Exelon Generation 10-Q 8 Nov 22 2022 Q3 Quarterly report Financial data

Cover Page

Cover Page	9 Months Ended
	Sep. 30, 2022 shares
Document Information [Line Items]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Sep. 30, 2022
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 Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock Shares Outstanding	327,017,895
Document Fiscal Year Focus	2022
Document Fiscal Period Focus	Q3
Current Fiscal Year End Date	--12-31
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 Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Central Index Key	0001168165

Consolidated Statements of Oper

Consolidated Statements of Operations and Comprehensive Income, Parent - USD ($) shares in Thousands, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021
Operating revenues
Operating revenues	$ 6,051	$ 4,082	$ 16,947	$ 13,245
Operating revenues from affiliates	0	324	160	872
Total operating revenues	6,051	4,406	17,107	14,117
Operating expenses
Purchased power and fuel	4,695	1,542	11,749	8,103
Purchased power and fuel from affiliates	0	4	5	0
Operating and maintenance	989	761	3,422	2,955
Operating and maintenance from affiliates	0	177	44	458
Depreciation and amortization	262	866	818	2,735
Taxes other than income taxes	145	115	415	354
Total operating expenses	6,091	3,465	16,453	14,605
(Loss) gain on sales of assets and businesses	(1)	65	13	144
Operating (loss) income	(41)	1,006	667	(344)
Other income and (deductions)
Interest expense, net	(75)	(73)	(186)	(214)
Interest expense to affiliates	0	(4)	(1)	(11)
Other, net	(196)	(115)	(1,169)	561
Total other income and (deductions)	(271)	(192)	(1,356)	336
(Loss) income before income taxes	(312)	814	(689)	(8)
Income taxes	(123)	177	(504)	108
Equity in losses of unconsolidated affiliates	(4)	(4)	(10)	(6)
Net (loss) income	(193)	633	(195)	(122)
Net (loss) income attributable to noncontrolling interests	(5)	26	(1)	125
Net (loss) income attributable to membership interest	(188)	607	(194)	(247)
Comprehensive (loss) income, net of income taxes
Net loss	(193)	633	(195)	(122)
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	(2)	0	(4)	0
Actuarial loss reclassified to periodic cost	28	0	73	0
Pension and non-pension postretirement benefit plan valuation adjustment	4	0	4	0
Unrealized loss on cash flow hedges	(1)	(1)	0	(1)
Unrealized loss on foreign currency translation	(6)	(4)	(4)	0
Other comprehensive income (loss), net of income taxes	23	(4)	68	(1)
Comprehensive (loss) income	(170)	629	(127)	(123)
Comprehensive (loss) income attributable to noncontrolling interests	(5)	26	(1)	125
Comprehensive (loss) income attributable to membership interests	$ (165)	$ 603	$ (126)	$ (248)
Average shares of common stock outstanding:
Basic (in shares)	327,000	0	327,000	0
Assumed exercise and/or distributions of stock-based awards (in shares)	1,000	0	1,000	0
Diluted (in shares)	328,000	0	328,000	0
Earnings per average common share
Basic (in dollars per share)	$ (0.57)	$ 0	$ (0.59)	$ 0
Diluted (in dollars per share)	$ (0.57)	$ 0	$ (0.59)	$ 0

Consolidated Statements of Cash

Consolidated Statements of Cash Flows, Parent - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021
Cash flows from operating activities
Net loss	$ (195)	$ (122)
Adjustments to reconcile net loss to net cash flows provided by operating activities:
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization	1,810	3,951
Asset impairments	0	537
Gain on sales of assets and businesses	(13)	(144)
Deferred income taxes and amortization of investment tax credits	(915)	(204)
Net fair value changes related to derivatives	544	(1,244)
Net realized and unrealized losses (gains) on NDT funds	1,032	(383)
Net unrealized loss on CTV investments	27	83
Other non-cash operating activities	304	(582)
Changes in assets and liabilities:
Accounts receivable	(150)	(207)
Receivables from and payables to affiliates, net	20	82
Inventories	(166)	(29)
Accounts payable and accrued expenses	789	357
Option premiums paid, net	(163)	(186)
Collateral received, net	766	1,974
Income taxes	364	177
Pension and non-pension postretirement benefit contributions	(229)	(237)
Other assets and liabilities	(3,756)	(2,849)
Net cash flows (used in) provided by operating activities	69	974
Cash flows from investing activities
Capital expenditures	(1,090)	(1,086)
Proceeds from NDT fund sales	3,034	5,766
Investment in NDT funds	(3,212)	(5,900)
Collection of DPP, net	3,095	3,052
Proceeds from sales of assets and businesses	41	802
Other investing activities	3	5
Net cash flows provided by investing activities	1,871	2,639
Cash flows from financing activities
Change in short-term borrowings	(209)	(340)
Proceeds from short-term borrowings with maturities greater than 90 days	0	880
Repayments of short-term borrowings with maturities greater than 90 days	(1,180)	0
Issuance of long-term debt	9	152
Retirement of long-term debt	(1,143)	(89)
Retirement of long-term debt to affiliate	(258)	0
Changes in money pool with Exelon	0	(285)
Acquisition of CENG noncontrolling interest	0	(885)
Distributions to Exelon	0	(1,373)
Contribution from Exelon	1,750	64
Dividends paid on common stock	(139)	0
Other financing activities	(43)	(45)
Net cash flows used in financing activities	(1,213)	(1,921)
Increase in cash, restricted cash, and cash equivalents	727	1,692
Cash, restricted cash, and cash equivalents at beginning of period	576	327
Cash, restricted cash, and cash equivalents at end of period	1,303	2,019
Supplemental cash flow information
Decrease in capital expenditures not paid	(17)	(77)
Increase in DPP	3,733	2,933
Increase in PP&E related to ARO update	$ 342	$ 550

Consolidated Balance Sheets, Pa

Consolidated Balance Sheets, Parent - USD ($) $ in Millions		Sep. 30, 2022	Dec. 31, 2021
Current assets
Cash and cash equivalents		$ 1,192	$ 504
Restricted cash and cash equivalents		111	72
Accounts receivable
Customer accounts receivable (net of allowance for credit losses of $55 as of September 30, 2022 and December 31, 2021)		1,819	1,669
Other accounts receivable (net of allowance for credit losses of $5 as of September 30, 2022 and December 31, 2021)		579	592
Mark-to-market derivative assets		2,557	2,169
Receivables from affiliates		0	160
Inventories, net
Natural gas, oil and emission allowances		422	284
Materials and supplies		1,042	1,004
Renewable energy credits		524	520
Other		1,607	1,007
Total current assets		9,853	7,981
Property, plant, and equipment (net of accumulated depreciation and amortization of $16,574 and $15,873 as of September 30, 2022 and December 31, 2021, respectively)		19,705	19,612
Deferred debits and other assets
Nuclear decommissioning trust funds		13,453	15,938
Investments		193	174
Mark-to-market derivative assets		1,252	949
Prepaid pension asset		0	1,683
Deferred income taxes		23	32
Other		2,137	1,717
Total deferred debits and other assets		17,058	20,493
Total assets	[1]	46,616	48,086
Current liabilities
Short-term borrowings		693	2,082
Long-term debt due within one year		181	1,220
Accounts payable		2,597	1,757
Accrued expenses		933	737
Payables to affiliates		0	131
Mark-to-market derivative liabilities		2,392	981
Renewable energy credit obligation		773	777
Other		318	311
Total current liabilities		7,887	7,996
Long-term debt		4,480	4,575
Long-term debt to affiliates		0	319
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		2,647	3,703
Asset retirement obligations		12,564	12,819
Pension obligations		636	0
Non-pension postretirement benefit obligations		861	847
Spent nuclear fuel obligation		1,219	1,210
Payables to affiliates		0	3,357
Payables related to Regulatory Agreement Units		2,658	0
Mark-to-market derivative liabilities		1,244	513
Other		1,251	1,133
Total deferred credits and other liabilities		23,080	23,582
Total liabilities	[1]	35,447	36,472
Commitments and contingencies (Note 15)
Shareholders' equity
Predecessor Member's Equity	[2]	0	11,250
Common stock (No par value, 1,000 shares authorized, 327 shares outstanding as of September 30, 2022)		13,255	0
Retained deficit		(483)	0
Accumulated other comprehensive loss, net		(1,969)	(31)
Total shareholders’ equity		10,803	11,219
Noncontrolling interests		366	395
Total equity		11,169	11,614
Total liabilities and equity		$ 46,616	$ 48,086
[1]Our consolidated assets include $3,133 million and $2,549 million at September 30, 2022 and December 31, 2021, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Our consolidated liabilities include $1,049 million and $1,077 million at September 30, 2022 and December 31, 2021, respectively, of certain VIEs for which the VIE creditors do not have recourse to us. See Note 18 — 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.

Consolidated Balance Sheets, _2

Consolidated Balance Sheets, Parent (Parenthetical) $ in Millions	Sep. 30, 2022 USD ($) $ / shares shares
Allowance for credit losses	$ 55
Allowance for other credit losses	5
Accumulated depreciation and amortization	$ 16,574
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
Total assets	$ 46,616	[1]
Total liabilities	35,447	[1]
Variable Interest Entity, Primary Beneficiary
Total assets	3,339
Total liabilities	1,050
Variable Interest Entity, Primary Beneficiary | Nonrecourse
Total liabilities	1,049
Variable Interest Entity, Primary Beneficiary | Asset Pledged as Collateral
Total assets	$ 3,133
[1]Our consolidated assets include $3,133 million and $2,549 million at September 30, 2022 and December 31, 2021, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Our consolidated liabilities include $1,049 million and $1,077 million at September 30, 2022 and December 31, 2021, respectively, of certain VIEs for which the VIE creditors do not have recourse to us. See Note 18 — Variable Interest Entities for additional information.

Consolidated Statements of Chan

Consolidated Statements of Changes in Equity, Parent - USD ($) $ in Millions	Total	Common Stock	Membership Interest	Undistributed Earnings	Accumulated Other Comprehensive Loss, net	Noncontrolling Interests	Predecessor Member's Equity	[1]
Beginning Balance at Dec. 31, 2020	$ 14,676		$ 9,624	$ 2,805	$ (30)	$ 2,277
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net (loss) income	(769)			(793)		24
Changes in equity of noncontrolling interests	(10)					(10)
Distributions to member	(458)			(458)
Other comprehensive income, net of income taxes	1				1
Ending Balance at Mar. 31, 2021	13,440		9,624	1,554	(29)	2,291
Beginning Balance at Dec. 31, 2020	14,676		9,624	2,805	(30)	2,277
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net (loss) income	(122)
Other comprehensive income, net of income taxes	(1)
Ending Balance at Sep. 30, 2021	12,035		10,480	1,185	(31)	401
Beginning Balance at Dec. 31, 2020	14,676		9,624	2,805	(30)	2,277
Ending Balance (in shares) at Dec. 31, 2021		0
Ending balance at Dec. 31, 2021	11,614	$ 0		0	(31)	395	$ 11,250
Beginning Balance at Mar. 31, 2021	13,440		9,624	1,554	(29)	2,291
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net (loss) income	13			(61)		74
Changes in equity of noncontrolling interests	(12)					(12)
Distributions to member	(458)			(458)
Other comprehensive income, net of income taxes	2				2
Ending Balance at Jun. 30, 2021	12,985		9,624	1,035	(27)	2,353
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net (loss) income	633			607		26
Changes in equity of noncontrolling interests	(13)					(13)
Acquisition of CENG noncontrolling interest	(885)		1,080			(1,965)
Deferred tax adjustment related to acquisition of CENG noncontrolling interest	(288)		(288)
Contribution from member	64		64
Distributions to member	(457)			(457)
Other comprehensive income, net of income taxes	(4)				(4)
Ending Balance at Sep. 30, 2021	12,035		$ 10,480	1,185	(31)	401
Ending Balance (in shares) at Mar. 31, 2022		326,699,000,000
Ending balance at Mar. 31, 2022	11,505	$ 13,212		(91)	(2,016)	400	0
Beginning Balance (in shares) at Dec. 31, 2021		0
Beginning balance at Dec. 31, 2021	11,614	$ 0		0	(31)	395	11,250
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net (loss) income	(195)
Other comprehensive income, net of income taxes	$ 68
Ending Balance (in shares) at Sep. 30, 2022	327,000,000	327,018,000,000
Ending balance at Sep. 30, 2022	$ 11,169	$ 13,255		(483)	(1,969)	366	0
Beginning Balance (in shares) at Mar. 31, 2022		326,699,000,000
Beginning balance at Mar. 31, 2022	11,505	$ 13,212		(91)	(2,016)	400	0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net (loss) income	(113)			(111)		(2)
Changes in equity of noncontrolling interests	(9)					(9)
Employee incentive plan (in shares)		146,000,000
Employee incentive plans	29	$ 29
Common stock dividends	(47)			(47)
Other comprehensive income, net of income taxes	24				24
Ending Balance (in shares) at Jun. 30, 2022		326,845,000,000
Ending balance at Jun. 30, 2022	11,389	$ 13,241		(249)	(1,992)	389	0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net (loss) income	(193)			(188)		(5)
Changes in equity of noncontrolling interests	(18)					(18)
Employee incentive plan (in shares)		173,000,000
Employee incentive plans	14	$ 14
Common stock dividends	(46)			(46)
Other comprehensive income, net of income taxes	$ 23				23
Ending Balance (in shares) at Sep. 30, 2022	327,000,000	327,018,000,000
Ending balance at Sep. 30, 2022	$ 11,169	$ 13,255		$ (483)	$ (1,969)	$ 366	$ 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 Statements of Ch_2

Consolidated Statements of Changes in Equity, Parent (Parenthetical) - $ / shares	2 Months Ended	3 Months Ended
	Mar. 31, 2022	Sep. 30, 2022	Jun. 30, 2022
Statement of Stockholders' Equity [Abstract]
Common stock dividends (in dollars per share)	$ 0.14	$ 0.14	$ 0.14

Consolidated Statements of Op_2

Consolidated Statements of Operations and Comprehensive Income - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021
Operating revenues
Operating revenues	$ 6,051	$ 4,082	$ 16,947	$ 13,245
Operating revenues from affiliates	0	324	160	872
Total operating revenues	6,051	4,406	17,107	14,117
Operating expenses
Purchased power and fuel	4,695	1,542	11,749	8,103
Purchased power and fuel from affiliates	0	4	5	0
Operating and maintenance	989	761	3,422	2,955
Operating and maintenance from affiliates	0	177	44	458
Depreciation and amortization	262	866	818	2,735
Taxes other than income taxes	145	115	415	354
Total operating expenses	6,091	3,465	16,453	14,605
(Loss) gain on sales of assets and businesses	(1)	65	13	144
Operating (loss) income	(41)	1,006	667	(344)
Other income and (deductions)
Interest expense, net	(75)	(73)	(186)	(214)
Interest expense to affiliates	0	(4)	(1)	(11)
Other, net	(196)	(115)	(1,169)	561
Total other income and (deductions)	(271)	(192)	(1,356)	336
(Loss) income before income taxes	(312)	814	(689)	(8)
Income taxes	(123)	177	(504)	108
Equity in losses of unconsolidated affiliates	(4)	(4)	(10)	(6)
Net (loss) income	(193)	633	(195)	(122)
Net (loss) income attributable to noncontrolling interests	(5)	26	(1)	125
Net (loss) income attributable to membership interest	(188)	607	(194)	(247)
Comprehensive (loss) income, net of income taxes
Net loss	(193)	633	(195)	(122)
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	(2)	0	(4)	0
Actuarial loss reclassified to periodic cost	28	0	73	0
Pension and non-pension postretirement benefit plan valuation adjustment	4	0	4	0
Unrealized loss on cash flow hedges	(1)	(1)	0	(1)
Unrealized loss on foreign currency translation	(6)	(4)	(4)	0
Other comprehensive income (loss), net of income taxes	23	(4)	68	(1)
Comprehensive (loss) income	(170)	629	(127)	(123)
Comprehensive (loss) income attributable to noncontrolling interests	(5)	26	(1)	125
Comprehensive (loss) income attributable to membership interests	(165)	603	(126)	(248)
Constellation Energy Generation, LLC
Operating revenues
Operating revenues	6,051	4,082	16,947	13,245
Operating revenues from affiliates	0	324	160	872
Total operating revenues	6,051	4,406	17,107	14,117
Operating expenses
Purchased power and fuel	4,695	1,542	11,749	8,103
Purchased power and fuel from affiliates	0	4	5	0
Operating and maintenance	989	761	3,422	2,955
Operating and maintenance from affiliates	0	177	44	458
Depreciation and amortization	262	866	818	2,735
Taxes other than income taxes	145	115	415	354
Total operating expenses	6,091	3,465	16,453	14,605
(Loss) gain on sales of assets and businesses	(1)	65	13	144
Operating (loss) income	(41)	1,006	667	(344)
Other income and (deductions)
Interest expense, net	(75)	(73)	(186)	(214)
Interest expense to affiliates	0	(4)	(1)	(11)
Other, net	(196)	(115)	(1,169)	561
Total other income and (deductions)	(271)	(192)	(1,356)	336
(Loss) income before income taxes	(312)	814	(689)	(8)
Income taxes	(123)	177	(504)	108
Equity in losses of unconsolidated affiliates	(4)	(4)	(10)	(6)
Net (loss) income	(193)	633	(195)	(122)
Net (loss) income attributable to noncontrolling interests	(5)	26	(1)	125
Net (loss) income attributable to membership interest	(188)	607	(194)	(247)
Comprehensive (loss) income, net of income taxes
Net loss	(193)	633	(195)	(122)
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	(2)	0	(4)	0
Actuarial loss reclassified to periodic cost	28	0	73	0
Pension and non-pension postretirement benefit plan valuation adjustment	4	0	4	0
Unrealized loss on cash flow hedges	(1)	0	(1)	(1)
Unrealized loss on foreign currency translation	(6)	(4)	(4)	0
Other comprehensive income (loss), net of income taxes	23	(4)	68	(1)
Comprehensive (loss) income	(170)	629	(127)	(123)
Comprehensive (loss) income attributable to noncontrolling interests	(5)	26	(1)	125
Comprehensive (loss) income attributable to membership interests	$ (165)	$ 603	$ (126)	$ (248)

