigation (MDL) pending in Texas state court. The MDL now includes all of the above-described Texas state court matters. We are now defendants in approximately 150 lawsuits in the MDL brought by several hundred plaintiffs and more than 130 insurance companies. Defendants filed Motions to Dismiss the amended complaints in five bellwether cases in July 2022. Briefing was completed in September 2022, and oral argument was held on October 11 and 12, 2022. On February 3, 2023, the court granted the motions to dismiss in part and denied them in part. As a result, we remain a defendant in the lawsuits. On June 27, 2022, a new group of 24 plaintiff customers filed a petition in Starr County seeking damages and redress for property damage and other injury. One plaintiff household was a customer of Constellation NewEnergy, Inc. as the Retail Electricity Provider (REP). This is the first time that Constellation has been named in a winter storm lawsuit as a REP. We dispute liability and deny that we are responsible for any of plaintiffs’ alleged claims and are vigorously contesting them. No loss contingencies have been reflected in the consolidated financial statements with respect to these matters, as such contingencies are neither probable nor reasonably estimable at this time. • On March 22, 2021, an LDC filed a lawsuit in Missouri federal court against us for breach of contract and unjust enrichment, seeking damages of approximately $40 million. The plaintiff claims that we failed to deliver gas to our customers in February of 2021, causing the plaintiff to incur damages by forcing it to purchase gas for our customers and by our refusal to pay the resulting penalties. On March 26, 2021, we filed a complaint with the MPSC against the LDC to void the OFO penalties, or alternatively to grant a waiver or variance from the tariff requirements, to prohibit the LDC from billing or otherwise attempting to collect from us or any Missouri customer any portion of the penalties claimed by the LDC until the resolution of the complaint, and to prohibit the LDC from taking any retaliatory measure, including termination of service. On September 1, 2021, the MPSC consolidated our complaint with two other similar complaints from other companies. On January 4, 2022, the court denied our motion to dismiss, but in the alternative granted its motion to stay pending MPSC resolution of our complaint. Based on the penalty provisions within the tariff that was in effect at the relevant time, we have recorded a liability of approximately $40 million as of December 31, 2021. On May 25, 2022, a settlement was approved by the MPSC. In connection with the settlement, the liability was revised to $11 million as of June 30, 2022, and was paid in the third quarter of 2022. On June 14, 2022, the lawsuit in Missouri federal court was dismissed. General. We are involved in various other litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. We maintain accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of reasonably possible loss, particularly where (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.

Stock-Based Compensation Plans

Stock-Based Compensation Plans	12 Months Ended
Stock-Based Compensation Plans	Dec. 31, 2022
Share-Based Payment Arrangement [Abstract]
Stock-Based Compensation Plans	Stock-Based Compensation Plans Effective February 1, 2022, we established our own LTIP and began granting cash and stock-based awards that primarily include performance share awards and restricted stock units. Our LTIP authorized 20,000,000 shares of common stock for these awards. The existing, unvested cash and stock-based awards issued through the Exelon LTIP were modified in connection with the separation to align with our performance metrics and maintain an equivalent value immediately before and after separation. The impact of this modification was not material to our stock-based compensation expense for the year ended December 31, 2022. Our employees were granted stock-based awards through the Exelon LTIP prior to separation, which primarily included performance share awards, restricted stock units, and stock options. We also granted cash awards. Performance share awards were typically settled 50% in common stock and 50% in cash at the end of a three The following table presents the stock-based compensation expense included in the Consolidated Statements of Operations and Comprehensive Income. The information does not include expenses related to the cash awards as they are not considered stock-based compensation plans under the applicable authoritative guidance: Year Ended December 31, 2022 (a) 2021 (b) 2020 (b) Total stock-based compensation expense included in operating and maintenance expense $ 116 $ 47 $ 27 Income tax benefit (29) (12) (7) Total after-tax stock-based compensation expense $ 87 $ 35 $ 20 __________ (a) Costs recognized for the year ended December 31, 2022 are related to the Constellation LTIP. (b) Costs recognized for the years ended December 31, 2021 and 2020 were allocated to us by Exelon under the Exelon LTIP prior to separation. We receive a tax deduction based on the intrinsic value of the award on the distribution date for restricted stock units. The tax deduction related to performance share awards was not material for the year ended December 31, 2022. For each award, throughout the requisite service period, we recognize the tax benefit related to compensation costs. The following table presents information regarding our realized tax benefit when distributed: December 31, 2022 Restricted stock units $ 2 Performance Share Awards Performance share awards are granted under the LTIP. The performance share awards are typically settled 50% in common stock and 50% in cash at the end of the three The common stock portion of the performance share awards is considered an equity award and is valued based on our stock price on the grant date. The cash portion of the performance share awards is considered a liability award which is remeasured each reporting period based on the current stock price. As the value of the common stock and cash portions of the awards are based on the stock price during the performance period, coupled with changes in the total expected payout of the award, the compensation costs are subject to volatility until payout is established. For nonretirement-eligible employees, performance share awards are recognized over the vesting period of three years using the straight-line method. For performance share awards granted to retirement-eligible employees, the value of the performance shares is recognized ratably over the vesting period, which is the year of grant. We process forfeitures as they occur for employees who do not complete the requisite service period. The following table summarizes our nonvested performance share awards activity: Shares Weighted Average Grant Date Fair Value (per share) Nonvested at December 31, 2021 — $ — Granted 1,575,542 48.33 Change in performance 728,054 47.30 Forfeited (22,617) 48.55 Undistributed vested awards (a) (1,431,637) 48.35 Nonvested at December 31, 2022 849,342 $ 47.40 __________ (a) Includes 1,272,921 of performance share awards that vested but were not distributed to retirement-eligible employees during 2022. The following table summarizes the weighted average grant date fair value and the total fair value of performance share awards vested: December 31, 2022 (a) Weighted average grant date fair value (per share) $ 48.33 Total fair value of performance shares vested 69 __________ (a) As of December 31, 2022, $28 million of total unrecognized compensation costs related to nonvested performance shares are expected to be recognized over the remaining weighted-average period of 1.7 years . Restricted Stock Units Restricted stock units are granted under the LTIP with the majority being settled in a specific number of shares of common stock after the service condition has been met. The corresponding cost is measured based on the grant date fair value of the restricted stock unit issued. The value of the restricted stock units is expensed over the requisite service period using the straight-line method. The requisite service period for restricted stock units is generally three The following table summarizes our nonvested restricted stock unit activity: Shares Weighted Average Grant Date Fair Value (per share) Nonvested at December 31, 2021 — $ — Granted 1,497,651 54.17 Vested (144,903) 49.82 Forfeited (62,238) 59.47 Undistributed vested awards (a) (499,842) 55.16 Nonvested at December 31, 2022 790,668 $ 53.72 __________ (a) Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2022. The following table summarizes the weighted average grant date fair value and the total fair value of restricted stock units vested: December 31, 2022 (a) Weighted average grant date fair value (per share) $ 54.17 Total fair value of performance shares vested 35 __________ (a) As of December 31, 2022, $27 million of total unrecognized compensation costs related to nonvested restricted stock units are expected to be recognized over the remaining weighted-average period of 2.0 years.

Changes in Accumulated Other Co

Changes in Accumulated Other Comprehensive Income	12 Months Ended
Changes in Accumulated Other Comprehensive Income	Dec. 31, 2022
Equity [Abstract]
Changes in Accumulated Other Comprehensive Income	Changes in Accumulated Other Comprehensive Income The following tables present changes in AOCI, net of tax, by component: Losses on Cash Flow Hedges Pension and Non-Pension Postretirement Benefit Plan Items (a) Foreign Currency Items Total Balance at December 31, 2019 $ (5) $ — $ (27) $ (32) OCI before reclassifications (2) — 4 2 Net current-period OCI (2) — 4 2 Balance at December 30, 2020 $ (7) $ — $ (23) $ (30) OCI before reclassifications (1) — — (1) Net current-period OCI (1) — — (1) Balance at December 30, 2021 $ (8) $ — $ (23) $ (31) Separation-related adjustments — (2,006) — (2,006) OCI before reclassifications (1) 186 (3) 182 Amounts reclassified from AOCI — 95 — 95 Net current-period OCI (1) (1,725) (3) (1,729) Balance at December 30, 2022 $ (9) $ (1,725) $ (26) $ (1,760) __________ (a) AOCI amounts are included in the computation of net periodic pension and OPEB cost. See Note 15 — Retirement Benefits for additional information. See our Statements of Operations and Comprehensive Income for individual components of AOCI. The following table presents income tax (expense) benefit allocated to each component of our other comprehensive income (loss): Year Ended December 31, 2022 2021 2020 Pension and non-pension postretirement benefit plans: Actuarial loss reclassified to periodic benefit cost $ (33) $ — $ — Pension and non-pension postretirement benefit plans valuation adjustment (a) 619 — — __________ (a) Includes $680 million of income tax benefit related to the separation adjustment for the year ended December 31, 2022.

Variable Interest Entities

Variable Interest Entities	12 Months Ended
Variable Interest Entities	Dec. 31, 2022
Variable Interest Entity [Abstract]
Variable Interest Entity	Variable Interest Entities As of December 31, 2022 and 2021, we consolidated several VIEs or VIE groups for which we are the primary beneficiary (see Consolidated VIEs below) and had significant interests in several other VIEs for which we do not have the power to direct the entities’ activities and, accordingly, we were not the primary beneficiary (see Unconsolidated VIEs below). Consolidated and unconsolidated VIEs are aggregated to the extent that the entities have similar risk profiles. Consolidated VIEs The table below shows the carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in the consolidated financial statements as of December 31, 2022 and 2021. The assets, except as noted in the footnotes to the table below, can only be used to settle obligations of the VIEs. The liabilities, except as noted in the footnotes to the table below, are such that creditors, or beneficiaries, do not have recourse to our general credit. December 31, 2022 December 31, 2021 Cash and cash equivalents $ 51 $ 35 Restricted cash and cash equivalents 46 48 Accounts receivable Customer 20 24 Other 9 6 Inventories, net Materials and supplies 12 14 Other current assets 549 405 Total current assets 687 532 Property, plant and equipment, net 1,965 2,027 Other noncurrent assets 190 215 Total noncurrent assets 2,155 2,242 Total assets (a) $ 2,842 $ 2,774 Long-term debt due within one year $ 60 $ 70 Accounts payable 17 10 Accrued expenses 23 21 Other current liabilities 2 1 Total current liabilities 102 102 Long-term debt 764 822 Asset retirement obligations 173 151 Other noncurrent liabilities 3 3 Total noncurrent liabilities 940 976 Total liabilities (b) $ 1,042 $ 1,078 _______ (a) Our balances include unrestricted assets f or current unamortized energy contract assets of $23 million and $23 million, disclosed within other current assets in the table above and noncurrent unamortized energy contract assets of $178 million and $202 million, disclosed within other noncurrent assets in the table above as of December 31, 2022 and 2021, respectively. (b) Our balances include liabilities with recourse of $1 million and $1 million as of December 31, 2022 and 2021, respectively. As of December 31, 2022 and 2021, our consolidated VIEs included the following: Consolidated VIE or VIE groups: Reason entity is a VIE: Reason we are the primary beneficiary: CRP - A collection of wind and solar project entities. We have a 51% equity ownership in CRP. See additional discussion below. Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner. We conduct the operational activities. Bluestem Wind Energy Holdings, LLC - A Tax Equity structure which is consolidated by CRP. Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner. We conduct the operational activities. Antelope Valley - A solar generating facility, which is 100% owned by us. Antelope Valley sells all of its output to PG&E through a PPA. The PPA contract absorbs variability through a performance guarantee. We conduct all activities. NER - A bankruptcy remote, special purpose entity which is 100% owned by us, which purchases certain of our customer accounts receivable arising from the sale of retail electricity. NER’s assets will be available first and foremost to satisfy the claims of the creditors of NER. Refer to Note 6 —Accounts Receivable for additional information on the sale of receivables. Equity capitalization is insufficient to support its operations. We conduct all activities. CRP - CRP is a collection of wind and solar project entities and some of these project entities are VIEs that are consolidated by CRP. While we or CRP own 100% of the solar entities and 100% of the majority of the wind entities, it has been determined that the wholly owned solar and wind entities are VIEs because the entities' customers absorb price variability from the entities through fixed price power and/or REC purchase agreements. Additionally, for the wind entities that have minority interests, it has been determined that these entities are VIEs because the governance rights of some investors are not proportional to their financial rights. We are the primary beneficiary of these solar and wind entities that qualify as VIEs because we control operations and direct all activities of the facilities. There is limited recourse to us related to certain solar and wind entities. In 2017, our interests in CRP were contributed to and are pledged for the CR non-recourse debt project financing structure. Refer to Note 17 — Debt and Credit Agreements for additional information. Unconsolidated VIEs Our variable interests in unconsolidated VIEs generally include equity investments and energy purchase and sale contracts. For the equity investments, the carrying amount of the investments is reflected in the Consolidated Balance Sheets in Investments. For the energy purchase and sale contracts (commercial agreements), the carrying amount of assets and liabilities in the Consolidated Balance Sheets that relate to our involvement with the VIEs are predominantly related to working capital accounts and generally represent the amounts owed by, or owed to, us for the deliveries associated with the current billing cycles under the commercial agreements. As of December 31, 2022 and 2021, we had significant unconsolidated variable interests in several VIEs for which we were not the primary beneficiary. These interests include certain equity method investments and certain commercial agreements. The following table presents summary information about our significant unconsolidated VIE entities: December 31, 2022 December 31, 2021 Commercial Equity Total Commercial Equity Total Total assets (a) $ 715 $ — $ 715 $ 772 $ 372 $ 1,144 Total liabilities (a) 54 — 54 80 216 296 Our ownership interest in VIE (a) — — — — 139 139 Other ownership interests in VIE (a) 661 — 661 692 17 709 __________ (a) These items represent amounts on the unconsolidated VIE balance sheets, not in the Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs. We do not have any exposure to loss as we do not have a carrying amount in the equity investment VIEs as o f December 31, 2022 and 2021. As of December 31, 2022 and 2021, the unconsolidated VIEs consist of: Unconsolidated VIE groups: Reason entity is a VIE: Reason we are not the primary beneficiary: Equity investments in distributed energy companies. We have a 90% equity ownership in a distributed energy company. We sold this investment in the fourth quarter of 2022 resulting in it no longer being classified as an unconsolidated VIE . Similar structures to a limited partnership and the limited partners do not have kick out rights with respect to the general partner. We do not conduct the operational activities. Energy Purchase and Sale agreements - We have several energy purchase and sale agreements with generating facilities. PPA contracts that absorb variability through fixed pricing. We do not conduct the operational activities.

Supplemental Financial Informat

Supplemental Financial Information	12 Months Ended
Supplemental Financial Information	Dec. 31, 2022
Supplemental Financial Information [Abstract]
Supplemental Financial Information	Supplemental Financial Information Supplemental Statement of Operations Information The following tables provide additional information about material items recorded in the Consolidated Statements of Operations and Comprehensive Income. Taxes other than income taxes For the Years Ended December 31, 2022 2021 2020 Gross receipts (a) $ 130 $ 99 $ 99 Property 274 268 265 Payroll 130 109 113 __________ (a) Represent gross receipts taxes related to our retail operations. The offsetting collection of gross receipts taxes from customers is recorded in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income. Other, net For the Years Ended December 31, 2022 2021 2020 Decommissioning-related activities: Net realized income on NDT funds (a) Regulatory Agreement Units $ 333 $ 817 $ 185 Non-Regulatory Agreement Units 97 449 160 Net unrealized (losses) gains on NDT funds Regulatory Agreement Units (1,354) 351 724 Non-Regulatory Agreement Units (798) 209 391 Regulatory offset to NDT fund-related activities (b) 820 (917) (729) Decommissioning-related activities (902) 909 731 Investment income 58 — — Non-service net periodic benefit credit (c) 110 — — Net realized and unrealized (losses) gains from equity investments (d) (13) (160) 186 Return to provision adjustment (e) (49) — — __________ (a) Realized income includes interest, dividends and realized gains and losses on sales of NDT fund investments. (b) Includes the elimination of decommissioning-related activities and the elimination of income taxes related to all NDT fund activity for the Regulatory Agreement Units except for decommissioning-related impacts that were not offset for the Byron units starting in the second quarter of 2021. With our September 15, 2021 reversal of the previous decision to retire Byron, we resumed contractual offset for Byron as of that date. See Note 10 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning and the contractual offset suspension for the Byron units. (c) Historically, we were allocated our portion of pension and OPEB non-service credits (costs) from Exelon, which was included in Operating and maintenance expense. Effective February 1, 2022, the non-service credit (cost) components will now be included in Other, net, in accordance with single employer plan accounting. See Note 15 — Retirement Benefits for additional information. (d) For 2022, represents Net realized and unrealized (losses) gains from equity investments. For 2021 and 2020, represents Net unrealized (losses) gains from equity investments. (e) This reflects amounts contractually owed to Exelon under the tax matters agreement, which is offset in Income taxes. See Note 14 — Income Taxes for additional information. Supplemental Cash Flow Information The following tables provide additional information about material items recorded in the Consolidated Statements of Cash Flows. Depreciation, amortization and accretion For the Years Ended December 31, 2022 2021 2020 Property, plant, and equipment (a) $ 1,065 $ 2,954 $ 2,070 Amortization of intangible assets, net (a) 26 49 53 Amortization of energy contract assets and liabilities (b) 35 31 30 Nuclear fuel (c) 758 992 983 ARO accretion (d) 543 514 500 Total depreciation, amortization, and accretion $ 2,427 $ 4,540 $ 3,636 _________ (a) Included in Depreciation and amortization expense in the Consolidated Statements of Operations and Comprehensive Income. (b) Included in Operating revenues or Purchased power and fuel expense in the Consolidated Statements of Operations and Comprehensive Income. (c) Included in Purchased power and fuel expense in the Consolidated Statements of Operations and Comprehensive Income. (d) Included in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. Cash paid during the year For the Years Ended December 31, 2022 2021 2020 Interest (net of amount capitalized) $ 230 $ 275 $ 331 Income taxes (net of refunds) 287 426 70 Other non-cash operating activities CEG Parent Constellation For the Years Ended December 31, For the Years Ended December 31, 2022 2021 2020 2022 2021 2020 Pension and non-pension postretirement benefit costs $ 17 $ 123 $ 115 $ 17 $ 123 $ 115 Other decommissioning-related activity (a) (263) (946) (659) (263) (946) (659) Energy-related options (b) 293 125 104 293 125 104 Severance costs (1) (73) 90 (1) (73) 90 Long-term incentive plan 44 — — — — — Provision for excess and obsolete inventory (12) (13) 128 (12) (13) 128 Amortization of operating ROU asset 75 119 155 75 119 155 Loss on sale of receivables 69 36 30 69 36 30 Fair value adjustments related to gas imbalances 37 — — 37 — — Prior merger commitment (c) (50) — — (50) — — __________ (a) Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units except for decommissioning-related impacts that were not offset for the Byron units starting in the second quarter of 2021, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income, and income taxes related to all NDT fund activity for these units. With our September 15, 2021 reversal of the previous decision to retire Byron, we resumed contractual offset for Byron as of that date. See Note 10 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning and the contractual offset suspension for the Byron units. (b) Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations. (c) Reversal of a charge related to a prior 2012 merger commitment. See Note 19 - Commitments and Contingencies for additional information. The following table provides a reconciliation of cash, restricted cash, and cash equivalents reported in the Consolidated Balance Sheets that sum to the total of the same amounts in the Consolidated Statements of Cash Flows. December 31, 2022 CEG Parent Constellation Cash and cash equivalents $ 422 $ 403 Restricted cash and cash equivalents 106 98 Total cash, restricted cash, and cash equivalents $ 528 $ 501 December 31, 2021 CEG Parent Constellation Cash and cash equivalents $ 504 $ 504 Restricted cash and cash equivalents 72 72 Total cash, restricted cash, and cash equivalents $ 576 $ 576 December 31, 2020 CEG Parent Constellation Cash and cash equivalents $ 226 $ 226 Restricted cash and cash equivalents 89 89 Cash, restricted cash, and cash equivalents - Held for Sale 12 12 Total cash, restricted cash, and cash equivalents $ 327 $ 327 December 31, 2019 CEG Parent Constellation Cash and cash equivalents $ 303 $ 303 Restricted cash and cash equivalents 146 146 Total cash, restricted cash, and cash equivalents $ 449 $ 449 For additional information on restricted cash, see Note 1 — Basis of Presentation. Supplemental Balance Sheet Information The following tables provide additional information about material items recorded in the Consolidated Balance Sheets. Investments December 31, 2022 December 31, 2021 Equity method investments $ 82 $ 62 Other investments: Employee benefit trusts and investments (a) 68 72 Equity investments without readily determinable fair values 46 33 Other available for sale debt security investments 6 7 Total investments $ 202 $ 174 __________ (a) Debt and equity security investments are recorded at fair market value. Accrued expenses December 31, 2022 CEG Parent Constellation Compensation-related accruals (a) $ 540 $ 502 Taxes accrued 257 257 Accrued expenses December 31, 2021 CEG Parent Constellation Compensation-related accruals (a) $ 356 $ 356 Taxes accrued 272 272 __________ (a) Primarily includes accrued payroll, bonuses and other incentives, vacation, and benefits.

Related Party Transactions

Related Party Transactions	12 Months Ended
Related Party Transactions	Dec. 31, 2022
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions Prior to completion of the separation on February 1, 2022, we engaged in transactions with affiliates of Exelon in the normal course of business, these affiliate transactions are summarized in the tables below. After February 1, 2022, all transactions with Exelon or its affiliates are no longer related party transactions. Operating revenues from affiliates The following table presents our Operating revenues from affiliates: For the Years Ended 2022 (a) 2021 2020 ComEd (b) $ 58 $ 376 $ 330 PECO (c) 33 196 190 BGE (d) 18 236 315 PHI 51 366 367 Pepco (e) 39 270 279 DPL (f) 10 79 75 ACE (g) 2 17 13 Other — 14 9 Total operating revenues from affiliates $ 160 $ 1,188 $ 1,211 __________ (a) Represents only January 2022 costs prior to separation on February 1, 2022. (b) We have an ICC-approved RFP contract with ComEd to provide a portion of ComEd’s electricity supply requirements. We also sell RECs and ZECs to ComEd. (c) We provide electric supply to PECO under contracts executed through PECO’s competitive procurement process. In addition, we have a ten-year agreement with PECO to sell solar AECs. (d) We provide a portion of BGE’s energy requirements under its MDPSC-approved market-based SOS and gas commodity programs. (e) We provide electric supply to Pepco under contracts executed through Pepco's competitive procurement process approved by the MDPSC and DCPSC. (f) We provide a portion of DPL's energy requirements under its MDPSC and DEPSC approved market-based SOS commodity programs. (g) We provide electric supply to ACE under contracts executed through ACE's competitive procurement process. Service Company Costs for Corporate Support We received a variety of corporate support services from Exelon. Through its business services subsidiary, BSC, Exelon provided support services at cost, including legal, human resources, financial, information technology, and supply management services. The costs of BSC were directly charged or allocated to us. Certain of these services will continue after the separation and are covered by the TSA. See Note 1 — Basis of Presentation for additional information. The following table presents the service company costs allocated to us: Operating and maintenance from Capitalized costs For the Years Ended December 31, For the Years Ended December 31, 2022 (a) 2021 2020 2022 (a) 2021 2020 $ 44 $ 588 $ 552 $ 15 $ 129 $ 54 __________ (a) Represents only January 2022 costs prior to separation on February 1, 2022. Current Receivables from/Payables to affiliates The following table presents Current receivables from affiliates and Current payables to affiliates: December 31, 2021 Receivables from affiliates: Payables to affiliates: ComEd $ 84 $ 13 PECO 30 — BGE 4 — Pepco 20 — DPL 4 — ACE 7 — BSC — 102 Other 11 16 Total(a) $ 160 $ 131 __________ (a) Prior to the completion of the separation on February 1, 2022, we engaged in transactions with affiliates of Exelon in the normal course of business. As of December 31, 2022, all transactions with Exelon or its affiliates are third-party transactions. Payables Related to Regulatory Agreement Units We have Noncurrent payables to ComEd and PECO as a result of the nuclear decommissioning contractual construct whereby, to the extent NDT funds are greater than the underlying ARO at the end of decommissioning, such amounts are due back to ComEd and PECO, as applicable, for payment to their respective customers. See Note 10 — Asset Retirement Obligations for additional information.

Schedule II - Valuation and Qua

Schedule II - Valuation and Qualifying Accounts	12 Months Ended
Schedule II - Valuation and Qualifying Accounts	Dec. 31, 2022
SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract]
Valuation and Qualifying Accounts	Constellation Energy Corporation and Subsidiary Companies Constellation Energy Generation, LLC and Subsidiary Companies Schedule II – Valuation and Qualifying Accounts Additions and adjustments Description Balance at Charged to Charged Deductions Balance at (In millions) For the year ended December 31, 2022 Allowance for credit losses $ 59 $ 10 $ — $ 18 (a) $ 51 Deferred tax valuation allowance 22 — (11) — 11 Reserve for obsolete materials 250 11 (6) 17 238 For the year ended December 31, 2021 Allowance for credit losses $ 32 $ 34 $ — $ 7 (a) $ 59 Deferred tax valuation allowance 23 — (1) — 22 Reserve for obsolete materials 265 (6) (2) 7 250 For the year ended December 31, 2020 Allowance for credit losses $ 81 $ 12 $ (56) $ 5 (a) $ 32 Deferred tax valuation allowance 24 — (1) — 23 Reserve for obsolete materials 143 123 (b) (1) — 265 __________ (a) Write-offs, net of recoveries of individual accounts receivable. (b) Primarily reflects expense resulting from materials and supplies inventory reserve adjustments as a result of the decision to early retire Byron, Dresden, and Mystic 8 and 9. See Note 7—Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information.