Consolidated Statements of Ca_2

Consolidated Statements of Cash Flows - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021
Cash flows from operating activities
Net loss	$ (195)	$ (122)
Adjustments to reconcile net loss to net cash flows (used in) provided by operating activities
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization	1,810	3,951
Asset impairments	0	537
Gain on sales of assets and businesses	(13)	(144)
Deferred income taxes and amortization of investment tax credits	(915)	(204)
Net fair value changes related to derivatives	544	(1,244)
Net realized and unrealized losses (gains) on NDT funds	1,032	(383)
Net unrealized loss on CTV investments	27	83
Other non-cash operating activities	304	(582)
Changes in assets and liabilities:
Accounts receivable	(150)	(207)
Receivables from and payables to affiliates, net	20	82
Inventories	(166)	(29)
Accounts payable and accrued expenses	789	357
Option premiums paid, net	(163)	(186)
Collateral received, net	766	1,974
Income taxes	364	177
Pension and non-pension postretirement benefit contributions	(229)	(237)
Other assets and liabilities	(3,756)	(2,849)
Net cash flows (used in) provided by operating activities	69	974
Cash flows from investing activities
Capital expenditures	(1,090)	(1,086)
Proceeds from NDT fund sales	3,034	5,766
Investment in NDT funds	(3,212)	(5,900)
Collection of DPP, net	3,095	3,052
Proceeds from sales of assets and businesses	41	802
Other investing activities	3	5
Net cash flows provided by investing activities	1,871	2,639
Cash flows from financing activities
Changes in short-term borrowings	(209)	(340)
Proceeds from short-term borrowings with maturities greater than 90 days	0	880
Repayments of short-term borrowings with maturities greater than 90 days	(1,180)	0
Issuance of long-term debt	9	152
Retirement of long-term debt	(1,143)	(89)
Retirement of long-term debt to affiliate	(258)	0
Changes in money pool with Exelon	0	(285)
Acquisition of CENG noncontrolling interest	0	(885)
Distributions to member	0	(1,373)
Contribution from Exelon	1,750	64
Other financing activities	(43)	(45)
Net cash flows used in financing activities	(1,213)	(1,921)
Increase in cash, restricted cash, and cash equivalents	727	1,692
Cash, restricted cash, and cash equivalents at beginning of period	576	327
Cash, restricted cash, and cash equivalents at end of period	1,303	2,019
Supplemental cash flow information
Decrease in capital expenditures not paid	(17)	(77)
Increase in DPP	3,733	2,933
Increase in PP&E related to ARO update	342	550
Constellation Energy Generation, LLC
Cash flows from operating activities
Net loss	(195)	(122)
Adjustments to reconcile net loss to net cash flows (used in) provided by operating activities
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization	1,810	3,951
Asset impairments	0	537
Gain on sales of assets and businesses	(13)	(144)
Deferred income taxes and amortization of investment tax credits	(915)	(204)
Net fair value changes related to derivatives	544	(1,244)
Net realized and unrealized losses (gains) on NDT funds	1,032	(383)
Net unrealized loss on CTV investments	27	83
Other non-cash operating activities	265	(582)
Changes in assets and liabilities:
Accounts receivable	(126)	(207)
Receivables from and payables to affiliates, net	62	82
Inventories	(166)	(29)
Accounts payable and accrued expenses	733	357
Option premiums paid, net	(163)	(186)
Collateral received, net	766	1,974
Income taxes	364	177
Pension and non-pension postretirement benefit contributions	(229)	(237)
Other assets and liabilities	(3,803)	(2,849)
Net cash flows (used in) provided by operating activities	(7)	974
Cash flows from investing activities
Capital expenditures	(1,090)	(1,086)
Proceeds from NDT fund sales	3,034	5,766
Investment in NDT funds	(3,212)	(5,900)
Collection of DPP, net	3,095	3,052
Proceeds from sales of assets and businesses	41	802
Other investing activities	3	5
Net cash flows provided by investing activities	1,871	2,639
Cash flows from financing activities
Changes in short-term borrowings	(209)	(340)
Proceeds from short-term borrowings with maturities greater than 90 days	0	880
Repayments of short-term borrowings with maturities greater than 90 days	(1,180)	0
Issuance of long-term debt	9	152
Retirement of long-term debt	(1,143)	(89)
Retirement of long-term debt to affiliate	(258)	0
Changes in money pool with Exelon	0	(285)
Acquisition of CENG noncontrolling interest	0	(885)
Distributions to member	(139)	(1,373)
Contribution from Exelon	1,750	64
Other financing activities	(56)	(45)
Net cash flows used in financing activities	(1,226)	(1,921)
Increase in cash, restricted cash, and cash equivalents	638	1,692
Cash, restricted cash, and cash equivalents at beginning of period	576	327
Cash, restricted cash, and cash equivalents at end of period	1,214	2,019
Supplemental cash flow information
Decrease in capital expenditures not paid	(17)	(77)
Increase in DPP	3,733	2,933
Increase in PP&E related to ARO update	$ 342	$ 550

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions		Sep. 30, 2022	Dec. 31, 2021
Current assets
Cash and cash equivalents		$ 1,192	$ 504
Restricted cash and cash equivalents		111	72
Accounts receivable
Customer accounts receivable (net of allowance for credit losses of $55 as of September 30, 2022 and December 31, 2021)		1,819	1,669
Other accounts receivable (net of allowance for credit losses of $5 as of September 30, 2022 and December 31, 2021)		579	592
Mark-to-market derivative assets		2,557	2,169
Receivables from affiliates		0	160
Inventories, net
Natural gas, oil, and emission allowances		422	284
Materials and supplies		1,042	1,004
Renewable energy credits		524	520
Other		1,607	1,007
Total current assets		9,853	7,981
Property, plant, and equipment (net of accumulated depreciation and amortization of $16,574 and $15,873 as of September 30, 2022 and December 31, 2021, respectively)		19,705	19,612
Deferred debits and other assets
Nuclear decommissioning trust funds		13,453	15,938
Investments		193	174
Mark-to-market derivative assets		1,252	949
Prepaid pension asset		0	1,683
Deferred income taxes		23	32
Other		2,137	1,717
Total deferred debits and other assets		17,058	20,493
Total assets	[1]	46,616	48,086
Current liabilities
Short-term borrowings		693	2,082
Long-term debt due within one year		181	1,220
Accounts payable		2,597	1,757
Accrued expenses		933	737
Payables to affiliates		0	131
Mark-to-market derivative liabilities		2,392	981
Renewable energy credit obligation		773	777
Other		318	311
Total current liabilities		7,887	7,996
Long-term debt		4,480	4,575
Long-term debt to affiliates		0	319
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		2,647	3,703
Asset retirement obligations		12,564	12,819
Pension obligations		636	0
Non-pension postretirement benefit obligations		861	847
Spent nuclear fuel obligation		1,219	1,210
Payables to affiliates		0	3,357
Payables related to Regulatory Agreement Units		2,658	0
Mark-to-market derivative liabilities		1,244	513
Other		1,251	1,133
Total deferred credits and other liabilities		23,080	23,582
Total liabilities	[1]	35,447	36,472
Commitments and contingencies
Member’s equity
Membership interest	[2]	0	11,250
Undistributed earnings		(483)	0
Accumulated other comprehensive loss, net		(1,969)	(31)
Total liabilities and equity		46,616	48,086
Constellation Energy Generation, LLC
Current assets
Cash and cash equivalents		1,131	504
Restricted cash and cash equivalents		83	72
Accounts receivable
Customer accounts receivable (net of allowance for credit losses of $55 as of September 30, 2022 and December 31, 2021)		1,819	1,669
Other accounts receivable (net of allowance for credit losses of $5 as of September 30, 2022 and December 31, 2021)		555	592
Mark-to-market derivative assets		2,557	2,169
Receivables from affiliates		0	160
Inventories, net
Natural gas, oil, and emission allowances		422	284
Materials and supplies		1,042	1,004
Renewable energy credits		524	520
Other		1,607	1,007
Total current assets		9,740	7,981
Property, plant, and equipment (net of accumulated depreciation and amortization of $16,574 and $15,873 as of September 30, 2022 and December 31, 2021, respectively)		19,705	19,612
Deferred debits and other assets
Nuclear decommissioning trust funds		13,453	15,938
Investments		193	174
Mark-to-market derivative assets		1,252	949
Prepaid pension asset		0	1,683
Deferred income taxes		23	32
Other		2,137	1,717
Total deferred debits and other assets		17,058	20,493
Total assets	[3]	46,503	48,086
Current liabilities
Short-term borrowings		693	2,082
Long-term debt due within one year		181	1,220
Accounts payable		2,553	1,757
Accrued expenses		898	737
Payables to affiliates		42	131
Mark-to-market derivative liabilities		2,392	981
Renewable energy credit obligation		773	777
Other		317	311
Total current liabilities		7,849	7,996
Long-term debt		4,480	4,575
Long-term debt to affiliates		0	319
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		2,647	3,703
Asset retirement obligations		12,564	12,819
Pension obligations		636	0
Non-pension postretirement benefit obligations		861	847
Spent nuclear fuel obligation		1,219	1,210
Payables to affiliates		0	3,357
Payables related to Regulatory Agreement Units		2,658	0
Mark-to-market derivative liabilities		1,244	513
Other		1,197	1,133
Total deferred credits and other liabilities		23,026	23,582
Total liabilities	[3]	35,355	36,472
Commitments and contingencies
Member’s equity
Membership interest		12,326	10,482
Undistributed earnings		425	768
Accumulated other comprehensive loss, net		(1,969)	(31)
Total member’s equity		10,782	11,219
Noncontrolling interests		366	395
Total equity		11,148	11,614
Total liabilities and equity		$ 46,503	$ 48,086
[1]Our consolidated assets include $3,133 million and $2,549 million at September 30, 2022 and December 31, 2021, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Our consolidated liabilities include $1,049 million and $1,077 million at September 30, 2022 and December 31, 2021, respectively, of certain VIEs for which the VIE creditors do not have recourse to us. See Note 18 — 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 $3,133 million and $2,549 million as of September 30, 2022 and December 31, 2021, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Our consolidated liabilities include $1,049 million and $1,077 million as of September 30, 2022 and December 31, 2021, respectively, of certain VIEs for which the VIE creditors do not have recourse to us. See Note 18 — Variable Interest Entities for additional information.

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions		Sep. 30, 2022	Dec. 31, 2021
Allowance for credit losses		$ 55	$ 55
Allowance for other credit losses		5	5
Accumulated depreciation and amortization		16,574	15,873
Total assets	[1]	46,616	48,086
Total liabilities	[1]	35,447	36,472
Variable Interest Entity, Primary Beneficiary
Total assets		3,339	2,774
Total liabilities		1,050	1,078
Variable Interest Entity, Primary Beneficiary | Nonrecourse
Total liabilities		1,049	1,077
Variable Interest Entity, Primary Beneficiary | Asset Pledged as Collateral
Total assets		3,133	2,549
Constellation Energy Generation, LLC
Allowance for credit losses		55	55
Allowance for other credit losses		5	5
Accumulated depreciation and amortization		16,574	15,873
Total assets	[2]	46,503	48,086
Total liabilities	[2]	35,355	36,472
Constellation Energy Generation, LLC | Variable Interest Entity, Primary Beneficiary | Nonrecourse
Total liabilities		1,049	1,077
Constellation Energy Generation, LLC | Variable Interest Entity, Primary Beneficiary | Asset Pledged as Collateral
Total assets		$ 3,133	$ 2,549
[1]Our consolidated assets include $3,133 million and $2,549 million at September 30, 2022 and December 31, 2021, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Our consolidated liabilities include $1,049 million and $1,077 million at September 30, 2022 and December 31, 2021, respectively, of certain VIEs for which the VIE creditors do not have recourse to us. See Note 18 — Variable Interest Entities for additional information.[2]Our consolidated assets include $3,133 million and $2,549 million as of September 30, 2022 and December 31, 2021, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Our consolidated liabilities include $1,049 million and $1,077 million as of September 30, 2022 and December 31, 2021, respectively, of certain VIEs for which the VIE creditors do not have recourse to us. See Note 18 — Variable Interest Entities for additional information.

Consolidated Statement of Chang

Consolidated Statement of Changes in Equity - USD ($) $ in Millions	Total	Membership Interest	Undistributed Earnings	Accumulated Other Comprehensive Loss, net	Noncontrolling Interests	Constellation Energy Generation, LLC	Constellation Energy Generation, LLC Membership Interest	Constellation Energy Generation, LLC Undistributed Earnings	Constellation Energy Generation, LLC Accumulated Other Comprehensive Loss, net	Constellation Energy Generation, LLC Noncontrolling Interests
Beginning Balance at Dec. 31, 2020	$ 14,676	$ 9,624	$ 2,805	$ (30)	$ 2,277	$ 14,676	$ 9,624	$ 2,805	$ (30)	$ 2,277
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net (loss) income	(769)		(793)		24	(769)		(793)		24
Changes in equity of noncontrolling interests	(10)				(10)	(10)				(10)
Distributions to member	(458)		(458)			(458)		(458)
Other comprehensive income, net of income taxes	1			1		1			1
Ending Balance at Mar. 31, 2021	13,440	9,624	1,554	(29)	2,291	13,440	9,624	1,554	(29)	2,291
Beginning Balance at Dec. 31, 2020	14,676	9,624	2,805	(30)	2,277	14,676	9,624	2,805	(30)	2,277
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net (loss) income	(122)					(122)
Other comprehensive income, net of income taxes	(1)					(1)
Ending Balance at Sep. 30, 2021	12,035	10,480	1,185	(31)	401	12,035	10,480	1,185	(31)	401
Beginning Balance at Dec. 31, 2020	14,676	9,624	2,805	(30)	2,277	14,676	9,624	2,805	(30)	2,277
Ending Balance at Dec. 31, 2021						11,614	10,482	768	(31)	395
Beginning Balance at Mar. 31, 2021	13,440	9,624	1,554	(29)	2,291	13,440	9,624	1,554	(29)	2,291
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net (loss) income	13		(61)		74	13		(61)		74
Changes in equity of noncontrolling interests	(12)				(12)	(12)				(12)
Distributions to member	(458)		(458)			(458)		(458)
Other comprehensive income, net of income taxes	2			2		2			2
Ending Balance at Jun. 30, 2021	12,985	9,624	1,035	(27)	2,353	12,985	9,624	1,035	(27)	2,353
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net (loss) income	633		607		26	633		607		26
Changes in equity of noncontrolling interests	(13)				(13)	(13)				(13)
Acquisition of CENG noncontrolling interest	(885)	1,080			(1,965)	(885)	1,080			(1,965)
Deferred tax adjustment related to acquisition of CENG noncontrolling interest	(288)	(288)				(288)	(288)
Contribution from member	64	64				64	64
Distributions to member	(457)		(457)			(457)		(457)
Other comprehensive income, net of income taxes	(4)			(4)		(4)			(4)
Ending Balance at Sep. 30, 2021	12,035	$ 10,480	1,185	(31)	401	12,035	10,480	1,185	(31)	401
Beginning Balance at Dec. 31, 2021						11,614	10,482	768	(31)	395
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net (loss) income						111		106		5
Separation-related adjustments						(166)	1,844	(11)	(2,006)	7
Changes in equity of noncontrolling interests						(7)				(7)
Distributions to member						(46)		(46)
Other comprehensive income, net of income taxes						21			21
Ending Balance at Mar. 31, 2022						11,527	12,326	817	(2,016)	400
Beginning Balance at Dec. 31, 2021						11,614	10,482	768	(31)	395
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net (loss) income	(195)					(195)
Other comprehensive income, net of income taxes	68					68
Ending Balance at Sep. 30, 2022						11,148	12,326	425	(1,969)	366
Beginning Balance at Mar. 31, 2022						11,527	12,326	817	(2,016)	400
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net (loss) income	(113)		(111)		(2)	(113)		(111)		(2)
Changes in equity of noncontrolling interests	(9)				(9)	(9)				(9)
Distributions to member						(47)		(47)
Other comprehensive income, net of income taxes	24			24		24			24
Ending Balance at Jun. 30, 2022						11,382	12,326	659	(1,992)	389
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net (loss) income	(193)		$ (188)		(5)	(193)		(188)		(5)
Changes in equity of noncontrolling interests	(18)				$ (18)	(18)				(18)
Distributions to member						(46)		(46)
Other comprehensive income, net of income taxes	$ 23			$ 23		23			23
Ending Balance at Sep. 30, 2022						$ 11,148	$ 12,326	$ 425	$ (1,969)	$ 366

Basis of Presentation

Basis of Presentation	9 Months Ended
	Sep. 30, 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 (the separation), 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 as of September 30, 2022 and for the three and nine months ended September 30, 2022 and 2021 are unaudited but, in our opinion include all adjustments that are considered necessary for a fair statement of the financial statements in accordance with GAAP. All adjustments are of a normal, recurring nature, except as otherwise disclosed. 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. Constellation's December 31, 2021 Consolidated Balance Sheet was derived from audited financial statements. The interim financial statements are to be read in conjunction with prior annual financial statements and notes. Financial results for interim periods are not necessarily indicative of results that may be expected for any other interim period or for the fiscal year ending December 31, 2022. These Combined Notes to Consolidated Financial Statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations. 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. 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 now 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 facility agreements providing $4.5 billion of capacity. Beginning on February 1, 2022, the amounts Exelon billed us for services pursuant to the TSA were $68 million and $193 million for the three and nine months ended September 30, 2022, respectively, and the amounts we billed Exelon for services pursuant to the TSA were $12 million and $32 million for the three and nine months ended September 30, 2022, respectively. See Note 1 — Significant Accounting Policies of our 2021 Form 10-K for additional information on significant accounting policies. The following policy was added as a result of separation. Retirement Benefits Effective upon separation, we sponsor defined benefit pension and OPEB plans as described in Note 11 — Retirement Benefits. The plan obligations and costs of providing benefits under these plans were measured as of February 1, 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.

Mergers, Acquisitions, and Disp

Mergers, Acquisitions, and Dispositions	9 Months Ended
	Sep. 30, 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 owns 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 was 100% consolidated in our financial statements. See Note 21 — Variable Interest Entities of our 2021 Form 10-K for additional information. 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 have 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 in 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 10 — Income Taxes for additional information. The following table summarizes the effects of the changes in our ownership interest in CENG in Members Equity: Three Months Ended September 30, 2021 Nine Months Ended September 30, 2021 Net income (loss) attributable to membership interest $ 607 $ (247) Pre-tax increase in membership interest for purchase of EDF's 49.99% equity interest (a) 1,080 1,080 Decrease in membership interest due to deferred tax liabilities resulting from purchase of EDF's equity interest (a) (288) (288) Change from net income (loss) attributable to membership interest and transfers from noncontrolling interest. $ 1,399 $ 545 __________ (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 MW 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 Statements of Operations and Comprehensive Income. See Note 17 — Debt and Credit Agreements of our 2021 Form 10-K for additional information on the SolGen nonrecourse debt included as part of the transaction. Agreement for the Sale of Our Biomass Facility On April 28, 2021, we entered into a purchase agreement with ReGenerate Energy Holdings, LLC (“ReGenerate”), under which ReGenerate agreed to purchase our interest in the Albany Green Energy biomass facility. As a result, in the second quarter of 2021, we recorded a pre-tax impairment charge of $140 million in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. Completion of the transaction was subject to the satisfaction of various customary closing conditions that were

Regulatory Matters

Regulatory Matters	9 Months Ended
	Sep. 30, 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 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 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. See Note 3 – Regulatory Matters of our 2021 Form 10-K for additional information. As a result of this event, we incurred a loss of approximately $880 million for the nine months ended September 30, 2021. By comparison, for the nine months ended September 30, 2022, the estimated impact reduced our overall Net loss by approximately $30 million, primarily the result of impacts from a payment to ERCOT from a defaulting market participant and the settlement of a dispute related to gas penalties. The estimated impact to our Net loss for the three months ended September 30, 2022 and 2021 was not material. In response to the high demand and significantly reduced total generation on the system, the PUCT directed ERCOT to use an administrative price cap of $9,000/MWh during firm load shedding events. 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; 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 remaining defaults. Due to a market participant paying off their debt to ERCOT, this was reduced to approximately $1.9 billion as of September 30, 2022. Remaining defaults, under ERCOT rules, are allocated to the remaining market participants. We recorded our estimated obligation of the remaining defaults, net of legislative solutions and on a discounted basis, of approximately $16 million and $17 million as of September 30, 2022 and December 31, 2021, respectively, which was expected to be paid over a term of 62 years and 83 years, respectively. 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 remaining default owed to ERCOT. The ERCOT claim is now in mediation and is addressed in the Chapter 11 Plan of Reorganization filed by the Debtor (market participant) on September 1, 2022. The filing does not represent the final terms and conditions of settlements that the Debtor has negotiated or is continuing to negotiate. However, if approved by the bankruptcy court as filed, the issue would be resolved. A ruling is expected in the fourth quarter of 2022, and we cannot reasonably predict the outcome of this proceeding. 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. New England Regulatory Matters Mystic Units 8 and 9 Cost of Service Agreement. In November 2021, FERC issued an order directing a decrease to the Return on Equity (“ROE”) used in the Mystic Cost of Service Agreement (the “Mystic COS”) from 9.33% to 9.19%. The ROE impacts the return Mystic collects on its rate base under the agreement. 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. 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. On December 20, 2018, FERC issued an order on the key elements of the Mystic COS, including recovery of costs associated with the operation of the Everett Marine Terminal (EMT). On July 17, 2020, FERC issued an order on rehearing of that decision. Both orders were appealed to the U.S. Court of Appeals for the D.C. Circuit. 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. See Note 3 – Regulatory Matters of our 2021 Form 10-K and Note 7 – Early Plant Retirements for additional information. 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. Federal Regulatory Matters Inflation Reduction Act of 2022. On August 16, 2022, Congress passed and President Biden signed into law the Inflation Reduction Act of 2022 (IRA of 2022), 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 of 2022 includes a 15% book-minimum tax on applicable corporations. We do not expect this to have a material impact to our financial statements. Operating License Renewals 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.

Revenue from Contracts with Cus

Revenue from Contracts with Customers	9 Months Ended
	Sep. 30, 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. See Note 4 — Revenue from Contracts with Customers of our 2021 Form 10-K for additional information regarding the primary sources of revenue. 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, respectively, in the Consolidated Balance Sheets. The following table provides a rollforward of the contract assets reflected in the Consolidated Balance Sheets for the three and nine months ended September 30, 2022 and 2021. Contract Assets Balance as of December 31, 2021 $ 149 Amounts reclassified to receivables (16) Revenues recognized 9 Balance as of March 31, 2022 $ 142 Amounts reclassified to receivables (13) Revenues recognized 10 Balance as of June 30, 2022 $ 139 Amounts reclassified to receivables (5) Revenues recognized 21 Balance as of September 30, 2022 $ 155 Balance as of December 31, 2020 $ 144 Amounts reclassified to receivables (16) Revenues recognized 13 Amounts previously held-for-sale 12 Balance as of March 31, 2021 $ 153 Amounts reclassified to receivables (12) Revenues recognized 9 Balance as of June 30, 2021 $ 150 Amounts reclassified to receivables (15) Revenues recognized 14 Balance as of September 30, 2021 $ 149 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 was initially established at $16.50 per MWh of production up to the annual cap, while requiring delivery of all ZECs produced by our participating nuclear 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 for the three and nine months ended September 30, 2022 and 2021. Contract Liabilities Balance as of December 31, 2021 $ 75 Consideration received or due 50 Revenues recognized (63) Balance as of March 31, 2022 $ 62 Consideration received or due 27 Revenues recognized (63) Balance as of June 30, 2022 $ 26 Consideration received or due 71 Revenues recognized (68) Balance as of September 30, 2022 $ 29 Balance as of December 31, 2020 $ 84 Consideration received or due 31 Revenues recognized (64) Amounts previously held-for-sale 3 Balance as of March 31, 2021 $ 54 Consideration received or due 39 Revenues recognized (68) Balance as of June 30, 2021 $ 25 Consideration received or due 93 Revenues recognized (65) Balance as of September 30, 2021 $ 53 The following table reflects revenues recognized in the three and nine months ended September 30, 2022 and 2021, which were included in contract liabilities at December 31, 2021 and 2020, respectively: Three Months Ended September 30, Nine Months Ended September 30, 2022 2021 2022 2021 Revenues recognized $ 2 $ 2 $ 70 $ 81 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 September 30, 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. 2022 2023 2024 2025 2026 and thereafter Total Remaining performance obligations $ 97 $ 161 $ 63 $ 32 $ 152 $ 505 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	9 Months Ended
	Sep. 30, 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 the FRCC, MISO’s Southern Region, and the remaining portions of the SERC not included within MISO or PJM. • West represents operations in the 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 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 affiliate sales to Exelon's utility subsidiaries prior to the separation on February 1, 2022. 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 natural gas, as well as other miscellaneous business activities that are not significant to our overall operating revenues or 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 three and nine months ended September 30, 2022 and 2021. Three Months Ended September 30, 2022 Revenues from external customers (a) Contracts with customers Other (b) Total Intersegment Revenues Total Revenues Mid-Atlantic $ 1,561 $ 97 $ 1,658 $ 1 $ 1,659 Midwest 1,182 (133) 1,049 (2) 1,047 New York 536 (110) 426 (3) 423 ERCOT 328 168 496 (6) 490 Other Power Regions 1,315 611 1,926 10 1,936 Total Competitive Businesses Electric Revenues 4,922 633 5,555 — 5,555 Competitive Businesses Natural Gas Revenues 471 599 1,070 — 1,070 Competitive Businesses Other Revenues (c) 154 (728) (574) — (574) Total Consolidated Operating Revenues $ 5,547 $ 504 $ 6,051 $ — $ 6,051 Three Months Ended September 30, 2021 Revenues from external customers (a) Contracts with customers Other (b) Total Intersegment Revenues Total Revenues Mid-Atlantic $ 1,145 $ 123 $ 1,268 $ 4 $ 1,272 Midwest 1,084 (99) 985 — 985 New York 445 10 455 — 455 ERCOT 191 165 356 2 358 Other Power Regions 948 318 1,266 (6) 1,260 Total Competitive Businesses Electric Revenues 3,813 517 4,330 — 4,330 Competitive Businesses Natural Gas Revenues 266 309 575 — 575 Competitive Businesses Other Revenues (c) 95 (594) (499) — (499) Total Consolidated Operating Revenues $ 4,174 $ 232 $ 4,406 $ — $ 4,406 Nine Months Ended September 30, 2022 Revenues from external customers (a) Contracts with customers Other (b) Total Intersegment Revenues Total Revenues Mid-Atlantic $ 3,894 $ 70 $ 3,964 $ 3 $ 3,967 Midwest 3,749 (401) 3,348 (3) 3,345 New York 1,492 (314) 1,178 — 1,178 ERCOT 744 476 1,220 (10) 1,210 Other Power Regions 3,756 1,423 5,179 10 5,189 Total Competitive Businesses Electric Revenues 13,635 1,254 14,889 — 14,889 Competitive Businesses Natural Gas Revenues 1,770 1,778 3,548 — 3,548 Competitive Businesses Other Revenues (c) 416 (1,746) (1,330) — (1,330) Total Consolidated Operating Revenues $ 15,821 $ 1,286 $ 17,107 $ — $ 17,107 Nine Months Ended September 30, 2021 Revenues from external customers (a) Contracts with customers Other (b) Total Intersegment Revenues Total Revenues Mid-Atlantic $ 3,377 $ 134 $ 3,511 $ 16 $ 3,527 Midwest 3,067 (123) 2,944 1 2,945 New York 1,204 (30) 1,174 (1) 1,173 ERCOT 724 155 879 11 890 Other Power Regions 3,043 713 3,756 (27) 3,729 Total Competitive Businesses Electric Revenues 11,415 849 12,264 — 12,264 Competitive Businesses Natural Gas Revenues 1,384 1,024 2,408 — 2,408 Competitive Businesses Other Revenues (c) 291 (846) (555) — (555) Total Consolidated Operating Revenues $ 13,090 $ 1,027 $ 14,117 $ — $ 14,117 __________ (a) Includes all wholesale and retail electric sales to third parties and affiliate sales to Exelon's utility subsidiaries prior to the separation on February 1, 2022. See Note 20 - 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-mar ket losses o f $681 million a nd $635 million for the three months ended September 30, 2022 and 2021, respectively, and unrealized mark-to-market losses of $1,899 million and $958 million for the nine months ended September 30, 2022 and 2021, respectively, and the elimination of intersegment revenues. Three Months Ended September 30, 2022 Three Months Ended September 30, 2021 RNF from external (a) Intersegment Total RNF from external (a) Intersegment Total Mid-Atlantic $ 553 $ 2 $ 555 $ 567 $ 3 $ 570 Midwest 572 — 572 655 — 655 New York 268 (1) 267 343 3 346 ERCOT 104 (38) 66 181 (2) 179 Other Power Regions 274 (17) 257 233 (22) 211 Total RNF for Reportable Segments 1,771 (54) 1,717 1,979 (18) 1,961 Other (b) (415) 54 (361) 881 18 899 Total RNF $ 1,356 $ — $ 1,356 $ 2,860 $ — $ 2,860 Nine Months Ended September 30, 2022 Nine Months Ended September 30, 2021 RNF from external (a) Intersegment Total RNF from external (a) Intersegment Total Mid-Atlantic $ 1,606 $ 6 $ 1,612 $ 1,698 $ 14 $ 1,712 Midwest 2,008 2 2,010 2,014 1 2,015 New York 822 5 827 873 7 880 ERCOT 321 (86) 235 (775) (147) (922) Other Power Regions 741 (31) 710 641 (77) 564 Total RNF for Reportable Segments 5,498 (104) 5,394 4,451 (202) 4,249 Other (b) (145) 104 (41) 1,563 202 1,765 Total RNF $ 5,353 $ — $ 5,353 $ 6,014 $ — $ 6,014 __________ (a) Includes purchases and sales from/to third parties and affiliate sales to Exelon's utility subsidiaries prior to the separation on February 1, 2022. See Note 20 - 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 $(524) million and gains of $754 million for the three months ended September 30, 2022 and 2021, respectively, and unrealized mark-to-market losses of ($571) million and gains of $1,242 million for the nine months ended September 30, 2022 and 2021, respectively; • Accelerated nuclear fuel amortization associated with the announced early plant retirements as discussed in Note 7 - Early Plant Retirements of $42 million and $148 million for the three and nine months ended September 30, 2021, respectively. • The elimination of intersegment RNF.