Basis of Presentation (Policies

Basis of Presentation (Policies)	12 Months Ended
Basis of Presentation (Policies)	Dec. 31, 2022
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation On February 21, 2021, the Board of Directors of Exelon authorized management to pursue a plan to separate its competitive generation and customer-facing energy businesses, conducted through Constellation Energy Generation, LLC ( “ Constellation ” , formerly Exelon Generation Company, LLC) and its subsidiaries, into an independent, publicly-traded company. CEG Parent, a direct, wholly owned subsidiary of Exelon, was newly formed for the purpose of separation and had not engaged in any business activities nor had any assets or liabilities prior to the separation. On February 1, 2022, the separation was completed and CEG Parent holds all the interests in Constellation previously held by Exelon. As an individual registrant, Constellation has historically filed consolidated financial statements to reflect its financial position and operating results as a stand-alone, wholly owned subsidiary of Exelon. The accompanying Consolidated Financial Statements have been prepared in accordance with GAAP for annual financial statements and in accordance with the instructions to Form 10-K and Regulation S-X promulgated by the SEC. The Consolidated Financial Statements include the accounts of our subsidiaries and all intercompany transactions have been eliminated. CEG Parent's prior period financial statements have been adjusted to reflect the balances of Constellation in accordance with applicable guidance. Amounts disclosed relate to CEG Parent and Constellation unless specifically noted as relating to CEG Parent only. Unless otherwise indicated or the context otherwise requires, references herein to the terms “we,” “us,” and “our” refer collectively to CEG Parent and Constellation. We own 100% of our significant consolidated subsidiaries, either directly or indirectly, except for certain consolidated VIEs, including CRP, of which we hold a 51% interest. The remaining interests in the consolidated VIEs are included in noncontrolling interests on the Consolidated Balance Sheets. See Note 22 — Variable Interest Entities for additional information on consolidated VIEs. We consolidate the accounts of entities in which we have a controlling financial interest, after the elimination of intercompany transactions. Where we do not have a controlling financial interest in an entity, proportionate consolidation, equity method accounting or accounting for investments in equity securities with or without readily determinable fair value is applied. We apply proportionate consolidation when we have an undivided interest in an asset and are proportionately liable for our share of each liability associated with the asset. We proportionately consolidate our undivided ownership interest in jointly owned electric plants. Under proportionate consolidation, we separately record our proportionate share of the assets, liabilities, revenues and expenses related to the undivided interest in the asset. We apply equity method accounting when we have a significant influence over an investee through an ownership in equity, which generally approximates a 20% to 50% voting interest. We apply equity method accounting to certain investments and joint ventures. Under equity method accounting, we report our interest in the entity as an investment and our percentage share of the earnings from the entity as single line items in our consolidated financial statements. We use accounting for investments in equity securities with or without readily determinable fair values if we lack a significant influence, which generally results when we hold less than 20% of the common stock of an entity. Under accounting for investments in equity securities with readily determinable fair values, the investments are reported based on quoted prices in active markets and realized and unrealized gains and losses are included in earnings. Under accounting for investments in equity securities without readily determinable fair values, the investments are reported at cost adjusted for changes
Separation From Parent	Separation from Exelon On February 1, 2022, Exelon completed the separation through a pro-rata distribution of all of the outstanding shares of our common stock, no par value, on the basis of one such share for every three shares of Exelon common stock held on January 20, 2022, the record date of the distribution. We are an independent, publicly traded company listed on the Nasdaq Stock Market under the symbol “CEG”, and regular-way trading began on February 2, 2022. Exelon no longer retains any ownership interest in CEG Parent or Constellation. Prior to completion of the separation, our financial statements include certain transactions with affiliates of Exelon, which are disclosed as related party transactions. After February 1, 2022, all transactions with Exelon or its affiliates are no longer related party transactions. In order to govern the ongoing relationships with Exelon after the separation, and to facilitate an orderly transition, we entered into several agreements with Exelon, including the following: • Separation Agreement – sets forth the principal actions to be taken in connection with the separation, including the transfer of assets and assumption of liabilities and establishes certain rights and obligations between us following the distribution • Transition Services Agreement (TSA) – governs all matters relating to the provision of services between us and Exelon on a transitional basis, in addition to providing us with certain services for an expected period of two-years, provided that certain services may be longer than the term and services may be extended with approval from both parties; the services include support for information technology, accounting, finance, human resources, security, and various other administrative and operational services • Employee Matters Agreement (EMA) – addresses certain employment, compensation and benefits matters, including the allocation of employees between us and Exelon and the allocation and treatment of certain assets and liabilities relating to our employees and former employees • Tax Matters Agreement (TMA) - governs the respective rights, responsibilities, and obligations between us and Exelon with respect to all tax matters (excluding employee-related taxes covered under EMA), in addition to certain restrictions which generally prohibit us from taking or failing to take any action in the two-year period following the distribution that would prevent the distribution from qualifying as tax-free for U.S. federal income tax purposes, including limitations on our ability to pursue certain equity issuances, strategic transactions, repurchases or other transactions
Use of Estimates	Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Areas in which significant estimates have been made include, but are not limited to, the accounting for nuclear decommissioning costs and other AROs, pension and OPEB plans, inventory reserves, allowance for credit losses, long-lived asset impairment assessments, derivative instruments, unamortized energy contracts, fixed asset depreciation, environmental costs and other loss contingencies, taxes and unbilled energy revenues. Actual results could differ from those estimates.
Revenues	Revenues Operating Revenues. Our operating revenues generally consist of revenues from contracts with customers involving the sale and delivery of energy commodities and related products and services and realized and unrealized revenues recognized under mark-to-market energy commodity derivative contracts. We recognize revenue from contracts with customers to depict the transfer of goods or services to customers in an amount that we expect to be entitled to in exchange for those goods or services. Our primary source of revenue includes competitive sales of power, natural gas, and other energy-related products and services. At the end of each reporting period, we accrue an estimate for the unbilled amount of energy delivered or services provided to customers. Option Contracts, Swaps and Commodity Derivatives. Certain option contracts and swap arrangements that meet the definition of derivative instruments are recorded at fair value with subsequent changes in fair value recognized as revenue or expense. The classification of revenue or expense is based on the intent of the transaction. See Note 16 — Derivative Financial Instruments for additional information.
Taxes Directly Imposed on Revenue-Producing Transactions	Taxes Directly Imposed on Revenue-Producing Transactions. We collect certain taxes from customers such as sales and gross receipts taxes, along with other taxes, surcharges and fees, that are levied by state or local governments on the sale or distribution of electricity and natural gas. Some of these taxes are imposed on the customer, but paid by us, while others are imposed on us. Where these taxes are imposed on the customer, such as sales taxes, they are reported on a net basis in revenues. However, where these taxes are imposed on us, such as gross receipts taxes, they are reported on a gross basis. Accordingly, revenues are recognized for the taxes collected from customers along with an offsetting expense. Se e Note 23 — Supplemental Financial Information for the taxes that are presented on a gross basis.
Leases	Leases We recognize a ROU asset and lease liability for operating leases with a term of greater than one year. Operating lease ROU assets are included in Other deferred debits and other assets and operating lease liabilities are included in Other current liabilities and Other deferred credits and other liabilities on the Consolidated Balance Sheets. The ROU asset is measured as the sum of (1) the present value of all remaining fixed and in-substance fixed payments using the rate implicit in the lease whenever that is readily determinable or our incremental borrowing rate, (2) any lease payments made at or before the commencement date (less any lease incentives received) and (3) any initial direct costs incurred. The lease liability is measured the same as the ROU asset, but excludes any payments made before the commencement date and initial direct costs incurred. Lease terms include options to extend or terminate the lease if it is reasonably certain they will be exercised. We include non-lease components for most asset classes, which are service-related costs that are not integral to the use of the asset, in the measurement of the ROU asset and lease liability. Expense for operating leases and leases with a term of one year or less is recognized on a straight-line basis over the term of the lease, unless another systematic and rational basis is more representative of the derivation of benefit from use of the leased property. Variable lease payments are recognized in the period in which the related obligation is incurred and consist primarily of payments for purchases of electricity under contracted generation that are based on the electricity produced by those generating assets. Operating lease expense and variable lease payments are recorded to Purchased power and fuel expense for contracted generation or Operating and maintenance expense for all other lease agreements in the Consolidated Statements of Operations and Comprehensive Income. Income from operating leases, including subleases, is recognized on a straight-line basis over the term of the lease, unless another systematic and rational basis is more representative of the pattern in which income is earned over the term of the lease. Variable lease payments are recognized in the period in which the related obligation is performed and consist primarily of payments received from sales of electricity under contracted generation that are based on the electricity produced by those generating assets. Operating lease income and variable lease payments are recorded to Operating revenues in the Consolidated Statements of Operations and Comprehensive Income. Our operating leases consist primarily of contracted generation, real estate including office buildings, and vehicles and equipment. We generally account for contracted generation in which the generating asset is not renewable as a lease if the customer has dispatch rights and obtains substantially all the economic benefits. We generally do not account for contracted generation in which the generating asset is renewable as a lease if the customer does not design the generating asset. We account for land right arrangements that provide for exclusive use as leases while shared use land arrangements are generally not leases. See Note 11 — Leases for additional information.
Income Taxes	Income Taxes Deferred federal and state income taxes are recorded on temporary differences between the book and tax basis of assets and liabilities and for tax benefits carried forward. ITCs have been deferred in the Consolidated Balance Sheets and are recognized in book income over the life of the related property. We account for uncertain income tax positions using a benefit recognition model with a two-step approach; a more-likely-than-not recognition criterion; and a measurement approach that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. If it is not more-likely-than-not that the benefit of the tax position will be sustained on its technical merits, no benefit is recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. We recognize accrued interest related to unrecognized tax benefits in Interest expense, net or Other, net (interest income) and recognize penalties related to unrecognized tax benefits in Other, net in the Consolidated Statements of Operations and Comprehensive Income.
Cash and Cash Equivalents	Cash and Cash Equivalents We consider investments purchased with an original maturity of three months or less to be cash equivalents. Restricted Cash and Cash Equivalents Restricted cash and cash equivalents represent funds that are restricted to satisfy designated current liabilities. As of December 31, 2022 and 2021, restricted cash and cash equivalents primarily represented the payment of medical, dental, vision, and long-term disability benefits and project-specific nonrecourse financing structures for debt service and financing of operations of the underlying entities. See Note 17 — Debt and Credit Agreements and Note 23 — Supplemental Financial Information for additional information.
Allowance for Credit Losses on Accounts Receivables	Allowance for Credit Losses on Accounts Receivables The allowance for credit losses reflects our best estimate of losses on the customers' accounts receivable balances based on historical experience, current information, and reasonable and supportable forecasts. The allowance for credit losses for our retail customers is based on accounts receivable aging historical experience coupled with specific identification through a credit monitoring process, which considers current conditions and forward-looking information such as industry trends, macroeconomic factors, changes in the regulatory environment, external credit ratings, publicly available news, payment status, payment history, and the exercise of collateral calls. The allowance for credit losses for our wholesale customers is developed using a credit monitoring process, like that used for retail customers. When a wholesale customer’s risk characteristics are no longer aligned with the pooled population, we use specific identification to develop an allowance for credit losses. Adjustments to the allowance for credit losses are recorded in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income.
Variable Interest Entities	Variable Interest Entities We account for our investments in and arrangements with VIEs based on the following specific requirements: • qualitative assessment of factors determinant in whether we have a controlling financial interest, • ongoing reconsideration of this assessment, and • where we consolidate a VIE (as primary beneficiary), disclosure of (1) the assets of the consolidated VIE, if they can be used to only settle specific obligations of the consolidated VIE, and (2) the liabilities of a consolidated VIE for which creditors do not have recourse to the general credit of the primary beneficiary. See Note 22 — Variable Interest Entities for additional information.
Inventories	Inventories Inventory is recorded at the lower of weighted average cost or net realizable value. Provisions are recorded for excess and obsolete inventory. Natural gas, oil, materials and supplies, and emissions allowances are generally included in inventory when purchased. Natural gas, oil, and emissions allowances are expensed to Purchased power and fuel expense. Materials and supplies generally include items utilized within our generating plants and are expensed to Operating and maintenance or capitalized to Property, plant and equipment, as appropriate, when installed or used.
Debt and Equity Security Investments	Debt and Equity Security Investments Debt and Equity Investments within NDT funds. We have debt and equity securities held in our NDT funds which are measured and recorded at fair value. Realized and unrealized gains and losses, net of tax, on our NDT funds associated with the Regulatory Agreement Units are included in Noncurrent payables related to Regulatory Agreement Units. Realized and unrealized gains and losses, net of tax, on our NDT funds associated with the Non-Regulatory Agreement Units are included in Other, net in the Consolidated Statements of Operations and Comprehensive Income. For equity securities without readily determinable fair values, we have elected to use the measurement alternative to measure these investments, defined as cost adjusted for changes from observable transactions for identical or similar investments of the same issuer, less impairment. Our NDT funds are classified as current or noncurrent assets, depending on the timing of the decommissioning activities and income taxes on trust earnings. See Note 18 — Fair Value of Financial Assets and Liabilities and Note 10 — Asset Retirement Obligations for additional information. Equity Security Investments without Readily Determinable Fair Values. We have certain equity securities without readily determinable fair values. We have elected to use the measurement alternative to measure these investments, defined as cost adjusted for changes from observable transactions for identical or similar investments of the same issuer, less impairment. Changes in measurement are reported in Other, net in the Consolidated Statements of Operations and Comprehensive Income. See Note 18 — Fair Value of Financial Assets for additional information. Equity Security Investments with Readily Determinable Fair Values. We have certain equity securities with readily determinable fair values. Realized and unrealized gains and losses are included in Other, net in the Consolidated Statements of Operations and Comprehensive Income. See Note 18 — Fair Value of Financial Assets and Liabilities for additional information.
Property, Plant and Equipment	Property, Plant and Equipment Property, plant and equipment is recorded at original cost. Original cost includes construction-related direct labor and material costs. When appropriate, original cost also includes capitalized interest. Costs associated with nuclear outages and planned major maintenance activities, are expensed to Operating and maintenance expense or capitalized to Property, plant, and equipment based on the nature of the activities in the period incurred. The cost of repairs and maintenance and minor replacements of property, is charged to Operating and maintenance expense as incurred. Upon retirement, the cost of property is generally charged to accumulated depreciation in accordance with the composite and group methods of depreciation. Upon replacement of an asset, the costs to remove the asset, net of salvage, are capitalized to gross plant when incurred as part of the cost of the newly-installed asset and recorded to depreciation expense over the life of the new asset. Removal costs, net of salvage, incurred for property that will not be replaced is charged to Operating and maintenance expense as incurred. Certain assets follow the unitary method of depreciation and recognize gains and losses in the period of replacement or retirement. These gains and losses are recorded in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. Capitalized Software. Certain costs, such as design, coding, and testing incurred during the application development stage of software projects that are internally developed or purchased for operational use are capitalized in Property, plant and equipment in the Consolidated Balance Sheets. Similar costs incurred for cloud-based solutions treated as service arrangements are capitalized in Other current assets and Deferred debits and other assets in the Consolidated Balance Sheets. Such capitalized amounts are amortized ratably over the expected lives of the projects when they become operational, generally not to exceed five years. Certain other capitalized software costs are being amortized over longer lives based on the expected life. Capitalized Interest. During construction, we capitalize the costs of debt funds. Most projects will use a debt rate calculated using the general corporate debt pool. In some cases, projects are specifically financed and use a project specific debt rate, which is excluded from the general corporate debt pool. Capitalization of debt funds is recorded as a charge to construction work in progress and as a non-cash credit to interest expense. See Note 8 — Property, Plant, and Equipment, Note 9 — Jointly Owned Electric Utility Plant and Note 23 — Supplemental Financial Information for additional information.
Nuclear Fuel	Nuclear Fuel The cost of nuclear fuel is capitalized in Property, plant and equipment and charged to Purchased power and fuel using the unit-of-production method. Any potential future SNF disposal fees will also be expensed through Purchased power and fuel expense. Additionally, certain on-site SNF storage costs are being reimbursed by the DOE since a DOE (or government-owned) long-term storage facility has not been completed. See Note 19 — Commitments and Contingencies for additional information regarding the cost of SNF storage and disposal.
Depreciation and Amortization	Depreciation and Amortization Except for the amortization of nuclear fuel, depreciation, inclusive of ARC, is generally recorded over the estimated service lives of property, plant and equipment on a straight-line basis using the group, composite or unitary methods of depreciation. The group approach is typically for groups of similar assets that have approximately the same useful lives and the composite approach is used for dissimilar assets that have different lives. Under both methods, a reporting entity depreciates the assets over the average life of the assets in the group. The estimated service lives are based on a combination of depreciation studies, historical retirements, site licenses and management estimates of operating costs and expected future energy market conditions. See Note 7 — Early Plant Retirements for additional information on the impacts of early plant retirements, Note 8 — Property, Plant, and Equipment for additional information regarding depreciation, and Note 23 — Supplemental Financial Information for additional information regarding nuclear fuel.
Asset Retirement Obligations	Asset Retirement Obligations We estimate and recognize a liability for our legal obligation to perform asset retirement activities even though the timing and/or methods of settlement may be conditional on future events. We generally update our nuclear decommissioning ARO annually, unless circumstances warrant more frequent updates, based on our annual evaluation of cost escalation factors and probabilities assigned to the multiple outcome scenarios within our probability-weighted discounted cash flow models. Our multiple outcome scenarios are generally based on decommissioning cost studies which are updated, on a rotational basis, for each of our nuclear units at least every five years, unless circumstances warrant more frequent updates. AROs are accreted throughout each year to reflect the time value of money for these present value obligations through a charge to Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income for Non-Regulatory Agreement Units and through a decrease in noncurrent payables related to Regulatory Agreement Units. See Note 10 — Asset Retirement Obligations for additional information.
Accounting Implications of the Regulatory Agreement Units with ComEd and PECO	Accounting Implications of the Regulatory Agreement Units with ComEd and PECO Based on the regulatory agreements with the ICC and PAPUC that dictate our obligations related to the shortfall or excess of NDT funds necessary for decommissioning the former ComEd units on a unit-by-unit basis and the former PECO units in total, decommissioning-related activities net of applicable taxes, including realized and unrealized gains and losses on the NDT funds, depreciation of the ARC, and accretion of the decommissioning obligation are generally offset in the Consolidated Statements of Operations and Comprehensive Income and are recorded as noncurrent payables in the Consolidated Balance Sheets (within Payables related to Regulatory Agreement Units). See Note 10 — Asset Retirement Obligations for additional information.
Asset Impairments	Asset Impairments Long-Lived Assets. We regularly monitor and evaluate the carrying value of long-lived assets or asset groups for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the asset, or plans to dispose of a long-lived asset significantly before the end of its useful life. We determine if long-lived assets or asset groups are potentially impaired by comparing the undiscounted expected future cash flows to the carrying value when indicators of impairment exist. When the undiscounted cash flow analysis indicates a long-lived asset or asset group may not be recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. Generally, pre-tax impairment losses are recorded in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. See Note 12 — Asset Impairments for additional information. Equity Method Investments. We regularly monitor and evaluate equity method investments to determine whether they are impaired. An impairment is recorded when the investment has experienced a decline in value that is other-than-temporary in nature. Additionally, if the entity in which we hold an investment recognizes an impairment loss, we would record their proportionate share of that impairment loss and evaluate the investment for an other-than-temporary decline in value. These impairment losses are recorded in Equity in (losses) earnings of unconsolidated affiliates in the Consolidated Statements of Operations and Comprehensive Income. Equity Security Investments. Equity investments with readily determinable fair values are measured and recorded at fair value with any changes in fair value recorded in Other, net in the Consolidated Statements of Operations and Comprehensive Income. Investments in equity securities without readily determinable fair values are qualitatively assessed for impairment each reporting period. If it is determined that the equity security is impaired, an impairment loss will be recognized in Other, net in the Consolidated Statements of Operations and Comprehensive Income to the amount by which the security’s carrying amount exceeds its fair value.
Derivative Financial Instruments	Derivative Financial Instruments All derivatives are recognized on the balance sheet at their fair value unless they qualify for certain exceptions, including NPNS. For derivatives intended to serve as economic hedges, changes in fair value are recognized in earnings each period. Amounts classified in earnings are included in Operating revenues, Purchased power and fuel, or Interest expense in the Consolidated Statements of Operations and Comprehensive Income based on the activity the transaction is economically hedging. While most of the derivatives serve as economic hedges, there are also derivatives entered into for proprietary trading purposes, subject to our RMP, and changes in the fair value of those derivatives are recorded in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income. Cash inflows and outflows related to derivative instruments are included as a component of operating, investing, or financing cash flows in the Consolidated Statements of Cash Flows, depending on the nature of each transaction. As part of the energy marketing business, we enter contracts to buy and sell energy to meet the requirements of our customers. These contracts include short-term and long-term commitments to purchase and sell energy and energy-related products in the energy markets with the intent and ability to deliver or take delivery of the underlying physical commodity. NPNS are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period and will not be financially settled. Revenues and expenses on derivative contracts that qualify, and are designated, as NPNS are recognized when the underlying physical transaction is completed. While these contracts are considered derivative financial instruments, they are not required to be recorded at fair value. See Note 16 — Derivative Financial Instruments for additional information.
Retirement Benefits	Retirement Benefits Prior to separation, Exelon sponsored defined benefit pension plans and OPEB plans as described in Note 15 — Retirement Benefits . The plan obligations and costs of providing benefits under these plans were measured as of December 31, 2021. We accounted for our participation in Exelon’s pension and OPEB plans by applying multi-employer accounting. Exelon allocated costs related to its pension and OPEB plans to its subsidiaries based on both active and retired employee participation in each plan. We included the service cost and non- service cost components in Operating and maintenance expense and Property, plant, and equipment, net in the consolidated financial statements. Effective upon separation, we sponsor defined benefit pension and OPEB plans as described in Note 15 — Retirement Benefits. The plan obligations and costs of providing benefits under these plans were measured upon separation as of February 1, 2022 and remeasured as of December 31, 2022. The measurement involved various factors, assumptions, and accounting elections. The impact of assumption changes or experience different from that assumed on pension and OPEB obligations is recognized over time rather than immediately recognized in the Consolidated Statements of Operations and Comprehensive Income. Gains or losses more than the greater of ten percent of the PBO or the MRV of plan assets are amortized over the expected average remaining service period of plan participants. Gains or losses more than the greater of ten percent of the APBO or the MRV of plan assets are amortized over the average future remaining lifetime of the current inactive population for the OPEB plans. We report the pension and OPEB service cost and non-service cost (credit) components of net periodic benefit costs (credits) for all plans separately in our Consolidated Statements of Operations and Comprehensive Income. Effective February 1, 2022, the service cost component continues to be included in Operating and maintenance expense and Property, plant, and equipment, net (where criteria for capitalization of direct labor has been met) while the non-service cost (credit) components are included in Other, net, in accordance with single employer plan accounting.

Mergers, Acquisitions, and Di_2

Mergers, Acquisitions, and Dispositions (Tables)	12 Months Ended
Mergers, Acquisitions, and Dispositions (Tables)	Dec. 31, 2022
Mergers, Acquisitions, and Dispositions [Abstract]
Schedule of Changes in Ownership Interest	The following table summarizes the effects of the changes in our ownership interest in CENG in Member's Equity: For the Year Ended December 31, 2021 Net loss attributable to membership interest $ (205) Pre-tax increase in membership interest for purchase of EDF's 49.99% equity interest (a) 1,080 Decrease in membership interest due to deferred tax liabilities resulting from purchase of EDF's equity interest (a) (288) Change from net loss attributable to membership interest and transfers from noncontrolling interest $ 587 __________ (a) Represents non-cash activity in the consolidated financial statements.

Revenue from Contracts with C_2

Revenue from Contracts with Customers (Tables)	12 Months Ended
Revenue from Contracts with Customers (Tables)	Dec. 31, 2022
Revenue from Contract with Customer [Abstract]
Contract with Customer, Contract Asset, Contract Liability, and Receivable	The following table provides a rollforward of the contract assets reflected in the Consolidated Balance Sheets: Contract Assets Balance as of December 31, 2020 $ 144 Amounts reclassified to receivables (59) Revenues recognized 52 Amounts previously held-for-sale 12 Balance as of December 31, 2021 149 Amounts reclassified to receivables (81) Revenues recognized 62 Balance as of December 31, 2022 $ 130 The following table provides a rollforward of the contract liabilities reflected in the Consolidated Balance Sheets: Contract Liabilities Balance as of December 31, 2019 $ 71 Consideration received or due 282 Revenues recognized (266) Contracts liabilities reclassified as held for sale (3) Balance as of December 31, 2020 84 Consideration received or due 251 Revenues recognized (263) Amounts previously held-for-sale 3 Balance as of December 31, 2021 75 Consideration received or due 339 Revenues recognized (367) Balance as of December 31, 2022 $ 47
Contract with Customer, Prior Year Contract Revenues Recognized in Current Year	The following table reflects revenues recognized in the years ended December 31, 2022, 2021 and 2020, which were included in contract liabilities at December 31, 2021, 2020, and 2019, respectively: 2022 2021 2020 Revenues recognized $ 71 $ 82 $ 64
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction	The following table shows the amounts of future revenues expected to be recorded in each year for performance obligations that are unsatisfied or partially unsatisfied as of December 31, 2022. This disclosure only includes contracts for which the total consideration is fixed and determinable at contract inception. The average contract term varies by customer type and commodity but ranges from one month to several years. This disclosure excludes our power and gas sales contracts as they contain variable volumes and/or variable pricing. 2023 2024 2025 2026 2027 and thereafter Total Remaining performance obligations $ 221 $ 78 $ 35 $ 15 $ 136 $ 485

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
Segment Information (Tables)	Dec. 31, 2022
Segment Reporting [Abstract]
Revenue from External Customers by Geographic Areas	The following tables disaggregate the revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. The disaggregation of revenues reflects our two primary products of power sales and natural gas sales, with further disaggregation of power sales provided by geographic region. The following tables also show the reconciliation of reportable segment revenues and RNF to our total revenues and RNF for the years ended December 31, 2022, 2021, and 2020. 2022 Revenues from external customers (a) Contracts with customers Other (b) Total Intersegment Revenues Total Revenues Mid-Atlantic $ 5,264 $ (105) $ 5,159 $ 5 $ 5,164 Midwest 5,164 (507) 4,657 (7) 4,650 New York 2,004 (408) 1,596 (1) 1,595 ERCOT 954 602 1,556 (13) 1,543 Other Power Regions 5,035 1,681 6,716 16 6,732 Total Competitive Businesses Electric Revenues $ 18,421 $ 1,263 $ 19,684 $ — $ 19,684 Competitive Businesses Natural Gas Revenues 2,559 2,408 4,967 — 4,967 Competitive Businesses Other Revenues (c) 591 (802) (211) — (211) Total Consolidated Operating Revenues $ 21,571 $ 2,869 $ 24,440 $ — $ 24,440 2021 Revenues from external customers (a) Contracts with customers Other (b) Total Intersegment Revenues Total Revenues Mid-Atlantic $ 4,381 $ 183 $ 4,564 $ 20 $ 4,584 Midwest 4,265 (205) 4,060 — 4,060 New York 1,633 (57) 1,576 (1) 1,575 ERCOT 896 276 1,172 9 1,181 Other Power Regions 3,937 981 4,918 (28) 4,890 Total Competitive Businesses Electric Revenues $ 15,112 $ 1,178 $ 16,290 $ — $ 16,290 Competitive Businesses Natural Gas Revenues 1,777 1,602 3,379 — 3,379 Competitive Businesses Other Revenues (c) 365 (385) (20) — (20) Total Consolidated Operating Revenues $ 17,254 $ 2,395 $ 19,649 $ — $ 19,649 2020 Revenues from external customers (a) Contracts with customers Other (b) Total Intersegment Revenues Total Revenues Mid-Atlantic $ 4,785 $ (168) $ 4,617 $ 28 $ 4,645 Midwest 3,717 312 4,029 (5) 4,024 New York 1,444 (12) 1,432 (1) 1,431 ERCOT 735 198 933 25 958 Other Power Regions 3,586 463 4,049 (47) 4,002 Total Competitive Businesses Electric Revenues $ 14,267 $ 793 $ 15,060 $ — $ 15,060 Competitive Businesses Natural Gas Revenues 1,283 720 2,003 — 2,003 Competitive Businesses Other Revenues (c) 355 185 540 — 540 Total Consolidated Operating Revenues $ 15,905 $ 1,698 $ 17,603 $ — $ 17,603 __________ (a) Includes all wholesale and retail electric sales to third parties and affiliated sales to Exelon's utility subsidiaries prior to the separation on February 1, 2022. See Note 24 — Related Party Transactions for additional information. (b) Includes revenues from derivatives and leases. (c) Represents activities not allocated to a region. See text above for a description of included activities. Includes unrealized mark-to-market losses of $1,188 million and $633 million and gains of $110 million for the years ended December 31, 2022, 2021, and 2020, respectively. 2022 2021 2020 RNF from external (a) Intersegment Total RNF from external (a) Intersegment Total RNF from external (a) Intersegment Total Mid-Atlantic $ 2,129 $ 9 $ 2,138 $ 2,247 $ 17 $ 2,264 $ 2,174 $ 30 $ 2,204 Midwest 2,765 (1) 2,764 2,717 — 2,717 2,902 — 2,902 New York 1,061 6 1,067 1,151 10 1,161 983 14 997 ERCOT 503 (96) 407 (668) (157) (825) 407 19 426 Other Power Regions 952 (31) 921 984 (93) 891 759 (94) 665 Total RNF for Reportable Segments $ 7,410 $ (113) $ 7,297 $ 6,431 $ (223) $ 6,208 $ 7,225 $ (31) $ 7,194 Other (b) (432) 113 (319) 1,055 223 1,278 793 31 824 Total RNF $ 6,978 $ — $ 6,978 $ 7,486 $ — $ 7,486 $ 8,018 $ — $ 8,018 __________ (a) Includes purchases and sales from/to third parties and affiliated sales to Exelon's utility subsidiaries prior to the separation on February 1, 2022. See Note 24 — Related Party Transactions for additional information. (b) Other represents activities not allocated to a region. See text above for a description of included activities. Primarily includes: • Unrealized mark-to-market losses of $1,013 million, and gains of $565 million, and $295 million for the years ended December 31, 2022, 2021, and 2020, respectively; • Accelerated nuclear fuel amortization associated with the announced early plant retirements as discussed in Note 7 - Early Plant Retirements of $148 million, and $60 million for the years ended December 31, 2021, and 2020, respectively; and • The elimination of intersegment RNF.

Accounts Receivable (Tables)

Accounts Receivable (Tables)	12 Months Ended
Accounts Receivable (Tables)	Dec. 31, 2022
Receivables [Abstract]
Allowance for Credit Losses Rollforward	The following table presents the rollforward of Allowance for Credit Losses on Customer Accounts Receivable, which does not include any allowance related to the sales of Customer Accounts Receivable disclosed below. Allowance for Credit Losses on Other Accounts Receivable was not material as of the balance sheet dates. Balance as of December 31, 2020 $ 32 Plus: Current period provision for expected credit losses 30 Less: Write-offs, net of recoveries (a) 7 Balance as of December 31, 2021 55 Plus: Current period provision for expected credit losses 9 Less: Write-offs, net of recoveries (a) 18 Balance as of December 31, 2022 $ 46 __________
Purchases and Sales of Accounts Receivable	The following table summarizes the impact of the sale of certain receivables: As of December 31, 2022 2021 Derecognized receivables transferred at fair value $ 1,615 $ 1,265 Cash proceeds received 1,100 900 DPP 515 365 For the Years Ended December 31, 2022 2021 2020 Loss on sale of receivables (a) $ 69 $ 36 $ 30 _________ (a) Reflected in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. This represents the amount by which the accounts receivable sold into the Facility are discounted, limited to credit losses. For the Years Ended December 31, 2022 2021 2020 Proceeds from new transfers (a) $ 6,108 $ 6,095 $ 2,816 Cash collections received on DPP and reinvested in the Facility (b) 4,764 3,502 3,771 Cash collections reinvested in the Facility 10,872 9,597 6,587 _________ (a) Customer accounts receivable sold into the Facility were $11,274 million and $9,747 million for the years ended December 31, 2022 and 2021, respectively. (b) Does not include the $200 million in net cash proceeds received from the Purchasers in 2022 and $400 million in cash proceeds received from the Purchasers in 2021. For the Years Ended December 31, 2022 2021 2020 Total receivables sold $ 423 $ 147 $ 824 Related party transactions: Receivables sold to Exelon's utility subsidiaries prior to the separation on February 1, 2022 4 23 252

Early Plant Retirements (Tables

Early Plant Retirements (Tables)	12 Months Ended
Early Plant Retirements (Tables)	Dec. 31, 2022
Implications of Potential Early Plant Retirements [Abstract]
Restructuring and Related Costs	The total impact for the years ended December 31, 2021 and 2020 in the Consolidated Statements of Operations and Comprehensive Income resulting from the initial decision and subsequent reversal of the decision to early retire Byron and Dresden is summarized in the table below. Income statement expense (pre-tax) 2021 2020 Depreciation and amortization Accelerated depreciation (a) $ 1,805 $ 895 Accelerated nuclear fuel amortization 148 60 Operating and maintenance One-time charges (94) 255 Other charges (b) 9 34 Contractual offset (c) (451) (364) Total $ 1,417 $ 880 _________ (a) Includes the accelerated depreciation of plant assets including any ARC. (b) For 2020, reflects the net impacts associated with the remeasurement of the ARO. See Note 10 - Asset Retirement Obligations for additional information. (c) Reflects contractual offset for ARO accretion, ARC depreciation, ARO remeasurement, and excludes any changes in earnings in the NDT funds. Decommissioning-related impacts were not offset for the Byron units starting in the second quarter of 2021 due to the inability to recognize a regulatory asset at ComEd. With our September 15, 2021 reversal of the previous decision to retire Byron, we resumed contractual offset for Byron as of that date. Based on the regulatory agreement with the ICC, decommissioning-related activities are offset in the Consolidated Statements of Operations and Comprehensive Income as long as the net cumulative decommissioning-related activity result in a regulatory liability at ComEd. The offset resulted in an equal adjustment to the noncurrent payables to ComEd. See Note 10 - Asset Retirement Obligations for additional information.