Accounts Receivable

Accounts Receivable	9 Months Ended
	Sep. 30, 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. Three Months Ended September 30, 2022 Balance as of June 30, 2022 (a) $ 49 Plus: Current period provision for expected credit losses 9 Less: Write-offs, net of recoveries (b) 3 Balance as of September 30, 2022 (a) $ 55 Three Months Ended September 30, 2021 Balance as of June 30, 2021 (a) $ 75 Plus: Current period provision for expected credit losses 10 Less: Write-offs, net of recoveries (b) 1 Balance as of September 30, 2021 (a) $ 84 Nine Months Ended September 30, 2022 Balance as of December 31, 2021 (a) $ 55 Plus: Current period provision for expected credit losses 12 Less: Write-offs, net of recoveries (b) 12 Balance as of September 30, 2022 (a) $ 55 Nine Months Ended September 30, 2021 Balance as of December 31, 2020 (a) $ 32 Plus: Current period provision for expected credit losses (c) 57 Less: Write-offs, net of recoveries (b) 5 Balance as of September 30, 2021 (a) $ 84 __________ (a) Allowance for Credit Losses on Other Accounts Receivable were not material as of the balance sheet dates. (b) Recoveries were not material. (c) Primarily relates to the impacts of the February 2021 extreme cold weather event. See Note 3 — Regulatory Matters for additional information . Unbilled Customer Revenue We recorded $369 million and $373 million of unbilled customer revenues in Customer accounts receivables, net in the Consolidated Balance Sheets as of September 30, 2022 and December 31, 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. No additional funds were drawn in connection with the amendment. 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 September 30, 2022 As of December 31, 2021 Derecognized receivables transferred at fair value $ 1,675 $ 1,265 Cash proceeds received 700 900 DPP 975 365 Three Months Ended September 30, Nine Months Ended September 30, 2022 2021 2022 2021 Loss on sale of receivables (a) $ 15 $ 1 $ 39 $ 26 __________ (a) Reflected in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. Nine Months Ended September 30, 2022 2021 Proceeds from new transfers (a) $ 4,807 $ 4,440 Cash collections received on DPP and reinvested in the Facility (b) 3,295 2,652 Cash collections reinvested in the Facility 8,102 7,092 __________ (a) Customer accounts receivable sold into the Facility were $8,540 million and $7,373 million for the nine months ended September 30, 2022 and 2021, respectively. (b) Does not include $200 million net cash payments to the Purchasers in the third quarter of 2022 and $400 million cash proceeds received from the Purchasers in the first quarter of 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 14 — Fair Value of Financial Assets and Liabilities and Note 18 — 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 include Exelon's utility subsidiaries. The following table presents the total receivables sold. Nine Months Ended September 30, 2022 2021 Total receivables sold $ 312 $ 117 Related party transactions: Receivables sold to Exelon's utility subsidiaries prior to the separation on February 1, 2022 4 17

Early Plant Retirements

Early Plant Retirements	9 Months Ended
	Sep. 30, 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 of 2022, 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 of our 2021 Form 10-K 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 of our 2021 Form 10-K 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 three and nine months ended September 30, 2021 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) Three Months Ended September 30, 2021 Nine Months Ended September 30, 2021 Depreciation and amortization Accelerated depreciation (a) $ 574 $ 1,805 Accelerated nuclear fuel amortization 42 148 Operating and maintenance One-time charges (94) (94) Other charges 4 8 Contractual offset (b) (60) (451) Total $ 466 $ 1,416 _________ (a) Includes the accelerated depreciation of plant assets including any ARC. (b) 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 of our 2021 Form 10-K 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 - 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.

Nuclear Decommissioning

Nuclear Decommissioning	9 Months Ended
	Sep. 30, 2022
Asset Retirement Obligation Disclosure [Abstract]
Nuclear Decommissioning	Nuclear Decommissioning 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. 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, 2021 to September 30, 2022: 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 394 Costs incurred related to decommissioning plants (50) Balance as of September 30, 2022 (a) $ 12,372 __________ (a) Includes $45 million and $72 million as the current portion of the ARO as of September 30, 2022 and December 31, 2021, respectively, which is included in Other current liabilities in the Consolidated Balance Sheets. During the nine months ended September 30, 2022, the net $648 million decrease in the ARO for the 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 of 2022 and useful life extension for Clinton and Dresden plants. See Note 3 - Regulatory Matters and Note 7 - Early Plant Retirements for additional information • An 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 three and nine months ended September 30, 2022 in the Consolidated Statement of Operations and Comprehensive Income. NDT Funds We had NDT funds totaling $13,546 million and $16,064 million as of September 30, 2022 and December 31, 2021, respectively. The NDT funds also include $93 million and $126 million for the current portion of the NDT funds as of September 30, 2022 and December 31, 2021, respectively, which are included in Other current assets in the Consolidated Balance Sheets. See Note 19 — Supplemental Financial Information for additional information on activities of the NDT funds. Accounting Implications of the Regulatory Agreements 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, respectively, 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. See Note 10 — Asset Retirement Obligations of our 2021 Form 10-K for additional information on our continued obligations associated with the former ComEd and PECO nuclear units. The following table presents our noncurrent payables to ComEd and PECO which are recorded as Payables related to Regulatory Agreement Units as of September 30, 2022 and noncurrent Payables to affiliates as of December 31, 2021: September 30, 2022 December 31, 2021 ComEd $ 2,469 $ 2,760 PECO 189 597 Additionally, during the second and third quarter of 2021, a pre-tax charge of $53 million and $140 million, respectively, was recorded in the Consolidated Statements of Operations and Comprehensive Income for decommissioning-related activities that were not offset for the Byron units due to the temporary suspension of contractual offset accounting. With our September 15, 2021 reversal of the previous decision to retire Byron and the corresponding adjustment to the ARO for Byron, we resumed contractual offset for Byron as of that date. See Note 10 — Asset Retirement Obligations of our 2021 Form 10-K for additional information on adjustments to the Byron ARO. 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. 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. No additional actions are required aside from the PAPUC filing in accordance with the tariff. See Note 10 – Asset Retirement Obligations of our 2021 Form 10-K for information regarding the amount collected from PECO customers for decommissioning costs of the former PECO nuclear units. 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 fall below investment grade. See Note 1 — Basis of Presentation for additional information.

Asset Impairments

Asset Impairments	9 Months Ended
	Sep. 30, 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. New England Asset Group 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 Statements 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 EGRP 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 Statements of Operations and Comprehensive Income. Agreement for the Sale of Our Biomass Facility See Note 2 — Mergers, Acquisitions, and Dispositions for information on a pre-tax impairment recorded in the second quarter of 2021 related to the Albany Green Energy biomass facility.

Income Taxes

Income Taxes	9 Months Ended
	Sep. 30, 2022
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes Rate Reconciliation The effective income tax rate from continuing operations varies from the U.S. federal statutory rate principally due to the following: Three Months Ended September 30, 2022 (a) 2021 U.S. federal statutory rate 21.0 % 21.0 % Increase (decrease) due to: State income taxes, net of federal income tax benefit (9.5) 4.4 Qualified NDT fund income and losses 22.1 0.9 Amortization of investment tax credit, including deferred taxes on basis differences 1.9 (0.7) Production tax credits and other credits 8.0 (1.4) Noncontrolling interests (0.5) (0.6) Other (3.6) (1.9) Effective income tax rate (b) 39.4 % 21.7 % Nine Months Ended September 30, 2022 (a) 2021 (a) U.S. federal statutory rate 21.0 % 21.0 % Increase (decrease) due to: State income taxes, net of federal income tax benefit (9.0) 90.2 Qualified NDT fund income and losses 48.6 (1,932.6) Amortization of investment tax credit, including deferred taxes on basis differences 2.0 130.6 Production tax credits and other credits 8.3 425.1 Noncontrolling interests — 145.2 Other 2.2 (229.5) Effective income tax rate (b) 73.1 % (1,350.0) % __________ (a) For every period, except the three months ended September 30, 2021, we recognized a loss on Income before income taxes. As a result, positive percentages represent an income tax benefit and negative percentages represent income tax expense for the periods presented. (b) The 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. The effective tax rate in 2021 is primarily due to the impacts of the February 2021 extreme cold weather event on Income before income taxes. Recognition of Unrecognized Tax Benefits The following table presents the unrecognized tax benefits that, if recognized, would decrease the effe ctive tax rate. September 30, 2022 $ 29 December 31, 2021 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. Other Tax Matters CENG Put Option On August 6, 2021, we entered into a settlement agreement pursuant to which we purchased EDF’s equity interest in CENG. We recorded deferred tax liabilities of $288 million in Membership Interest in our 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. Tax Matters Agreement In connection with the separation, we entered into a 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 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 reflected a payable of $103 million upon separation 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 March 31, 2022. As of September 30, 2022, the amounts within Accounts payable and Noncurrent other liabilities are $55 million and $50 million, respectively. 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 Exelon tax sharing agreement then existing, 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 September 30, 2022, we had $106 million in Other accounts receivable and $409 million in Other deferre d debits and other assets for the reclassified tax attributes .

Retirement Benefits

Retirement Benefits	9 Months Ended
	Sep. 30, 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 current participants (inclusive of employees transferred 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 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 present our benefit obligations net of plan assets on our balance sheet within the following line items: September 30, 2022 December 31, 2021 Pension Benefits OPEB Pension Benefits OPEB Prepaid pension asset $ — $ — $ 1,683 $ — Other current liabilities (9) (17) — — Pension obligations (636) — — — Non-pension postretirement benefit — (861) — (847) (Unfunded) funded status (net benefit obligation less plan assets) $ (645) $ (878) $ 1,683 $ (847) 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 expectations 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. In 2022, we adopted the revised mortality tables and projection scales released by the SOA. The following table summarizes the assumptions we used to determine the benefit obligations as of February 1, 2022 and costs for 2022: Pension OPEB Discount rate (a) 3.23 % 3.21 % Investment crediting rate (b) 3.86 % N/A Expected return on plan assets (c) 7.00 % 6.50 % Rate of compensation increase 3.75 % 3.75 % Mortality table 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 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. (c) Applicable to our pension and OPEB plans with plan assets, with the OPEB rate representing a weighted average. 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, in accordance with single employer plan accounting. 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 following tables present the components of our net periodic benefit costs (credits), prior to capitalization and co-owner allocations, for the three and nine months ended September 30, 2022 and 2021: Pension Benefits OPEB Total Pension Benefits and OPEB Three Months Ended September 30, Three Months Ended September 30, Three Months Ended September 30, 2022 2021 2022 2021 2022 2021 Components of net periodic benefit cost (credit) Service cost $ 31 $ 36 $ 6 $ 8 $ 37 $ 44 Non-service components of pension benefits & OPEB cost (credit) Interest cost 74 59 14 12 88 71 Expected return on assets (143) (123) (14) (15) (157) (138) Amortization of: Prior service cost (credit) — — (2) (3) (2) (3) Actuarial loss (gain) 37 50 — 3 37 53 Settlement charges 5 10 — — 5 10 Non-service components of pension benefits & OPEB credit (a) (27) (4) (2) (3) (29) (7) Net periodic benefit cost (b,c) $ 4 $ 32 $ 4 $ 5 $ 8 $ 37 Pension Benefits OPEB Total Pension Benefits and OPEB Nine Months Ended September 30, Nine Months Ended September 30, Nine Months Ended September 30, 2022 2021 2022 2021 2022 2021 Components of net periodic benefit cost (credit) Service cost $ 94 $ 109 $ 18 $ 22 $ 112 $ 131 Non-service components of pension benefits & OPEB cost (credit) Interest cost 217 177 42 34 259 211 Expected return on assets (423) (370) (42) (44) (465) (414) Amortization of: Prior service cost (credit) 1 — (5) (7) (4) (7) Actuarial loss (gain) 111 149 (1) 8 110 157 Settlement charges 5 14 — — 5 14 Non-service components of pension benefits & OPEB credit (a) (89) (30) (6) (9) (95) (39) Net periodic benefit cost (b,c) $ 5 $ 79 $ 12 $ 13 $ 17 $ 92 __________ (a) The pension benefit and OPEB non-service costs (credits) for the three and nine months ended September 30, 2021 are reflected in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. Effective February 1, 2022, these non-service costs (credits) are reflected in Other, net in the Consolidated Statements of Operations and Comprehensive Income. (b) The pension benefit and OPEB service costs reflected in the Consolidated Statements of Operations and Comprehensive Income for the three and nine months ended September 30, 2022 totaled $33 million and $98 million, respectively. The pension benefit and OPEB non-service credits reflected in the Consolidated Statements of Operations and Comprehensive Income for the three and nine months ended September 30, 2022 totaled ($27) million and ($85) million, respectively. (c) The pension benefit and OPEB service costs reflected in the Consolidated Statements of Operations and Comprehensive Income for the three and nine months ended September 30, 2021 totaled $32 million and $103 million, respectively. The pension benefit and OPEB non-service credits reflected in the Consolidated Statements of Operations and Comprehensive Income for the three and nine months ended September 30, 2021 totaled ($11) million and ($36) million, respectively. 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 September 30, 2022: September 30, 2022 Pension plans 12.2 OPEB plans: Benefit Eligibility Age 7.5 Expected Retirement 8.3 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 of 2006 (the Act), and management of the pension obligation. The 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 contributions below reflect a funding strategy to make levelized annual contributions with the objective of achieving 100% funded status on an ABO basis 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. There are no additional contributions expected for the remainder of 2022. Our non-qualified pension plans are not funded given that they are not subject to statutory minimum contribution requirements. While OPEB plans are also not subject to statutory minimum contribution requirements, we do fund certain plans. For our funded OPEB plans, contributions generally equal accounting costs; however, we consider several factors in determining the level of contributions to these plans, including liabilities management and levels of benefit claims paid. The estimated benefit payments to the non-qualified pension plans in 2022 are $21 million and the planned contributions to the OPEB plans, including estimated benefit payments to unfunded plans is $27 million. The benefit payments to the non-qualified pension plans and OPEB plans were $8 million and $8 million for the three months ended September 30, 2022, respectively. The benefit payments to the non-qualified pension plans and OPEB plans were $16 million and $21 million for the nine months ended September 30, 2022, respectively. Estimated Future Benefit Payments Estimated future benefit payments to participants in all pension and OPEB plans were: Pension Benefits OPEB 2022 (a) $ 532 $ 108 2023 521 108 2024 524 108 2025 536 107 2026 533 107 2027 through 2031 2,710 540 Total estimated future benefits payments through 2031 $ 5,356 $ 1,078 __________ (a) Amount represents estimated benefit payments for the calendar year. 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 liabilities. 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 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. Defined Contribution Savings Plans We sponsor the Constellation Employee Savings Plan, a 401(k) defined contribution savings plan. 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 $16 million and $14 million for the three months ended September 30, 2022 and 2021, respectively, and $44 million and $40 million for the nine months ended September 30, 2022 and 2021, respectively.