Property, Plant, and Equipment

Property, Plant, and Equipment (Tables)	12 Months Ended
Property, Plant, and Equipment (Tables)	Dec. 31, 2022
Property, Plant and Equipment [Abstract]
Property, Plant, and Equipment	The following table presents a summary of property, plant, and equipment by asset category as of December 31, 2022 and 2021: Asset Category December 31, 2022 December 31, 2021 Electric $ 30,804 $ 29,910 Nuclear fuel (a) 5,106 5,166 Construction work in progress 630 399 Other property, plant, and equipment 8 10 Total property, plant, and equipment 36,548 35,485 Less: accumulated depreciation (b) 16,726 15,873 Property, plant, and equipment, net $ 19,822 $ 19,612 __________ (a) Includes nuclear fuel that is in the fabrication and installation phase of $937 million and $859 million as of December 31, 2022 and 2021, respectively. (b) Includes accumulated amortization of nuclear fuel in the reactor core of $2,657 million and $2,765 million as of December 31, 2022 and 2021, respectively. The following table presents the average service life for each asset category in number of years: Asset Category Average Service Life (years) Electric 1-52 Nuclear fuel 1-8 Other property, plant, and equipment 1-10

Jointly Owned Electric Utilit_2

Jointly Owned Electric Utility Plant (Tables)	12 Months Ended
Jointly Owned Electric Utility Plant (Tables)	Dec. 31, 2022
Public Utilities, Property, Plant and Equipment [Abstract]
Schedule of Jointly Owned Utility Plants	Our material undivided ownership interests in jointly owned nuclear plants as of December 31, 2022 and 2021 were as follows: Nuclear Generation Quad Cities Peach Salem Nine Mile Point Unit 2 Operator Constellation Constellation PSEG Nuclear Constellation Ownership interest 75.00 % 50.00 % 42.59 % 82.00 % Our share as of December 31, 2022 Plant in service $ 1,243 $ 1,534 $ 772 $ 1,063 Accumulated depreciation 761 659 328 256 Construction work in progress 7 12 23 26 Our share as of December 31, 2021 Plant in service $ 1,211 $ 1,515 $ 756 $ 1,002 Accumulated depreciation 715 628 299 222 Construction work in progress 11 12 20 41

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
Asset Retirement Obligations (Tables)	Dec. 31, 2022
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation Rollforward	The following table provides a rollforward of the nuclear decommissioning AROs reflected in the Consolidated Balance Sheets from December 31, 2020 to December 31, 2022: Balance as of December 31, 2020 $ 11,922 Net increase due to changes in, and timing of, estimated future cash flows 324 Accretion expense 503 Costs incurred related to decommissioning plants (73) Balance as of December 31, 2021 (a) 12,676 Net decrease due to changes in, and timing of, estimated future cash flows (648) Accretion expense 532 Costs incurred related to decommissioning plants (60) Balance as of December 31, 2022 (a) $ 12,500 __________ (a) Includes $40 million and $72 million as the current portion of the ARO as of December 31, 2022 and 2021, respectively, which is included in Other current liabilities in the Consolidated Balance Sheets. The following table provides a rollforward of the non-nuclear AROs reflected in the Consolidated Balance Sheets from December 31, 2020 to December 31, 2022: Balance as of December 31, 2020 $ 212 Net increase due to changes in, and timing of, estimated future cash flows 5 Accretion expense 11 Asset divestitures (19) Payments (3) AROs previously held for sale 10 Balance as of December 31, 2021 216 Net increase due to changes in, and timing of, estimated future cash flows 18 Accretion expense 11 Asset divestitures (1) Payments (5) Balance as of December 31, 2022 $ 239 .
Related Party Transactions - Noncurrent Receivables from/Payables to Affiliates	The following table presents our noncurrent payables to ComEd and PECO which are recorded as Payables related to Regulatory Agreement Units as of December 31, 2022 and noncurrent Payables to affiliates as of December 31, 2021: December 31, 2022 December 31, 2021 ComEd $ 2,660 $ 2,760 PECO 237 597

Leases (Tables)

Leases (Tables)	12 Months Ended
Leases (Tables)	Dec. 31, 2022
Leases [Abstract]
Components of Lease Cost	The following table outlines other terms and conditions of the lease agreements as of December 31, 2022. We did not have material finance leases in 2022, 2021, or in 2020. In Years Remaining lease terms 1-33 Options to extend the term 2-30 Options to terminate within 1-2 The components of operating lease costs were as follows: For the Years Ended December 31, 2022 2021 2020 Operating lease costs $ 109 $ 161 $ 194 Variable lease costs 169 168 234 __________ (a) Excludes $49 million, $44 million, $44 million of sublease income recorded for each of the years ended December 31, 2022, 2021, and 2020 respectively. The weighted average remaining lease terms, in years, and the weighted average discount rates for operating leases as of December 31, 2022 were as follows: As of December 31, 2022 2021 2020 Weighted average remaining lease term 9.3 10.1 10.5 Weighted average discount rate 5.0 % 5.0 % 4.9 % In Years Remaining lease terms 1-18 Options to extend the term 1-20
Supplemental Balance Sheet Information Related to Lessee Right-of-Use Assets and Lease Liabilities	The following table provides additional information regarding the presentation of operating lease ROU assets and lease liabilities in the Consolidated Balance Sheets: As of December 31, 2022 2021 Operating lease ROU assets (a) Other deferred debits and other assets $ 545 $ 604 Operating lease liabilities (a) Other current liabilities 67 72 Other deferred credits and other liabilities 643 705 Total operating lease liabilities $ 710 $ 777 __________ (a) The operating ROU assets and lease liabilities include $248 million and $377 million, respectively, related to contracted generation as of December 31, 2022, and $293 million and $429 million, respectively, as of December 31, 2021.
Lessee, Operating Lease, Liability, Maturity	The following table reconciles the undiscounted cash flows for our operating leases to the operating lease liabilities recorded on our consolidated balance sheet as of December 31, 2022: Year Amount 2023 $ 101 2024 99 2025 102 2026 102 2027 100 Thereafter 421 Total lease payments 925 Less: Imputed interest 215 Operating lease liabilities $ 710
Lessee, Operating Lease, Supplemental Cash Flow Information	Supplemental cash flow information related to operating leases was as follows: For the Years Ended December 31, 2022 2021 2020 Cash paid for amounts included in the measurement of operating lease liabilities $ 114 $ 162 $ 204 ROU assets obtained in exchange for operating lease obligations 14 2 3
Components of Operating Lease Income	The components of lease income were as follows: For the Years Ended December 31, 2022 2021 2020 Operating lease income $ 51 $ 47 $ 47 Variable lease income 258 261 282
Lessor, Operating Lease, Payment to be Received, Fiscal Year Maturity	The following table presents maturity analysis of the lease payments we expect to receive as of December 31, 2022: Year Amount 2023 $ 48 2024 48 2025 48 2026 49 2027 49 Thereafter 133 Total $ 375

Intangible Assets (Tables)

Intangible Assets (Tables)	12 Months Ended
Intangible Assets (Tables)	Dec. 31, 2022
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Finite-Lived Intangible Assets	Our intangible assets and liabilities, included in Other current assets, Other deferred debits and other assets, Other current liabilities, Other deferred credits and other liabilities in the Consolidated Balance Sheets, consisted of the following as of December 31, 2022 and 2021. The intangible assets and liabilities shown below are generally amortized on a straight line basis, except for unamortized energy contracts which are amortized in relation to the expected realization of the underlying cash flows: December 31, 2022 December 31, 2021 Gross Accumulated Amortization Net Gross Accumulated Amortization Net Unamortized Energy Contracts $ 1,960 $ (1,708) $ 252 $ 1,963 $ (1,673) $ 290 Customer Relationships 356 (265) 91 330 (243) 87 Trade Name 222 (222) — 222 (218) 4 Total $ 2,538 $ (2,195) $ 343 $ 2,515 $ (2,134) $ 381
Schedule Of Finite-Lived Intangible Assets Amortization Expense	The following table summarizes the amortization expense related to intangible assets and liabilities for each of the years ended December 31, 2022, 2021, and 2020: For the Years Ended December 31, Amortization Expense (a) 2022 $ 61 2021 80 2020 81 __________ (a) See Note 23 — Supplemental Financial Information for additional information related to the amortization of unamortized energy contracts.
Schedule of Finite-Lived Intangible Assets, Future Amortization Expense [Table Text Block]	The following table summarizes the estimated future amortization expense related to intangible assets and liabilities as of December 31, 2022: For the Years Ending December 31, Estimated Future Amortization Expense 2023 $ 59 2024 56 2025 47 2026 40 2027 27
Schedule of Alternative or Renewable Energy Credits [Table Text Block]	The following table presents current RECs as of December 31, 2022 and 2021: December 31, 2022 December 31, 2021 Current REC's $ 617 $ 520

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
Income Taxes (Tables)	Dec. 31, 2022
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense (Benefit)	Income taxes are comprised of the following components: For the Years Ended December 31, 2022 (a) 2021 (a) 2020 (a) Federal Current $ 219 $ 394 $ 130 Deferred (655) (153) 150 ITC amortization (15) (15) (25) State Current 34 36 40 Deferred 29 (37) (46) Total $ (388) $ 225 $ 249 _________ (a) Negative amounts represent income tax benefit. Positive amounts represent income tax expense.
Effective Income Tax Rate Reconciliation	The effective income tax rate varies from the U.S. federal statutory rate principally due to the following: For the Years Ended December 31, 2022 (a) 2021 2020 U.S. federal statutory rate 21.0 % 21.0 % 21.0 % (Decrease) increase due to: State income taxes, net of federal income tax benefit (c) (9.2) — 0.5 Qualified NDT fund income and losses 46.3 165.1 23.5 Amortization of investment tax credit, including deferred taxes on basis differences 2.2 (9.0) (2.6) Production tax credits and other credits 7.7 (28.7) (5.4) Noncontrolling interests (0.3) (3.0) 3.2 Tax Settlements — — (10.3) Other (d) 3.9 2.6 (0.1) Effective income tax rate (b) 71.6 % 148.0 % 29.8 % _________ (a) Positive percentages represent income tax benefit. Negative percentages represent income tax expense. (b) The change in effective tax rate in 2022 is primarily due to the impacts of higher unrealized NDT losses on Income before income taxes and one-time income tax adjustments. (c) Includes $30 million related to state rate changes and certain state tax positions. (d) Primarily related to a $32 million prior period income tax adjustment recorded in 2022.
Tax Effects of Temporary Differences	The tax effects of temporary differences and carryforwards, which give rise to significant portions of the deferred tax (liabilities) assets, as of December 31, 2022 and 2021 are presented below: December 31, 2022 December 31, 2021 Plant basis differences $ (3,005) $ (2,812) Accrual based contracts (35) (38) Derivatives and other financial instruments 43 (172) Deferred pension and postretirement obligation 287 (274) Nuclear decommissioning activities (371) (912) Deferred debt refinancing costs — 15 Tax loss carryforward, net of valuation allowances 67 53 Tax credit carryforward 179 778 Investment in partnerships (205) (252) Other, net 407 312 Deferred income tax liabilities (net) $ (2,633) $ (3,302) Unamortized ITCs (354) (369) Total deferred income tax liabilities (net) and $ (2,987) $ (3,671)
Summary of Loss Carryforwards	The following table provides our carryforwards, of which the state related items are presented on a post-apportioned basis, and any corresponding valuation allowances as of December 31, 2022: Federal December 31, 2022 Federal general business credits carryforwards and other carryforwards $ 178 State State net operating losses and other carryforwards 939 Deferred taxes on state tax attributes (net) 78 Valuation allowance on state tax attributes 11 Year in which net operating loss or credit carryforwards will begin to expire 2035
Schedule of Unrecognized Tax Benefits Roll Forward	The following table presents changes in unrecognized tax benefits: Unrecognized tax benefits Balance as of December 31, 2019 $ 441 Increases based on tax positions related to 2020 1 Increases based on tax positions prior to 2020 23 Decreases based on tax positions prior to 2020 (a) (346) Decrease from settlements with taxing authorities (a) (69) Balance as of December 31, 2020 50 Change to positions that only affect timing (1) Increases based on tax positions related to 2021 1 Increases based on tax positions prior to 2021 1 Decreases based on tax positions prior to 2021 (2) Balance as of December 31, 2021 49 Change to positions that only affect timing (5) Increases based on tax positions related to 2022 29 Increases based on tax positions prior to 2022 (b) 6 Decreases based on tax positions prior to 2022 (b) (55) Balance as of December 31, 2022 $ 24 __________ (a) Our unrecognized federal and state tax benefits decreased in the first quarter of 2020 by approximately $411 million due to the settlement of a federal refund claim with IRS Appeals. The recognition of these tax benefits resulted in an increase in net income of $73 million in the first quarter of 2020, reflecting a decrease to income tax expense of $67 million. (b) Tax positions prior to 2022 remained with Exelon and are not reflected in this table as of December 31, 2022. See discussion below under the Tax Matters Agreement for responsibility of taxes for this period.
Summary of Positions for which Significant Change in Unrecognized Tax Benefits is Reasonably Possible	The following table presents the unrecognized tax benefits that, if recognized, would decrease the effe ctive tax rate: December 31, 2022 $ 29 December 31, 2021 39 December 31, 2020 39
Summary of Income Tax Examinations	Description of tax years open to assessment by major jurisdiction Major Jurisdiction Open Years (a) Federal consolidated income tax returns 2010-2021 Illinois unitary corporate income tax returns 2012-2021 New Jersey separate corporate income tax returns 2017-2018 New Jersey combined corporate income tax returns 2019-2021 New York combined corporate income tax returns 2015-2021 Pennsylvania separate corporate income tax returns 2019-2021 __________ (a) Tax years open to assessment include years when we were consolidated by Exelon. See discussion below under the Tax Matters Agreement for responsibility of taxes of these open years.
Allocation of Federal Tax Benefit Under Tax Sharing Agreement	The following table presents the allocation of tax benefits from Exelon to us under the Tax Sharing Agreement: December 31, 2021 64 December 31, 2020 64

Retirement Benefits (Tables)

Retirement Benefits (Tables)	12 Months Ended
Retirement Benefits (Tables)	Dec. 31, 2022
Retirement Benefits [Abstract]
Defined Benefit Plan, Plan with Projected Benefit Obligation in Excess of Plan Assets	The following tables provide a rollforward of the changes in the benefit obligations and plan assets for the year ended December 31, 2022 for all plans combined: Pension Benefits OPEB Change in benefit obligation: Benefit obligation as of the beginning of the year $ — $ 847 Separation-related adjustment 9,220 933 Benefit obligation as of February 1, 2022 9,220 1,780 Service cost 115 23 Interest cost 269 52 Plan participants' contributions — 20 Actuarial gain, net (1,756) (401) Settlements (15) — Gross benefits paid (558) (114) Benefit obligation as of the end of year $ 7,275 $ 1,360 Pension Benefits OPEB Change in plan assets: Prepaid pension asset as of the beginning of year $ 1,683 $ — Separation-related adjustment 6,584 904 Fair value of net plan assets as of February 1, 2022 8,267 904 Actual return on plan assets (1,245) (99) Employer contributions 211 — Plan participants' contributions — 15 Gross benefits paid (558) (86) Settlements (15) — Fair value of net plan assets as of the end of year $ 6,660 $ 734
Schedule of Defined Benefit Plans Disclosures	We present our benefit obligations net of plan assets on our Consolidated Balance Sheets within the following line items: Pension Benefits OPEB 2022 2021 2022 2021 Prepaid pension asset $ — $ 1,683 $ — $ — Other current liabilities (10) — (17) — Pension obligations (605) — — — Non-pension postretirement benefit — — (609) (847) (Unfunded) funded status (net benefit obligation less plan assets) $ (615) $ 1,683 $ (626) $ (847) The following table provides the ABO and fair value of plan assets for all pension plans with an ABO in excess of plan assets. Information for pension and OPEB plans with projected PBO and APBO, respectively, in excess of plan assets has been disclosed in the Obligations and Plan Assets table above as all pension and OPEB plans are underfunded. ABO in Excess of Plan Assets December 31, 2022 ABO $ (7,121) Fair value of net plan assets 6,660 We recognize the overfunded or underfunded status of defined benefit pension and OPEB plans as an asset or liability on our balance sheet, with offsetting entries to AOCI. An updated measurement was performed as of December 31, 2022, the impact of which was recognized in AOCI as an actuarial gain. The following tables provide the pre-tax components of AOCI for the year ended December 31, 2022, for all plans combined: Pension Benefits OPEB Changes in plan assets and benefit obligations recognized in AOCI: Separation related adjustment $ 2,664 $ 22 Current year actuarial (gain) loss 11 (253) Amortization of actuarial (loss) gain (134) 1 Amortization of prior service (cost) credit (1) 7 Settlements (6) — Total recognized in AOCI $ 2,534 $ (223) The following table provides the components of gross accumulated other comprehensive loss that have not been recognized as components of periodic benefit cost as of December 31, 2022, for all plans combined: Pension Benefits OPEB Prior service cost (credit) $ 10 $ (30) Actuarial loss (gain) 2,524 (193) Total $ 2,534 $ (223) The resulting average remaining service periods for pension and OPEB were as follows as of December 31, 2022: December 31, 2022 Pension plans 12.2 OPEB plans: Benefit Eligibility Age 7.4 Expected Retirement 8.3 The following assumptions were used to determine the benefit obligations for the plans as of December 31, 2022 and at separation. Assumptions used to determine year-end benefit obligations are the assumptions used to estimate the subsequent year’s net periodic benefit costs. Pension Benefits OPEB December 31, 2022 February 1, 2022 December 31, 2022 February 1, 2022 Discount rate (a) 5.52 % 3.23 % 5.50 % 3.21 % Investment crediting rate (b) 5.15 % 3.86 % N/A N/A Rate of compensation increase 3.75 % 3.75 % 3.75 % 3.75 % Mortality table Pri-2012 table with MP-2021 improvement scale (adjusted) Pri-2012 table with MP-2021 improvement scale (adjusted) Pri-2012 table with MP-2021 improvement scale (adjusted) Pri-2012 table with MP-2021 improvement scale (adjusted) Healthcare cost trend on covered charges N/A N/A Initial and ultimate rate of 5.00% Initial and ultimate rate of 5.00% __________ (a) The discount rates above represent the blended rates used to establish the majority of Constellation's pension and OPEB costs. (b) The investment crediting rate above represents a weighted average rate. Estimated future benefit payments to participants over the next ten years in all pension and OPEB plans as of December 31, 2022 are as follows: Pension Benefits OPEB 2023 $ 525 $ 105 2024 531 105 2025 544 105 2026 541 105 2027 547 106 2028 through 2032 2,792 525 Total estimated future benefits payments through 2032 $ 5,480 $ 1,051 Asset Category Pension Benefits OPEB Equity securities 21 % 43 % Fixed income securities 54 % 45 % Alternative investments (a) 25 % 12 % Total 100 % 100 % __________ (a)Alternative investments include private equity, hedge funds, real estate, and private credit.
Calculation of Net Periodic Benefit Costs	The following table presents the components of our net periodic benefit costs (credits), prior to capitalization and co-owner allocations, for the years ended December 31, 2022, 2021 and 2020: Pension Benefits OPEB Total Pension Benefits and OPEB 2022 2021 (a) 2020 (a) 2022 2021 (a) 2020 (a) 2022 2021 (a) 2020 (a) Components of net periodic benefit cost (credit): Service cost $ 126 $ 145 $ 137 $ 25 $ 29 $ 34 $ 151 $ 174 $ 171 Non-service components of pension benefits & OPEB cost (credit): Interest cost 290 235 280 55 45 61 345 280 341 Expected return on assets (565) (493) (474) (55) (58) (62) (620) (551) (536) Amortization of: Prior service cost (credit) 1 1 1 (7) (9) (49) (6) (8) (48) Actuarial loss (gain) 148 199 164 (1) 10 15 147 209 179 Settlement charges 6 20 9 — — (1) 6 20 8 Non-service components of pension benefits & OPEB credit (b) (120) (38) (20) (8) (12) (36) (128) (50) (56) Net periodic benefit cost (credit) (c)(d)(e) $ 6 $ 107 $ 117 $ 17 $ 17 $ (2) $ 23 $ 124 $ 115 __________ (a) Costs recognized for the years ended December 31, 2021 and 2020 were allocated to us by Exelon under the Exelon sponsored pension and OPEB plans prior to separation. (b) Effective February 1, 2022, these non-service costs (credits) are reflected in Other, net in the Consolidated Statements of Operations and Comprehensive Income. (c) The pension benefit and OPEB service costs reflected in the Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2022 totaled $131 million. The pension benefit and OPEB non-service credits reflected in the Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2022 totaled ($116) million. (d) The pension benefit and OPEB service costs reflected in the Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2021 totaled $144 million. The pension benefit and OPEB non-service credits reflected in the Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2021 totaled ($50) million. (e) The pension benefit and OPEB service costs reflected in the Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2020 totaled $140 million. The pension benefit and OPEB non-service credits reflected in the Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2020 totaled ($43) million.
Schedule of Allocation of Plan Assets	The following table presents pension and OPEB plan assets measured and recorded at fair value in our Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2022: December 31. 2022 Level 1 Level 2 Level 3 Not subject to leveling Total Pension plan assets (a) Cash equivalents $ 216 $ — $ — $ — $ 216 Equities (b) 776 — — 368 1,144 Fixed income: U.S. Treasury and agencies 693 128 — — 821 State and municipal debt — 44 — — 44 Corporate debt — 1,736 8 — 1,744 Other (b) — 43 — 470 513 Fixed income subtotal 693 1,951 8 470 3,122 Private equity — — 180 585 765 Hedge funds — — — 429 429 Real estate — — — 547 547 Private credit — — — 480 480 Pension plan assets subtotal 1,685 1,951 188 2,879 6,703 OPEB plan assets (a) Cash equivalents 40 — — — 40 Equities 152 — — 146 298 Fixed income: U.S. Treasury and agencies 10 27 — — 37 State and municipal debt — 4 — — 4 Corporate debt — 27 — — 27 Other 57 3 — 111 171 Fixed income subtotal 67 61 — 111 239 Hedge funds — — — 59 59 Real estate — — — 62 62 Private credit — — — 36 36 OPEB plan assets subtotal 259 61 — 414 734 Total pension and OPEB plan assets (c) $ 1,944 $ 2,012 $ 188 $ 3,293 $ 7,437 __________ (a) See Note 18 — Fair Value of Financial Assets and Liabilities for a description of levels within the fair value hierarchy. (b) Includes derivative instruments of $6 million for the year ended December 31, 2022, which have total notional amounts of $1,879 million as of December 31, 2022. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not represent the amount of the company’s exposure to credit or market loss. (c) Excludes net liabilities of $43 million as of December 31, 2022, which include certain derivative assets that have notional amounts of $41 million as of December 31, 2022. These items are required to reconcile to the fair value of net plan assets and consist primarily of receivables or payables related to pending securities sales and purchases, and interest and dividends receivable.
Pension And Other Postretirement Benefit Contributions	The following tables provide our contributions to the pension and OPEB plans: Pension benefits OPEB 2021 2020 2021 2020 $ 231 $ 236 $ 28 $ 19 The following table provides our planned contributions to our qualified pension plans, non-qualified pension plans, and OPEB plans in 2023 (including our benefit payments related to unfunded plans): Qualified Pension Plans Non-Qualified Pension Plans OPEB Planned contributions $ 21 $ 10 $ 17
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation	The following table presents the reconciliation of Level 3 assets and liabilities measured at fair value for pension and OPEB plans for the year ended December 31, 2022: Pension Assets Fixed Income Equities Private Equity Total Balance as of January 1, 2022 $ — $ — $ — $ — Separation related adjustment 9 — — 9 Actual return on plan assets: Relating to assets still held as of the reporting date (1) — (54) (55) Purchases and settlements: Purchases — — 18 18 Settlements (a) — — (4) (4) Transfers into Level 3 (b) — — 220 220 Balance as of December 31, 2022 $ 8 $ — $ 180 $ 188 __________ (a) Represents cash settlements only. (b) Includes certain private equity investments previously measured at fair value using NAV or its equivalent as a practical expedient at separation transferred to Level 3 primarily due to changes in market liquidity or data.

Derivative Financial Instrume_2

Derivative Financial Instruments (Tables)	12 Months Ended
Derivative Financial Instruments (Tables)	Dec. 31, 2022
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Summary of the Derivative Fair Value	The following tables provide a summary of the derivative fair value balances recorded as of December 31, 2022 and 2021: December 31, 2022 Economic Proprietary Collateral (a)(b) Netting (a) Total Mark-to-market derivative assets (current assets) $ 15,296 $ 10 $ 161 $ (13,123) $ 2,344 Mark-to-market derivative assets (noncurrent assets) 5,100 — 217 (4,074) 1,243 Total mark-to-market derivative assets 20,396 10 378 (17,197) 3,587 Mark-to-market derivative liabilities (current liabilities) (15,049) (6) 374 13,123 (1,558) Mark-to-market derivative liabilities (noncurrent liabilities) (5,203) — 146 4,074 (983) Total mark-to-market derivative liabilities (20,252) (6) 520 17,197 (2,541) Total mark-to-market derivative net assets $ 144 $ 4 $ 898 $ — $ 1,046 December 31, 2021 Mark-to-market derivative assets (current assets) $ 10,915 $ 25 $ 152 $ (8,923) $ 2,169 Mark-to-market derivative assets (noncurrent assets) 3,224 2 15 (2,298) 943 Total mark-to-market derivative assets 14,139 27 167 (11,221) 3,112 Mark-to-market derivative liabilities (current liabilities) (10,143) (19) 262 8,923 (977) Mark-to-market derivative liabilities (noncurrent liabilities) (2,893) (1) 83 2,298 (513) Total mark-to-market derivative liabilities (13,036) (20) 345 11,221 (1,490) Total mark-to-market derivative net assets $ 1,103 $ 7 $ 512 $ — $ 1,622 _________ (a) We net all available amounts allowed in our Consolidated Balance Sheets in accordance with authoritative guidance for derivatives. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases we may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, letters of credit and other forms of non-cash collateral. These amounts are not material as of December 31, 2022 and 2021 and not reflected in the table above. (b) Includes $836 million and $897 million of variation margin held from the exchanges as of December 31, 2022 and 2021, respectively. The following table provides the mark-to-market derivative assets and liabilities as of December 31, 2022: December 31, 2022 Economic Netting (a) Total Mark-to-market derivative assets (current assets) $ 29 $ (5) $ 24 Mark-to-market derivative assets (noncurrent assets) 18 — 18 Total mark-to-market derivative assets 47 (5) 42 Mark-to-market derivative liabilities (current liabilities) (5) 5 — Mark-to-market derivative liabilities (noncurrent liabilities) — — — Total mark-to-market derivative liabilities (5) 5 — Total mark-to-market derivative net assets $ 42 $ — $ 42 _________
Economic Hedges (Commodity Price Risk)	For the years ended December 31, 2022, 2021, and 2020, we recognized the following net pre-tax commodity mark-to-market gains (losses) which are also located in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows. Gains (Losses) Income Statement Location 2022 2021 2020 Operating revenues $ (1,193) $ (635) $ 112 Purchased power and fuel 167 1,206 168 Total $ (1,026) $ 571 $ 280
Disclosure of Credit Derivatives	The following tables provide information on the credit exposure for all derivative instruments, NPNS and payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of December 31, 2022. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties. The amounts in the tables below exclude credit risk exposure from individual retail counterparties, nuclear fuel procurement contracts, and exposure through RTOs, ISOs, NYMEX, ICE, NASDAQ, NGX, and Nodal commodity exchanges. Rating as of December 31, 2022 Total Credit Collateral (a) Net Number of Net Exposure of Investment grade $ 1,304 $ 135 $ 1,169 — $ — Non-investment grade 110 88 22 — — No external ratings Internally rated — investment grade 106 — 106 — — Internally rated — non-investment grade 374 40 334 — — Total $ 1,894 $ 263 $ 1,631 — $ — Net Credit Exposure by Type of Counterparty As of December 31, 2022 Investor-owned utilities, marketers, power producers $ 1,311 Energy cooperatives and municipalities 112 Financial Institutions 9 Other 199 Total $ 1,631 __________ (a) As of December 31, 2022, credit collateral held from counterparties where we had credit exposure included $152 million of cash and $111 million of letters of credit. The credit collateral does not include non-liquid collateral.
Fair Value of Derivatives with Credit- Risk Related Contingent Features	The aggregate fair value of all derivative instruments with credit-risk-related contingent features in a liability position that are not fully collateralized (excluding transactions on the exchanges that are fully collateralized) is detailed in the table below: As of December 31, Credit-Risk-Related Contingent Features 2022 2021 Gross fair value of derivative contracts containing this feature (a) $ (4,736) $ (3,872) Offsetting fair value of in-the-money contracts under master netting arrangements (b) 2,048 2,424 Net fair value of derivative contracts containing this feature (c) $ (2,688) $ (1,448) __________ (a) Amount represents the gross fair value of out-of-the-money derivative contracts containing credit-risk-related contingent features ignoring the effects of master netting agreements. (b) Amount represents the offsetting fair value of in-the-money derivative contracts under legally enforceable master netting agreements with the same counterparty, which reduces the amount of any liability for which we could potentially be required to post collateral. (c) Amount represents the net fair value of out-of-the-money derivative contracts containing credit-risk-related contingent features after considering the mitigating effects of offsetting positions under master netting arrangements and reflects the actual net liability upon which any potential contingent collateral obligations would be based.
Cash Collateral and Letters of Credit on Derivative Contracts	As of December 31, 2022 and 2021, we posted or held the following amounts of cash collateral and letters of credit on derivative contracts with external counterparties, after giving consideration to offsetting derivative and non-derivative positions under master netting agreements. As of December 31, 2022 2021 Cash collateral posted (a) $ 1,636 $ 713 Letters of credit posted (a) 947 755 Cash collateral held (a) 765 182 Letters of credit held (a) 115 124 Additional collateral required in the event of a credit downgrade below investment grade (at BB+/Ba1) (b)(c) 3,337 2,113 _________ (a) The cash collateral and letters of credit amounts are inclusive of NPNS contracts. (b) Certain of our contracts contain provisions that allow a counterparty to request additional collateral when there has been a subjective determination that our credit quality has deteriorated, generally termed “adequate assurance.” Due to the subjective nature of these provisions, we estimate the amount of collateral that we may ultimately be required to post in relation to the maximum exposure with the counterparty.

Debt and Credit Agreements (Tab

Debt and Credit Agreements (Tables)	12 Months Ended
Debt and Credit Agreements (Tables)	Dec. 31, 2022
Debt Disclosure [Abstract]
Schedule of Commercial Paper, Credit Facilities and Borrowing Rates	The following table reflects our commercial paper program supported by the revolving credit agreements as of December 31, 2022 and 2021: Maximum Outstanding Commercial Weighted Average Interest Rate on 2022 (a)(b)(c) 2021 (a)(d) 2022 2021 2022 2021 $ 3,500 $ 5,300 $ 959 $ 702 4.90 % 0.66 % __________ (a) Excludes $1,200 million in bilateral credit facilities as of December 31, 2022 and 2021, and $131 million in credit facilities for project finance as of both December 31, 2022 and 2021, respectively. These credit facilities do not back our commercial paper program. (b) Excludes the liquidity facility, which has a bank commitment of $971 million as of December 31, 2022. This credit facility does not back our commercial paper program. (c) Excludes customer accounts receivable Facility that has total capacity of $1.1 billion as of December 31, 2022. See Note 6 — Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information. (d) Excludes $44 million of credit facility agreements arranged at minority and community banks as of December 31, 2021. These facilities expired on October 7, 2022 and were solely utilized to issue letters of credit. As of December 31, 2022, and 2021 we had the following aggregate bank commitments, credit facility borrowings and available capacity under our respective credit facilities: Available Capacity as of December 31, 2022 Facility Type Aggregate Bank Facility Draws Outstanding Actual To Support Syndicated Revolver $ 3,500 $ — $ 765 $ 2,735 $ 1,776 Bilaterals 1,200 — 867 333 — Liquidity Facility 971 — 732 139 (a) — Project Finance 131 — 111 20 — Total $ 5,802 $ — $ 2,475 $ 3,227 $ 1,776 __________ (a) The maximum amount of the bank commitment is not to exceed $971 million. The aggregate available capacity of the facility is subject to market fluctuations based on the value of U.S Treasury Securities which determines the amount of collateral held in the trust. We may post additional collateral to borrow up to the maximum bank commitment. As of December 31, 2022, without posting additional collateral, the actual availability of facility, prior to outstanding letters of credit was $871 million. Available Capacity as of December 31, 2021 Facility Type Aggregate Bank (b) Facility Draws Outstanding Actual To Support Syndicated Revolver (a) $ 5,300 $ — $ 1,230 $ 4,070 $ 3,368 Bilaterals 1,200 — 1,029 171 — Project Finance 131 — 116 15 — Total $ 6,631 $ — $ 2,375 $ 4,256 $ 3,368 __________ (a) Our syndicated revolving credit facility was replaced by the $3.5 billion 5-year revolving credit agreement entered into on February 1, 2022 in connection with the separation. (b) Excludes $44 million of credit facility agreements arranged at minority and community banks. These facilities expired on October 7, 2022 and were solely utilized to issue letters of credit. As of December 31, 2021, letters of credit issued under these facilities totaled $5 million.
Schedule of Bilateral Credit Agreements	Bilateral Credit Agreements The following table reflects the bilateral credit agreements at December 31, 2022: Date Initiated Latest Amendment Date Maturity Date(a) Amount January 5, 2016 (b) April 2, 2021 April 5, 2023 $ 150 October 25, 2019 (b) N/A N/A 200 November 20, 2019 (b) N/A N/A 300 November 21, 2019 (b) N/A N/A 100 November 21, 2019 (b) November 15, 2022 November 21, 2024 100 May 15, 2020 (b)(d) February 9, 2022 N/A 200 August 12, 2022 (b) N/A N/A 50 August 24, 2022 (b)(c) N/A August 23, 2024 100 __________ (a) Credit facilities that do not contain a maturity date are specific to the agreements set within each contract. In some instances, credit facilities are automatically renewed based on the contingency standards set within the specific agreement. (b) Bilateral credit agreements solely support the issuance of letters of credit and do not back our commercial paper program. (c) On January 20, 2023, the bilateral credit agreement decreased to $10 million. (d) On January 31, 2023, the bilateral credit agreement increased to $250 million.
Schedule of Long-term Debt Instruments	Long-Term Debt The following table presents the outstanding long-term debt as of December 31, 2022 and 2021: Maturity December 31, Rates 2022 2021 Long-term debt Senior unsecured notes 3.25 % - 6.25 % 2025 - 2042 $ 2,938 $ 4,219 Notes payable and other 2.10 % - 6.96 % 2023 - 2028 68 103 Nonrecourse debt: Fixed rates 2.29 % - 6.00 % 2031 - 2037 839 909 Variable rates 2.99 % - 7.24 % 2026 - 2027 805 870 Total long-term debt 4,650 6,101 Unamortized debt discount and premium, net (5) (7) Unamortized debt issuance costs (36) (42) Fair value adjustment — 62 Long-term debt due within one year (143) (1,220) Long-term debt $ 4,466 $ 4,894
Schedule of Maturities of Long-term Debt	Long-term debt maturities in the periods 2023 through 2027 and thereafter are as follows: 2023 $ 143 2024 110 2025 986 2026 121 2027 735 Thereafter 2,555 Total $ 4,650

Fair Value of Financial Asset_2

Fair Value of Financial Assets and Liabilities (Tables)	12 Months Ended
Fair Value of Financial Assets and Liabilities (Tables)	Dec. 31, 2022
Fair Value Disclosures [Abstract]
Fair Value of Financial Liabilities Recorded at Amortized Cost	The following tables present the carrying amounts and fair values of the short-term liabilities, long-term debt, and the SNF obligation as of December 31, 2022 and 2021. We have no financial liabilities classified as Level 1. The carrying amounts of the short-term liabilities as presented in the Consolidated Balance Sheets are representative of their fair value (Level 2) because of the short-term nature of these instruments. December 31, 2022 December 31, 2021 Carrying Amount Fair Value Carrying Amount Fair Value Level 2 Level 3 Total Level 2 Level 3 Total Long-Term Debt, including amounts due within one year $ 4,609 $ 3,688 $ 859 $ 4,547 $ 6,114 $ 5,749 $ 1,093 $ 6,842 SNF Obligation 1,230 1,021 — 1,021 1,210 1,060 — 1,060
Assets and Liabilities Measured and Recorded at Fair Value on Recurring Basis	The following tables present assets and liabilities measured and recorded at fair value in the Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2022 and 2021: As of December 31, 2022 As of December 31, 2021 Level 1 Level 2 Level 3 Not subject to leveling Total Level 1 Level 2 Level 3 Not subject to leveling Total Assets Cash equivalents (a) $ 41 $ — $ — $ — $ 41 $ 113 $ — $ — $ — $ 113 NDT fund investments Cash equivalents (b) 349 88 — — 437 465 116 — — 581 Equities 3,462 1,498 — 1,421 6,381 4,564 1,805 — 1,645 8,014 Fixed income Corporate debt (c) — 885 264 — 1,149 — 1,145 286 — 1,431 U.S. Treasury and agencies 1,996 46 — — 2,042 2,193 30 — — 2,223 Foreign governments — 39 — — 39 — 60 — — 60 State and municipal debt — 53 — — 53 — 26 — — 26 Other 21 21 — 1,649 1,691 29 23 — 1449 1,501 Fixed income subtotal 2,017 1,044 264 1,649 4,974 2,222 1,284 286 1,449 5,241 Private credit — — 159 643 802 — — 178 624 802 Private equity — — — 687 687 — — — 673 673 Real estate — — — 1,014 1,014 — — — 864 864 NDT fund investments subtotal (d)(e) 5,828 2,630 423 5,414 14,295 7,251 3,205 464 5,255 16,175 Rabbi trust investments Cash equivalents 1 — — — 1 3 — — — 3 Mutual funds 39 — — — 39 36 — — — 36 Life insurance contracts — 27 1 — 28 — 33 — — 33 Rabbi trust investments subtotal 40 27 1 — 68 39 33 — — 72 Investments in equities 6 — — — 6 43 — — — 43 Commodity derivative assets Economic hedges 3,505 11,353 5,585 — 20,443 3,017 7,223 3,899 — 14,139 Proprietary trading — 4 6 — 10 — 19 8 — 27 Effect of netting and allocation of (f)(g) (2,951) (10,348) (3,525) — (16,824) (2,108) (6,177) (2769) — (11,054) Commodity derivative assets subtotal 554 1,009 2,066 — 3,629 909 1,065 1,138 — 3,112 DPP consideration — 515 — — 515 — 365 — — 365 Total assets 6,469 4,181 2,490 5,414 18,554 8,355 4,668 1,602 5,255 19,880 Liabilities Commodity derivative liabilities Economic hedges (3,171) (11,498) (5,588) — (20,257) (2,201) (6,870) (3,965) — (13,036) Proprietary trading — (4) (2) — (6) — (18) (2) — (20) Effect of netting and allocation of collateral (f)(g) 3,279 10,700 3,743 — 17,722 2,189 6,642 2,735 — 11,566 Commodity derivative liabilities subtotal 108 (802) (1,847) — (2,541) (12) (246) (1,232) — (1,490) Deferred compensation obligation — (57) — — (57) — (43) — — (43) Total liabilities 108 (859) (1,847) — (2,598) (12) (289) (1,232) — (1,533) Total net assets $ 6,577 $ 3,322 $ 643 $ 5,414 $ 15,956 $ 8,343 $ 4,379 $ 370 $ 5,255 $ 18,347 __________ (a) CEG Parent has $49 million of Level 1 cash equivalents as of December 31, 2022. We exclude cash of $390 million and $417 million as of December 31, 2022 and December 31, 2021, respectively, and restricted cash of $70 million and $46 million as of December 31, 2022 and December 31, 2021, respectively. CEG Parent has excluded an additional $19 million of cash as of December 31, 2022. (b) Includes $99 million and $116 million of cash received from outstanding repurchase agreements as of December 31, 2022 and 2021, respectively, and is offset by an obligation to repay upon settlement of the agreement as discussed in (e) below. (c) Includes investments in equities sold short of ($45) million and ($55) million as of December 31, 2022 and 2021, respectively, held in an investment vehicle primarily to hedge the equity option component of convertible debt. (d) Includes net derivative assets of $1 million and net derivative liabilities of $1 million, which have total notional amounts of $494 million and $687 million as of December 31, 2022 and 2021, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the periods ended and do not represent the amount of our exposure to credit or market loss. (e) Excludes net liabilities of $168 million and $111 million as of December 31, 2022 and 2021, respectively, which include certain derivative assets that have notional amounts of $59 million and $182 million as of December 31, 2022 and 2021, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, repurchase agreement obligations, and payables related to pending securities purchases. The repurchase agreements are generally short-term in nature with durations generally of 30 days or less. (f) Net collateral posted to counterparties totaled $328 million, $352 million, and $218 million allocated to Level 1, Level 2, and Level 3 mark-to-market derivatives, respectively, as of December 31, 2022. Net collateral posted to/(received from) counterparties totaled $81 million, $465 million, and ($34) million allocated to Level 1, Level 2, and Level 3 mark-to-market derivatives, respectively, as of December 31, 2021. (g) Includes $836 million and $897 million of variation margin held from the exchanges as of December 31, 2022 and 2021, respectively.
Fair Value Reconciliation of Level 3 Assets and Liabilities Measured at Fair Value on a Recurring Basis	The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2022 and 2021: For the Year Ended December 31, 2022 NDT Fund Investments Mark-to-Market Life Insurance Contracts Total Balance as of January 1, 2022 $ 464 $ (94) $ — $ 370 Total realized / unrealized losses Included in net income (2) (753) (a) (2) (757) Included in noncurrent payables to affiliates (10) — — (10) Change in collateral — 253 — 253 Impacts of separation — — 3 3 Purchases, sales, issuances and settlements Purchases 5 594 — 599 Sales — (50) — (50) Settlements (35) (102) — (137) Transfers into Level 3 2 381 (b) — 383 Transfers out of Level 3 (1) (10) (b) — (11) Balance as of December 31, 2022 $ 423 $ 219 $ 1 $ 643 The amount of total losses included in income attributed to the change in unrealized losses related to assets and liabilities as of December 31, 2022 $ (2) $ (1,265) $ (2) $ (1,269) For the Year Ended December 31, 2021 NDT Fund Investments Mark-to-Market Total Balance as of January 1, 2021 $ 497 $ 430 $ 927 Total realized / unrealized gains (losses) Included in net income 5 (812) (a) (807) Included in noncurrent payables to affiliates 19 — 19 Change in collateral — (196) (196) Purchases, sales, issuances and settlements Purchases 4 162 166 Sales — (10) (10) Settlements (61) — (61) Transfers into Level 3 — 19 (b) 19 Transfers out of Level 3 — 313 (b) 313 Balance as of December 31, 2021 $ 464 $ (94) $ 370 The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of December 31, 2021 $ 5 $ (1,222) $ (1,217) __________ (a) Includes an addition of $410 million for realized losses due to the settlement of derivative contracts for both of the years ended December 31, 2022 and 2021, respectively. (b) Transfers into and out of Level 3 generally occur when the contract tenor becomes less and more observable, respectively, primarily due to changes in market liquidity or assumptions for certain commodity contracts.
Total Realized and Unrealized Gains (Losses) Included in Income for Level 3 Assets and Liabilities Measured at Fair Value on a Recurring Basis	The following table presents the income statement classification of the total realized and unrealized (losses) gains included in income for Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2022, 2021, and 2020: Operating Purchased Other, net 2022 2021 2020 2022 2021 2020 2022 2021 2020 Total (losses) gains included in net income $ (860) $ (1,343) $ (404) $ 5 $ 531 $ (10) $ (4) $ 5 $ 2 Total unrealized (losses) gains (1,330) (1,577) (31) 65 355 37 (2) 5 2
Fair Value Reconciliation of Level 3 Assets and Liabilities Measured at Fair Value on a Recurring Basis, Valuation Technique	The following table presents the significant inputs to the forward curve used to value these positions: Type of trade Fair Value as of December 31, 2022 Fair Value as of December 31, 2021 Valuation Unobservable 2022 Range & Arithmetic Average 2021 Range & Arithmetic Average Mark-to-market derivatives—Economic hedges (a)(b) $ (3) $ (66) Discounted Cash Flow Forward power $0.63 - $283 $72 $8.86 - $481 $55 Forward gas $1.67 - $26 $4.57 $1.69 - $17 $3.50 Option Volatility 97% - 119% 111% 24% - 284% 56% __________ (a) The valuation techniques, unobservable inputs, ranges, and arithmetic averages are the same for the asset and liability positions. (b) The fair values do not include cash collateral posted (received) on level three positions of $218 million and ($34) million as of December 31, 2022 and December 31, 2021, respectively.

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
Commitments and Contingencies (Tables)	Dec. 31, 2022
Commitments and Contingencies Disclosure [Abstract]
Other Commitments	Commercial commitments as of December 31, 2022, representing commitments potentially triggered by future events, were as follows: Expiration within Total 2023 2024 2025 2026 2027 2028 and beyond Letters of credit $ 2,475 $ 2,465 $ 10 $ — $ — $ — $ — Surety bonds (a) 978 977 1 — — — — Total commercial commitments $ 3,453 $ 3,442 $ 11 $ — $ — $ — $ — __________
Schedule of Government Settlement Agreements	As of December 31, 2022 and 2021, the amount of SNF storage costs for which reimbursement has been or will be requested from the DOE under the DOE settlement agreements is as follows: December 31, 2022 December 31, 2021 DOE receivable - current (a) $ 125 $ 241 DOE receivable - noncurrent (b) 130 85 Amounts owed to co-owners (c) (12) (35) __________ (a) Recorded in Other accounts receivable. (b) Recorded in Deferred debits and other assets, other. (c) Recorde d in Other accounts receivable. Represents amounts owed to the co-owners of Peach Bottom, Quad Cities, and Nine Mile Point Unit 2 generating facilitie
Spent Nuclear Fuel Obligation	The below table outlines the SNF liability recorded as of December 31, 2022 and 2021: December 31, 2022 December 31, 2021 Former ComEd units (a) $ 1,100 $ 1,083 Fitzpatrick (b) 130 127 Total SNF Obligation $ 1,230 $ 1,210 __________ (a) ComEd previously elected to defer payment of the one-time fee of $277 million for its units, with interest to the date of payment, until just prior to the first delivery of SNF to the DOE. The unfunded liabilities for SNF disposal costs, including the one-time fee, were transferred to us as part of Exelon’s 2001 corporate restructuring. (b) A prior owner of FitzPatrick elected to defer payment of the one-time fee of $34 million, with interest to the date of payment, for the FitzPatrick unit. As part of the FitzPatrick acquisition on March 31, 2017, we assumed a SNF liability for the DOE one-time fee obligation with interest related to FitzPatrick along with an offsetting asset, included in Other deferred debits and other assets, for the contractual right to reimbursement from NYPA, a prior owner of FitzPatrick, for amounts paid for the FitzPatrick DOE one-time fee obligation.

Stock-Based Compensation Plans

Stock-Based Compensation Plans (Tables)	12 Months Ended
Stock-Based Compensation Plans (Tables)	Dec. 31, 2022
Share-Based Payment Arrangement [Abstract]
Share-based Payment Arrangement, Cost by Plan	The following table presents the stock-based compensation expense included in the Consolidated Statements of Operations and Comprehensive Income. The information does not include expenses related to the cash awards as they are not considered stock-based compensation plans under the applicable authoritative guidance: Year Ended December 31, 2022 (a) 2021 (b) 2020 (b) Total stock-based compensation expense included in operating and maintenance expense $ 116 $ 47 $ 27 Income tax benefit (29) (12) (7) Total after-tax stock-based compensation expense $ 87 $ 35 $ 20 __________ (a) Costs recognized for the year ended December 31, 2022 are related to the Constellation LTIP. (b) Costs recognized for the years ended December 31, 2021 and 2020 were allocated to us by Exelon under the Exelon LTIP prior to separation.
Stock Based Compensation Tax Benefit	The following table presents information regarding our realized tax benefit when distributed: December 31, 2022 Restricted stock units $ 2
Share-Based Payment Arrangement, Performance Shares, Activity	The following table summarizes our nonvested performance share awards activity: Shares Weighted Average Grant Date Fair Value (per share) Nonvested at December 31, 2021 — $ — Granted 1,575,542 48.33 Change in performance 728,054 47.30 Forfeited (22,617) 48.55 Undistributed vested awards (a) (1,431,637) 48.35 Nonvested at December 31, 2022 849,342 $ 47.40 __________ (a) Includes 1,272,921 of performance share awards that vested but were not distributed to retirement-eligible employees during 2022. The following table summarizes the weighted average grant date fair value and the total fair value of performance share awards vested: December 31, 2022 (a) Weighted average grant date fair value (per share) $ 48.33 Total fair value of performance shares vested 69 __________ (a) As of December 31, 2022, $28 million of total unrecognized compensation costs related to nonvested performance shares are expected to be recognized over the remaining weighted-average period of 1.7 years . The following table summarizes our nonvested restricted stock unit activity: Shares Weighted Average Grant Date Fair Value (per share) Nonvested at December 31, 2021 — $ — Granted 1,497,651 54.17 Vested (144,903) 49.82 Forfeited (62,238) 59.47 Undistributed vested awards (a) (499,842) 55.16 Nonvested at December 31, 2022 790,668 $ 53.72 __________ (a) Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2022. The following table summarizes the weighted average grant date fair value and the total fair value of restricted stock units vested: December 31, 2022 (a) Weighted average grant date fair value (per share) $ 54.17 Total fair value of performance shares vested 35 __________ (a) As of December 31, 2022, $27 million of total unrecognized compensation costs related to nonvested restricted stock units are expected to be recognized over the remaining weighted-average period of 2.0 years.

Changes in Accumulated Other _2

Changes in Accumulated Other Comprehensive Income (Tables)	12 Months Ended
Changes in Accumulated Other Comprehensive Income (Tables)	Dec. 31, 2022
Equity [Abstract]
Schedule Of Changes In Accumulated Other Comprehensive Income (Loss)	The following tables present changes in AOCI, net of tax, by component: Losses on Cash Flow Hedges Pension and Non-Pension Postretirement Benefit Plan Items (a) Foreign Currency Items Total Balance at December 31, 2019 $ (5) $ — $ (27) $ (32) OCI before reclassifications (2) — 4 2 Net current-period OCI (2) — 4 2 Balance at December 30, 2020 $ (7) $ — $ (23) $ (30) OCI before reclassifications (1) — — (1) Net current-period OCI (1) — — (1) Balance at December 30, 2021 $ (8) $ — $ (23) $ (31) Separation-related adjustments — (2,006) — (2,006) OCI before reclassifications (1) 186 (3) 182 Amounts reclassified from AOCI — 95 — 95 Net current-period OCI (1) (1,725) (3) (1,729) Balance at December 30, 2022 $ (9) $ (1,725) $ (26) $ (1,760) __________ (a) AOCI amounts are included in the computation of net periodic pension and OPEB cost. See Note 15 — Retirement Benefits for additional information. See our Statements of Operations and Comprehensive Income for individual components of AOCI. The following table presents income tax (expense) benefit allocated to each component of our other comprehensive income (loss): Year Ended December 31, 2022 2021 2020 Pension and non-pension postretirement benefit plans: Actuarial loss reclassified to periodic benefit cost $ (33) $ — $ — Pension and non-pension postretirement benefit plans valuation adjustment (a) 619 — — __________ (a) Includes $680 million of income tax benefit related to the separation adjustment for the year ended December 31, 2022.

Variable Interest Entities (Tab

Variable Interest Entities (Tables)	12 Months Ended
Variable Interest Entities (Tables)	Dec. 31, 2022
Variable Interest Entity [Abstract]
Consolidated VIEs - Assets and Liabilities	December 31, 2022 December 31, 2021 Cash and cash equivalents $ 51 $ 35 Restricted cash and cash equivalents 46 48 Accounts receivable Customer 20 24 Other 9 6 Inventories, net Materials and supplies 12 14 Other current assets 549 405 Total current assets 687 532 Property, plant and equipment, net 1,965 2,027 Other noncurrent assets 190 215 Total noncurrent assets 2,155 2,242 Total assets (a) $ 2,842 $ 2,774 Long-term debt due within one year $ 60 $ 70 Accounts payable 17 10 Accrued expenses 23 21 Other current liabilities 2 1 Total current liabilities 102 102 Long-term debt 764 822 Asset retirement obligations 173 151 Other noncurrent liabilities 3 3 Total noncurrent liabilities 940 976 Total liabilities (b) $ 1,042 $ 1,078 _______ (a) Our balances include unrestricted assets f or current unamortized energy contract assets of $23 million and $23 million, disclosed within other current assets in the table above and noncurrent unamortized energy contract assets of $178 million and $202 million, disclosed within other noncurrent assets in the table above as of December 31, 2022 and 2021, respectively. (b) Our balances include liabilities with recourse of $1 million and $1 million as of December 31, 2022 and 2021, respectively.
Schedule of Variable Interest Entities	As of December 31, 2022 and 2021, our consolidated VIEs included the following: Consolidated VIE or VIE groups: Reason entity is a VIE: Reason we are the primary beneficiary: CRP - A collection of wind and solar project entities. We have a 51% equity ownership in CRP. See additional discussion below. Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner. We conduct the operational activities. Bluestem Wind Energy Holdings, LLC - A Tax Equity structure which is consolidated by CRP. Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner. We conduct the operational activities. Antelope Valley - A solar generating facility, which is 100% owned by us. Antelope Valley sells all of its output to PG&E through a PPA. The PPA contract absorbs variability through a performance guarantee. We conduct all activities. NER - A bankruptcy remote, special purpose entity which is 100% owned by us, which purchases certain of our customer accounts receivable arising from the sale of retail electricity. NER’s assets will be available first and foremost to satisfy the claims of the creditors of NER. Refer to Note 6 —Accounts Receivable for additional information on the sale of receivables. Equity capitalization is insufficient to support its operations. We conduct all activities. As of December 31, 2022 and 2021, the unconsolidated VIEs consist of: Unconsolidated VIE groups: Reason entity is a VIE: Reason we are not the primary beneficiary: Equity investments in distributed energy companies. We have a 90% equity ownership in a distributed energy company. We sold this investment in the fourth quarter of 2022 resulting in it no longer being classified as an unconsolidated VIE . Similar structures to a limited partnership and the limited partners do not have kick out rights with respect to the general partner. We do not conduct the operational activities. Energy Purchase and Sale agreements - We have several energy purchase and sale agreements with generating facilities. PPA contracts that absorb variability through fixed pricing. We do not conduct the operational activities.
Schedule of Variable Interest Entities	The following table presents summary information about our significant unconsolidated VIE entities: December 31, 2022 December 31, 2021 Commercial Equity Total Commercial Equity Total Total assets (a) $ 715 $ — $ 715 $ 772 $ 372 $ 1,144 Total liabilities (a) 54 — 54 80 216 296 Our ownership interest in VIE (a) — — — — 139 139 Other ownership interests in VIE (a) 661 — 661 692 17 709 __________ (a) These items represent amounts on the unconsolidated VIE balance sheets, not in the Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs. We do not have any exposure to loss as we do not have a carrying amount in the equity investment VIEs as o f December 31, 2022 and 2021.

Supplemental Financial Inform_2

Supplemental Financial Information (Tables)	12 Months Ended
Supplemental Financial Information (Tables)	Dec. 31, 2022
Supplemental Financial Information [Abstract]
Schedule Of Taxes Excluding Income And Excise Taxes	The following tables provide additional information about material items recorded in the Consolidated Statements of Operations and Comprehensive Income. Taxes other than income taxes For the Years Ended December 31, 2022 2021 2020 Gross receipts (a) $ 130 $ 99 $ 99 Property 274 268 265 Payroll 130 109 113 __________ (a) Represent gross receipts taxes related to our retail operations. The offsetting collection of gross receipts taxes from customers is recorded in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income.
Schedule of Other Nonoperating Income, by Component	Other, net For the Years Ended December 31, 2022 2021 2020 Decommissioning-related activities: Net realized income on NDT funds (a) Regulatory Agreement Units $ 333 $ 817 $ 185 Non-Regulatory Agreement Units 97 449 160 Net unrealized (losses) gains on NDT funds Regulatory Agreement Units (1,354) 351 724 Non-Regulatory Agreement Units (798) 209 391 Regulatory offset to NDT fund-related activities (b) 820 (917) (729) Decommissioning-related activities (902) 909 731 Investment income 58 — — Non-service net periodic benefit credit (c) 110 — — Net realized and unrealized (losses) gains from equity investments (d) (13) (160) 186 Return to provision adjustment (e) (49) — — __________ (a) Realized income includes interest, dividends and realized gains and losses on sales of NDT fund investments. (b) Includes the elimination of decommissioning-related activities and the elimination of income taxes related to all NDT fund activity for the Regulatory Agreement Units except for decommissioning-related impacts that were not offset for the Byron units starting in the second quarter of 2021. With our September 15, 2021 reversal of the previous decision to retire Byron, we resumed contractual offset for Byron as of that date. See Note 10 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning and the contractual offset suspension for the Byron units. (c) Historically, we were allocated our portion of pension and OPEB non-service credits (costs) from Exelon, which was included in Operating and maintenance expense. Effective February 1, 2022, the non-service credit (cost) components will now be included in Other, net, in accordance with single employer plan accounting. See Note 15 — Retirement Benefits for additional information. (d) For 2022, represents Net realized and unrealized (losses) gains from equity investments. For 2021 and 2020, represents Net unrealized (losses) gains from equity investments. (e) This reflects amounts contractually owed to Exelon under the tax matters agreement, which is offset in Income taxes. See Note 14 — Income Taxes for additional information.
Cash Flow Supplemental Disclosures	The following tables provide additional information about material items recorded in the Consolidated Statements of Cash Flows. Depreciation, amortization and accretion For the Years Ended December 31, 2022 2021 2020 Property, plant, and equipment (a) $ 1,065 $ 2,954 $ 2,070 Amortization of intangible assets, net (a) 26 49 53 Amortization of energy contract assets and liabilities (b) 35 31 30 Nuclear fuel (c) 758 992 983 ARO accretion (d) 543 514 500 Total depreciation, amortization, and accretion $ 2,427 $ 4,540 $ 3,636 _________ (a) Included in Depreciation and amortization expense in the Consolidated Statements of Operations and Comprehensive Income. (b) Included in Operating revenues or Purchased power and fuel expense in the Consolidated Statements of Operations and Comprehensive Income. (c) Included in Purchased power and fuel expense in the Consolidated Statements of Operations and Comprehensive Income. (d) Included in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. Cash paid during the year For the Years Ended December 31, 2022 2021 2020 Interest (net of amount capitalized) $ 230 $ 275 $ 331 Income taxes (net of refunds) 287 426 70 Other non-cash operating activities CEG Parent Constellation For the Years Ended December 31, For the Years Ended December 31, 2022 2021 2020 2022 2021 2020 Pension and non-pension postretirement benefit costs $ 17 $ 123 $ 115 $ 17 $ 123 $ 115 Other decommissioning-related activity (a) (263) (946) (659) (263) (946) (659) Energy-related options (b) 293 125 104 293 125 104 Severance costs (1) (73) 90 (1) (73) 90 Long-term incentive plan 44 — — — — — Provision for excess and obsolete inventory (12) (13) 128 (12) (13) 128 Amortization of operating ROU asset 75 119 155 75 119 155 Loss on sale of receivables 69 36 30 69 36 30 Fair value adjustments related to gas imbalances 37 — — 37 — — Prior merger commitment (c) (50) — — (50) — — __________ (a) Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units except for decommissioning-related impacts that were not offset for the Byron units starting in the second quarter of 2021, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income, and income taxes related to all NDT fund activity for these units. With our September 15, 2021 reversal of the previous decision to retire Byron, we resumed contractual offset for Byron as of that date. See Note 10 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning and the contractual offset suspension for the Byron units. (b) Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations. (c) Reversal of a charge related to a prior 2012 merger commitment. See Note 19 - Commitments and Contingencies for additional information. The following table provides a reconciliation of cash, restricted cash, and cash equivalents reported in the Consolidated Balance Sheets that sum to the total of the same amounts in the Consolidated Statements of Cash Flows. December 31, 2022 CEG Parent Constellation Cash and cash equivalents $ 422 $ 403 Restricted cash and cash equivalents 106 98 Total cash, restricted cash, and cash equivalents $ 528 $ 501 December 31, 2021 CEG Parent Constellation Cash and cash equivalents $ 504 $ 504 Restricted cash and cash equivalents 72 72 Total cash, restricted cash, and cash equivalents $ 576 $ 576 December 31, 2020 CEG Parent Constellation Cash and cash equivalents $ 226 $ 226 Restricted cash and cash equivalents 89 89 Cash, restricted cash, and cash equivalents - Held for Sale 12 12 Total cash, restricted cash, and cash equivalents $ 327 $ 327 December 31, 2019 CEG Parent Constellation Cash and cash equivalents $ 303 $ 303 Restricted cash and cash equivalents 146 146 Total cash, restricted cash, and cash equivalents $ 449 $ 449 For additional information on restricted cash, see Note 1 — Basis of Presentation.
Supplemental Balance Sheet Information	The following tables provide additional information about material items recorded in the Consolidated Balance Sheets. Investments December 31, 2022 December 31, 2021 Equity method investments $ 82 $ 62 Other investments: Employee benefit trusts and investments (a) 68 72 Equity investments without readily determinable fair values 46 33 Other available for sale debt security investments 6 7 Total investments $ 202 $ 174 __________ (a) Debt and equity security investments are recorded at fair market value. Accrued expenses December 31, 2022 CEG Parent Constellation Compensation-related accruals (a) $ 540 $ 502 Taxes accrued 257 257 Accrued expenses December 31, 2021 CEG Parent Constellation Compensation-related accruals (a) $ 356 $ 356 Taxes accrued 272 272 __________ (a) Primarily includes accrued payroll, bonuses and other incentives, vacation, and benefits.