Derivative Financial Instrument

Derivative Financial Instruments	9 Months Ended
	Sep. 30, 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 consumed. 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 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 September 30, 2022 and December 31, 2021: September 30, 2022 Economic Proprietary Collateral (a)(b) Netting (a) Total Mark-to-market derivative assets (current assets) $ 27,702 $ 24 $ (372) $ (24,816) $ 2,538 Mark-to-market derivative assets (noncurrent assets) 7,103 1 (27) (5,848) 1,229 Total mark-to-market derivative assets 34,805 25 (399) (30,664) 3,767 Mark-to-market derivative liabilities (current liabilities) (27,225) (21) 50 24,816 (2,380) Mark-to-market derivative liabilities (noncurrent liabilities) (7,205) — 114 5,848 (1,243) Total mark-to-market derivative liabilities (34,430) (21) 164 30,664 (3,623) Total mark-to-market derivative net assets (liabilities) $ 375 $ 4 $ (235) $ — $ 144 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 (liabilities) $ 1,103 $ 7 $ 512 $ — $ 1,622 _________ (a) We net all available amounts allowed under the derivative authoritative guidance in our Consolidated Balance Sheets. 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 September 30, 2022 and December 31, 2021 and not reflected in the tables above. (b) Includes $2,013 million and $897 million of variation margin held from the exchanges as of September 30, 2022 and December 31, 2021, respectively. Economic Hedges (Commodity Price Risk) For the three and nine months ended September 30, 2022 and 2021, 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. Three Months Ended September 30, Nine Months Ended September 30, 2022 2021 2022 2021 Income Statement Location (Losses) Gains (Losses) Gains Operating revenues $ (691) $ (637) $ (1,913) $ (961) Purchased power and fuel 171 1,392 1,346 2,209 Total $ (520) $ 755 $ (567) $ 1,248 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 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 September 30, 2022, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York, and ERCOT reportable segments is 97%-100% and 92%-95% for 2022 and 2023, 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 three and nine months ended September 30, 2022 and 2021, activity associated with proprietary trading activities 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 $563 million and $486 million as of September 30, 2022 and December 31, 2021, respectively. The following table provides the mark-to-market derivative assets and liabilities as of September 30, 2022: September 30, 2022 Economic Netting (a) Total Mark-to-market derivative assets (current assets) $ 27 $ (8) $ 19 Mark-to-market derivative assets (noncurrent assets) 23 — 23 Total mark-to-market derivative assets 50 (8) 42 Mark-to-market derivative liabilities (current liabilities) (20) 8 (12) Mark-to-market derivative liabilities (noncurrent liabilities) (1) — (1) Total mark-to-market derivative liabilities (21) 8 (13) Total mark-to-market derivative net assets (liabilities) $ 29 $ — $ 29 _________ (a) We net all available amounts allowed under the derivative authoritative guidance in our Consolidated Balance Sheets. 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 risk for the three and nine months ended September 30, 2022 and 2021 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 commodity 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 September 30, 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, NGX, and Nodal commodity exchanges. Rating as of September 30, 2022 Total Credit Collateral (a) Net Number of Net Exposure of Investment grade $ 1,515 $ 584 $ 931 — $ — Non-investment grade 14 — 14 — — No external ratings Internally rated — investment grade 109 — 109 — — Internally rated — non-investment grade 330 89 241 — — Total $ 1,968 $ 673 $ 1,295 — $ — Net Credit Exposure by Type of Counterparty As of September 30, 2022 Investor-owned utilities, marketers, power producers $ 1,057 Energy cooperatives and municipalities 96 Financial institutions 53 Other 89 Total $ 1,295 __________ (a) As of September 30, 2022, credit collateral held from counterparties where we had credit exposure included $530 million of cash and $143 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 a combination of several months of future payments (e.g., capacity payments) and 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: Credit-Risk-Related Contingent Features September 30, 2022 December 31, 2021 Gross fair value of derivative contracts containing this feature (a) $ (8,882) $ (3,872) Offsetting fair value of in-the-money contracts under master netting arrangements (b) 5,336 2,424 Net fair value of derivative contracts containing this feature (c) $ (3,546) $ (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 September 30, 2022 and December 31, 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. September 30, 2022 December 31, 2021 Cash collateral posted (a) $ 1,370 $ 713 Letters of credit posted (a) 1,146 755 Cash collateral held (a) 1,605 182 Letters of credit held (a) 161 124 Additional collateral required in the event of a credit downgrade below investment grade (at BB+/Ba1) (b)(c) 3,115 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	9 Months Ended
	Sep. 30, 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 and bilateral credit agreements as of September 30, 2022 and December 31, 2021: Outstanding Commercial Average Interest Rate on September 30, 2022 December 31, 2021 September 30, 2022 December 31, 2021 $ 493 $ 702 3.95 % 0.66 % 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 revolving credit facility at a variable interest rate of SOFR plus 1.275%, with a maturity of February 1, 2027 and on February 9, 2022, we entered into a $1 billion liquidity facility with the primary purpose of supporting our letter of credit issuances with a maturity of January 31, 2027. As of September 30, 2022, we had the following aggregate bank commitments, credit facility borrowings and available capacity under our respective credit facilities: Available Capacity as of September 30, 2022 Facility Type Aggregate Bank Facility Draws Outstanding Actual To Support Syndicated Revolver (a) $ 3,500 $ — $ 1,503 $ 1,997 $ 1,504 Bilaterals (b) 1,200 — 1,034 166 — Liquidity Facility (c) 971 — 861 110 — Project Finance 131 — 111 20 — Total $ 5,802 $ — $ 3,509 $ 2,293 $ 1,504 __________ (a) Excludes $44 million of credit facility agreements arranged at minority and community banks. These facilities expired on October 7, 2022. As of September 30, 2022, there were no letters of credit issued under these facilities. (b) On July 15, 2022, a bilateral credit agreement initiated on November 21, 2019 decreased from $150 million to $100 million. On August 12, 2022, we initiated a new bilateral credit agreement for $50 million. This credit agreement does not contain a maturity date and is automatically renewed based on the contingency standards within the specific agreement. On August 24, 2022, we initiated a new bilateral credit agreement for $100 million with a maturity date of August 23, 2024. (c) 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 September 30, 2022, without posting additional collateral, the actual availability of facility, prior to outstanding letters of credit was $877 million. 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 date of March 16, 2022. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.875% and all indebtedness thereunder is 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 Sheet 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 bear 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 is unsecured. The loan agreement was amended on January 24, 2022 to change the maturity date to June 30, 2022 from August 5, 2022. We repaid the term loan on April 15, 2022 that was reflected in Short-term borrowings in the Consolidated Balance Sheet as of December 31, 2021. See Note 2 — Mergers, Acquisitions, and Dispositions of our 2021 Form 10-K for additional information. Long-Term Debt Debt Issuances and Redemptions During the nine months ended September 30, 2022, the following long-term debt was issued: Type Interest Rate Maturity Amount Use of Proceeds Energy Efficiency Project Financing (a) 2.20% - 2.44% March 31, 2023 - February 29, 2024 $ 9 Funding to install energy conservation measures. __________ (a) For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt. During the nine months ended September 30, 2022, the following long-term debt was retired and/or redeemed: Type Interest Rate Maturity Amount Senior Notes 3.40% March 15, 2022 $ 500 Senior Notes 4.25% June 15, 2022 523 CR Nonrecourse Debt 3 month LIBOR + 2.50% December 15, 2027 41 Continental Wind Nonrecourse Debt 6.00% February 28, 2033 36 West Medway II Nonrecourse Debt 1 month LIBOR + 2.875% March 31, 2026 17 Antelope Valley DOE Nonrecourse Debt 2.29% - 3.56% January 5, 2037 14 RPG Nonrecourse Debt 4.11% March 31, 2035 9 Energy Efficiency Project Financing 3.71% December 31, 2022 3 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 Corporate. In connection with the separation, on January 31, 2022, we paid cash to Exelon Corporate in the amount of $258 million to settle the intercompany loan with the difference of $61 million recorded to membership interest. Debt Covenants As of September 30, 2022, we are in compliance with all debt covenants.

Fair Value of Financial Assets

Fair Value of Financial Assets and Liabilities	9 Months Ended
	Sep. 30, 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 table presents the carrying amounts and fair values of the short-term liabilities, long-term debt, and the SNF obligation as of September 30, 2022 and December 31, 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. September 30, 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 $ 4,661 $ 3,577 $ 907 $ 4,484 $ 6,114 $ 5,749 $ 1,093 $ 6,842 SNF Obligation 1,219 975 — 975 1,210 1,060 — 1,060 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 September 30, 2022 and December 31, 2021: As of September 30, 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) $ 16 $ — $ — $ — $ 16 $ 113 $ — $ — $ — $ 113 NDT fund investments Cash equivalents (b) 494 94 — — 588 465 116 — — 581 Equities 3,153 1,330 2 1,145 5,630 4,564 1,805 — 1,645 8,014 Fixed income Corporate debt (c) — 982 264 — 1,246 — 1,145 286 — 1,431 U.S. Treasury and agencies 1,960 19 — — 1,979 2,193 30 — — 2,223 Foreign governments — 42 — — 42 — 60 — — 60 State and municipal debt — 46 — — 46 — 26 — — 26 Other 20 19 — 1,665 1,704 29 23 — 1,449 1,501 Fixed income subtotal 1,980 1,108 264 1,665 5,017 2,222 1,284 286 1,449 5,241 Private credit — — 164 640 804 — — 178 624 802 Private equity — — — 678 678 — — — 673 673 Real estate — — — 1,007 1,007 — — — 864 864 NDT fund investments subtotal (d)(e) 5,627 2,532 430 5,135 13,724 7,251 3,205 464 5,255 16,175 Rabbi trust investments Cash equivalents 1 — — — 1 3 — — — 3 Mutual funds 36 — — — 36 36 — — — 36 Life insurance contracts — 27 1 — 28 — 33 — — 33 Rabbi trust investments subtotal 37 27 1 — 65 39 33 — — 72 Investments in equities 6 — — — 6 43 — — — 43 Mark-to-market derivative assets Economic hedges 6,689 16,175 11,991 — 34,855 3,017 7,223 3,899 — 14,139 Proprietary trading — 11 14 — 25 — 19 8 — 27 Effect of netting and allocation of (f)(g) (5,233) (15,882) (9,956) — (31,071) (2,108) (6,177) (2,769) — (11,054) Mark-to-market derivative assets subtotal 1,456 304 2,049 — 3,809 909 1,065 1,138 — 3,112 DPP consideration — 975 — — 975 — 365 — — 365 Total assets 7,142 3,838 2,480 5,135 18,595 8,355 4,668 1,602 5,255 19,880 Liabilities Mark-to-market derivative liabilities Economic hedges (5,438) (15,909) (13,104) — (34,451) (2,201) (6,870) (3,965) — (13,036) Proprietary trading — (12) (9) — (21) — (18) (2) — (20) Effect of netting and allocation of collateral (f)(g) 5,492 15,733 9,611 — 30,836 2,189 6,642 2,735 — 11,566 Mark-to-market derivative liabilities subtotal 54 (188) (3,502) — (3,636) (12) (246) (1,232) — (1,490) Deferred compensation obligation — (53) — — (53) — (43) — — (43) Total liabilities 54 (241) (3,502) — (3,689) (12) (289) (1,232) — (1,533) Total net assets (liabilities) $ 7,196 $ 3,597 $ (1,022) $ 5,135 $ 14,906 $ 8,343 $ 4,379 $ 370 $ 5,255 $ 18,347 __________ (a) CEG Parent has $44 million of Level 1 cash equivalents as of September 30, 2022. We exclude cash of $1,123 million and $417 million as of September 30, 2022 and December 31, 2021, respectively, and restricted cash of $75 million and $46 million as of September 30, 2022 and December 31, 2021, respectively. CEG Parent has excluded an additional $61 million of cash as of September 30, 2022. (b) Includes $89 million and $116 million of cash received from outstanding repurchase agreements as of September 30, 2022 and December 31, 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 ($38) million and ($55) million as of September 30, 2022 and December 31, 2021, respectively, held in an investment vehicle primarily to hedge the equity option component of convertible debt. (d) Includes net derivative liabilities of $1 million, which have total notional amounts of $432 million and $687 million as of September 30, 2022 and December 31, 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 $178 million and $111 million as of September 30, 2022 and December 31, 2021, respectively, which include certain derivative assets that have notional amounts of $140 million and $182 million as of September 30, 2022 and December 31, 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) Collateral posted/(received) from counterparties, net of collateral paid to counterparties, totaled $259 million, ($149) million, and ($345) million allocated to Level 1, Level 2, and Level 3 mark-to-market derivatives, respectively, as of September 30, 2022. Collateral posted/(received) from counterparties, net of collateral paid to 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 $2,013 million and $897 million of variation margin held from the exchanges as of September 30, 2022 and December 31, 2021, respectively. As of September 30, 2022, we have outstanding commitments to invest in private credit, private equity, and real estate investments of $242 million, $144 million, and $412 million, respectively. These commitments will be funded by our existing NDT funds. We hold investments without readily determinable fair values with carrying amounts of $45 million and $33 million as of September 30, 2022 and December 31, 2021, respectively. Changes in fair value, cumulative adjustments, and impairments were not material for the three and nine months ended September 30, 2022 and the year ended December 31, 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 three and nine months ended September 30, 2022 and 2021: For the Three Months Ended September 30, 2022 NDT Fund Investments Mark-to-Market Life Insurance Contracts Total Balance as of June 30, 2022 $ 431 $ (743) $ 1 $ (311) Total realized / unrealized (losses) gains Included in net income — (925) (a) — (925) Included in Payable related to Regulatory Agreement Units (2) — — (2) Change in collateral — (58) — (58) Purchases, sales, issuances and settlements Purchases — 333 — 333 Sales — (7) — (7) Settlements — — — — Transfers into Level 3 1 1 (b) — 2 Transfers out of Level 3 — (54) (b) — (54) Balance as of September 30, 2022 $ 430 $ (1,453) $ 1 $ (1,022) The amount of total (losses) gains included in income attributed to the change in unrealized (losses) gains related to assets and liabilities as of September 30, 2022 $ (1) $ (889) $ — $ (890) For the Three Months Ended September 30, 2021 NDT Fund Investments Mark-to-Market Total Balance as of June 30, 2021 $ 461 $ (465) $ (4) Total realized / unrealized gains (losses) Included in net income 3 (970) (a) (967) Included in noncurrent payables to affiliates 11 — 11 Change in collateral — (413) (413) Purchases, sales, issuances and settlements Purchases 2 6 8 Sales — 6 6 Settlements (2) — (2) Transfers into Level 3 — 2 (b) 2 Transfers out of Level 3 — (27) (b) (27) Balance as of September 30, 2021 $ 475 $ (1,861) $ (1,386) The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2021 $ 3 $ (1,004) $ (1,001) For the Nine Months Ended September 30, 2022 NDT Fund Investments Mark-to-Market Life Insurance Contracts Total Balance as of December 31, 2021 $ 464 $ (94) $ — $ 370 Total realized / unrealized losses Included in net income (2) (1,823) (a) (2) (1,827) Included in Payable related to Regulatory Agreement Units (11) — — (11) Change in collateral — (312) — (312) Impacts of separation — — 3 3 Purchases, sales, issuances and settlements Purchases 5 499 — 504 Sales — (44) — (44) Settlements (28) (30) — (58) Transfers into Level 3 2 418 (b) — 420 Transfers out of Level 3 — (67) (b) — (67) Balance as of September 30, 2022 $ 430 $ (1,453) $ 1 $ (1,022) The amount of total losses included in income attributed to the change in unrealized losses related to assets and liabilities as of September 30, 2022 $ (2) $ (1,951) $ (2) $ (1,955) For the Nine Months Ended September 30, 2021 NDT Fund Investments Mark-to-Market Total Balance as of December 31, 2020 $ 497 $ 430 $ 927 Total realized / unrealized gains (losses) Included in net income 4 (1,606) (a) (1,602) Included in noncurrent payables to affiliates 18 — 18 Change in collateral — (751) (751) Purchases, sales, issuances and settlements Purchases 3 120 123 Sales — 7 7 Settlements (48) — (48) Transfers into Level 3 1 3 (b) 4 Transfers out of Level 3 — (64) (b) (64) Balance as of September 30, 2021 $ 475 $ (1,861) $ (1,386) The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2021 $ 4 $ (1,527) $ (1,523) __________ (a) Includes a reduction of $35 million for realized gains and an addition of $98 million for realized losses due to the settlement of derivative contracts for the three and nine months ended September 30, 2022, respectively. Includes an addition of $34 million for realized losses and a reduction of $80 million for realized gains due to the settlement of derivative contracts for the three and nine months ended September 30, 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 tables present the income statement classification of the total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis during the three and nine months ended September 30, 2022 and 2021: For the Three Months Ended September 30, Operating Purchased Other, net 2022 2021 2022 2021 2022 2021 Total (losses) gains included in net income $ (545) $ (1,274) $ (380) $ 304 $ — $ 3 Total unrealized (losses) gains (768) (1,361) (121) 357 (1) 3 For the Nine Months Ended September 30, Operating Purchased Other, net 2022 2021 2022 2021 2022 2021 Total (losses) gains included in net income $ (1,786) $ (1,944) $ (67) $ 338 $ (4) $ 4 Total unrealized (losses) gains (2,353) (1,969) 402 443 (4) 4 Our valuation techniques used to measure the fair value of the assets and liabilities shown in the tables below are in accordance with the policies discussed in Note 18 — Fair Value of Financial Assets and Liabilities of our 2021 Form 10-K. Valuation Techniques Used to Determine Net Asset Value Certain NDT Fund Investments are not classified within the fair value hierarchy and are included under the heading “Not subject to leveling” in the table above. These investments are measured at fair value using NAV per share as a practical expedient and include commingled funds, mutual funds which are not publicly quoted, managed private credit funds, private equity and real estate funds. For commingled funds and mutual funds, which are not publicly quoted, the fair value is primarily derived from the quoted prices in active markets on the underlying securities and can typically be redeemed monthly with 30 or less days of notice and without further restrictions. 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. Private equity and real estate investments include those in limited partnerships that invest in operating companies and real estate holding companies that are not publicly traded on a stock exchange, such as, leveraged buyouts, growth capital, venture capital, distressed investments, investments in natural resources, and direct investments in pools of real estate properties. 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 and real estate valuations are reported by the fund manager and are based on the valuation of the underlying investments, which include inputs such as cost, operating results, discounted future cash flows, market based comparable data, and independent appraisals from sources with professional qualifications. These valuation inputs are unobservable. Mark-to-Market Derivatives See Note 12 — 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 September 30, 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) $ (1,113) $ (66) Discounted Cash Flow Forward power $9.26 - $1,108 $100 $8.86 - $481 $55 Forward gas $2.55 - $31 $5.25 $1.69 - $17 $3.50 Option Volatility 100% - 128% 113% 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 received on level 3 positions of $345 million and $34 million as of September 30, 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. Increases (decreases) in the forward commodity price in isolation would result in significantly higher (lower) fair values for long positions (contracts that give us the obligation or option to purchase a commodity), with offsetting impacts to short positions (contracts that give us the obligation or right to sell a commodity). Increases (decreases) in volatility would increase (decrease) the value for the holder of the option (writer of the option). Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of volatility of prices. An increase to the reserves listed above would decrease the fair value of the positions. An increase to the heat rate or renewable factors would increase the fair value accordingly. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets.