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
Related Party Transactions (Tables)	Dec. 31, 2022
Related Party Transactions [Abstract]
Schedule of Related Party Transactions	The following table presents our Operating revenues from affiliates: For the Years Ended 2022 (a) 2021 2020 ComEd (b) $ 58 $ 376 $ 330 PECO (c) 33 196 190 BGE (d) 18 236 315 PHI 51 366 367 Pepco (e) 39 270 279 DPL (f) 10 79 75 ACE (g) 2 17 13 Other — 14 9 Total operating revenues from affiliates $ 160 $ 1,188 $ 1,211 __________ (a) Represents only January 2022 costs prior to separation on February 1, 2022. (b) We have an ICC-approved RFP contract with ComEd to provide a portion of ComEd’s electricity supply requirements. We also sell RECs and ZECs to ComEd. (c) We provide electric supply to PECO under contracts executed through PECO’s competitive procurement process. In addition, we have a ten-year agreement with PECO to sell solar AECs. (d) We provide a portion of BGE’s energy requirements under its MDPSC-approved market-based SOS and gas commodity programs. (e) We provide electric supply to Pepco under contracts executed through Pepco's competitive procurement process approved by the MDPSC and DCPSC. (f) We provide a portion of DPL's energy requirements under its MDPSC and DEPSC approved market-based SOS commodity programs. (g) We provide electric supply to ACE under contracts executed through ACE's competitive procurement process.
Related Party Transactions - BSC Service Companies	The following table presents the service company costs allocated to us: Operating and maintenance from Capitalized costs For the Years Ended December 31, For the Years Ended December 31, 2022 (a) 2021 2020 2022 (a) 2021 2020 $ 44 $ 588 $ 552 $ 15 $ 129 $ 54 __________ (a) Represents only January 2022 costs prior to separation on February 1, 2022.
Related Party Transactions - Current Receivables From/Payables To Affiliates	The following table presents Current receivables from affiliates and Current payables to affiliates: December 31, 2021 Receivables from affiliates: Payables to affiliates: ComEd $ 84 $ 13 PECO 30 — BGE 4 — Pepco 20 — DPL 4 — ACE 7 — BSC — 102 Other 11 16 Total(a) $ 160 $ 131 __________ (a) Prior to the completion of the separation on February 1, 2022, we engaged in transactions with affiliates of Exelon in the normal course of business. As of December 31, 2022, all transactions with Exelon or its affiliates are third-party transactions.

Basis of Presentation (Details)

Basis of Presentation (Details) $ in Millions		12 Months Ended
Basis of Presentation (Details) $ in Millions	Jan. 31, 2022 USD ($)	Dec. 31, 2022 USD ($) segment	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)
Significant Accounting Policies Additional Narrative Information [Line Items]
Number of reportable segments \| segment		5
Contributions from member	$ 1,750	$ 1,750	$ 64	$ 64
Payables to affiliates		0	3,357
Short-term borrowings	$ 200	1,159	2,082
Credit facility term	5 years
Credit facility	$ 4,500	5,802	$ 6,631
Billings from related party		266
Billings to related party		$ 43
Pension Benefits
Significant Accounting Policies Additional Narrative Information [Line Items]
Contributions from member	192
Exelon Consolidation
Significant Accounting Policies Additional Narrative Information [Line Items]
Payables to affiliates	$ 258
Constellation Renewables
Significant Accounting Policies Additional Narrative Information [Line Items]
Ownership interest		51%	51%

Mergers, Acquisitions, and Di_3

Mergers, Acquisitions, and Dispositions - Narrative (Details) $ in Millions					3 Months Ended	12 Months Ended
	Aug. 06, 2021 USD ($)	Mar. 31, 2021 USD ($)	Dec. 08, 2020 site MW	Apr. 01, 2014 USD ($)	Jun. 30, 2021 USD ($)	Dec. 31, 2021 USD ($)
Mergers, Acquisitions, and Dispositions [Line Items]
Decrease in membership interest due to deferred tax liabilities resulting from purchase of EDF's equity interest						$ (288)
Solar Business \| Disposal Group, Disposed of by Sale, Not Discontinued Operations
Mergers, Acquisitions, and Dispositions [Line Items]
MW of generation \| MW			360
Number of sites \| site			600
Purchase price		$ 810
Cash proceeds received		675
Long-term debt assumed by buyer		125
Pre-tax gain on disposition		$ 68
Constellation Energy Generation, LLC
Mergers, Acquisitions, and Dispositions [Line Items]
Decrease in membership interest due to deferred tax liabilities resulting from purchase of EDF's equity interest						(288)
Constellation Energy Generation, LLC \| CENG
Mergers, Acquisitions, and Dispositions [Line Items]
Ownership interest	50.01%
Constellation Energy Generation, LLC \| Albany Green Energy biomass facility
Mergers, Acquisitions, and Dispositions [Line Items]
Purchase price					$ 36
Pre-tax impairment charge					$ 140
Constellation Energy Generation, LLC \| CENG
Mergers, Acquisitions, and Dispositions [Line Items]
Equity interest	49.99%
Constellation Energy Generation, LLC \| CENG
Mergers, Acquisitions, and Dispositions [Line Items]
Special distribution				$ 400
Aggregate distributions due				$ 400
Return per annum				8.50%
Pre-tax increase in membership interest for purchase of EDF's 49.99% equity interest	$ 885					1,080
Decrease in membership interest due to deferred tax liabilities resulting from purchase of EDF's equity interest						$ 288
Nine Mile Point Unit 2 \| Constellation Energy Generation, LLC \| CENG
Mergers, Acquisitions, and Dispositions [Line Items]
Ownership interest	82%

Mergers, Acquisitions, and Di_4

Mergers, Acquisitions, and Dispositions - Changes in Ownership Equity (Details) - USD ($) $ in Millions		12 Months Ended
	Aug. 06, 2021	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Schedule of Changes in Ownership Interest [Line Items]
Net loss attributable to membership interest		$ (160)	$ (205)	$ 589
Decrease in membership interest due to deferred tax liabilities resulting from purchase of EDF's equity interest			288
Constellation Energy Generation, LLC
Schedule of Changes in Ownership Interest [Line Items]
Net loss attributable to membership interest		$ (160)	(205)	$ 589
Decrease in membership interest due to deferred tax liabilities resulting from purchase of EDF's equity interest			288
Constellation Energy Generation, LLC \| CENG
Schedule of Changes in Ownership Interest [Line Items]
Equity interest	49.99%
CENG \| Constellation Energy Generation, LLC
Schedule of Changes in Ownership Interest [Line Items]
Net loss attributable to membership interest			(205)
Pre-tax increase in membership interest for purchase of EDF's 49.99% equity interest	$ 885		1,080
Decrease in membership interest due to deferred tax liabilities resulting from purchase of EDF's equity interest			(288)
Change from net loss attributable to membership interest and transfers from noncontrolling interest			$ 587

Regulatory Matters (Details)

Regulatory Matters (Details) - USD ($)				1 Months Ended	12 Months Ended
Regulatory Matters (Details) - USD ($)	Jul. 15, 2021	Feb. 15, 2021	Mar. 06, 2020	Nov. 30, 2021	Dec. 31, 2022	Dec. 31, 2021
Regulatory Matters Additional Narrative Information [Line Items]
Return on equity approved percentage	9.33%			9.19%
Defaulting Market Participant and Settlement of Regulatory Matters
Regulatory Matters Additional Narrative Information [Line Items]
Reduction to net income					$ 50,000,000	$ 800,000,000
Texas-based generating assets
Regulatory Matters Additional Narrative Information [Line Items]
Market payment shortfall in collections						17,000,000
Peach Bottom Units 2 and 3
Regulatory Matters Additional Narrative Information [Line Items]
Operating license renewal period			20 years
ERCOT
Regulatory Matters Additional Narrative Information [Line Items]
Administrative price cap		$ 9,000
Market payment shortfall in collections					0	$ 2,500,000,000
ERCOT \| Defaulting Market Participant and Settlement of Regulatory Matters
Regulatory Matters Additional Narrative Information [Line Items]
Market payment shortfall in collections					1,900,000,000
ERCOT \| Public Utility Commission of Texas
Regulatory Matters Additional Narrative Information [Line Items]
Securitized funds allocation					$ 2,100,000,000
Maximum \| Defaulting Market Participant and Settlement of Regulatory Matters
Regulatory Matters Additional Narrative Information [Line Items]
Term to be paid						83 years

Revenue from Contracts with C_3

Revenue from Contracts with Customers - Contract Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Change in Contract with Customer, Asset [Abstract]
Beginning Balance	$ 149	$ 144
Amounts reclassified to receivables	(81)	(59)
Revenues recognized	62	52
Amounts previously held-for-sale		12
Ending Balance	$ 130	$ 149

Revenue from Contracts with C_4

Revenue from Contracts with Customer - Contract Liabilities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Contract Liabilities [Roll Forward]
Beginning Balance	$ 75	$ 84	$ 71
Consideration received or due	339	251	282
Revenues recognized	(367)	(263)	(266)
Contracts liabilities reclassified as held for sale		3	(3)
Ending Balance	$ 47	$ 75	$ 84

Revenue from Contracts with C_5

Revenue from Contracts with Customers - Performance Obligations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenues recognized	$ 24,440	$ 19,649	$ 17,603
Remaining performance obligations	485
Contract Liability
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenues recognized	71	$ 82	$ 64
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations	$ 221
Remaining performance obligations, timing	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations	$ 78
Remaining performance obligations, timing	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations	$ 35
Remaining performance obligations, timing	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations	$ 15
Remaining performance obligations, timing	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations	$ 136
Remaining performance obligations, timing	1 year

Segment Information - Narrative

Segment Information - Narrative (Details)	12 Months Ended
Segment Information - Narrative (Details)	Dec. 31, 2022 segment
Segment Reporting [Abstract]
Number of reportable segments	5

Segment Information - Generatio

Segment Information - Generation Total Revenues (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Segment Reporting Information [Line Items]
Revenues	$ 24,440	$ 19,649	$ 17,603
Mid-Atlantic
Segment Reporting Information [Line Items]
Revenues	5,164	4,584	4,645
Midwest
Segment Reporting Information [Line Items]
Revenues	4,650	4,060	4,024
New York
Segment Reporting Information [Line Items]
Revenues	1,595	1,575	1,431
ERCOT
Segment Reporting Information [Line Items]
Revenues	1,543	1,181	958
Other Power Regions
Segment Reporting Information [Line Items]
Revenues	6,732	4,890	4,002
Total Competitive Businesses Electric Revenues
Segment Reporting Information [Line Items]
Revenues	19,684	16,290	15,060
Competitive Businesses Natural Gas Revenues
Segment Reporting Information [Line Items]
Revenues	4,967	3,379	2,003
Competitive Businesses Other Revenues
Segment Reporting Information [Line Items]
Revenues	(211)	(20)	540
Unrealized mark-to-market gains (losses)	(1,188)	(633)	110
Total Consolidated Operating Revenues
Segment Reporting Information [Line Items]
Revenues	24,440	19,649	17,603
Operating Segments \| Mid-Atlantic
Segment Reporting Information [Line Items]
Revenues	5,159	4,564	4,617
Operating Segments \| Midwest
Segment Reporting Information [Line Items]
Revenues	4,657	4,060	4,029
Operating Segments \| New York
Segment Reporting Information [Line Items]
Revenues	1,596	1,576	1,432
Operating Segments \| ERCOT
Segment Reporting Information [Line Items]
Revenues	1,556	1,172	933
Operating Segments \| Other Power Regions
Segment Reporting Information [Line Items]
Revenues	6,716	4,918	4,049
Operating Segments \| Total Competitive Businesses Electric Revenues
Segment Reporting Information [Line Items]
Revenues	19,684	16,290	15,060
Operating Segments \| Competitive Businesses Natural Gas Revenues
Segment Reporting Information [Line Items]
Revenues	4,967	3,379	2,003
Operating Segments \| Competitive Businesses Other Revenues
Segment Reporting Information [Line Items]
Unrealized mark-to-market gains (losses)	(1,013)	565	295
Operating Segments \| Total Consolidated Operating Revenues
Segment Reporting Information [Line Items]
Revenues	24,440	19,649	17,603
Intersegment Revenues \| Mid-Atlantic
Segment Reporting Information [Line Items]
Revenues	5	20	28
Intersegment Revenues \| Midwest
Segment Reporting Information [Line Items]
Revenues	(7)	0	(5)
Intersegment Revenues \| New York
Segment Reporting Information [Line Items]
Revenues	(1)	(1)	(1)
Intersegment Revenues \| ERCOT
Segment Reporting Information [Line Items]
Revenues	(13)	9	25
Intersegment Revenues \| Other Power Regions
Segment Reporting Information [Line Items]
Revenues	16	(28)	(47)
Intersegment Revenues \| Total Competitive Businesses Electric Revenues
Segment Reporting Information [Line Items]
Revenues	0	0	0
Intersegment Revenues \| Competitive Businesses Natural Gas Revenues
Segment Reporting Information [Line Items]
Revenues	0	0	0
Intersegment Revenues \| Competitive Businesses Other Revenues
Segment Reporting Information [Line Items]
Revenues	0	0	0
Intersegment Revenues \| Total Consolidated Operating Revenues
Segment Reporting Information [Line Items]
Revenues	0	0	0
Corporate, Non-Segment \| Competitive Businesses Other Revenues
Segment Reporting Information [Line Items]
Revenues	(211)	(20)	540
Contracts with customers \| Operating Segments \| Mid-Atlantic
Segment Reporting Information [Line Items]
Revenues	5,264	4,381	4,785
Contracts with customers \| Operating Segments \| Midwest
Segment Reporting Information [Line Items]
Revenues	5,164	4,265	3,717
Contracts with customers \| Operating Segments \| New York
Segment Reporting Information [Line Items]
Revenues	2,004	1,633	1,444
Contracts with customers \| Operating Segments \| ERCOT
Segment Reporting Information [Line Items]
Revenues	954	896	735
Contracts with customers \| Operating Segments \| Other Power Regions
Segment Reporting Information [Line Items]
Revenues	5,035	3,937	3,586
Contracts with customers \| Operating Segments \| Total Competitive Businesses Electric Revenues
Segment Reporting Information [Line Items]
Revenues	18,421	15,112	14,267
Contracts with customers \| Operating Segments \| Competitive Businesses Natural Gas Revenues
Segment Reporting Information [Line Items]
Revenues	2,559	1,777	1,283
Contracts with customers \| Operating Segments \| Total Consolidated Operating Revenues
Segment Reporting Information [Line Items]
Revenues	21,571	17,254	15,905
Contracts with customers \| Corporate, Non-Segment \| Competitive Businesses Other Revenues
Segment Reporting Information [Line Items]
Revenues	591	365	355
Other \| Operating Segments \| Mid-Atlantic
Segment Reporting Information [Line Items]
Revenues	(105)	183	(168)
Other \| Operating Segments \| Midwest
Segment Reporting Information [Line Items]
Revenues	(507)	(205)	312
Other \| Operating Segments \| New York
Segment Reporting Information [Line Items]
Revenues	(408)	(57)	(12)
Other \| Operating Segments \| ERCOT
Segment Reporting Information [Line Items]
Revenues	602	276	198
Other \| Operating Segments \| Other Power Regions
Segment Reporting Information [Line Items]
Revenues	1,681	981	463
Other \| Operating Segments \| Total Competitive Businesses Electric Revenues
Segment Reporting Information [Line Items]
Revenues	1,263	1,178	793
Other \| Operating Segments \| Competitive Businesses Natural Gas Revenues
Segment Reporting Information [Line Items]
Revenues	2,408	1,602	720
Other \| Operating Segments \| Total Consolidated Operating Revenues
Segment Reporting Information [Line Items]
Revenues	2,869	2,395	1,698
Other \| Corporate, Non-Segment \| Competitive Businesses Other Revenues
Segment Reporting Information [Line Items]
Revenues	$ (802)	$ (385)	$ 185

Segment Information - Generat_2

Segment Information - Generation Total Revenues Net of Purchased Power and Fuel Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Mid-Atlantic
Segment Reporting Information [Line Items]
Total RNF	$ 2,138	$ 2,264	$ 2,204
Midwest
Segment Reporting Information [Line Items]
Total RNF	2,764	2,717	2,902
New York
Segment Reporting Information [Line Items]
Total RNF	1,067	1,161	997
ERCOT
Segment Reporting Information [Line Items]
Total RNF	407	(825)	426
Other Power Regions
Segment Reporting Information [Line Items]
Total RNF	921	891	665
Total Competitive Businesses Electric Revenues
Segment Reporting Information [Line Items]
Total RNF	7,297	6,208	7,194
Competitive Businesses Other Revenues
Segment Reporting Information [Line Items]
Total RNF	(319)	1,278	824
Unrealized mark-to-market gains (losses)	(1,188)	(633)	110
Total Consolidated Operating Revenues
Segment Reporting Information [Line Items]
Total RNF	6,978	7,486	8,018
Operating Segments \| Mid-Atlantic
Segment Reporting Information [Line Items]
RNF from external customers	2,129	2,247	2,174
Operating Segments \| Midwest
Segment Reporting Information [Line Items]
RNF from external customers	2,765	2,717	2,902
Operating Segments \| New York
Segment Reporting Information [Line Items]
RNF from external customers	1,061	1,151	983
Operating Segments \| ERCOT
Segment Reporting Information [Line Items]
RNF from external customers	503	(668)	407
Operating Segments \| Other Power Regions
Segment Reporting Information [Line Items]
RNF from external customers	952	984	759
Operating Segments \| Total Competitive Businesses Electric Revenues
Segment Reporting Information [Line Items]
RNF from external customers	7,410	6,431	7,225
Operating Segments \| Competitive Businesses Other Revenues
Segment Reporting Information [Line Items]
RNF from external customers	(432)	1,055	793
Unrealized mark-to-market gains (losses)	(1,013)	565	295
Nuclear Fuel Amortization		148	60
Operating Segments \| Total Consolidated Operating Revenues
Segment Reporting Information [Line Items]
RNF from external customers	6,978	7,486	8,018
Intersegment Revenues \| Mid-Atlantic
Segment Reporting Information [Line Items]
Intersegment RNF	9	17	30
Intersegment Revenues \| Midwest
Segment Reporting Information [Line Items]
Intersegment RNF	(1)	0	0
Intersegment Revenues \| New York
Segment Reporting Information [Line Items]
Intersegment RNF	6	10	14
Intersegment Revenues \| ERCOT
Segment Reporting Information [Line Items]
Intersegment RNF	(96)	(157)	19
Intersegment Revenues \| Other Power Regions
Segment Reporting Information [Line Items]
Intersegment RNF	(31)	(93)	(94)
Intersegment Revenues \| Total Competitive Businesses Electric Revenues
Segment Reporting Information [Line Items]
Intersegment RNF	(113)	(223)	(31)
Intersegment Revenues \| Competitive Businesses Other Revenues
Segment Reporting Information [Line Items]
Intersegment RNF	113	223	31
Intersegment Revenues \| Total Consolidated Operating Revenues
Segment Reporting Information [Line Items]
Intersegment RNF	$ 0	$ 0	$ 0

Accounts Receivable - Allowance

Accounts Receivable - Allowance for Credit Losses Rollforward (Details) - Customer accounts receivable - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Beginning balance	$ 55	$ 32
Plus: Current period provision for expected credit losses	9	30
Less: Write-offs, net of recoveries	18	7
Ending balance	$ 46	$ 55

Accounts Receivable - Narrative

Accounts Receivable - Narrative (Details) - USD ($) $ in Millions	Dec. 31, 2022	Aug. 16, 2022	Jan. 31, 2022	Dec. 31, 2021	Apr. 08, 2020
Accounts, Notes, Loans and Financing Receivable [Line Items]
Unbilled customer revenues	$ 564			$ 373
Credit facility	$ 5,802		$ 4,500	$ 6,631
Sale of Accounts Receivable
Accounts, Notes, Loans and Financing Receivable [Line Items]
Credit facility		$ 1,100			$ 900

Accounts Receivable - Purchases

Accounts Receivable - Purchases and Sales of Accounts Receivable (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Mar. 31, 2021
Accounts, Notes, Loans and Financing Receivable [Line Items]
Cash proceeds received	$ 200			$ 400
Loss on sale of receivables	69	$ 36	$ 30
Proceeds from new transfers	6,108	6,095	2,816
Cash collections received on DPP and reinvested in the Facility	4,764	3,502	3,771
Cash collections reinvested in the Facility	10,872	9,597	6,587
Total receivables sold	423	147	824
Exelon Utility Registrants Affiliates
Accounts, Notes, Loans and Financing Receivable [Line Items]
Receivables sold to Exelon's utility subsidiaries prior to the separation on February 1, 2022	4	23	$ 252
Sale of Accounts Receivable
Accounts, Notes, Loans and Financing Receivable [Line Items]
Derecognized receivables transferred at fair value	1,615	1,265
Cash proceeds received	1,100	900
DPP	515	365
Customer accounts receivable sold into the Facility	$ 11,274	$ 9,747

Early Plant Retirements - Narra

Early Plant Retirements - Narrative (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Property, Plant and Equipment [Line Items]
Depreciation and amortization			$ 1,091	$ 3,003	$ 2,123
Nuclear Fleet
Property, Plant and Equipment [Line Items]
Operating license renewal period			80 years
Clinton and Dresden Units
Property, Plant and Equipment [Line Items]
Operating license renewal period	20 years
Byron Dresden \| Facility Closing
Property, Plant and Equipment [Line Items]
Other one-time charges				(9)	(34)
Constellation New England
Property, Plant and Equipment [Line Items]
One time charges					22
Depreciation and amortization			$ 0	41	26
Constellation Energy Generation, LLC
Property, Plant and Equipment [Line Items]
Depreciation and amortization			$ 1,091	$ 3,003	$ 2,123
Constellation Energy Generation, LLC \| Byron Dresden \| Facility Closing
Property, Plant and Equipment [Line Items]
Severance costs		$ (81)
Other one-time charges		$ (13)

Early Plant Retirements - Preta

Early Plant Retirements - Pretax Expense (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Sep. 30, 2021	Dec. 31, 2021	Dec. 31, 2020
Restructuring Cost and Reserve [Line Items]
Restructuring, Incurred Cost, Statement of Income or Comprehensive Income [Extensible Enumeration]		Operating and maintenance	Operating and maintenance
Facility Closing \| Byron Dresden
Restructuring Cost and Reserve [Line Items]
Accelerated depreciation		$ 1,805	$ 895
Accelerated nuclear fuel amortization		148	60
One-time charges		(94)	255
Other charges		9	34
Contractual offset		(451)	(364)
Total		$ 1,417	$ 880
Constellation Energy Generation, LLC \| Facility Closing \| Byron Dresden
Restructuring Cost and Reserve [Line Items]
Other charges	$ 13

Property, Plant, and Equipmen_2

Property, Plant, and Equipment - Summary of Property, Plant and Equipment (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	$ 36,548	$ 35,485
Less: accumulated depreciation	16,726	15,873
Property, plant, and equipment, net	19,822	19,612
Nuclear fuel - work in progress	937	859
Electric
Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	$ 30,804	29,910
Electric \| Minimum
Property, Plant and Equipment [Line Items]
Average Service Life (years)	1 year
Electric \| Maximum
Property, Plant and Equipment [Line Items]
Average Service Life (years)	52 years
Nuclear fuel
Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	$ 5,106	5,166
Less: accumulated depreciation	$ 2,657	2,765
Nuclear fuel \| Minimum
Property, Plant and Equipment [Line Items]
Average Service Life (years)	1 year
Nuclear fuel \| Maximum
Property, Plant and Equipment [Line Items]
Average Service Life (years)	8 years
Construction work in progress
Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	$ 630	399
Other property, plant, and equipment
Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	$ 8	$ 10
Other property, plant, and equipment \| Minimum
Property, Plant and Equipment [Line Items]
Average Service Life (years)	1 year
Other property, plant, and equipment \| Maximum
Property, Plant and Equipment [Line Items]
Average Service Life (years)	10 years

Property, Plant, and Equipmen_3

Property, Plant, and Equipment - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Property, Plant and Equipment [Line Items]
Interest	$ 25	$ 15	$ 22
Electric
Property, Plant and Equipment [Line Items]
Annual depreciation rate	3.46%	8.67%	6.11%

Jointly Owned Electric Utilit_3

Jointly Owned Electric Utility Plant (Details) - Nuclear Plant - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Quad Cities
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Ownership interest	75%
Plant in service	$ 1,243	$ 1,211
Accumulated depreciation	761	715
Construction work in progress	$ 7	11
Peach Bottom
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Ownership interest	50%
Plant in service	$ 1,534	1,515
Accumulated depreciation	659	628
Construction work in progress	$ 12	12
Salem
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Ownership interest	42.59%
Plant in service	$ 772	756
Accumulated depreciation	328	299
Construction work in progress	$ 23	20
Nine Mile Point Unit 2
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Ownership interest	82%
Plant in service	$ 1,063	1,002
Accumulated depreciation	256	222
Construction work in progress	$ 26	$ 41

Asset Retirement Obligations -

Asset Retirement Obligations - Nuclear Decommissioning Asset Retirement Obligation Rollforward (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Accretion expense	$ 543	$ 514	$ 500
Nuclear Decommissioning
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	12,676	11,922
Net increase (decrease) due to changes in, and timing of, estimated future cash flows	(648)	324
Accretion expense	532	503
Costs incurred related to decommissioning plants	(60)	(73)
Ending balance	12,500	12,676	$ 11,922
ARO, current obligation	$ 40	$ 72

Asset Retirement Obligations _2

Asset Retirement Obligations - Narrative (Details) - USD ($) $ in Millions		3 Months Ended	9 Months Ended	12 Months Ended
	Mar. 31, 2022	Jun. 30, 2021	Sep. 30, 2021	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Asset Retirement Obligations [Line Items]
Shortfall of decommissioning funds with recourse				$ 50
Percent of additional decommissioning shortfall with recourse				5%
Nuclear decommissioning trust funds				$ 14,114	$ 15,938
Number of years used in present value measurement				30 years
Annual average accretion of the ARO				4%
Historical five-year annual average pre-tax return on NDT funds				5.30%
Minimum
Asset Retirement Obligations [Line Items]
Number of years used in present value measurement				10 years
Estimated targeted annual pre-tax return on nuclear decommissioning funds				6.20%
Maximum
Asset Retirement Obligations [Line Items]
Number of years used in present value measurement				70 years
Estimated targeted annual pre-tax return on nuclear decommissioning funds				6.90%
Constellation Energy Generation, LLC
Asset Retirement Obligations [Line Items]
Nuclear decommissioning trust funds				$ 14,114	15,938
Estimated annual after-tax return on nuclear decommissioning funds				2%
PECO Energy Co
Asset Retirement Obligations [Line Items]
Estimated annual after-tax return on nuclear decommissioning funds				3%
Nuclear Decommissioning
Asset Retirement Obligations [Line Items]
Net increase (decrease) due to changes in, and timing of, estimated future cash flows				$ (648)	324
Net decrease due to increase in discount rates				(790)
Decrease due to changes in assumed retirement dates				(235)
Net increase due to revisions to projected decommission schedule				320	550
Net increase (decrease) due to higher estimated decommissioning costs				75	(170)
Net increase (decrease) in operating and maintenance expense				(226)	51
Increase (decrease) in ARO due to revisions in assumed retirement dates					90
Increase (decrease) in ARO for impacts of revised decommissioning cost estimates					(150)
Asset retirement obligation				$ 12,500	12,676	$ 11,922
Nine Mile Point Unit 2
Asset Retirement Obligations [Line Items]
Percent of additional decommissioning shortfall with recourse				50%
Nuclear decommissioning trust funds				$ 15
Zion Station
Asset Retirement Obligations [Line Items]
Asset retirement obligation				138
Nonnuclear Decommissioning Asset Retirement Obligation
Asset Retirement Obligations [Line Items]
Asset retirement obligation				239	216	$ 212
Nuclear Decommissioning Byron
Asset Retirement Obligations [Line Items]
Decommissioning related activities		$ 53	$ 140
Nuclear Decommissioning Trust Fund Investments
Asset Retirement Obligations [Line Items]
Annual recovery	$ 4
Assets, Total
Asset Retirement Obligations [Line Items]
Nuclear decommissioning trust funds				14,127	16,064
Assets, Total \| Zion Station
Asset Retirement Obligations [Line Items]
Nuclear decommissioning trust funds				58
Other Current Assets
Asset Retirement Obligations [Line Items]
Nuclear decommissioning trust funds				$ 13	$ 126

Nuclear Decommissioning - Noncu

Nuclear Decommissioning - Noncurrent Related Party Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Asset Retirement Obligations [Line Items]
Payables to affiliates	$ 0	$ 3,357
ComEd
Asset Retirement Obligations [Line Items]
Payables to affiliates	2,660	2,760
PECO
Asset Retirement Obligations [Line Items]
Payables to affiliates	$ 237	$ 597

Asset Retirement Obligations _3

Asset Retirement Obligations - Non-Nuclear Asset Retirement Obligations Rollforward (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Accretion expense	$ 543	$ 514	$ 500
Nonnuclear Decommissioning Asset Retirement Obligation
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	216	212
Other one-time charges	18	5
Accretion expense	11	11
Asset divestitures	(1)	(19)
Payments	(5)	(3)
Ending balance	$ 239	216	$ 212
Nonnuclear Decommissioning Asset Retirement Obligation \| Disposal Group, Held-for-sale or Disposed of by Sale, Not Discontinued Operations
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Other one-time charges		$ 10

Leases - Lease Terms (Details)

Leases - Lease Terms (Details)	12 Months Ended
Leases - Lease Terms (Details)	Dec. 31, 2022
Minimum
Lessor, Lease, Description [Line Items]
Remaining lease terms	1 year
Options to extend the term	2 years
Options to terminate within	1 year
Remaining lease terms	1 year
Options to extend the term	1 year
Maximum
Lessor, Lease, Description [Line Items]
Remaining lease terms	33 years
Options to extend the term	30 years
Options to terminate within	2 years
Remaining lease terms	18 years
Options to extend the term	20 years

Leases - Components of Lease Co

Leases - Components of Lease Cost (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Leases [Abstract]
Operating lease costs	$ 109	$ 161	$ 194
Variable lease costs	169	168	234
Sublease income	$ 49	$ 44	$ 44

Leases - Supplemental Balance S

Leases - Supplemental Balance Sheet Information (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Supplemental Balance Sheet Information [Line Items]
Operating lease ROU assets	$ 545	$ 604
Other current liabilities	67	72
Other deferred credits and other liabilities	643	705
Operating lease liabilities	$ 710	$ 777
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Other	Other
Operating Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration]	Other	Other
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]	Other Liabilities, Noncurrent	Other Liabilities, Noncurrent
Long-term Contract for Purchase of Electric Power
Supplemental Balance Sheet Information [Line Items]
Operating lease ROU assets	$ 248	$ 293
Operating lease liabilities	$ 377	$ 429

Leases - Operating Leases (Deta

Leases - Operating Leases (Details)	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Lessee, Lease, Description [Line Items]
Weighted average remaining lease term	9 years 3 months 18 days	10 years 1 month 6 days	10 years 6 months
Weighted average discount rate	5%	5%	4.90%

Lessee - Lessee Future Minimum

Lessee - Lessee Future Minimum Operating Lease Maturity Payments (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Leases [Abstract]
2023	$ 101
2024	99
2025	102
2026	102
2027	100
Thereafter	421
Total lease payments	925
Less: Imputed interest	215
Operating lease liabilities	$ 710	$ 777

Leases - Supplemental Cash Flow

Leases - Supplemental Cash Flow Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Leases [Abstract]
Cash paid for amounts included in the measurement of operating lease liabilities	$ 114	$ 162	$ 204
ROU assets obtained in exchange for operating lease obligations	$ 14	$ 2	$ 3

Lessor - Components of Operatin

Lessor - Components of Operating Lease Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Leases [Abstract]
Operating lease income	$ 51	$ 47	$ 47
Variable lease income	$ 258	$ 261	$ 282

Lessor - Operating Lease, Payme

Lessor - Operating Lease, Payments, Fiscal Year Maturity (Details) $ in Millions	Dec. 31, 2022 USD ($)
Leases [Abstract]
2023	$ 48
2024	48
2025	48
2026	49
2027	49
Thereafter	133
Total	$ 375

Asset Impairments (Details)

Asset Impairments (Details) - USD ($) $ in Millions	3 Months Ended			12 Months Ended
Asset Impairments (Details) - USD ($) $ in Millions	Sep. 30, 2021	Jun. 30, 2021	Sep. 30, 2020	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Property, Plant and Equipment [Line Items]
Pre-tax impairment charge				$ 0	$ 545	$ 563
Constellation Energy Generation, LLC
Property, Plant and Equipment [Line Items]
Pre-tax impairment charge				$ 0	$ 545	$ 563
Constellation Energy Generation, LLC \| Constellation New England
Property, Plant and Equipment [Line Items]
Pre-tax impairment charge		$ 350	$ 500
Constellation Energy Generation, LLC \| Contracted Wind Project \| Utilities Operating Expense Maintenance Operations And Other Costs And Expenses
Property, Plant and Equipment [Line Items]
Pre-tax impairment charge	$ 45
Constellation Energy Generation, LLC \| Contracted Wind Project \| Net Income (Loss) Attributable to Noncontrolling Interest
Property, Plant and Equipment [Line Items]
Pre-tax impairment charge	$ 21

Intangible Assets - Schedule of

Intangible Assets - Schedule of Other Intangible Assets (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Finite-Lived Intangible Assets [Line Items]
Gross	$ 2,538	$ 2,515
Accumulated Amortization	(2,195)	(2,134)
Net	343	381
Unamortized Energy Contracts
Finite-Lived Intangible Assets [Line Items]
Gross	1,960	1,963
Accumulated Amortization	(1,708)	(1,673)
Net	252	290
Customer Relationships
Finite-Lived Intangible Assets [Line Items]
Gross	356	330
Accumulated Amortization	(265)	(243)
Net	91	87
Trade Name
Finite-Lived Intangible Assets [Line Items]
Gross	222	222
Accumulated Amortization	(222)	(218)
Net	$ 0	$ 4

Intangible Assets - Summary of

Intangible Assets - Summary of Amortization Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Goodwill and Intangible Assets Disclosure [Abstract]
Amortization Expense	$ 61	$ 80	$ 81

Intangible Assets - Schedule _2

Intangible Assets - Schedule of Finite-Lived Intangible Assets, Future Amortization Expense (Details) $ in Millions	Dec. 31, 2022 USD ($)
Goodwill and Intangible Assets Disclosure [Abstract]
2023	$ 59
2024	56
2025	47
2026	40
2027	$ 27

Intangible Assets - Renewable a

Intangible Assets - Renewable and Alternative Energy Credits (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Renewable energy credit current
Finite-Lived Intangible Assets [Line Items]
Current REC's	$ 617	$ 520

Income Taxes - Components of In

Income Taxes - Components of Income Tax Expense (Benefit) from Continuing Operations (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2020	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Federal
Current		$ 219	$ 394	$ 130
Deferred		(655)	(153)	150
ITC amortization		(15)	(15)	(25)
State
Current		34	36	40
Deferred		29	(37)	(46)
Total	$ 67	$ (388)	$ 225	$ 249

Income Taxes - Reconciliation t

Income Taxes - Reconciliation to Effective Tax Rate (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Income Tax Disclosure [Abstract]
U.S. federal statutory rate	21%	21%	21%
State income taxes, net of federal income tax benefit	(9.20%)	0%	0.50%
Qualified NDT fund income and losses	46.30%	165.10%	23.50%
Amortization of investment tax credit, including deferred taxes on basis differences	2.20%	(9.00%)	(2.60%)
Production tax credits and other credits	7.70%	(28.70%)	(5.40%)
Noncontrolling interests	(0.30%)	(3.00%)	3.20%
Tax Settlements	0%	0%	(10.30%)
Other	3.90%	2.60%	(0.10%)
Effective income tax rate	71.60%	148%	29.80%
State rate changes and tax positions	$ 30
Prior period income tax adjustment	$ 32

Income Taxes - Tax Effects of T

Income Taxes - Tax Effects of Temporary Differences and Carryforwards (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Plant basis differences	$ (3,005)	$ (2,812)
Accrual based contracts	(35)	(38)
Derivatives and other financial instruments	43
Derivatives and other financial instruments		(172)
Deferred pension and postretirement obligation	287
Deferred pension and postretirement obligation		(274)
Nuclear decommissioning activities	(371)	(912)
Deferred debt refinancing costs	0	15
Tax loss carryforward, net of valuation allowances	67	53
Tax credit carryforward	179	778
Investment in partnerships	(205)	(252)
Other, net	407	312
Deferred income tax liabilities (net)	2,633	3,302
Unamortized ITCs	(354)	(369)
Total deferred income tax liabilities (net) and unamortized ITCs	$ 2,987	$ 3,671

Income Taxes - Schedule of Carr

Income Taxes - Schedule of Carryforwards and Corresponding Valuation Allowances (Details) $ in Millions	Dec. 31, 2022 USD ($)
Federal
Operating Loss Carryforwards [Line Items]
Federal general business credits carryforwards and other carryforwards	$ 178
State
Operating Loss Carryforwards [Line Items]
State net operating losses and other carryforwards	939
Deferred taxes on state tax attributes (net)	78
Valuation allowance on state tax attributes	$ 11

Income Taxes - Reconciliation o

Income Taxes - Reconciliation of Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2020	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Beginning Balance	$ 441	$ 49	$ 50	$ 441
Change to positions that only affect timing		(5)	(1)
Increases based on tax positions related to current year		29	1	1
Increases based on tax positions prior to current year		6	1	23
Decreases based on tax positions prior to current year		(55)	(2)	(346)
Decrease from settlements with taxing authorities				(69)
Ending Balance		24	49	50
Decrease in unrecognized tax benefits	411
Increase in net income due to recognition of tax benefits	73
Income taxes	$ 67	$ (388)	$ 225	$ 249

Income Taxes - Recognition of U

Income Taxes - Recognition of Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Decrease in effective tax rate, unrecognized tax benefits if recognized	$ 29	$ 39	$ 39

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) - USD ($)		12 Months Ended
Income Taxes - Narrative (Details) - USD ($)	Aug. 06, 2021	Dec. 31, 2021	Dec. 31, 2022	Mar. 31, 2022	Feb. 01, 2022
Income Taxes [Line Items]
Decrease in membership interest due to deferred tax liabilities resulting from purchase of EDF's equity interest		$ 288,000,000
Deferred income taxes and unamortized ITCs		3,703,000,000	$ 3,031,000,000
Other		592,000,000	731,000,000
Other deferred debits and other assets		$ 1,717,000,000	2,106,000,000
Separation from Parent
Income Taxes [Line Items]
Payable for tax liabilities upon separation					$ 103,000,000
Deferred income taxes and unamortized ITCs					508,000,000
Other			168,000,000		11,000,000
Other deferred debits and other assets			362,000,000		$ 497,000,000
Separation from Parent \| Accounts Payable
Income Taxes [Line Items]
Payable for tax liabilities upon separation				$ 53,000,000
Separation from Parent \| Other Noncurrent Liabilities
Income Taxes [Line Items]
Payable for tax liabilities upon separation			50,000,000	$ 50,000,000
Separation from Parent \| Other Receivables, Net, Current
Income Taxes [Line Items]
Payable for tax liabilities upon separation			$ 18,000,000
CENG
Income Taxes [Line Items]
Decrease in membership interest due to deferred tax liabilities resulting from purchase of EDF's equity interest	$ 288,000,000

Income Taxes - Allocation of Ta

Income Taxes - Allocation of Tax Benefits (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Allocation of federal benefits under tax sharing agreement	$ 64	$ 64

Retirement Benefits - Narrative

Retirement Benefits - Narrative (Details) $ in Millions		1 Months Ended	11 Months Ended	12 Months Ended
Retirement Benefits - Narrative (Details) $ in Millions	Feb. 01, 2022 USD ($)	Feb. 28, 2022 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2023
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Actuarial losses and prior service costs	$ 2,006
Matching contributions to savings plan				$ 90	$ 53	$ 63
Pension Plan, Defined Benefit
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension obligations	953
Pension plan assets	$ 8,267		$ 6,660	$ 6,660	1,683
Expected long-term rate of return on plan assets			0.0700	0.0700
Discount rate	3.23%		5.52%	5.52%
Annual qualified pension contribution		$ 192	$ 211
Actual long-term rate of return on plan assets			(0.1840)	(0.1840)
Pension Plan, Defined Benefit \| Forecast [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Expected long-term rate of return on plan assets							0.0650
OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension obligations	$ 876
Pension plan assets	$ 904		$ 734	$ 734	$ 0
Expected long-term rate of return on plan assets	0.0639		0.0639	0.0639
Discount rate	3.21%		5.50%	5.50%
Annual qualified pension contribution			$ 0
Benefit payments				$ 26
Actual long-term rate of return on plan assets			(0.1120)	(0.1120)
OPEB \| Forecast [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Expected long-term rate of return on plan assets							0.0650
Non-Qualified Pension Plans
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Benefit payments				$ 20

Retirement Benefits - Benefit O

Retirement Benefits - Benefit Obligation and Plan Assets (Details) - USD ($) $ in Millions	1 Months Ended		11 Months Ended	12 Months Ended
	Feb. 28, 2022	Jan. 31, 2022	Dec. 31, 2022	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Change in benefit obligation:
Service cost				$ 151	$ 174	$ 171
Interest cost				345	280	341
Pension Benefits
Change in benefit obligation:
Beginning balance		$ 0		0
Separation-related adjustment		9,220
Ending balance			$ 7,275	7,275	0
Service cost			115	126	145	137
Interest cost			269	290	235	280
Plan participants' contributions			0
Actuarial gain, net			(1,756)
Settlements			(15)
Gross benefits paid			(558)
Change in plan assets:
Beginning balance		1,683		1,683
Separation-related adjustment		6,584
Ending balance			6,660	6,660	1,683
Actual return on plan assets			(1,245)
Employer contributions	$ 192		211
Plan participants' contributions			0
Gross benefits paid			(558)
Settlements			(15)
OPEB
Change in benefit obligation:
Beginning balance		847		847
Separation-related adjustment		933
Ending balance			1,360	1,360	847
Service cost			23	25	29	34
Interest cost			52	55	45	$ 61
Plan participants' contributions			20
Actuarial gain, net			(401)
Settlements			0
Gross benefits paid			(114)
Change in plan assets:
Beginning balance		0		0
Separation-related adjustment		$ 904
Ending balance			734	$ 734	$ 0
Actual return on plan assets			(99)
Employer contributions			0
Plan participants' contributions			15
Gross benefits paid			(86)
Settlements			$ 0

Retirement Benefits - Benefit_2

Retirement Benefits - Benefit Obligations Net of Plan Assets, Balance Sheet (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Defined Contribution Plan Disclosure [Line Items]
Prepaid pension asset	$ 0	$ 1,683
Pension Benefits
Defined Contribution Plan Disclosure [Line Items]
Prepaid pension asset	0	1,683
Other current liabilities	(10)	0
Pension obligations	(605)	0
Non-pension postretirement benefit obligations	0	0
(Unfunded) funded status (net benefit obligation less plan assets)	(615)	1,683
OPEB
Defined Contribution Plan Disclosure [Line Items]
Prepaid pension asset	0	0
Other current liabilities	(17)	0
Pension obligations	0	0
Non-pension postretirement benefit obligations	(609)	(847)
(Unfunded) funded status (net benefit obligation less plan assets)	$ (626)	$ (847)

Retirement Benefits - Accumulat

Retirement Benefits - Accumulated Benefit Obligation (Details) $ in Millions	Dec. 31, 2022 USD ($)
Retirement Benefits [Abstract]
ABO	$ (7,121)
Fair value of net plan assets	$ 6,660

Retirement Benefits - Net Benef

Retirement Benefits - Net Benefit Costs (Details) - USD ($) $ in Millions	11 Months Ended	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Defined Contribution Plan Disclosure [Line Items]
Service cost		$ 151	$ 174	$ 171
Interest cost		$ 345	$ 280	$ 341
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Interest Cost, Statement of Income or Comprehensive Income [Extensible Enumeration]		Other, net	Other, net	Other, net
Expected return on assets		$ (620)	$ (551)	$ (536)
Defined Benefit Plan, Net Periodic Benefit (Cost) Credit, Expected Return (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]		Other, net	Other, net	Other, net
Prior service cost (credit)		$ (6)	$ (8)	$ (48)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Amortization of Prior Service Cost (Credit), Statement of Income or Comprehensive Income [Extensible Enumeration]		Other, net	Other, net	Other, net
Actuarial loss (gain)		$ 147	$ 209	$ 179
Defined Benefit Plan, Net Periodic Benefit (Cost) Credit, Amortization of Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]		Other, net	Other, net	Other, net
Settlement charges		$ 6	$ 20	$ 8
Non-service components of pension benefits & OPEB credit		(128)	(50)	(56)
Net periodic benefit cost		23	124	115
Pension Benefits
Defined Contribution Plan Disclosure [Line Items]
Service cost	$ 115	126	145	137
Interest cost	269	290	235	280
Expected return on assets		(565)	(493)	(474)
Prior service cost (credit)		1	1	1
Actuarial loss (gain)		148	199	164
Settlement charges		6	20	9
Non-service components of pension benefits & OPEB credit		(120)	(38)	(20)
Net periodic benefit cost		6	107	117
OPEB
Defined Contribution Plan Disclosure [Line Items]
Service cost	23	25	29	34
Interest cost	$ 52	55	45	61
Expected return on assets		(55)	(58)	(62)
Prior service cost (credit)		(7)	(9)	(49)
Actuarial loss (gain)		(1)	10	15
Settlement charges		0	0	(1)
Non-service components of pension benefits & OPEB credit		(8)	(12)	(36)
Net periodic benefit cost		17	17	(2)
Pension Plan and Other Postretirement Benefits Plan
Defined Contribution Plan Disclosure [Line Items]
Non-service components of pension benefits & OPEB credit		(116)	(50)	(43)
Net periodic benefit cost		$ 131	$ 144	$ 140

Retirement Benefits - Changes i

Retirement Benefits - Changes in Plan Assets Recognized in AOCI (Details) $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($)
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Separation related adjustment	$ 2,664
Current year actuarial (gain) loss	11
Amortization of actuarial (loss) gain	(134)
Amortization of prior service (cost) credit	(1)
Settlements	(6)
Total recognized in AOCI	2,534
Current year prior service cost (credit)	10
Actuarial loss (gain)	2,524
OPEB
Defined Benefit Plan Disclosure [Line Items]
Separation related adjustment	22
Current year actuarial (gain) loss	(253)
Amortization of actuarial (loss) gain	1
Amortization of prior service (cost) credit	7
Settlements	0
Total recognized in AOCI	(223)
Current year prior service cost (credit)	(30)
Actuarial loss (gain)	$ (193)

Retirement Benefits - Remaining

Retirement Benefits - Remaining Service Period (Details)	12 Months Ended
Retirement Benefits - Remaining Service Period (Details)	Dec. 31, 2022
Pension Benefits
Defined Contribution Plan Disclosure [Line Items]
Pension plans	12 years 2 months 12 days
OPEB
Defined Contribution Plan Disclosure [Line Items]
Benefit Eligibility Age	7 years 4 months 24 days
Expected Retirement	8 years 3 months 18 days

Retirement Benefits - Assumptio

Retirement Benefits - Assumptions (Details)	Dec. 31, 2022	Feb. 01, 2022
Pension Benefits
Defined Contribution Plan Disclosure [Line Items]
Discount rate	5.52%	3.23%
Investment crediting rate	5.15%	3.86%
Rate of compensation increase	3.75%	3.75%
OPEB
Defined Contribution Plan Disclosure [Line Items]
Discount rate	5.50%	3.21%
Rate of compensation increase	3.75%	3.75%

Retirement Benefits - Contribut

Retirement Benefits - Contributions Made to Pension and Other Postretirement Benefit Plans (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Planned contributions	$ 21	$ 231	$ 236
OPEB
Defined Benefit Plan Disclosure [Line Items]
Planned contributions	17	$ 28	$ 19
Non-Qualified Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Planned contributions	$ 10

Retirement Benefits - Estimated

Retirement Benefits - Estimated Future Benefit Payments (Details) $ in Millions	Dec. 31, 2022 USD ($)
Pension Benefits
Defined Contribution Plan Disclosure [Line Items]
2023	$ 525
2024	531
2025	544
2026	541
2027	547
2028 through 2032	2,792
Total estimated future benefits payments through 2032	5,480
OPEB
Defined Contribution Plan Disclosure [Line Items]
2023	105
2024	105
2025	105
2026	105
2027	106
2028 through 2032	525
Total estimated future benefits payments through 2032	$ 1,051

Retirement Benefits - Target Al

Retirement Benefits - Target Allocation (Details)	Dec. 31, 2022
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Total	100%
OPEB
Defined Benefit Plan Disclosure [Line Items]
Total	100%
Equities \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Total	21%
Equities \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Total	43%
Fixed income subtotal \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Total	54%
Fixed income subtotal \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Total	45%
Alternative investments \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Total	25%
Alternative investments \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Total	12%

Retirement Benefits - Fair Valu

Retirement Benefits - Fair Value of Plan Assets (Details) - USD ($) $ in Millions	Dec. 31, 2022	Feb. 01, 2022	Dec. 31, 2021
Defined Benefit Plan Disclosure [Line Items]
Notational amount	$ 41
Net liabilities excluded	43
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	6,660	$ 8,267	$ 1,683
Derivative instruments	6
Notational amount	1,879
OPEB
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	734	$ 904	$ 0
Fair Value, Recurring
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	7,437
Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	6,703
Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	734
Level 1 \| Fair Value, Recurring
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	1,944
Level 1 \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	1,685
Level 1 \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	259
Level 2 \| Fair Value, Recurring
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	2,012
Level 2 \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	1,951
Level 2 \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	61
Level 3 \| Fair Value, Recurring
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	188
Level 3 \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	188
Level 3 \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	0
Not subject to leveling \| Fair Value, Recurring
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	3,293
Not subject to leveling \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	2,879
Not subject to leveling \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	414
Cash equivalents \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	216
Cash equivalents \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	40
Cash equivalents \| Level 1 \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	216
Cash equivalents \| Level 1 \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	40
Cash equivalents \| Level 2 \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	0
Cash equivalents \| Level 2 \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	0
Cash equivalents \| Level 3 \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	0
Cash equivalents \| Level 3 \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	0
Cash equivalents \| Not subject to leveling \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	0
Cash equivalents \| Not subject to leveling \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	0
Equities \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	1,144
Equities \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	298
Equities \| Level 1 \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	776
Equities \| Level 1 \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	152
Equities \| Level 2 \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	0
Equities \| Level 2 \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	0
Equities \| Level 3 \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	0
Equities \| Level 3 \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	0
Equities \| Not subject to leveling \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	368
Equities \| Not subject to leveling \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	146
U.S. Treasury and agencies \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Fixed income subtotal	821
U.S. Treasury and agencies \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Fixed income subtotal	37
U.S. Treasury and agencies \| Level 1 \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Fixed income subtotal	693
U.S. Treasury and agencies \| Level 1 \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Fixed income subtotal	10
U.S. Treasury and agencies \| Level 2 \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Fixed income subtotal	128
U.S. Treasury and agencies \| Level 2 \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Fixed income subtotal	27
U.S. Treasury and agencies \| Level 3 \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Fixed income subtotal	0
U.S. Treasury and agencies \| Level 3 \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Fixed income subtotal	0
U.S. Treasury and agencies \| Not subject to leveling \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Fixed income subtotal	0
U.S. Treasury and agencies \| Not subject to leveling \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Fixed income subtotal	0
State and municipal debt \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Fixed income subtotal	44
State and municipal debt \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Fixed income subtotal	4
State and municipal debt \| Level 1 \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Fixed income subtotal	0
State and municipal debt \| Level 1 \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Fixed income subtotal	0
State and municipal debt \| Level 2 \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Fixed income subtotal	44
State and municipal debt \| Level 2 \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Fixed income subtotal	4
State and municipal debt \| Level 3 \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Fixed income subtotal	0
State and municipal debt \| Level 3 \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Fixed income subtotal	0
State and municipal debt \| Not subject to leveling \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Fixed income subtotal	0
State and municipal debt \| Not subject to leveling \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Fixed income subtotal	0
Corporate debt \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Fixed income subtotal	1,744
Corporate debt \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Fixed income subtotal	27
Corporate debt \| Level 1 \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Fixed income subtotal	0
Corporate debt \| Level 1 \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Fixed income subtotal	0
Corporate debt \| Level 2 \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Fixed income subtotal	1,736
Corporate debt \| Level 2 \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Fixed income subtotal	27
Corporate debt \| Level 3 \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Fixed income subtotal	8
Corporate debt \| Level 3 \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Fixed income subtotal	0
Corporate debt \| Not subject to leveling \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Fixed income subtotal	0
Corporate debt \| Not subject to leveling \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Fixed income subtotal	0
Other \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Fixed income subtotal	513
Other \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Fixed income subtotal	171
Other \| Level 1 \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Fixed income subtotal	0
Other \| Level 1 \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Fixed income subtotal	57
Other \| Level 2 \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Fixed income subtotal	43
Other \| Level 2 \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Fixed income subtotal	3
Other \| Level 3 \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Fixed income subtotal	0
Other \| Level 3 \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Fixed income subtotal	0
Other \| Not subject to leveling \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Fixed income subtotal	470
Other \| Not subject to leveling \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Fixed income subtotal	111
Fixed income subtotal \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	3,122
Fixed income subtotal \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	239
Fixed income subtotal \| Level 1 \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	693
Fixed income subtotal \| Level 1 \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	67
Fixed income subtotal \| Level 2 \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	1,951
Fixed income subtotal \| Level 2 \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	61
Fixed income subtotal \| Level 3 \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	8
Fixed income subtotal \| Level 3 \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	0
Fixed income subtotal \| Not subject to leveling \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	470
Fixed income subtotal \| Not subject to leveling \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	111
Private equity \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	765
Private equity \| Level 1 \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	0
Private equity \| Level 2 \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	0
Private equity \| Level 3 \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	180
Private equity \| Not subject to leveling \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	585
Hedge funds \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	429
Hedge funds \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	59
Hedge funds \| Level 1 \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	0
Hedge funds \| Level 1 \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	0
Hedge funds \| Level 2 \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	0
Hedge funds \| Level 2 \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	0
Hedge funds \| Level 3 \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	0
Hedge funds \| Level 3 \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	0
Hedge funds \| Not subject to leveling \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	429
Hedge funds \| Not subject to leveling \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	59
Real estate \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	547
Real estate \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	62
Real estate \| Level 1 \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	0
Real estate \| Level 1 \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	0
Real estate \| Level 2 \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	0
Real estate \| Level 2 \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	0
Real estate \| Level 3 \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	0
Real estate \| Level 3 \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	0
Real estate \| Not subject to leveling \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	547
Real estate \| Not subject to leveling \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	62
Private credit \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	480
Private credit \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	36
Private credit \| Level 1 \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	0
Private credit \| Level 1 \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	0
Private credit \| Level 2 \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	0
Private credit \| Level 2 \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	0
Private credit \| Level 3 \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	0
Private credit \| Level 3 \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	0
Private credit \| Not subject to leveling \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	480
Private credit \| Not subject to leveling \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	$ 36

Retirement Benefits - Reconcili

Retirement Benefits - Reconciliation of Unobservable Inputs (Details) $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($)
Defined Benefit Plan Disclosure [Line Items]
Beginning Balance	$ 0
Separation related adjustment	9
Relating to assets still held as of the reporting date	(55)
Purchases	18
Settlements	(4)
Transfers into Level 3	220
Ending Balance	188
Fixed income subtotal
Defined Benefit Plan Disclosure [Line Items]
Beginning Balance	0
Separation related adjustment	9
Relating to assets still held as of the reporting date	(1)
Purchases	0
Settlements	0
Transfers into Level 3	0
Ending Balance	8
Equities
Defined Benefit Plan Disclosure [Line Items]
Beginning Balance	0
Separation related adjustment	0
Relating to assets still held as of the reporting date	0
Purchases	0
Settlements	0
Transfers into Level 3	0
Ending Balance	0
Private credit
Defined Benefit Plan Disclosure [Line Items]
Beginning Balance	0
Separation related adjustment	0
Relating to assets still held as of the reporting date	(54)
Purchases	18
Settlements	(4)
Transfers into Level 3	220
Ending Balance	$ 180

Derivative Financial Instrume_3

Derivative Financial Instruments - Summary of Derivative Fair Value Balances (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	$ 2,368	$ 2,169
Mark-to-market derivative assets (noncurrent assets)	1,261	949
Mark-to-market derivative liabilities (current liabilities)	(1,558)	(981)
Mark-to-market derivative liabilities (noncurrent liabilities)	(983)	(513)
Variation margin	836	897
Commodity Contract
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	2,344	2,169
Mark-to-market derivative assets (noncurrent assets)	1,243	943
Total mark-to-market derivative assets	3,587	3,112
Mark-to-market derivative liabilities (current liabilities)	(1,558)	(977)
Mark-to-market derivative liabilities (noncurrent liabilities)	(983)	(513)
Total mark-to-market derivative liabilities	(2,541)	(1,490)
Total mark-to-market derivative net assets	1,046	1,622
Commodity Contract \| Collateral
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	161	152
Mark-to-market derivative assets (noncurrent assets)	217	15
Total mark-to-market derivative assets	378	167
Mark-to-market derivative liabilities (current liabilities)	374	262
Mark-to-market derivative liabilities (noncurrent liabilities)	146	83
Total mark-to-market derivative liabilities	520	345
Total mark-to-market derivative net assets	898	512
Commodity Contract \| Netting
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	(13,123)	(8,923)
Mark-to-market derivative assets (noncurrent assets)	(4,074)	(2,298)
Total mark-to-market derivative assets	(17,197)	(11,221)
Mark-to-market derivative liabilities (current liabilities)	13,123	8,923
Mark-to-market derivative liabilities (noncurrent liabilities)	4,074	2,298
Total mark-to-market derivative liabilities	17,197	11,221
Total mark-to-market derivative net assets	0	0
Commodity Contract \| Economic Hedges
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	15,296	10,915
Mark-to-market derivative assets (noncurrent assets)	5,100	3,224
Total mark-to-market derivative assets	20,396	14,139
Mark-to-market derivative liabilities (current liabilities)	(15,049)	(10,143)
Mark-to-market derivative liabilities (noncurrent liabilities)	(5,203)	(2,893)
Total mark-to-market derivative liabilities	(20,252)	(13,036)
Total mark-to-market derivative net assets	144	1,103
Commodity Contract \| Proprietary Trading
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	10	25
Mark-to-market derivative assets (noncurrent assets)	0	2
Total mark-to-market derivative assets	10	27
Mark-to-market derivative liabilities (current liabilities)	(6)	(19)
Mark-to-market derivative liabilities (noncurrent liabilities)	0	(1)
Total mark-to-market derivative liabilities	(6)	(20)
Total mark-to-market derivative net assets	4	$ 7
Interest Rate Swap
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	24
Mark-to-market derivative assets (noncurrent assets)	18
Total mark-to-market derivative assets	42
Mark-to-market derivative liabilities (current liabilities)	0
Mark-to-market derivative liabilities (noncurrent liabilities)	0
Total mark-to-market derivative liabilities	0
Total mark-to-market derivative net assets	42
Interest Rate Swap \| Netting
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	(5)
Mark-to-market derivative assets (noncurrent assets)	0
Total mark-to-market derivative assets	(5)
Mark-to-market derivative liabilities (current liabilities)	5
Mark-to-market derivative liabilities (noncurrent liabilities)	0
Total mark-to-market derivative liabilities	5
Total mark-to-market derivative net assets	0
Interest Rate Swap \| Economic Hedges
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	29
Mark-to-market derivative assets (noncurrent assets)	18
Total mark-to-market derivative assets	47
Mark-to-market derivative liabilities (current liabilities)	(5)
Mark-to-market derivative liabilities (noncurrent liabilities)	0
Total mark-to-market derivative liabilities	(5)
Total mark-to-market derivative net assets	$ 42