Commitments and Contingencies

Commitments and Contingencies	9 Months Ended
	Sep. 30, 2022
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies Commitments Commercial Commitments. Commercial commitments as of September 30, 2022, representing commitments potentially triggered by future events, were as follows: Expiration within Total 2022 2023 2024 2025 2026 2027 and beyond Letters of credit $ 3,509 $ 2,125 $ 1,384 $ — $ — $ — $ — Surety bonds (a) 978 256 722 — — — — Total commercial commitments $ 4,487 $ 2,381 $ 2,106 $ — $ — $ — $ — __________ (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. 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 financial statements. We had accrued undiscounted amounts for environmental liabilities of $122 million and $120 million as of September 30, 2022 and December 31, 2021, 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 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 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 February 28, 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 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 September 30, 2022 and December 31, 2021, we recorded estimated liabilities of approximately $97 million and $81 million, respectively, in total for asbestos-related bodily injury claims. As of September 30, 2022, approximately $24 million of this amount related to 257 open claims presented to us, while the remaining $73 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 150 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. The motions were taken under advisement. 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 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	9 Months Ended
	Sep. 30, 2022
Share-Based Payment Arrangement [Abstract]
Stock-Based Compensation Plans	Stock-Based Compensation Plans Stock-Based Compensation 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 three and nine months ended September 30, 2022. The following table presents the stock-based compensation expense included in our 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. Three Months Ended September 30, Nine Months Ended September 30, 2022 2021 2022 2021 Total stock-based compensation expense included in operating and maintenance expense $ 53 $ 8 $ 85 $ 30 Income tax benefit (13) (2) (21) (8) Total after-tax stock-based compensation expense $ 40 $ 6 $ 64 $ 22 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-year performance period, subject to certain ownership thresholds that, if met, may result in cash settlement of the entire award. 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. During the nine months ended September 30, 2022, we granted performance share awards, inclusive of those converted at separation, totaling 1,501,673 shares with a weighted-average grant date fair value of $47.23. As of September 30, 2022, $31 million of total unrecognized compensation costs related to nonvested performance shares are expected to be recognized over the remaining weighted-average period of 2.0 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 During the nine months ended September 30, 2022, we granted restricted stock units, inclusive of those converted at separation, totaling 1,371,997 shares with a grant date fair value of $45.22. As of September 30, 2022, $29 million of total unrecognized compensation costs related to nonvested restricted stock units are expected to be recognized over the remaining weighted-average period of 2.3 years.

Changes in Accumulated Other Co

Changes in Accumulated Other Comprehensive Loss	9 Months Ended
	Sep. 30, 2022
Equity [Abstract]
Changes in Accumulated Other Comprehensive Loss	Changes in Accumulated Other Comprehensive Loss The following tables present changes in AOCI, net of tax, by component: Three Months Ended September 30, 2022 Losses on Cash Flow Hedges Pension and Non-Pension Postretirement Benefit Plan Items(a) Foreign Currency Items Total Beginning balance $ (8) $ (1,963) $ (21) $ (1,992) OCI before reclassifications — — (6) (6) Amounts reclassified from AOCI (1) 30 — 29 Net current-period OCI (1) 30 (6) 23 Ending balance $ (9) $ (1,933) $ (27) $ (1,969) Three Months Ended September 30, 2021 Losses on Cash Flow Hedges Pension and Non-Pension Postretirement Benefit Plan Items(a) Foreign Currency Items Total Beginning balance $ (7) $ — $ (20) $ (27) OCI before reclassifications (1) — (3) (4) Net current-period OCI (1) — (3) (4) Ending balance $ (8) $ — $ (23) $ (31) Nine Months Ended September 30, 2022 Losses on Cash Flow Hedges Pension and Non-Pension Postretirement Benefit Plan Items(a) Foreign Currency Items Total Beginning balance $ (8) $ — $ (23) $ (31) Separation-related adjustments — (2,006) — (2,006) OCI before reclassifications (1) — (4) (5) Amounts reclassified from AOCI — 73 — 73 Net current-period OCI (1) (1,933) (4) (1,938) Ending balance $ (9) $ (1,933) $ (27) $ (1,969) Nine Months Ended September 30, 2021 Losses on Cash Flow Hedges Pension and Non-Pension Postretirement Benefit Plan Items(a) Foreign Currency Items Total Beginning balance $ (7) $ — $ (23) $ (30) OCI before reclassifications (1) — — (1) Net current-period OCI (1) — — (1) Ending balance $ (8) $ — $ (23) $ (31) __________ (a) AOCI amounts are included in the computation of net periodic pension and OPEB cost. See Note 11 — Retirement Benefits for additional information. See our Statements of Operations and Comprehensive Income for individual components of AOCI. The following table presents income tax benefit (expense) allocated to each component of our other comprehensive loss: Three Months Ended September 30, Nine Months Ended September 30, 2022 2021 2022 2021 Pension and non-pension postretirement benefit plans: Actuarial loss reclassified to periodic benefit cost $ (9) $ — $ (24) $ — Pension and non-pension postretirement benefit plans valuation adjustment — — 680 —

Variable Interest Entities

Variable Interest Entities	9 Months Ended
	Sep. 30, 2022
Variable Interest Entity [Abstract]
Variable Interest Entities	Variable Interest Entities At September 30, 2022 and December 31, 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 September 30, 2022 and December 31, 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. September 30, 2022 December 31, 2021 Cash and cash equivalents $ 64 $ 35 Restricted cash and cash equivalents 42 48 Accounts receivable Customer 25 24 Other 8 6 Inventories, net Materials and supplies 12 14 Other current assets 1,022 405 Total current assets 1,173 532 Property, plant and equipment, net 1,971 2,027 Other noncurrent assets 195 215 Total noncurrent assets 2,166 2,242 Total assets (a) $ 3,339 $ 2,774 Long-term debt due within one year $ 60 $ 70 Accounts payable 19 10 Accrued expenses 20 21 Other current liabilities 2 1 Total current liabilities 101 102 Long-term debt 775 822 Asset retirement obligations 171 151 Other noncurrent liabilities 3 3 Total noncurrent liabilities 949 976 Total liabilities (b) $ 1,050 $ 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, noncurrent unamortized energy contract assets of $183 million and $202 million, disclosed within other noncurrent assets in the table above as of September 30, 2022 and December 31, 2021, respectively. (b) Our balances include liabilities with recourse of $1 million and $1 million as of September 30, 2022 and December 31, 2021, respectively. As of September 30, 2022 and December 31, 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 of our 2021 Form 10-K 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 September 30, 2022 and December 31, 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: September 30, 2022 December 31, 2021 Commercial Equity Total Commercial Equity Total Total assets (a) $ 716 $ 344 $ 1,060 $ 772 $ 372 $ 1,144 Total liabilities (a) 55 206 261 80 216 296 Our ownership interest in VIE (a) — 122 122 — 139 139 Other ownership interests in VIE (a) 661 16 677 692 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 September 30, 2022 and December 31, 2021. As of September 30, 2022 and December 31, 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. 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	9 Months Ended
	Sep. 30, 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 within our Consolidated Statements of Operations and Comprehensive Income. Operating revenues Three Months Ended September 30, Nine Months Ended September 30, 2022 2021 2022 2021 Operating lease income $ 29 $ 29 $ 46 $ 44 Variable lease income 77 71 204 207 Taxes other than income taxes Three Months Ended September 30, Nine Months Ended September 30, 2022 2021 2022 2021 Gross receipts (a) $ 39 $ 27 $ 100 $ 73 Property 67 66 206 199 Payroll 36 26 99 83 __________ (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 Three Months Ended September 30, Nine Months Ended September 30, 2022 2021 2022 2021 Decommissioning-related activities: Net realized income on NDT funds (a) Regulatory Agreement Units $ 61 $ 263 $ 333 $ 698 Non-Regulatory Agreement Units 15 102 115 392 Net unrealized (losses) gains on NDT funds Regulatory Agreement Units (386) (195) (1,777) 84 Non-Regulatory Agreement Units (225) (88) (1,077) 38 Regulatory offset to NDT fund-related activities (b) 262 (38) 1,160 (607) Decommissioning-related activities (273) 44 (1,246) 605 Non-service net periodic benefit credit (c) 27 — 79 — Net unrealized (losses) gains on CTV investments (d) (2) (179) (27) (83) __________ (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 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 income taxes related to all NDT fund activity for those 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 of our 2021 Form 10-K 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 11 — Retirement Benefits for additional information. (d) Net unrealized (losses) gains on CTV investments that became publicly traded in the fourth quarter of 2020 and the first half of 2021. Supplemental Cash Flow Information The following tables provide additional information about material items recorded within our Consolidated Statements of Cash Flows. Depreciation, amortization and accretion Nine Months Ended September 30, 2022 2021 Property, plant, and equipment (a) $ 798 $ 2,698 Amortization of intangible assets, net (a) 20 37 Amortization of energy contract assets and liabilities (b) 28 23 Nuclear fuel (c) 561 810 ARO accretion (d) 403 383 Total depreciation, amortization, and accretion $ 1,810 $ 3,951 __________ (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. Other non-cash operating activities CEG Parent Constellation Nine Months Ended September 30, Nine Months Ended September 30, 2022 2021 2022 2021 Pension and non-pension postretirement benefit costs $ 12 $ 92 $ 12 $ 92 Allowance for credit losses 12 59 12 59 Other decommissioning-related activity (a) (116) (810) (116) (810) Energy-related options (b) 239 45 239 45 Severance costs — (75) — (75) Long-term incentive plan 35 — — — Amortization of operating ROU asset 65 98 65 98 Loss on sale of receivables 39 26 39 26 Fair value adjustments related to gas imbalances 65 — 65 — 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 of our 2021 Form 10-K 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 15 - Commitments and Contingencies for additional information. The following table provides a reconciliation of cash, restricted cash, and cash equivalents reported within our Consolidated Balance Sheets that sum to the total of the same amounts in the Consolidated Statements of Cash Flows. CEG Parent Constellation September 30, 2022 Cash and cash equivalents $ 1,192 $ 1,131 Restricted cash and cash equivalents 111 83 Total cash, restricted cash, and cash equivalents $ 1,303 $ 1,214 December 31, 2021 Cash and cash equivalents $ 504 $ 504 Restricted cash and cash equivalents 72 72 Total cash, restricted cash, and cash equivalents $ 576 $ 576 September 30, 2021 Cash and cash equivalents $ 1,957 $ 1,957 Restricted cash and cash equivalents 62 62 Total cash, restricted cash, and cash equivalents $ 2,019 $ 2,019 December 31, 2020 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 For additional information on restricted cash see Note 1 — Significant Accounting Policies of our 2021 Form 10-K. Supplemental Balance Sheet Information The following table provides additional information about material items recorded within our Consolidated Balance Sheets. Accrued expenses September 30, 2022 CEG Parent Constellation Compensation-related accruals (a) $ 395 $ 359 Taxes accrued 401 401 December 31, 2021 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	9 Months Ended
	Sep. 30, 2022
Related Party Transactions [Abstract]
Related Party Transactions	Related Party TransactionsPrior 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: Three Months Ended September 30, Nine Months Ended September 30, 2022 2021 2022 (g) 2021 ComEd (a) $ — $ 96 $ 58 $ 249 PECO (b) — 59 33 142 BGE (c) — 65 18 195 PHI — 99 51 276 Pepco (d) — 69 39 199 DPL (e) — 25 10 63 ACE (f) — 5 2 14 Other — 5 — 10 Total operating revenues from affiliates $ — $ 324 $ 160 $ 872 __________ (a) 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. (b) 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. (c) We provide a portion of BGE’s energy requirements under its MDPSC-approved market-based SOS and gas commodity programs. (d) We provide electric supply to Pepco under contracts executed through Pepco's competitive procurement process approved by the MDPSC and DCPSC. (e) We provide a portion of DPL's energy requirements under its MDPSC and DEPSC approved market-based SOS commodity programs. (f) We provide electric supply to ACE under contracts executed through ACE's competitive procurement process. (g) Represents only January 2022 costs prior to separation on February 1, 2022. 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 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 Three Months Ended September 30, Nine Months Ended September 30, Three Months Ended September 30, Nine Months Ended September 30, 2022 2021 2022 (a) 2021 2022 2021 2022 (a) 2021 $ — $ 145 $ 44 $ 424 $ — $ 43 $ 15 $ 76 __________ (a) Represents only January 2022 costs prior to separation on February 1, 2022. Current Receivables from/Payables to Affiliates The following tables present 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 September 30, 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 8 — Nuclear Decommissioning for additional information.

Basis of Presentation (Policies

Basis of Presentation (Policies)	9 Months Ended
	Sep. 30, 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 (the separation), 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 as of September 30, 2022 and for the three and nine months ended September 30, 2022 and 2021 are unaudited but, in our opinion include all adjustments that are considered necessary for a fair statement of the financial statements in accordance with GAAP. All adjustments are of a normal, recurring nature, except as otherwise disclosed. 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. Constellation's December 31, 2021 Consolidated Balance Sheet was derived from audited financial statements. The interim financial statements are to be read in conjunction with prior annual financial statements and notes. Financial results for interim periods are not necessarily indicative of results that may be expected for any other interim period or for the fiscal year ending December 31, 2022. These Combined Notes to Consolidated Financial Statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations. 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.
Separation from Exelon	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 now 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
Retirement Benefits	Retirement Benefits Effective upon separation, we sponsor defined benefit pension and OPEB plans as described in Note 11 — Retirement Benefits. The plan obligations and costs of providing benefits under these plans were measured as of February 1, 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.

Mergers, Acquisitions, and Di_2

Mergers, Acquisitions, and Dispositions (Tables)	9 Months Ended
	Sep. 30, 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 Members Equity: Three Months Ended September 30, 2021 Nine Months Ended September 30, 2021 Net income (loss) attributable to membership interest $ 607 $ (247) Pre-tax increase in membership interest for purchase of EDF's 49.99% equity interest (a) 1,080 1,080 Decrease in membership interest due to deferred tax liabilities resulting from purchase of EDF's equity interest (a) (288) (288) Change from net income (loss) attributable to membership interest and transfers from noncontrolling interest. $ 1,399 $ 545 __________ (a) Represents non-cash activity in the consolidated financial statements.

Revenue from Contracts with C_2

Revenue from Contracts with Customers (Tables)	9 Months Ended
	Sep. 30, 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 for the three and nine months ended September 30, 2022 and 2021. Contract Assets Balance as of December 31, 2021 $ 149 Amounts reclassified to receivables (16) Revenues recognized 9 Balance as of March 31, 2022 $ 142 Amounts reclassified to receivables (13) Revenues recognized 10 Balance as of June 30, 2022 $ 139 Amounts reclassified to receivables (5) Revenues recognized 21 Balance as of September 30, 2022 $ 155 Balance as of December 31, 2020 $ 144 Amounts reclassified to receivables (16) Revenues recognized 13 Amounts previously held-for-sale 12 Balance as of March 31, 2021 $ 153 Amounts reclassified to receivables (12) Revenues recognized 9 Balance as of June 30, 2021 $ 150 Amounts reclassified to receivables (15) Revenues recognized 14 Balance as of September 30, 2021 $ 149 The following table provides a rollforward of the contract liabilities reflected in the Consolidated Balance Sheets for the three and nine months ended September 30, 2022 and 2021. Contract Liabilities Balance as of December 31, 2021 $ 75 Consideration received or due 50 Revenues recognized (63) Balance as of March 31, 2022 $ 62 Consideration received or due 27 Revenues recognized (63) Balance as of June 30, 2022 $ 26 Consideration received or due 71 Revenues recognized (68) Balance as of September 30, 2022 $ 29 Balance as of December 31, 2020 $ 84 Consideration received or due 31 Revenues recognized (64) Amounts previously held-for-sale 3 Balance as of March 31, 2021 $ 54 Consideration received or due 39 Revenues recognized (68) Balance as of June 30, 2021 $ 25 Consideration received or due 93 Revenues recognized (65) Balance as of September 30, 2021 $ 53
Contract with Customer, Prior Year Contract Revenues Recognized in Current Year	The following table reflects revenues recognized in the three and nine months ended September 30, 2022 and 2021, which were included in contract liabilities at December 31, 2021 and 2020, respectively: Three Months Ended September 30, Nine Months Ended September 30, 2022 2021 2022 2021 Revenues recognized $ 2 $ 2 $ 70 $ 81
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 September 30, 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. 2022 2023 2024 2025 2026 and thereafter Total Remaining performance obligations $ 97 $ 161 $ 63 $ 32 $ 152 $ 505

Segment Information (Tables)