Derivative Financial Instrume_4

Derivative Financial Instruments - Summary of Economic Hedges (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Derivative [Line Items]
Gains (Losses)	$ (986)	$ 568	$ 270
Economic Hedges \| Commodity Contract
Derivative [Line Items]
Gains (Losses)	(1,026)	571	280
Economic Hedges \| Commodity Contract \| Operating revenues
Derivative [Line Items]
Gains (Losses)	(1,193)	(635)	112
Economic Hedges \| Commodity Contract \| Purchased power and fuel
Derivative [Line Items]
Gains (Losses)	$ 167	$ 1,206	$ 168

Derivative Financial Instrume_5

Derivative Financial Instruments - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Derivative [Line Items]
Notational amount	$ 41
Economic Hedges
Derivative [Line Items]
Notational amount	$ 524	$ 486
Minimum
Derivative [Line Items]
Expected generation hedged in next twelve months	94%
Expected generation hedged in year two	75%
Maximum
Derivative [Line Items]
Expected generation hedged in next twelve months	97%
Expected generation hedged in year two	78%

Derivative Financial Instrume_6

Derivative Financial Instruments - Summary of Credit Risk Exposure (Details) $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($) counterparty
Derivative [Line Items]
Cash collateral	$ 152
Letters of credit held	111
Total Exposure Before Credit Collateral
Derivative [Line Items]
Total	1,894
Total Exposure Before Credit Collateral \| Internally rated — investment grade
Derivative [Line Items]
Total	106
Total Exposure Before Credit Collateral \| Internally rated — non-investment grade
Derivative [Line Items]
Total	374
Total Exposure Before Credit Collateral \| Investment grade
Derivative [Line Items]
Total	1,304
Total Exposure Before Credit Collateral \| Non-investment grade
Derivative [Line Items]
Total	110
Credit Collateral
Derivative [Line Items]
Total	263
Credit Collateral \| Internally rated — investment grade
Derivative [Line Items]
Total	0
Credit Collateral \| Internally rated — non-investment grade
Derivative [Line Items]
Total	40
Credit Collateral \| Investment grade
Derivative [Line Items]
Total	135
Credit Collateral \| Non-investment grade
Derivative [Line Items]
Total	88
Net Exposure
Derivative [Line Items]
Total	1,631
Net Exposure \| Financial Institutions
Derivative [Line Items]
Total	1,311
Net Exposure \| Energy cooperatives and municipalities
Derivative [Line Items]
Total	112
Net Exposure \| Financial Institutions
Derivative [Line Items]
Total	9
Net Exposure \| Other
Derivative [Line Items]
Total	199
Net Exposure \| Internally rated — investment grade
Derivative [Line Items]
Total	106
Net Exposure \| Internally rated — non-investment grade
Derivative [Line Items]
Total	334
Net Exposure \| Investment grade
Derivative [Line Items]
Total	1,169
Net Exposure \| Non-investment grade
Derivative [Line Items]
Total	$ 22
Number of Counterparties Greater than 10% of Net Exposure
Derivative [Line Items]
Number of counterparties \| counterparty	0
Number of Counterparties Greater than 10% of Net Exposure \| Internally rated — investment grade
Derivative [Line Items]
Number of counterparties \| counterparty	0
Number of Counterparties Greater than 10% of Net Exposure \| Internally rated — non-investment grade
Derivative [Line Items]
Number of counterparties \| counterparty	0
Number of Counterparties Greater than 10% of Net Exposure \| Investment grade
Derivative [Line Items]
Number of counterparties \| counterparty	0
Number of Counterparties Greater than 10% of Net Exposure \| Non-investment grade
Derivative [Line Items]
Number of counterparties \| counterparty	0
Net Exposure of Counterparties Greater than 10% of Net Exposure
Derivative [Line Items]
Total	$ 0
Net Exposure of Counterparties Greater than 10% of Net Exposure \| Internally rated — investment grade
Derivative [Line Items]
Total	0
Net Exposure of Counterparties Greater than 10% of Net Exposure \| Internally rated — non-investment grade
Derivative [Line Items]
Total	0
Net Exposure of Counterparties Greater than 10% of Net Exposure \| Investment grade
Derivative [Line Items]
Total	0
Net Exposure of Counterparties Greater than 10% of Net Exposure \| Non-investment grade
Derivative [Line Items]
Total	$ 0

Derivative Financial Instrume_7

Derivative Financial Instruments - Summary of Credit Risk Related Contingent Features (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Gross fair value of derivative contracts containing this feature	$ (4,736)	$ (3,872)
Offsetting fair value of in-the-money contracts under master netting arrangements	2,048	2,424
Net fair value of derivative contracts containing this feature	$ (2,688)	$ (1,448)

Derivative Financial Instrume_8

Derivative Financial Instruments - Summary of Cash Collateral and Letters of Credit (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Cash collateral posted	$ 1,636	$ 713
Letters of credit posted	947	755
Cash collateral held	765	182
Letters of credit held	115	124
Additional collateral required in the event of a credit downgrade below investment grade (at BB+/Ba1)	$ 3,337	$ 2,113

Debt and Credit Agreements - Co

Debt and Credit Agreements - Commercial Paper Borrowings (Details) - USD ($) $ in Millions	Dec. 31, 2022	Aug. 16, 2022	Feb. 09, 2022	Feb. 01, 2022	Jan. 31, 2022	Dec. 31, 2021	Apr. 08, 2020
Short-term Debt [Line Items]
Maximum Program Size	$ 5,802				$ 4,500	$ 6,631
Sale of Accounts Receivable
Short-term Debt [Line Items]
Maximum Program Size		$ 1,100					$ 900
Commercial Paper
Short-term Debt [Line Items]
Maximum Program Size	3,500					5,300
Outstanding Commercial Paper	$ 959					$ 702
Weighted Average Interest Rate on Commercial Paper Borrowings	4.90%					0.66%
Bilaterals
Short-term Debt [Line Items]
Maximum Program Size	$ 1,200					$ 1,200
Project Finance
Short-term Debt [Line Items]
Maximum Program Size	131					131
Liquidity Facility
Short-term Debt [Line Items]
Maximum Program Size	971		$ 1,000
Syndicated Revolver
Short-term Debt [Line Items]
Maximum Program Size	$ 3,500			$ 3,500	$ 5,300	5,300
Syndicated Revolver \| Community and Minority Facilities
Short-term Debt [Line Items]
Credit facility agreements with minority and community banks						$ 44

Debt and Credit Agreements - Na

Debt and Credit Agreements - Narrative (Details) $ in Millions								1 Months Ended	12 Months Ended	16 Months Ended
	Feb. 09, 2023 USD ($)	Jan. 26, 2023 USD ($)	Mar. 29, 2022 USD ($)	Jan. 31, 2022 USD ($)	Aug. 06, 2021 USD ($)	May 13, 2021 USD ($)	Mar. 19, 2020 USD ($)	Nov. 30, 2017 USD ($)	Dec. 31, 2022 USD ($) MW	Aug. 05, 2022	Feb. 09, 2022 USD ($)	Feb. 01, 2022 USD ($)	Dec. 31, 2021 USD ($)	Mar. 31, 2020 USD ($)	Mar. 31, 2016 USD ($)	Dec. 31, 2015	Sep. 30, 2013 USD ($)	Dec. 31, 2011 USD ($)
Schedule of line of credit, short term, and long term debt [Line Items]
Credit facility				$ 4,500					$ 5,802				$ 6,631
Short-term borrowings				200					1,159				2,082
Loan									0				0
Loan balance									4,650
Letters of credit outstanding									2,475				2,375
Total long-term debt									4,650				6,101
Nonrecourse
Schedule of line of credit, short term, and long term debt [Line Items]
Nonrecourse debt									2,000
Exelon Corporate
Schedule of line of credit, short term, and long term debt [Line Items]
Notes payable to related parties													319
Repayments of related party debt				258
Syndicated Revolver
Schedule of line of credit, short term, and long term debt [Line Items]
Credit facility				$ 5,300					3,500			$ 3,500	5,300
Loan									0				0
Letters of credit outstanding									765				1,230
Liquidity Facility
Schedule of line of credit, short term, and long term debt [Line Items]
Credit facility									971		$ 1,000
Loan									0
Letters of credit outstanding									$ 732
Daily Simple SOFR Rate \| Maximum
Schedule of line of credit, short term, and long term debt [Line Items]
Basis spread									0.275%
Daily Simple SOFR Rate \| Non-investment grade \| Maximum
Schedule of line of credit, short term, and long term debt [Line Items]
Basis spread									1%
Term SOFR Rate \| Maximum
Schedule of line of credit, short term, and long term debt [Line Items]
Basis spread									1.275%
Term SOFR Rate \| Non-investment grade \| Maximum
Schedule of line of credit, short term, and long term debt [Line Items]
Basis spread									2%
Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate \| Syndicated Revolver
Schedule of line of credit, short term, and long term debt [Line Items]
Line of credit facility, interest rate at period end												1.275%
Short Term Loan Agreements \| Unsecured notes
Schedule of line of credit, short term, and long term debt [Line Items]
Short-term borrowings			$ 200		$ 880		$ 200							$ 300
Repayments of short-term debt			$ 100
Debt instrument term					364 days
Short Term Loan Agreements \| Unsecured notes \| Subsequent Event
Schedule of line of credit, short term, and long term debt [Line Items]
Short-term borrowings	$ 400	$ 100
Short Term Loan Agreements \| London Interbank Offered Rate (LIBOR) \| Unsecured notes
Schedule of line of credit, short term, and long term debt [Line Items]
Basis spread					0.875%		0.875%			1%
Short Term Loan Agreements \| Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate \| Unsecured notes
Schedule of line of credit, short term, and long term debt [Line Items]
Basis spread			0.80%
Short Term Loan Agreements \| Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate \| Unsecured notes \| Subsequent Event
Schedule of line of credit, short term, and long term debt [Line Items]
Basis spread	1.05%	0.80%
Continetal Wind \| Nonrecourse
Schedule of line of credit, short term, and long term debt [Line Items]
Credit facility									$ 122
Loan balance									345				380
Letters of credit outstanding									$ 111
Notes																	$ 613
Total net capacity (in megawatts) \| MW									667
Rates									6%
Revolver facility									$ 4
Renewable Power Generation \| Nonrecourse
Schedule of line of credit, short term, and long term debt [Line Items]
Loan balance									80				90
Notes															$ 150
Rates															4.11%
Renewables 2017 \| Nonrecourse
Schedule of line of credit, short term, and long term debt [Line Items]
Loan balance								$ 850	709
Notational amount, debt								$ 636
Interest rate, debt hedge								2.32%
Total long-term debt									850
Renewables 2020 \| Nonrecourse
Schedule of line of credit, short term, and long term debt [Line Items]
Loan balance									$ 750
Rates									2.50%
Notational amount, debt									$ 516
Interest rate, debt hedge									1.05%
Floor rate									1%
Total long-term debt									$ 690				735
West Medway II, LLC \| Nonrecourse
Schedule of line of credit, short term, and long term debt [Line Items]
Credit facility						$ 150
Rates						3%
Notational amount, debt						$ 113
Interest rate, debt hedge						0.61%
Total long-term debt									$ 115				135
Antelope Valley Solar Ranch One \| Nonrecourse
Schedule of line of credit, short term, and long term debt [Line Items]
Basis spread									0.375%
Loan																		$ 646
Average blended interest rate																2.82%
Loan balance									$ 415				$ 435
Letters of credit outstanding									$ 37

Debt and Credit Agreements - Su

Debt and Credit Agreements - Summary of Bank Commitments, Credit Facility Borrowings and Available Capacity (Details) - USD ($) $ in Millions	Dec. 31, 2022	Feb. 09, 2022	Feb. 01, 2022	Jan. 31, 2022	Dec. 31, 2021
Short-term Debt [Line Items]
Aggregate Bank Commitment	$ 5,802			$ 4,500	$ 6,631
Facility Draws	0				0
Outstanding Letters of Credit	2,475				2,375
Actual	3,227				4,256
To Support Additional Commercial Paper	1,776				3,368
Syndicated Revolver
Short-term Debt [Line Items]
Aggregate Bank Commitment	3,500		$ 3,500	$ 5,300	5,300
Facility Draws	0				0
Outstanding Letters of Credit	765				1,230
Actual	2,735				4,070
To Support Additional Commercial Paper	1,776				3,368
Syndicated Revolver \| Community and Minority Facilities
Short-term Debt [Line Items]
Line of credit facility, current borrowing capacity					44
Syndicated Revolver \| Community and Minority Facilities \| Letter of credit
Short-term Debt [Line Items]
Line of credit facility, current borrowing capacity					5
Bilaterals
Short-term Debt [Line Items]
Aggregate Bank Commitment	1,200				1,200
Facility Draws	0				0
Outstanding Letters of Credit	867				1,029
Actual	333				171
To Support Additional Commercial Paper	0				0
Liquidity Facility
Short-term Debt [Line Items]
Aggregate Bank Commitment	971	$ 1,000
Facility Draws	0
Outstanding Letters of Credit	732
Actual	139
To Support Additional Commercial Paper	0
Liquidity Facility \| No Additional Collateral Posted
Short-term Debt [Line Items]
Actual	871
Project Finance
Short-term Debt [Line Items]
Aggregate Bank Commitment	131				131
Facility Draws	0				0
Outstanding Letters of Credit	111				116
Actual	20				15
To Support Additional Commercial Paper	$ 0				$ 0

Debt and Credit Agreements - _2

Debt and Credit Agreements - Summary of Credit Facility Thresholds (Details) - USD ($) $ in Millions	Jan. 31, 2023	Jan. 20, 2023	Dec. 31, 2022	Jan. 31, 2022	Dec. 31, 2021
Line of Credit Facility [Line Items]
Credit facility			$ 5,802	$ 4,500	$ 6,631
Bilaterals
Line of Credit Facility [Line Items]
Credit facility			1,200		$ 1,200
Bilaterals \| January 5, 2016
Line of Credit Facility [Line Items]
Credit facility			150
Bilaterals \| October 25, 2019
Line of Credit Facility [Line Items]
Credit facility			200
Bilaterals \| November 20, 2019
Line of Credit Facility [Line Items]
Credit facility			300
Bilaterals \| November 21, 2019(N/A)
Line of Credit Facility [Line Items]
Credit facility			100
Bilaterals \| November 21, 2019(November 21, 2022)
Line of Credit Facility [Line Items]
Credit facility			100
Bilaterals \| May 15, 2020
Line of Credit Facility [Line Items]
Credit facility			200
Bilaterals \| August 12, 2022
Line of Credit Facility [Line Items]
Credit facility			50
Bilaterals \| August 24, 2022
Line of Credit Facility [Line Items]
Credit facility			$ 100
Bilaterals \| January 20, 2023 \| Subsequent Event
Line of Credit Facility [Line Items]
Credit facility		$ 10
Bilaterals \| January 31, 2023 \| Subsequent Event
Line of Credit Facility [Line Items]
Credit facility	$ 250

Debt and Credit Agreements - _3

Debt and Credit Agreements - Summary of Outstanding Long-term Debt (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Debt Instrument [Line Items]
Total long-term debt	$ 4,650	$ 6,101
Unamortized debt discount and premium, net	(5)	(7)
Unamortized debt issuance costs	(36)	(42)
Fair value adjustment	0	62
Long-term debt due within one year	(143)	(1,220)
Long-term debt	4,466	4,894
Senior unsecured notes
Debt Instrument [Line Items]
Total long-term debt	$ 2,938	4,219
Senior unsecured notes \| Minimum
Debt Instrument [Line Items]
Rates	3.25%
Senior unsecured notes \| Maximum
Debt Instrument [Line Items]
Rates	6.25%
Notes payable and other
Debt Instrument [Line Items]
Total long-term debt	$ 68	103
Notes payable and other \| Minimum
Debt Instrument [Line Items]
Rates	2.10%
Notes payable and other \| Maximum
Debt Instrument [Line Items]
Rates	6.96%
Fixed rates
Debt Instrument [Line Items]
Total long-term debt	$ 839	909
Fixed rates \| Minimum
Debt Instrument [Line Items]
Rates	2.29%
Fixed rates \| Maximum
Debt Instrument [Line Items]
Rates	6%
Variable rates
Debt Instrument [Line Items]
Total long-term debt	$ 805	$ 870
Variable rates \| Minimum
Debt Instrument [Line Items]
Rates	2.99%
Variable rates \| Maximum
Debt Instrument [Line Items]
Rates	7.24%

Debt and Credit Agreements - Sc

Debt and Credit Agreements - Schedule of Long-term Debt Maturities (Details) $ in Millions	Dec. 31, 2022 USD ($)
Debt Disclosure [Abstract]
2023	$ 143
2024	110
2025	986
2026	121
2027	735
Thereafter	2,555
Total	$ 4,650

Fair Value of Financial Asset_3

Fair Value of Financial Assets and Liabilities - Fair Value of Financial Liabilities Recorded at Amortized Cost (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-Term Debt, including amounts due within one year	$ 0	$ 62
SNF Obligation	1,230	1,210
Carrying Amount
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-Term Debt, including amounts due within one year	4,609	6,114
SNF Obligation	1,230	1,210
Fair Value
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-Term Debt, including amounts due within one year	4,547	6,842
SNF Obligation	1,021	1,060
Fair Value \| Level 2
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-Term Debt, including amounts due within one year	3,688	5,749
SNF Obligation	1,021	1,060
Fair Value \| Level 3
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-Term Debt, including amounts due within one year	859	1,093
SNF Obligation	$ 0	$ 0

Fair Value of Financial Asset_4

Fair Value of Financial Assets and Liabilities - Fair Value Measurement of Assets and Liabilities, Recurring (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Net derivative assets	$ 1	$ 1
Net derivative liabilities	1	1
Asset, notational amount	494	687
Liability, notational amount	494	687
Notational amount	41
Variation margin	836	897
Cash and Cash Equivalents \| Constellation Energy Generation, LLC
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Cash equivalents	390	417
Restricted cash \| Constellation Energy Generation, LLC
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Cash equivalents	70	46
Nuclear Decommissioning Trust Fund Investments \| Maturity Less than 30 Days
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Cash	99	116
Exelon Corporate \| Cash and Cash Equivalents
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Cash equivalents	49
Exelon Corporate \| Cash
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Cash equivalents	19
Nuclear Decommissioning Trust Fund Investments
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Investments in equities sold short	(45)	(55)
Net liabilities	168	111
Notational amount	59	182
Fair Value, Recurring
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Cash equivalents	41	113
DPP consideration	515	365
Total assets	18,554	19,880
Deferred compensation obligation	(57)	(43)
Total liabilities	(2,598)	(1,533)
Total net assets	15,956	18,347
Fair Value, Recurring \| Commodity derivative liabilities subtotal
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Commodity derivative liabilities	(2,541)	(1,490)
Fair Value, Recurring \| Economic hedges
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Commodity derivative liabilities	(20,257)	(13,036)
Fair Value, Recurring \| Proprietary trading
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Commodity derivative liabilities	(6)	(20)
Fair Value, Recurring \| Effect of netting and allocation of collateral
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Commodity derivative liabilities	17,722	11,566
Fair Value, Recurring \| Nuclear Decommissioning Trust Fund Investments
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	14,295	16,175
Fair Value, Recurring \| Cash equivalents
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	437	581
Fair Value, Recurring \| Equities
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	6,381	8,014
Fair Value, Recurring \| Fixed income subtotal
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	4,974	5,241
Fair Value, Recurring \| Corporate debt
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	1,149	1,431
Fair Value, Recurring \| U.S. Treasury and agencies
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	2,042	2,223
Fair Value, Recurring \| Foreign governments
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	39	60
Fair Value, Recurring \| State and municipal debt
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	53	26
Fair Value, Recurring \| Other
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	1,691	1,501
Fair Value, Recurring \| Private credit
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	802	802
Fair Value, Recurring \| Private equity
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	687	673
Fair Value, Recurring \| Real estate
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	1,014	864
Fair Value, Recurring \| Rabbi trust investments subtotal
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	68	72
Fair Value, Recurring \| Cash equivalents
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	1	3
Fair Value, Recurring \| Mutual funds
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	39	36
Fair Value, Recurring \| Life insurance contracts
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	28	33
Fair Value, Recurring \| Investments in equities
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	6	43
Fair Value, Recurring \| Commodity derivative assets subtotal
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Commodity derivative assets	3,629	3,112
Fair Value, Recurring \| Economic hedges
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Commodity derivative assets	20,443	14,139
Fair Value, Recurring \| Proprietary trading
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Commodity derivative assets	10	27
Fair Value, Recurring \| Effect of netting and allocation of  collateral
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Commodity derivative assets	(16,824)	(11,054)
Level 1
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Collateral posted (received) from counterparties	328	81
Level 1 \| Fair Value, Recurring
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Cash equivalents	41	113
DPP consideration	0	0
Total assets	6,469	8,355
Deferred compensation obligation	0	0
Total liabilities	108
Total liabilities		(12)
Total net assets	6,577	8,343
Level 1 \| Fair Value, Recurring \| Commodity derivative liabilities subtotal
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Commodity derivative liabilities	108	(12)
Level 1 \| Fair Value, Recurring \| Economic hedges
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Commodity derivative liabilities	(3,171)	(2,201)
Level 1 \| Fair Value, Recurring \| Proprietary trading
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Commodity derivative liabilities	0	0
Level 1 \| Fair Value, Recurring \| Effect of netting and allocation of collateral
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Commodity derivative liabilities	3,279	2,189
Level 1 \| Fair Value, Recurring \| Nuclear Decommissioning Trust Fund Investments
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	5,828	7,251
Level 1 \| Fair Value, Recurring \| Cash equivalents
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	349	465
Level 1 \| Fair Value, Recurring \| Equities
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	3,462	4,564
Level 1 \| Fair Value, Recurring \| Fixed income subtotal
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	2,017	2,222
Level 1 \| Fair Value, Recurring \| Corporate debt
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	0	0
Level 1 \| Fair Value, Recurring \| U.S. Treasury and agencies
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	1,996	2,193
Level 1 \| Fair Value, Recurring \| Foreign governments
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	0	0
Level 1 \| Fair Value, Recurring \| State and municipal debt
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	0	0
Level 1 \| Fair Value, Recurring \| Other
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	21	29
Level 1 \| Fair Value, Recurring \| Private credit
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	0	0
Level 1 \| Fair Value, Recurring \| Private equity
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	0	0
Level 1 \| Fair Value, Recurring \| Real estate
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	0	0
Level 1 \| Fair Value, Recurring \| Rabbi trust investments subtotal
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	40	39
Level 1 \| Fair Value, Recurring \| Cash equivalents
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	1	3
Level 1 \| Fair Value, Recurring \| Mutual funds
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	39	36
Level 1 \| Fair Value, Recurring \| Life insurance contracts
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	0	0
Level 1 \| Fair Value, Recurring \| Investments in equities
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	6	43
Level 1 \| Fair Value, Recurring \| Commodity derivative assets subtotal
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Commodity derivative assets	554	909
Level 1 \| Fair Value, Recurring \| Economic hedges
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Commodity derivative assets	3,505	3,017
Level 1 \| Fair Value, Recurring \| Proprietary trading
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Commodity derivative assets	0	0
Level 1 \| Fair Value, Recurring \| Effect of netting and allocation of  collateral
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Commodity derivative assets	(2,951)	(2,108)
Level 2
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Collateral posted (received) from counterparties	352	465
Level 2 \| Fair Value, Recurring
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Cash equivalents	0	0
DPP consideration	515	365
Total assets	4,181	4,668
Deferred compensation obligation	(57)	(43)
Total liabilities	(859)	(289)
Total net assets	3,322	4,379
Level 2 \| Fair Value, Recurring \| Commodity derivative liabilities subtotal
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Commodity derivative liabilities	(802)	(246)
Level 2 \| Fair Value, Recurring \| Economic hedges
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Commodity derivative liabilities	(11,498)	(6,870)
Level 2 \| Fair Value, Recurring \| Proprietary trading
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Commodity derivative liabilities	(4)	(18)
Level 2 \| Fair Value, Recurring \| Effect of netting and allocation of collateral
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Commodity derivative liabilities	10,700	6,642
Level 2 \| Fair Value, Recurring \| Nuclear Decommissioning Trust Fund Investments
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	2,630	3,205
Level 2 \| Fair Value, Recurring \| Cash equivalents
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	88	116
Level 2 \| Fair Value, Recurring \| Equities
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	1,498	1,805
Level 2 \| Fair Value, Recurring \| Fixed income subtotal
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	1,044	1,284
Level 2 \| Fair Value, Recurring \| Corporate debt
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	885	1,145
Level 2 \| Fair Value, Recurring \| U.S. Treasury and agencies
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	46	30
Level 2 \| Fair Value, Recurring \| Foreign governments
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	39	60
Level 2 \| Fair Value, Recurring \| State and municipal debt
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	53	26
Level 2 \| Fair Value, Recurring \| Other
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	21	23
Level 2 \| Fair Value, Recurring \| Private credit
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	0	0
Level 2 \| Fair Value, Recurring \| Private equity
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	0	0
Level 2 \| Fair Value, Recurring \| Real estate
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	0	0
Level 2 \| Fair Value, Recurring \| Rabbi trust investments subtotal
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	27	33
Level 2 \| Fair Value, Recurring \| Cash equivalents
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	0	0
Level 2 \| Fair Value, Recurring \| Mutual funds
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	0	0
Level 2 \| Fair Value, Recurring \| Life insurance contracts
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	27	33
Level 2 \| Fair Value, Recurring \| Investments in equities
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	0	0
Level 2 \| Fair Value, Recurring \| Commodity derivative assets subtotal
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Commodity derivative assets	1,009	1,065
Level 2 \| Fair Value, Recurring \| Economic hedges
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Commodity derivative assets	11,353	7,223
Level 2 \| Fair Value, Recurring \| Proprietary trading
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Commodity derivative assets	4	19
Level 2 \| Fair Value, Recurring \| Effect of netting and allocation of  collateral
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Commodity derivative assets	(10,348)	(6,177)
Level 3
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Collateral posted (received) from counterparties	218	(34)
Level 3 \| Fair Value, Recurring
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Cash equivalents	0	0
DPP consideration	0	0
Total assets	2,490	1,602
Deferred compensation obligation	0	0
Total liabilities	(1,847)	(1,232)
Total net assets	643	370
Level 3 \| Fair Value, Recurring \| Commodity derivative liabilities subtotal
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Commodity derivative liabilities	(1,847)	(1,232)
Level 3 \| Fair Value, Recurring \| Economic hedges
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Commodity derivative liabilities	(5,588)	(3,965)
Level 3 \| Fair Value, Recurring \| Proprietary trading
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Commodity derivative liabilities	(2)	(2)
Level 3 \| Fair Value, Recurring \| Effect of netting and allocation of collateral
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Commodity derivative liabilities	3,743	2,735
Level 3 \| Fair Value, Recurring \| Nuclear Decommissioning Trust Fund Investments
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	423	464
Level 3 \| Fair Value, Recurring \| Cash equivalents
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	0	0
Level 3 \| Fair Value, Recurring \| Equities
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	0	0
Level 3 \| Fair Value, Recurring \| Fixed income subtotal
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	264	286
Level 3 \| Fair Value, Recurring \| Corporate debt
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	264	286
Level 3 \| Fair Value, Recurring \| U.S. Treasury and agencies
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	0	0
Level 3 \| Fair Value, Recurring \| Foreign governments
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	0	0
Level 3 \| Fair Value, Recurring \| State and municipal debt
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	0	0
Level 3 \| Fair Value, Recurring \| Other
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	0	0
Level 3 \| Fair Value, Recurring \| Private credit
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	159	178
Level 3 \| Fair Value, Recurring \| Private equity
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	0	0
Level 3 \| Fair Value, Recurring \| Real estate
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	0	0
Level 3 \| Fair Value, Recurring \| Rabbi trust investments subtotal
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	1	0
Level 3 \| Fair Value, Recurring \| Cash equivalents
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	0	0
Level 3 \| Fair Value, Recurring \| Mutual funds
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	0	0
Level 3 \| Fair Value, Recurring \| Life insurance contracts
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	1	0
Level 3 \| Fair Value, Recurring \| Investments in equities
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	0	0
Level 3 \| Fair Value, Recurring \| Commodity derivative assets subtotal
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Commodity derivative assets	2,066	1,138
Level 3 \| Fair Value, Recurring \| Economic hedges
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Commodity derivative assets	5,585	3,899
Level 3 \| Fair Value, Recurring \| Proprietary trading
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Commodity derivative assets	6	8
Level 3 \| Fair Value, Recurring \| Effect of netting and allocation of  collateral
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Commodity derivative assets	(3,525)	(2,769)
Not subject to leveling \| Fair Value, Recurring
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Cash equivalents	0	0
DPP consideration	0	0
Total assets	5,414	5,255
Deferred compensation obligation	0	0
Total liabilities	0	0
Total net assets	5,414	5,255
Not subject to leveling \| Fair Value, Recurring \| Commodity derivative liabilities subtotal
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Commodity derivative liabilities	0	0
Not subject to leveling \| Fair Value, Recurring \| Economic hedges
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Commodity derivative liabilities	0	0
Not subject to leveling \| Fair Value, Recurring \| Proprietary trading
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Commodity derivative liabilities	0	0
Not subject to leveling \| Fair Value, Recurring \| Effect of netting and allocation of collateral
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Commodity derivative liabilities	0	0
Not subject to leveling \| Fair Value, Recurring \| Nuclear Decommissioning Trust Fund Investments
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	5,414	5,255
Not subject to leveling \| Fair Value, Recurring \| Cash equivalents
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	0	0
Not subject to leveling \| Fair Value, Recurring \| Equities
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	1,421	1,645
Not subject to leveling \| Fair Value, Recurring \| Fixed income subtotal
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	1,649	1,449
Not subject to leveling \| Fair Value, Recurring \| Corporate debt
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	0	0
Not subject to leveling \| Fair Value, Recurring \| U.S. Treasury and agencies
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	0	0
Not subject to leveling \| Fair Value, Recurring \| Foreign governments
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	0	0
Not subject to leveling \| Fair Value, Recurring \| State and municipal debt
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	0	0
Not subject to leveling \| Fair Value, Recurring \| Other
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	1,649	1,449
Not subject to leveling \| Fair Value, Recurring \| Private credit
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	643	624
Not subject to leveling \| Fair Value, Recurring \| Private equity
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	687	673
Not subject to leveling \| Fair Value, Recurring \| Real estate
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	1,014	864
Not subject to leveling \| Fair Value, Recurring \| Rabbi trust investments subtotal
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	0	0
Not subject to leveling \| Fair Value, Recurring \| Cash equivalents
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	0	0
Not subject to leveling \| Fair Value, Recurring \| Mutual funds
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	0	0
Not subject to leveling \| Fair Value, Recurring \| Life insurance contracts
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	0	0
Not subject to leveling \| Fair Value, Recurring \| Investments in equities
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
NDT fund investments	0	0
Not subject to leveling \| Fair Value, Recurring \| Commodity derivative assets subtotal
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Commodity derivative assets	0	0
Not subject to leveling \| Fair Value, Recurring \| Economic hedges
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Commodity derivative assets	0	0
Not subject to leveling \| Fair Value, Recurring \| Proprietary trading
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Commodity derivative assets	0	0
Not subject to leveling \| Fair Value, Recurring \| Effect of netting and allocation of  collateral
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items]
Commodity derivative assets	$ 0	$ 0