Segment Information (Tables)	9 Months Ended
	Sep. 30, 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 three and nine months ended September 30, 2022 and 2021. Three Months Ended September 30, 2022 Revenues from external customers (a) Contracts with customers Other (b) Total Intersegment Revenues Total Revenues Mid-Atlantic $ 1,561 $ 97 $ 1,658 $ 1 $ 1,659 Midwest 1,182 (133) 1,049 (2) 1,047 New York 536 (110) 426 (3) 423 ERCOT 328 168 496 (6) 490 Other Power Regions 1,315 611 1,926 10 1,936 Total Competitive Businesses Electric Revenues 4,922 633 5,555 — 5,555 Competitive Businesses Natural Gas Revenues 471 599 1,070 — 1,070 Competitive Businesses Other Revenues (c) 154 (728) (574) — (574) Total Consolidated Operating Revenues $ 5,547 $ 504 $ 6,051 $ — $ 6,051 Three Months Ended September 30, 2021 Revenues from external customers (a) Contracts with customers Other (b) Total Intersegment Revenues Total Revenues Mid-Atlantic $ 1,145 $ 123 $ 1,268 $ 4 $ 1,272 Midwest 1,084 (99) 985 — 985 New York 445 10 455 — 455 ERCOT 191 165 356 2 358 Other Power Regions 948 318 1,266 (6) 1,260 Total Competitive Businesses Electric Revenues 3,813 517 4,330 — 4,330 Competitive Businesses Natural Gas Revenues 266 309 575 — 575 Competitive Businesses Other Revenues (c) 95 (594) (499) — (499) Total Consolidated Operating Revenues $ 4,174 $ 232 $ 4,406 $ — $ 4,406 Nine Months Ended September 30, 2022 Revenues from external customers (a) Contracts with customers Other (b) Total Intersegment Revenues Total Revenues Mid-Atlantic $ 3,894 $ 70 $ 3,964 $ 3 $ 3,967 Midwest 3,749 (401) 3,348 (3) 3,345 New York 1,492 (314) 1,178 — 1,178 ERCOT 744 476 1,220 (10) 1,210 Other Power Regions 3,756 1,423 5,179 10 5,189 Total Competitive Businesses Electric Revenues 13,635 1,254 14,889 — 14,889 Competitive Businesses Natural Gas Revenues 1,770 1,778 3,548 — 3,548 Competitive Businesses Other Revenues (c) 416 (1,746) (1,330) — (1,330) Total Consolidated Operating Revenues $ 15,821 $ 1,286 $ 17,107 $ — $ 17,107 Nine Months Ended September 30, 2021 Revenues from external customers (a) Contracts with customers Other (b) Total Intersegment Revenues Total Revenues Mid-Atlantic $ 3,377 $ 134 $ 3,511 $ 16 $ 3,527 Midwest 3,067 (123) 2,944 1 2,945 New York 1,204 (30) 1,174 (1) 1,173 ERCOT 724 155 879 11 890 Other Power Regions 3,043 713 3,756 (27) 3,729 Total Competitive Businesses Electric Revenues 11,415 849 12,264 — 12,264 Competitive Businesses Natural Gas Revenues 1,384 1,024 2,408 — 2,408 Competitive Businesses Other Revenues (c) 291 (846) (555) — (555) Total Consolidated Operating Revenues $ 13,090 $ 1,027 $ 14,117 $ — $ 14,117 __________ (a) Includes all wholesale and retail electric sales to third parties and affiliate sales to Exelon's utility subsidiaries prior to the separation on February 1, 2022. See Note 20 - 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-mar ket losses o f $681 million a nd $635 million for the three months ended September 30, 2022 and 2021, respectively, and unrealized mark-to-market losses of $1,899 million and $958 million for the nine months ended September 30, 2022 and 2021, respectively, and the elimination of intersegment revenues. Three Months Ended September 30, 2022 Three Months Ended September 30, 2021 RNF from external (a) Intersegment Total RNF from external (a) Intersegment Total Mid-Atlantic $ 553 $ 2 $ 555 $ 567 $ 3 $ 570 Midwest 572 — 572 655 — 655 New York 268 (1) 267 343 3 346 ERCOT 104 (38) 66 181 (2) 179 Other Power Regions 274 (17) 257 233 (22) 211 Total RNF for Reportable Segments 1,771 (54) 1,717 1,979 (18) 1,961 Other (b) (415) 54 (361) 881 18 899 Total RNF $ 1,356 $ — $ 1,356 $ 2,860 $ — $ 2,860 Nine Months Ended September 30, 2022 Nine Months Ended September 30, 2021 RNF from external (a) Intersegment Total RNF from external (a) Intersegment Total Mid-Atlantic $ 1,606 $ 6 $ 1,612 $ 1,698 $ 14 $ 1,712 Midwest 2,008 2 2,010 2,014 1 2,015 New York 822 5 827 873 7 880 ERCOT 321 (86) 235 (775) (147) (922) Other Power Regions 741 (31) 710 641 (77) 564 Total RNF for Reportable Segments 5,498 (104) 5,394 4,451 (202) 4,249 Other (b) (145) 104 (41) 1,563 202 1,765 Total RNF $ 5,353 $ — $ 5,353 $ 6,014 $ — $ 6,014 __________ (a) Includes purchases and sales from/to third parties and affiliate sales to Exelon's utility subsidiaries prior to the separation on February 1, 2022. See Note 20 - 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 $(524) million and gains of $754 million for the three months ended September 30, 2022 and 2021, respectively, and unrealized mark-to-market losses of ($571) million and gains of $1,242 million for the nine months ended September 30, 2022 and 2021, respectively; • Accelerated nuclear fuel amortization associated with the announced early plant retirements as discussed in Note 7 - Early Plant Retirements of $42 million and $148 million for the three and nine months ended September 30, 2021, respectively. • The elimination of intersegment RNF.

Accounts Receivable (Tables)

Accounts Receivable (Tables)	9 Months Ended
	Sep. 30, 2022
Receivables [Abstract]
Allowance for Credit Losses Rollforward	The following table presents the rollforward of Allowance for Credit Losses on Customer Accounts Receivable. Three Months Ended September 30, 2022 Balance as of June 30, 2022 (a) $ 49 Plus: Current period provision for expected credit losses 9 Less: Write-offs, net of recoveries (b) 3 Balance as of September 30, 2022 (a) $ 55 Three Months Ended September 30, 2021 Balance as of June 30, 2021 (a) $ 75 Plus: Current period provision for expected credit losses 10 Less: Write-offs, net of recoveries (b) 1 Balance as of September 30, 2021 (a) $ 84 Nine Months Ended September 30, 2022 Balance as of December 31, 2021 (a) $ 55 Plus: Current period provision for expected credit losses 12 Less: Write-offs, net of recoveries (b) 12 Balance as of September 30, 2022 (a) $ 55 Nine Months Ended September 30, 2021 Balance as of December 31, 2020 (a) $ 32 Plus: Current period provision for expected credit losses (c) 57 Less: Write-offs, net of recoveries (b) 5 Balance as of September 30, 2021 (a) $ 84 __________ (a) Allowance for Credit Losses on Other Accounts Receivable were not material as of the balance sheet dates. (b) Recoveries were not material. (c) Primarily relates to the impacts of the February 2021 extreme cold weather event. See Note 3 — Regulatory Matters for additional information
Purchases and Sales of Accounts Receivable	The following table summarizes the impact of the sale of certain receivables: As of September 30, 2022 As of December 31, 2021 Derecognized receivables transferred at fair value $ 1,675 $ 1,265 Cash proceeds received 700 900 DPP 975 365 Three Months Ended September 30, Nine Months Ended September 30, 2022 2021 2022 2021 Loss on sale of receivables (a) $ 15 $ 1 $ 39 $ 26 __________ (a) Reflected in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. Nine Months Ended September 30, 2022 2021 Proceeds from new transfers (a) $ 4,807 $ 4,440 Cash collections received on DPP and reinvested in the Facility (b) 3,295 2,652 Cash collections reinvested in the Facility 8,102 7,092 __________ (a) Customer accounts receivable sold into the Facility were $8,540 million and $7,373 million for the nine months ended September 30, 2022 and 2021, respectively. (b) Does not include $200 million net cash payments to the Purchasers in the third quarter of 2022 and $400 million cash proceeds received from the Purchasers in the first quarter of 2021. Nine Months Ended September 30, 2022 2021 Total receivables sold $ 312 $ 117 Related party transactions: Receivables sold to Exelon's utility subsidiaries prior to the separation on February 1, 2022 4 17

Early Plant Retirements (Tables

Early Plant Retirements (Tables)	9 Months Ended
	Sep. 30, 2022
Implications of Potential Early Plant Retirements [Abstract]
Restructuring and Related Costs	The total impact for the three and nine months ended September 30, 2021 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) Three Months Ended September 30, 2021 Nine Months Ended September 30, 2021 Depreciation and amortization Accelerated depreciation (a) $ 574 $ 1,805 Accelerated nuclear fuel amortization 42 148 Operating and maintenance One-time charges (94) (94) Other charges 4 8 Contractual offset (b) (60) (451) Total $ 466 $ 1,416 _________ (a) Includes the accelerated depreciation of plant assets including any ARC. (b) 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 of our 2021 Form 10-K for additional information.

Nuclear Decommissioning (Tables

Nuclear Decommissioning (Tables)	9 Months Ended
	Sep. 30, 2022
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation	The following table provides a rollforward of the nuclear decommissioning AROs reflected in the Consolidated Balance Sheets from December 31, 2021 to September 30, 2022: 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 394 Costs incurred related to decommissioning plants (50) Balance as of September 30, 2022 (a) $ 12,372 __________ (a) Includes $45 million and $72 million as the current portion of the ARO as of September 30, 2022 and December 31, 2021, respectively, which is included in Other current liabilities in the Consolidated Balance Sheets.
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 September 30, 2022 and noncurrent Payables to affiliates as of December 31, 2021: September 30, 2022 December 31, 2021 ComEd $ 2,469 $ 2,760 PECO 189 597

Income Taxes (Tables)

Income Taxes (Tables)	9 Months Ended
	Sep. 30, 2022
Income Tax Disclosure [Abstract]
Effective Income Tax Rate Reconciliation	The effective income tax rate from continuing operations varies from the U.S. federal statutory rate principally due to the following: Three Months Ended September 30, 2022 (a) 2021 U.S. federal statutory rate 21.0 % 21.0 % Increase (decrease) due to: State income taxes, net of federal income tax benefit (9.5) 4.4 Qualified NDT fund income and losses 22.1 0.9 Amortization of investment tax credit, including deferred taxes on basis differences 1.9 (0.7) Production tax credits and other credits 8.0 (1.4) Noncontrolling interests (0.5) (0.6) Other (3.6) (1.9) Effective income tax rate (b) 39.4 % 21.7 % Nine Months Ended September 30, 2022 (a) 2021 (a) U.S. federal statutory rate 21.0 % 21.0 % Increase (decrease) due to: State income taxes, net of federal income tax benefit (9.0) 90.2 Qualified NDT fund income and losses 48.6 (1,932.6) Amortization of investment tax credit, including deferred taxes on basis differences 2.0 130.6 Production tax credits and other credits 8.3 425.1 Noncontrolling interests — 145.2 Other 2.2 (229.5) Effective income tax rate (b) 73.1 % (1,350.0) % __________ (a) For every period, except the three months ended September 30, 2021, we recognized a loss on Income before income taxes. As a result, positive percentages represent an income tax benefit and negative percentages represent income tax expense for the periods presented. (b) The 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. The effective tax rate in 2021 is primarily due to the impacts of the February 2021 extreme cold weather event on Income before income taxes.
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. September 30, 2022 $ 29 December 31, 2021 39

Retirement Benefits (Tables)

Retirement Benefits (Tables)	9 Months Ended
	Sep. 30, 2022
Retirement Benefits [Abstract]
Schedule of Defined Benefit Plans Disclosures	We present our benefit obligations net of plan assets on our balance sheet within the following line items: September 30, 2022 December 31, 2021 Pension Benefits OPEB Pension Benefits OPEB Prepaid pension asset $ — $ — $ 1,683 $ — Other current liabilities (9) (17) — — Pension obligations (636) — — — Non-pension postretirement benefit — (861) — (847) (Unfunded) funded status (net benefit obligation less plan assets) $ (645) $ (878) $ 1,683 $ (847) The following table summarizes the assumptions we used to determine the benefit obligations as of February 1, 2022 and costs for 2022: Pension OPEB Discount rate (a) 3.23 % 3.21 % Investment crediting rate (b) 3.86 % N/A Expected return on plan assets (c) 7.00 % 6.50 % Rate of compensation increase 3.75 % 3.75 % Mortality table 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 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. (c) Applicable to our pension and OPEB plans with plan assets, with the OPEB rate representing a weighted average. The resulting average remaining service periods for pension and OPEB were as follows as of September 30, 2022: September 30, 2022 Pension plans 12.2 OPEB plans: Benefit Eligibility Age 7.5 Expected Retirement 8.3 Estimated future benefit payments to participants in all pension and OPEB plans were: Pension Benefits OPEB 2022 (a) $ 532 $ 108 2023 521 108 2024 524 108 2025 536 107 2026 533 107 2027 through 2031 2,710 540 Total estimated future benefits payments through 2031 $ 5,356 $ 1,078 __________ (a) Amount represents estimated benefit payments for the calendar year.
Schedule of Net Benefit Costs	The following tables present the components of our net periodic benefit costs (credits), prior to capitalization and co-owner allocations, for the three and nine months ended September 30, 2022 and 2021: Pension Benefits OPEB Total Pension Benefits and OPEB Three Months Ended September 30, Three Months Ended September 30, Three Months Ended September 30, 2022 2021 2022 2021 2022 2021 Components of net periodic benefit cost (credit) Service cost $ 31 $ 36 $ 6 $ 8 $ 37 $ 44 Non-service components of pension benefits & OPEB cost (credit) Interest cost 74 59 14 12 88 71 Expected return on assets (143) (123) (14) (15) (157) (138) Amortization of: Prior service cost (credit) — — (2) (3) (2) (3) Actuarial loss (gain) 37 50 — 3 37 53 Settlement charges 5 10 — — 5 10 Non-service components of pension benefits & OPEB credit (a) (27) (4) (2) (3) (29) (7) Net periodic benefit cost (b,c) $ 4 $ 32 $ 4 $ 5 $ 8 $ 37 Pension Benefits OPEB Total Pension Benefits and OPEB Nine Months Ended September 30, Nine Months Ended September 30, Nine Months Ended September 30, 2022 2021 2022 2021 2022 2021 Components of net periodic benefit cost (credit) Service cost $ 94 $ 109 $ 18 $ 22 $ 112 $ 131 Non-service components of pension benefits & OPEB cost (credit) Interest cost 217 177 42 34 259 211 Expected return on assets (423) (370) (42) (44) (465) (414) Amortization of: Prior service cost (credit) 1 — (5) (7) (4) (7) Actuarial loss (gain) 111 149 (1) 8 110 157 Settlement charges 5 14 — — 5 14 Non-service components of pension benefits & OPEB credit (a) (89) (30) (6) (9) (95) (39) Net periodic benefit cost (b,c) $ 5 $ 79 $ 12 $ 13 $ 17 $ 92 __________ (a) The pension benefit and OPEB non-service costs (credits) for the three and nine months ended September 30, 2021 are reflected in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. Effective February 1, 2022, these non-service costs (credits) are reflected in Other, net in the Consolidated Statements of Operations and Comprehensive Income. (b) The pension benefit and OPEB service costs reflected in the Consolidated Statements of Operations and Comprehensive Income for the three and nine months ended September 30, 2022 totaled $33 million and $98 million, respectively. The pension benefit and OPEB non-service credits reflected in the Consolidated Statements of Operations and Comprehensive Income for the three and nine months ended September 30, 2022 totaled ($27) million and ($85) million, respectively. (c) The pension benefit and OPEB service costs reflected in the Consolidated Statements of Operations and Comprehensive Income for the three and nine months ended September 30, 2021 totaled $32 million and $103 million, respectively. The pension benefit and OPEB non-service credits reflected in the Consolidated Statements of Operations and Comprehensive Income for the three and nine months ended September 30, 2021 totaled ($11) million and ($36) million, respectively.