Fair Value of Financial Asset_5

Fair Value of Financial Assets and Liabilities - Narrative (Details) - USD ($) $ / shares in Units, $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity investments without readily determinable fair values	$ 46	$ 33
Forward power basis	$ 72.43
Forward gas basis	$ 4.57
Private credit
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Outstanding commitments	$ 235
Private equity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Outstanding commitments	139
Real estate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Outstanding commitments	$ 392

Fair Value of Financial Asset_6

Fair Value of Financial Assets and Liabilities - Fair Value Reconciliation of Level 3 Assets and Liabilities Measured on a Recurring Basis (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Abstract]
Beginning Balance	$ 0
Total realized / unrealized gains (losses)
Included in net income	55
Purchases, sales, issuances and settlements
Purchases	18
Settlements	4
Transfers into Level 3	220
Ending Balance	188	$ 0
Level 3
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Abstract]
Beginning Balance	370	927
Total realized / unrealized gains (losses)
Included in net income	(757)	(807)
Included in noncurrent payables to affiliates	(10)	19
Change in collateral	253	(196)
Impacts of separation	3
Purchases, sales, issuances and settlements
Purchases	599	166
Sales	(50)	(10)
Settlements	(137)	(61)
Transfers into Level 3	383	19
Transfers out of Level 3	(11)	313
Ending Balance	643	370
The amount of total gains (losses) included in income attributed to the change in unrealized losses related to assets and liabilities	(1,269)	(1,217)
NDT Fund Investments \| Level 3
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Abstract]
Beginning Balance	464	497
Total realized / unrealized gains (losses)
Included in net income	(2)	5
Included in noncurrent payables to affiliates	(10)	19
Change in collateral	0	0
Impacts of separation	0
Purchases, sales, issuances and settlements
Purchases	5	4
Sales	0	0
Settlements	(35)	(61)
Transfers into Level 3	2	0
Transfers out of Level 3	(1)	0
Ending Balance	423	464
The amount of total gains (losses) included in income attributed to the change in unrealized losses related to assets and liabilities	(2)	5
Mark-to-Market Derivatives \| Level 3
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Abstract]
Beginning Balance	(94)	430
Total realized / unrealized gains (losses)
Included in net income	(753)	(812)
Included in noncurrent payables to affiliates	0	0
Change in collateral	253	(196)
Impacts of separation	0
Purchases, sales, issuances and settlements
Purchases	594	162
Sales	(50)	(10)
Settlements	(102)	0
Transfers into Level 3	381	19
Transfers out of Level 3	(10)	313
Ending Balance	219	(94)
The amount of total gains (losses) included in income attributed to the change in unrealized losses related to assets and liabilities	(1,265)	(1,222)
Realized gains (losses)	410	410
Life Insurance Contracts \| Level 3
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Abstract]
Beginning Balance	0
Total realized / unrealized gains (losses)
Included in net income	(2)
Included in noncurrent payables to affiliates	0
Change in collateral	0
Impacts of separation	3
Purchases, sales, issuances and settlements
Purchases	0
Sales	0
Settlements	0
Transfers into Level 3	0
Transfers out of Level 3	0
Ending Balance	1	$ 0
The amount of total gains (losses) included in income attributed to the change in unrealized losses related to assets and liabilities	$ (2)

Fair Value of Financial Asset_7

Fair Value of Financial Assets and Liabilities - Fair Value Assets and Liabilities Measure on a Recurring Basis Gain Loss Included in Earnings (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Fair Value Assets and Liabilities Measured on a Recurring Basis Gain Loss Included in Earnings [Line Items]
Total (losses) gains included in net income	$ (55)
Operating Revenues
Fair Value Assets and Liabilities Measured on a Recurring Basis Gain Loss Included in Earnings [Line Items]
Total (losses) gains included in net income	(860)	$ (1,343)	$ (404)
Total unrealized (losses) gains	$ (1,330)	$ (1,577)	$ (31)
Fair Value, Asset, Recurring Basis, Unobservable Input Reconciliation, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Operating revenues	Operating revenues	Operating revenues
Fair Value, Asset, Recurring Basis, Still Held, Unrealized Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Operating revenues	Operating revenues	Operating revenues
Purchased power and fuel
Fair Value Assets and Liabilities Measured on a Recurring Basis Gain Loss Included in Earnings [Line Items]
Total (losses) gains included in net income	$ 5	$ 531	$ (10)
Total unrealized (losses) gains	$ 65	$ 355	$ 37
Fair Value, Asset, Recurring Basis, Unobservable Input Reconciliation, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Purchased power and fuel	Purchased power and fuel	Purchased power and fuel
Fair Value, Asset, Recurring Basis, Still Held, Unrealized Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Purchased power and fuel	Purchased power and fuel	Purchased power and fuel
Other, net
Fair Value Assets and Liabilities Measured on a Recurring Basis Gain Loss Included in Earnings [Line Items]
Total (losses) gains included in net income	$ (4)	$ 5	$ 2
Total unrealized (losses) gains	$ (2)	$ 5	$ 2
Fair Value, Asset, Recurring Basis, Unobservable Input Reconciliation, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Other, net	Other, net	Other, net
Fair Value, Asset, Recurring Basis, Still Held, Unrealized Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Other, net	Other, net	Other, net

Fair Value of Financial Asset_8

Fair Value of Financial Assets and Liabilities - Fair Value Inputs Assets Quantitative Information (Details) - Level 3 $ in Millions	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)
Fair Value Measurement Inputs and Valuation Techniques [Abstract]
Cash collateral posted (received)	$ 218	$ (34)
Economic Hedges
Fair Value Measurement Inputs and Valuation Techniques [Abstract]
Mark-to-market derivatives—Economic hedges	$ (3)	$ (66)
Economic Hedges \| Minimum \| Discounted Cash Flow
Fair Value Measurement Inputs and Valuation Techniques [Abstract]
Forward power price	0.63	8.86
Forward gas price	1.67	1.69
Economic Hedges \| Minimum \| Option Model
Fair Value Measurement Inputs and Valuation Techniques [Abstract]
Volatility percentage	0.97	0.24
Economic Hedges \| Maximum \| Discounted Cash Flow
Fair Value Measurement Inputs and Valuation Techniques [Abstract]
Forward power price	283	481
Forward gas price	26	17
Economic Hedges \| Maximum \| Option Model
Fair Value Measurement Inputs and Valuation Techniques [Abstract]
Volatility percentage	1.19	2.84
Economic Hedges \| Arithmetic Average \| Discounted Cash Flow
Fair Value Measurement Inputs and Valuation Techniques [Abstract]
Forward power price	72	55
Forward gas price	4.57	3.50
Economic Hedges \| Arithmetic Average \| Option Model
Fair Value Measurement Inputs and Valuation Techniques [Abstract]
Volatility percentage	1.11	0.56

Commitments and Contingencies -

Commitments and Contingencies - Schedule of Commercial Commitments (Details) $ in Millions	Dec. 31, 2022 USD ($)
Guarantor Obligations [Line Items]
Total	$ 3,453
2023	3,442
2024	11
2025	0
2026	0
2027	0
2028 and beyond	0
Letters of credit
Guarantor Obligations [Line Items]
Total	2,475
2023	2,465
2024	10
2025	0
2026	0
2027	0
2028 and beyond	0
Surety bonds
Guarantor Obligations [Line Items]
Total	978
2023	977
2024	1
2025	0
2026	0
2027	0
2028 and beyond	$ 0

Commitments and Contingencies_2

Commitments and Contingencies - Narrative (Details) $ in Millions		12 Months Ended
	Mar. 22, 2021 USD ($)	Dec. 31, 2022 USD ($) Open_claim	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2016 USD ($)	Jun. 30, 2022 USD ($)	Aug. 03, 2020 USD ($)	Mar. 31, 2019 USD ($)	Sep. 30, 2018 USD ($)	Jan. 01, 2017 USD ($)
Commitments and Contingencies [Line Items]
Gain (loss) recognized		$ 50	$ 0	$ 0
Nuclear financial protection pool value										$ 450
Maximum recovery limit from a nuclear industry mutual insurance company in the event of multiple losses										13,200
Maximum annual assessment payment mandated by Price-Anderson Act for a nuclear incident										2,800
Maximum aggregate annual retrospective premium obligation		252
Maximum recovery, aggregate		3,200
Total cumulative cash reimbursements		1,731
Net cumulative cash reimbursements		1,501
Accrued undiscounted amounts, environmental liabilities		119	120
Asbestos-related bodily injury claims		$ 95	81
Former ComEd units
Commitments and Contingencies [Line Items]
Treasury interest rate		4.169%
Fitzpatrick
Commitments and Contingencies [Line Items]
Treasury interest rate		3.415%
Prior Merger Commitment
Commitments and Contingencies [Line Items]
Gain (loss) recognized		$ 50
Prior Merger Commitment
Commitments and Contingencies [Line Items]
Gain (loss) recognized					$ (50)
LDC Damages
Commitments and Contingencies [Line Items]
Avoided damages	$ 40
Damages sought			40			$ 11
West Lake
Commitments and Contingencies [Line Items]
Accrued undiscounted amounts, environmental liabilities								$ 295	$ 50
Environmental loss contingencies							$ 90
Open Claims
Commitments and Contingencies [Line Items]
Asbestos-related bodily injury claims		$ 23
Open claims \| Open_claim		253
Estimated Future Claims
Commitments and Contingencies [Line Items]
Asbestos-related bodily injury claims		$ 72
Nuclear Insurance Premiums
Commitments and Contingencies [Line Items]
Nuclear insurance liability limit per incident		13,700
Nuclear Insurance Premiums \| Maximum
Commitments and Contingencies [Line Items]
Nuclear financial protection pool value										$ 413
Guarantees Other Than Letters Of Credit and Nuclear Insurance Premiums
Commitments and Contingencies [Line Items]
Annual distribution, portion		$ 30	$ 114	$ 75

Commitments and Contingencies_3

Commitments and Contingencies - Settlement Agreements (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Commitments and Contingencies Disclosure [Abstract]
DOE receivable - current	$ 125	$ 241
DOE receivable - noncurrent	130	85
Amounts owed to co-owners	$ (12)	$ (35)

Commitments and Contingencies_4

Commitments and Contingencies - Schedule of Spent Nuclear Fuel Obligation (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Spent Nuclear Fuel Obligation [Line Items]
Spent nuclear fuel obligation	$ 1,230	$ 1,210
Former ComEd units
Spent Nuclear Fuel Obligation [Line Items]
Spent nuclear fuel obligation	1,100	1,083
One time fee	277
Fitzpatrick
Spent Nuclear Fuel Obligation [Line Items]
Spent nuclear fuel obligation	130	$ 127
One time fee	$ 34

Stock-Based Compensation Plan_2

Stock-Based Compensation Plans - Narrative (Details) - shares	12 Months Ended
	Dec. 31, 2022	Feb. 01, 2022
Long Term Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares authorized		20,000,000
Performance share awards \| Long Term Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance period	3 years
Percentage to be settled as common stock	50%
Percentage to be settled as cash	50%
Vesting period	3 years
Restricted stock units \| Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Requisite service period	3 years
Restricted stock units \| Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Requisite service period	5 years

Stock-Based Compensation Plan_3

Stock-Based Compensation Plans - Schedule of Stock-based Compensation Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Share-Based Payment Arrangement [Abstract]
Total stock-based compensation expense included in operating and maintenance expense	$ 116	$ 47	$ 27
Income tax benefit	(29)	(12)	(7)
Total after-tax stock-based compensation expense	$ 87	$ 35	$ 20

Stock-Based Compensation Plan_4

Stock-Based Compensation Plans - Compensation Costs Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Tax benefit on stock compensation	$ 29	$ 12	$ 7
Restricted stock units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Tax benefit on stock compensation	$ 2

Stock-Based Compensation Plan_5

Stock-Based Compensation Plans - Unit Activity (Details)	12 Months Ended
Stock-Based Compensation Plans - Unit Activity (Details)	Dec. 31, 2022 $ / shares shares
Performance share awards
Shares
Beginning Balance (in shares)	0
Granted (in shares)	1,575,542
Change in performance (in shares)	728,054
Forfeited (in shares)	(22,617)
Undistributed vested awards (in shares)	(1,431,637)
Ending Balance (in shares)	849,342
Fully vested (in shares)	1,272,921
Weighted Average Grant Date Fair Value (per share)
Beginning balance (in dollars per share) \| $ / shares	$ 0
Granted (in dollars per share) \| $ / shares	48.33
Change in performance (in dollars per share) \| $ / shares	47.30
Forfeited (in dollars per share) \| $ / shares	48.55
Undistributed vested awards (in dollars per share) \| $ / shares	48.35
Ending balance (in dollars per share) \| $ / shares	$ 47.40
Restricted stock units
Shares
Beginning Balance (in shares)	0
Granted (in shares)	1,497,651
Vested (in shares)	(144,903)
Forfeited (in shares)	(62,238)
Undistributed vested awards (in shares)	(499,842)
Ending Balance (in shares)	790,668
Weighted Average Grant Date Fair Value (per share)
Beginning balance (in dollars per share) \| $ / shares	$ 0
Granted (in dollars per share) \| $ / shares	54.17
Vested (in dollars per share) \| $ / shares	49.82
Forfeited (in dollars per share) \| $ / shares	59.47
Undistributed vested awards (in dollars per share) \| $ / shares	55.16
Ending balance (in dollars per share) \| $ / shares	$ 53.72

Stock-Based Compensation Plan_6

Stock-Based Compensation Plans - Unit Fair Value (Details) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($) $ / shares
Performance share awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant date fair value (in dollars per share) \| $ / shares	$ 48.33
Total fair value of performance shares vested	$ 69
Unrecognized compensation costs	$ 28
Remaining weighted-average period	1 year 8 months 12 days
Restricted stock units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant date fair value (in dollars per share) \| $ / shares	$ 54.17
Total fair value of performance shares vested	$ 35
Unrecognized compensation costs	$ 27
Remaining weighted-average period	2 years

Changes in Accumulated Other _3

Changes in Accumulated Other Comprehensive Income - Schedule of Changes in AOCI (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning Balance	$ 11,614	$ 14,676	$ 15,830
Separation-related adjustments	(197)
Other comprehensive income (loss), net of income taxes	277	(1)	2
Ending Balance	11,372	11,614	14,676
Losses on Cash Flow Hedges
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning Balance	(8)	(7)	(5)
Separation-related adjustments	0
OCI before reclassifications	(1)	(1)	(2)
Amounts reclassified from AOCI	0
Other comprehensive income (loss), net of income taxes	(1)	(1)	(2)
Ending Balance	(9)	(8)	(7)
Pension and non-pension postretirement benefit plans valuation adjustment(a)
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning Balance	0	0	0
Separation-related adjustments	(2,006)
OCI before reclassifications	186	0	0
Amounts reclassified from AOCI	95
Other comprehensive income (loss), net of income taxes	(1,725)	0	0
Ending Balance	(1,725)	0	0
Foreign Currency Items
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning Balance	(23)	(23)	(27)
Separation-related adjustments	0
OCI before reclassifications	(3)	0	4
Amounts reclassified from AOCI	0
Other comprehensive income (loss), net of income taxes	(3)	0	4
Ending Balance	(26)	(23)	(23)
Total
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning Balance	(31)	(30)	(32)
Separation-related adjustments	(2,006)
OCI before reclassifications	182	(1)	2
Amounts reclassified from AOCI	95
Other comprehensive income (loss), net of income taxes	(1,729)	(1)	2
Ending Balance	$ (1,760)	$ (31)	$ (30)

Changes in Accumulated Other _4

Changes in Accumulated Other Comprehensive Income - Income Taxes Allocated to Other Comprehensive Income (Loss) Components (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Actuarial loss reclassified to periodic benefit cost
Accumulated Other Comprehensive Income (Loss) [Line Items]
Pension and non-pension postretirement benefit plans	$ (33)	$ 0	$ 0
Pension and non-pension postretirement benefit plans valuation adjustment(a)
Accumulated Other Comprehensive Income (Loss) [Line Items]
Pension and non-pension postretirement benefit plans	619	$ 0	$ 0
Income tax benefit related to separation adjustment	$ 680

Variable Interest Entities - As

Variable Interest Entities - Assets and Liabilities of Consolidated VIEs (Details) - USD ($) $ in Millions		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Current assets
Cash and cash equivalents		$ 422	$ 504	$ 226	$ 303
Restricted cash and cash equivalents		106	72	$ 89	$ 146
Accounts receivable
Customer		2,585	1,669
Other		731	592
Inventories, net
Materials and supplies		1,076	1,004
Other current assets		1,026	1,007
Total current assets		9,360	7,981
Property, plant and equipment, net		19,822	19,612
Other		2,106	1,717
Total assets	[1]	46,909	48,086
Current liabilities
Long-term debt due within one year		143	1,220
Accounts payable		2,828	1,757
Accrued expenses		906	737
Other current liabilities		344	311
Total current liabilities		7,839	7,996
Long-term debt		4,466	4,575
Other noncurrent liabilities		1,178	1,133
Total deferred credits and other liabilities		23,232	23,582
Total liabilities	[1]	35,537	36,472
Recourse [Member]
Current liabilities
Total liabilities		1	1
Variable Interest Entity, Primary Beneficiary
Current assets
Cash and cash equivalents		51	35
Restricted cash and cash equivalents		46	48
Accounts receivable
Customer		20	24
Other		9	6
Inventories, net
Materials and supplies		12	14
Other current assets		549	405
Total current assets		687	532
Property, plant and equipment, net		1,965	2,027
Other		190	215
Total noncurrent assets		2,155	2,242
Total assets		2,842	2,774
Current liabilities
Long-term debt due within one year		60	70
Accounts payable		17	10
Accrued expenses		23	21
Other current liabilities		2	1
Total current liabilities		102	102
Long-term debt		764	822
Asset retirement obligations		173	151
Other noncurrent liabilities		3	3
Total deferred credits and other liabilities		940	976
Total liabilities		1,042	1,078
Unamortized energy contract assets, current		23	23
Unamortized energy contract assets, noncurrent		$ 178	$ 202

[1]Our consolidated assets include $2,641 million and $2,549 million at December 31, 2022 and 2021, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Our consolidated liabilities include $1,041 million and $1,077 million at December 31, 2022 and 2021, respectively, of certain VIEs for which the VIE creditors do not have recourse to us. See Note 22–Variable Interest Entities for additional information.

Variable Interest Entities - Na

Variable Interest Entities - Narrative (Details)	Dec. 31, 2022	Dec. 31, 2021
CRP
Variable Interest Entity [Line Items]
Ownership interest	51%	51%
Antelope Valley
Variable Interest Entity [Line Items]
Ownership interest	100%	100%
NER
Variable Interest Entity [Line Items]
Ownership interest	100%	100%
Distributed Energy Company
Variable Interest Entity [Line Items]
Ownership interest	90%	90%
Constellation Energy Generation, LLC \| Solar project entities
Variable Interest Entity [Line Items]
Ownership interest	100%
Constellation Energy Generation, LLC \| Wind project entities
Variable Interest Entity [Line Items]
Ownership interest	100%

Variable Interest Entities - Su

Variable Interest Entities - Summary of Significant Unconsolidated VIEs (Details) - USD ($) $ in Millions		Dec. 31, 2022	Dec. 31, 2021
Variable Interest Entity [Line Items]
Total assets	[1]	$ 46,909	$ 48,086
Total liabilities	[1]	35,537	36,472
Variable Interest Entity, Not Primary Beneficiary
Variable Interest Entity [Line Items]
Total assets		715	1,144
Total liabilities		54	296
Our ownership interest in VIE		0	139
Other ownership interests in VIE		661	709
Commercial Agreement VIEs \| Variable Interest Entity, Not Primary Beneficiary
Variable Interest Entity [Line Items]
Total assets		715	772
Total liabilities		54	80
Our ownership interest in VIE		0	0
Other ownership interests in VIE		661	692
Equity Investment VIEs \| Variable Interest Entity, Not Primary Beneficiary
Variable Interest Entity [Line Items]
Total assets		0	372
Total liabilities		0	216
Our ownership interest in VIE		0	139
Other ownership interests in VIE		$ 0	$ 17

[1]Our consolidated assets include $2,641 million and $2,549 million at December 31, 2022 and 2021, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Our consolidated liabilities include $1,041 million and $1,077 million at December 31, 2022 and 2021, respectively, of certain VIEs for which the VIE creditors do not have recourse to us. See Note 22–Variable Interest Entities for additional information.

Supplemental Financial Inform_3

Supplemental Financial Information - Summary of Taxes Other Than Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Income Statement [Abstract]
Gross receipts	$ 130	$ 99	$ 99
Property	274	268	265
Payroll	$ 130	$ 109	$ 113

Supplemental Financial Inform_4

Supplemental Financial Information - Summary of Other Income (Expense) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Supplemental Financial Information [Abstract]
Net realized income on NDT funds - Regulatory Agreement Units	$ 333	$ 817	$ 185
Net realized income on NDT funds - Non-Regulatory Agreement Units	97	449	160
Net unrealized (losses) gains on NDT funds - Regulatory Agreement Units	(1,354)	351	724
Net unrealized (losses) gains on NDT funds - Non-Regulatory Agreement Units	(798)	209	391
Regulatory offset to NDT fund-related activities	820	(917)	(729)
Decommissioning-related activities	(902)	909	731
Investment income	58	0	0
Non-service net periodic benefit credit	110	0	0
Net unrealized (losses) gains from CTV investments	(13)	(160)	186
Return to provision adjustment	$ (49)	$ 0	$ 0

Supplemental Financial Inform_5

Supplemental Financial Information - Supplemental Cash Flow Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Depreciation, amortization and accretion
Property, plant, and equipment	$ 1,065	$ 2,954	$ 2,070
Amortization of intangible assets, net	61	80	81
Nuclear fuel	758	992	983
ARO accretion	543	514	500
Total depreciation, amortization, and accretion	2,427	4,540	3,636
Cash paid during the year
Interest (net of amount capitalized)	230	275	331
Income taxes (net of refunds)	287	426	70
Other non-cash operating activities
Pension and non-pension postretirement benefit costs	17	123	115
Other decommissioning-related activity	(263)	(946)	(659)
Energy-related options	293	125	104
Severance costs	(1)	(73)	90
Long-term incentive plan	44	0	0
Provision for excess and obsolete inventory	(12)	(13)	128
Amortization of operating ROU asset	75	119	155
Loss on sale of receivables	69	36	30
Fair value adjustments related to gas imbalances	37	0	0
Prior merger commitment	(50)	0	0
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]
Cash and cash equivalents	422	504	226	$ 303
Restricted cash and cash equivalents	106	72	89	146
Cash, restricted cash, and cash equivalents - Held for Sale			12
Total cash, restricted cash, and cash equivalents	528	576	327	449
Constellation Energy Generation, LLC
Depreciation, amortization and accretion
Total depreciation, amortization, and accretion	2,427	4,540	3,636
Other non-cash operating activities
Pension and non-pension postretirement benefit costs	17	123	115
Other decommissioning-related activity	(263)	(946)	(659)
Energy-related options	293	125	104
Severance costs	(1)	(73)	90
Long-term incentive plan	0	0	0
Provision for excess and obsolete inventory	(12)	(13)	128
Amortization of operating ROU asset	75	119	155
Loss on sale of receivables	69	36	30
Fair value adjustments related to gas imbalances	37	0	0
Prior merger commitment	(50)	0	0
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]
Cash and cash equivalents	403	504	226	303
Restricted cash and cash equivalents	98	72	89	146
Cash, restricted cash, and cash equivalents - Held for Sale			12
Total cash, restricted cash, and cash equivalents	501	576	327	$ 449
Amortization of Intangible Assets Included in Depreciation Expense
Depreciation, amortization and accretion
Amortization of intangible assets, net	26	49	53
Unamortized Energy Contracts
Depreciation, amortization and accretion
Amortization of energy contract assets and liabilities	$ 35	$ 31	$ 30

Supplemental Financial Inform_6

Supplemental Financial Information - Supplemental Balance Sheet Information (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Investments [Abstract]
Equity investments without readily determinable fair values	$ 46	$ 33
Total investments	202	174
Accrued Expenses [Abstract]
Compensation-related accruals	540	356
Taxes accrued	257	272
Equity method investments
Investments [Abstract]
Equity method investments	82	62
Employee benefit trusts and investments
Investments [Abstract]
Employee benefit trusts and investments	68	72
Other available for sale debt security investments
Investments [Abstract]
Other available for sale debt security investments	6	7
Constellation Energy Generation, LLC
Investments [Abstract]
Total investments	202	174
Accrued Expenses [Abstract]
Compensation-related accruals	502	356
Taxes accrued	$ 257	$ 272

Related Party Transactions - Op

Related Party Transactions - Operating Revenues and Purchased Power and Fuel From Affiliates (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Related Party Transaction [Line Items]
Total operating revenues from affiliates	$ 160	$ 1,188	$ 1,211
ComEd
Related Party Transaction [Line Items]
Total operating revenues from affiliates	58	376	330
PECO
Related Party Transaction [Line Items]
Total operating revenues from affiliates	33	196	190
BGE
Related Party Transaction [Line Items]
Total operating revenues from affiliates	18	236	315
PHI
Related Party Transaction [Line Items]
Total operating revenues from affiliates	51	366	367
Pepco
Related Party Transaction [Line Items]
Total operating revenues from affiliates	39	270	279
DPL
Related Party Transaction [Line Items]
Total operating revenues from affiliates	10	79	75
ACE
Related Party Transaction [Line Items]
Total operating revenues from affiliates	2	17	13
Other
Related Party Transaction [Line Items]
Total operating revenues from affiliates	$ 0	$ 14	$ 9

Related Party Transactions - BS

Related Party Transactions - BSC Service Companies (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Related Party Transaction [Line Items]
Operating and maintenance from affiliates	$ 44	$ 621	$ 555
BSC
Related Party Transaction [Line Items]
Operating and maintenance from affiliates	44	588	552
Capitalized costs	$ 15	$ 129	$ 54

Related Party Transactions - Cu

Related Party Transactions - Current Receivables From/Payables To Affiliates (Details) $ in Millions	Dec. 31, 2021 USD ($)
Related Party Transaction [Line Items]
Receivables from affiliates:	$ 160
Payables to affiliates:	131
ComEd
Related Party Transaction [Line Items]
Receivables from affiliates:	84
Payables to affiliates:	13
PECO
Related Party Transaction [Line Items]
Receivables from affiliates:	30
Payables to affiliates:	0
BGE
Related Party Transaction [Line Items]
Receivables from affiliates:	4
Payables to affiliates:	0
Pepco
Related Party Transaction [Line Items]
Receivables from affiliates:	20
Payables to affiliates:	0
DPL
Related Party Transaction [Line Items]
Receivables from affiliates:	4
Payables to affiliates:	0
ACE
Related Party Transaction [Line Items]
Receivables from affiliates:	7
Payables to affiliates:	0
BSC
Related Party Transaction [Line Items]
Receivables from affiliates:	0
Payables to affiliates:	102
Other
Related Party Transaction [Line Items]
Receivables from affiliates:	11
Payables to affiliates:	$ 16

Schedule II - Valuation and Q_2

Schedule II - Valuation and Qualifying Accounts Schedule (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Allowance for credit losses
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of Period	$ 59	$ 32	$ 81
Charged to Costs and Expenses	10	34	12
Charged to Other Accounts	0	0	(56)
Deductions	18	7	5
Balance at End of Period	51	59	32
Deferred tax valuation allowance
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of Period	22	23	24
Charged to Costs and Expenses	0	0	0
Charged to Other Accounts	(11)	(1)	(1)
Deductions	0	0	0
Balance at End of Period	11	22	23
Reserve for obsolete materials
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of Period	250	265	143
Charged to Costs and Expenses	11	(6)	123
Charged to Other Accounts	(6)	(2)	(1)
Deductions	17	7	0
Balance at End of Period	$ 238	$ 250	$ 265

Uncategorized Items - ceg-20221

Label	Element	Value
Noncontrolling Interest, Period Increase (Decrease)	us-gaap_MinorityInterestPeriodIncreaseDecrease	$ (7,000,000)
Other Postretirement Benefits Plan [Member]
Defined Benefit Plan, Benefit Obligation	us-gaap_DefinedBenefitPlanBenefitObligation	1,780,000,000
Pension Plan [Member]
Defined Benefit Plan, Benefit Obligation	us-gaap_DefinedBenefitPlanBenefitObligation	9,220,000,000
Retained Earnings [Member]
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	us-gaap_ProfitLoss	(311,000,000)
Noncontrolling Interest [Member]
Noncontrolling Interest, Period Increase (Decrease)	us-gaap_MinorityInterestPeriodIncreaseDecrease	(7,000,000)
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	us-gaap_ProfitLoss	(7,000,000)
Predecessor Member's Equity [Member]
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	us-gaap_ProfitLoss	$ 151,000,000	[1]

[1]Represents Constellation’s predecessor member's equity prior to the separation transaction. Upon completion of the separation, the predecessor member's equity was transferred to CEG Parent’s Common stock. See Note 1 — Basis of Presentation for additional information on the separation.