Derivative Financial Instrume_2

Derivative Financial Instruments (Tables)	9 Months Ended
	Sep. 30, 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 September 30, 2022 and December 31, 2021: September 30, 2022 Economic Proprietary Collateral (a)(b) Netting (a) Total Mark-to-market derivative assets (current assets) $ 27,702 $ 24 $ (372) $ (24,816) $ 2,538 Mark-to-market derivative assets (noncurrent assets) 7,103 1 (27) (5,848) 1,229 Total mark-to-market derivative assets 34,805 25 (399) (30,664) 3,767 Mark-to-market derivative liabilities (current liabilities) (27,225) (21) 50 24,816 (2,380) Mark-to-market derivative liabilities (noncurrent liabilities) (7,205) — 114 5,848 (1,243) Total mark-to-market derivative liabilities (34,430) (21) 164 30,664 (3,623) Total mark-to-market derivative net assets (liabilities) $ 375 $ 4 $ (235) $ — $ 144 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 (liabilities) $ 1,103 $ 7 $ 512 $ — $ 1,622 _________ (a) We net all available amounts allowed under the derivative authoritative guidance in our Consolidated Balance Sheets. 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 September 30, 2022 and December 31, 2021 and not reflected in the tables above. (b) Includes $2,013 million and $897 million of variation margin held from the exchanges as of September 30, 2022 and December 31, 2021, respectively. The following table provides the mark-to-market derivative assets and liabilities as of September 30, 2022: September 30, 2022 Economic Netting (a) Total Mark-to-market derivative assets (current assets) $ 27 $ (8) $ 19 Mark-to-market derivative assets (noncurrent assets) 23 — 23 Total mark-to-market derivative assets 50 (8) 42 Mark-to-market derivative liabilities (current liabilities) (20) 8 (12) Mark-to-market derivative liabilities (noncurrent liabilities) (1) — (1) Total mark-to-market derivative liabilities (21) 8 (13) Total mark-to-market derivative net assets (liabilities) $ 29 $ — $ 29 _________
Economic Hedges (Commodity Price Risk)	For the three and nine months ended September 30, 2022 and 2021, 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. Three Months Ended September 30, Nine Months Ended September 30, 2022 2021 2022 2021 Income Statement Location (Losses) Gains (Losses) Gains Operating revenues $ (691) $ (637) $ (1,913) $ (961) Purchased power and fuel 171 1,392 1,346 2,209 Total $ (520) $ 755 $ (567) $ 1,248
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 September 30, 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, NGX, and Nodal commodity exchanges. Rating as of September 30, 2022 Total Credit Collateral (a) Net Number of Net Exposure of Investment grade $ 1,515 $ 584 $ 931 — $ — Non-investment grade 14 — 14 — — No external ratings Internally rated — investment grade 109 — 109 — — Internally rated — non-investment grade 330 89 241 — — Total $ 1,968 $ 673 $ 1,295 — $ — Net Credit Exposure by Type of Counterparty As of September 30, 2022 Investor-owned utilities, marketers, power producers $ 1,057 Energy cooperatives and municipalities 96 Financial institutions 53 Other 89 Total $ 1,295 __________ (a) As of September 30, 2022, credit collateral held from counterparties where we had credit exposure included $530 million of cash and $143 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: Credit-Risk-Related Contingent Features September 30, 2022 December 31, 2021 Gross fair value of derivative contracts containing this feature (a) $ (8,882) $ (3,872) Offsetting fair value of in-the-money contracts under master netting arrangements (b) 5,336 2,424 Net fair value of derivative contracts containing this feature (c) $ (3,546) $ (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 September 30, 2022 and December 31, 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. September 30, 2022 December 31, 2021 Cash collateral posted (a) $ 1,370 $ 713 Letters of credit posted (a) 1,146 755 Cash collateral held (a) 1,605 182 Letters of credit held (a) 161 124 Additional collateral required in the event of a credit downgrade below investment grade (at BB+/Ba1) (b)(c) 3,115 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)	9 Months Ended
	Sep. 30, 2022
Debt Disclosure [Abstract]
Schedule of Short-term Debt	The following table reflects our commercial paper program supported by the revolving credit agreements and bilateral credit agreements as of September 30, 2022 and December 31, 2021: Outstanding Commercial Average Interest Rate on September 30, 2022 December 31, 2021 September 30, 2022 December 31, 2021 $ 493 $ 702 3.95 % 0.66 %
Schedule of Line of Credit Facilities	As of September 30, 2022, we had the following aggregate bank commitments, credit facility borrowings and available capacity under our respective credit facilities: Available Capacity as of September 30, 2022 Facility Type Aggregate Bank Facility Draws Outstanding Actual To Support Syndicated Revolver (a) $ 3,500 $ — $ 1,503 $ 1,997 $ 1,504 Bilaterals (b) 1,200 — 1,034 166 — Liquidity Facility (c) 971 — 861 110 — Project Finance 131 — 111 20 — Total $ 5,802 $ — $ 3,509 $ 2,293 $ 1,504 __________ (a) Excludes $44 million of credit facility agreements arranged at minority and community banks. These facilities expired on October 7, 2022. As of September 30, 2022, there were no letters of credit issued under these facilities. (b) On July 15, 2022, a bilateral credit agreement initiated on November 21, 2019 decreased from $150 million to $100 million. On August 12, 2022, we initiated a new bilateral credit agreement for $50 million. This credit agreement does not contain a maturity date and is automatically renewed based on the contingency standards within the specific agreement. On August 24, 2022, we initiated a new bilateral credit agreement for $100 million with a maturity date of August 23, 2024. (c) 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 September 30, 2022, without posting additional collateral, the actual availability of facility, prior to outstanding letters of credit was $877 million.
Schedule of Long-term Debt Instruments	During the nine months ended September 30, 2022, the following long-term debt was issued: Type Interest Rate Maturity Amount Use of Proceeds Energy Efficiency Project Financing (a) 2.20% - 2.44% March 31, 2023 - February 29, 2024 $ 9 Funding to install energy conservation measures. __________ (a) For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt. During the nine months ended September 30, 2022, the following long-term debt was retired and/or redeemed: Type Interest Rate Maturity Amount Senior Notes 3.40% March 15, 2022 $ 500 Senior Notes 4.25% June 15, 2022 523 CR Nonrecourse Debt 3 month LIBOR + 2.50% December 15, 2027 41 Continental Wind Nonrecourse Debt 6.00% February 28, 2033 36 West Medway II Nonrecourse Debt 1 month LIBOR + 2.875% March 31, 2026 17 Antelope Valley DOE Nonrecourse Debt 2.29% - 3.56% January 5, 2037 14 RPG Nonrecourse Debt 4.11% March 31, 2035 9 Energy Efficiency Project Financing 3.71% December 31, 2022 3

Fair Value of Financial Asset_2

Fair Value of Financial Assets and Liabilities (Tables)	9 Months Ended
	Sep. 30, 2022
Fair Value Disclosures [Abstract]
Fair Value of Financial Liabilities Recorded at Amortized Cost	The following table presents the carrying amounts and fair values of the short-term liabilities, long-term debt, and the SNF obligation as of September 30, 2022 and December 31, 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. September 30, 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 $ 4,661 $ 3,577 $ 907 $ 4,484 $ 6,114 $ 5,749 $ 1,093 $ 6,842 SNF Obligation 1,219 975 — 975 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 September 30, 2022 and December 31, 2021: As of September 30, 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) $ 16 $ — $ — $ — $ 16 $ 113 $ — $ — $ — $ 113 NDT fund investments Cash equivalents (b) 494 94 — — 588 465 116 — — 581 Equities 3,153 1,330 2 1,145 5,630 4,564 1,805 — 1,645 8,014 Fixed income Corporate debt (c) — 982 264 — 1,246 — 1,145 286 — 1,431 U.S. Treasury and agencies 1,960 19 — — 1,979 2,193 30 — — 2,223 Foreign governments — 42 — — 42 — 60 — — 60 State and municipal debt — 46 — — 46 — 26 — — 26 Other 20 19 — 1,665 1,704 29 23 — 1,449 1,501 Fixed income subtotal 1,980 1,108 264 1,665 5,017 2,222 1,284 286 1,449 5,241 Private credit — — 164 640 804 — — 178 624 802 Private equity — — — 678 678 — — — 673 673 Real estate — — — 1,007 1,007 — — — 864 864 NDT fund investments subtotal (d)(e) 5,627 2,532 430 5,135 13,724 7,251 3,205 464 5,255 16,175 Rabbi trust investments Cash equivalents 1 — — — 1 3 — — — 3 Mutual funds 36 — — — 36 36 — — — 36 Life insurance contracts — 27 1 — 28 — 33 — — 33 Rabbi trust investments subtotal 37 27 1 — 65 39 33 — — 72 Investments in equities 6 — — — 6 43 — — — 43 Mark-to-market derivative assets Economic hedges 6,689 16,175 11,991 — 34,855 3,017 7,223 3,899 — 14,139 Proprietary trading — 11 14 — 25 — 19 8 — 27 Effect of netting and allocation of (f)(g) (5,233) (15,882) (9,956) — (31,071) (2,108) (6,177) (2,769) — (11,054) Mark-to-market derivative assets subtotal 1,456 304 2,049 — 3,809 909 1,065 1,138 — 3,112 DPP consideration — 975 — — 975 — 365 — — 365 Total assets 7,142 3,838 2,480 5,135 18,595 8,355 4,668 1,602 5,255 19,880 Liabilities Mark-to-market derivative liabilities Economic hedges (5,438) (15,909) (13,104) — (34,451) (2,201) (6,870) (3,965) — (13,036) Proprietary trading — (12) (9) — (21) — (18) (2) — (20) Effect of netting and allocation of collateral (f)(g) 5,492 15,733 9,611 — 30,836 2,189 6,642 2,735 — 11,566 Mark-to-market derivative liabilities subtotal 54 (188) (3,502) — (3,636) (12) (246) (1,232) — (1,490) Deferred compensation obligation — (53) — — (53) — (43) — — (43) Total liabilities 54 (241) (3,502) — (3,689) (12) (289) (1,232) — (1,533) Total net assets (liabilities) $ 7,196 $ 3,597 $ (1,022) $ 5,135 $ 14,906 $ 8,343 $ 4,379 $ 370 $ 5,255 $ 18,347 __________ (a) CEG Parent has $44 million of Level 1 cash equivalents as of September 30, 2022. We exclude cash of $1,123 million and $417 million as of September 30, 2022 and December 31, 2021, respectively, and restricted cash of $75 million and $46 million as of September 30, 2022 and December 31, 2021, respectively. CEG Parent has excluded an additional $61 million of cash as of September 30, 2022. (b) Includes $89 million and $116 million of cash received from outstanding repurchase agreements as of September 30, 2022 and December 31, 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 ($38) million and ($55) million as of September 30, 2022 and December 31, 2021, respectively, held in an investment vehicle primarily to hedge the equity option component of convertible debt. (d) Includes net derivative liabilities of $1 million, which have total notional amounts of $432 million and $687 million as of September 30, 2022 and December 31, 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 $178 million and $111 million as of September 30, 2022 and December 31, 2021, respectively, which include certain derivative assets that have notional amounts of $140 million and $182 million as of September 30, 2022 and December 31, 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) Collateral posted/(received) from counterparties, net of collateral paid to counterparties, totaled $259 million, ($149) million, and ($345) million allocated to Level 1, Level 2, and Level 3 mark-to-market derivatives, respectively, as of September 30, 2022. Collateral posted/(received) from counterparties, net of collateral paid to 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 $2,013 million and $897 million of variation margin held from the exchanges as of September 30, 2022 and December 31, 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 three and nine months ended September 30, 2022 and 2021: For the Three Months Ended September 30, 2022 NDT Fund Investments Mark-to-Market Life Insurance Contracts Total Balance as of June 30, 2022 $ 431 $ (743) $ 1 $ (311) Total realized / unrealized (losses) gains Included in net income — (925) (a) — (925) Included in Payable related to Regulatory Agreement Units (2) — — (2) Change in collateral — (58) — (58) Purchases, sales, issuances and settlements Purchases — 333 — 333 Sales — (7) — (7) Settlements — — — — Transfers into Level 3 1 1 (b) — 2 Transfers out of Level 3 — (54) (b) — (54) Balance as of September 30, 2022 $ 430 $ (1,453) $ 1 $ (1,022) The amount of total (losses) gains included in income attributed to the change in unrealized (losses) gains related to assets and liabilities as of September 30, 2022 $ (1) $ (889) $ — $ (890) For the Three Months Ended September 30, 2021 NDT Fund Investments Mark-to-Market Total Balance as of June 30, 2021 $ 461 $ (465) $ (4) Total realized / unrealized gains (losses) Included in net income 3 (970) (a) (967) Included in noncurrent payables to affiliates 11 — 11 Change in collateral — (413) (413) Purchases, sales, issuances and settlements Purchases 2 6 8 Sales — 6 6 Settlements (2) — (2) Transfers into Level 3 — 2 (b) 2 Transfers out of Level 3 — (27) (b) (27) Balance as of September 30, 2021 $ 475 $ (1,861) $ (1,386) The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2021 $ 3 $ (1,004) $ (1,001) For the Nine Months Ended September 30, 2022 NDT Fund Investments Mark-to-Market Life Insurance Contracts Total Balance as of December 31, 2021 $ 464 $ (94) $ — $ 370 Total realized / unrealized losses Included in net income (2) (1,823) (a) (2) (1,827) Included in Payable related to Regulatory Agreement Units (11) — — (11) Change in collateral — (312) — (312) Impacts of separation — — 3 3 Purchases, sales, issuances and settlements Purchases 5 499 — 504 Sales — (44) — (44) Settlements (28) (30) — (58) Transfers into Level 3 2 418 (b) — 420 Transfers out of Level 3 — (67) (b) — (67) Balance as of September 30, 2022 $ 430 $ (1,453) $ 1 $ (1,022) The amount of total losses included in income attributed to the change in unrealized losses related to assets and liabilities as of September 30, 2022 $ (2) $ (1,951) $ (2) $ (1,955) For the Nine Months Ended September 30, 2021 NDT Fund Investments Mark-to-Market Total Balance as of December 31, 2020 $ 497 $ 430 $ 927 Total realized / unrealized gains (losses) Included in net income 4 (1,606) (a) (1,602) Included in noncurrent payables to affiliates 18 — 18 Change in collateral — (751) (751) Purchases, sales, issuances and settlements Purchases 3 120 123 Sales — 7 7 Settlements (48) — (48) Transfers into Level 3 1 3 (b) 4 Transfers out of Level 3 — (64) (b) (64) Balance as of September 30, 2021 $ 475 $ (1,861) $ (1,386) The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2021 $ 4 $ (1,527) $ (1,523) __________ (a) Includes a reduction of $35 million for realized gains and an addition of $98 million for realized losses due to the settlement of derivative contracts for the three and nine months ended September 30, 2022, respectively. Includes an addition of $34 million for realized losses and a reduction of $80 million for realized gains due to the settlement of derivative contracts for the three and nine months ended September 30, 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 tables present the income statement classification of the total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis during the three and nine months ended September 30, 2022 and 2021: For the Three Months Ended September 30, Operating Purchased Other, net 2022 2021 2022 2021 2022 2021 Total (losses) gains included in net income $ (545) $ (1,274) $ (380) $ 304 $ — $ 3 Total unrealized (losses) gains (768) (1,361) (121) 357 (1) 3 For the Nine Months Ended September 30, Operating Purchased Other, net 2022 2021 2022 2021 2022 2021 Total (losses) gains included in net income $ (1,786) $ (1,944) $ (67) $ 338 $ (4) $ 4 Total unrealized (losses) gains (2,353) (1,969) 402 443 (4) 4
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 September 30, 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) $ (1,113) $ (66) Discounted Cash Flow Forward power $9.26 - $1,108 $100 $8.86 - $481 $55 Forward gas $2.55 - $31 $5.25 $1.69 - $17 $3.50 Option Volatility 100% - 128% 113% 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 received on level 3 positions of $345 million and $34 million as of September 30, 2022 and December 31, 2021, respectively.

Commitments and Contingencies (

Commitments and Contingencies (Tables)	9 Months Ended
	Sep. 30, 2022
Commitments and Contingencies Disclosure [Abstract]
Other Commitments	Commercial commitments as of September 30, 2022, representing commitments potentially triggered by future events, were as follows: Expiration within Total 2022 2023 2024 2025 2026 2027 and beyond Letters of credit $ 3,509 $ 2,125 $ 1,384 $ — $ — $ — $ — Surety bonds (a) 978 256 722 — — — — Total commercial commitments $ 4,487 $ 2,381 $ 2,106 $ — $ — $ — $ — __________

Stock-Based Compensation Plans

Stock-Based Compensation Plans (Tables)	9 Months Ended
	Sep. 30, 2022
Share-Based Payment Arrangement [Abstract]
Share-based Payment Arrangement, Cost by Plan	The following table presents the stock-based compensation expense included in our 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. Three Months Ended September 30, Nine Months Ended September 30, 2022 2021 2022 2021 Total stock-based compensation expense included in operating and maintenance expense $ 53 $ 8 $ 85 $ 30 Income tax benefit (13) (2) (21) (8) Total after-tax stock-based compensation expense $ 40 $ 6 $ 64 $ 22

Changes in Accumulated Other _2

Changes in Accumulated Other Comprehensive Loss (Tables)	9 Months Ended
	Sep. 30, 2022
Equity [Abstract]
Schedule of Changes in Accumulated Other Comprehensive Income (Loss)	The following tables present changes in AOCI, net of tax, by component: Three Months Ended September 30, 2022 Losses on Cash Flow Hedges Pension and Non-Pension Postretirement Benefit Plan Items(a) Foreign Currency Items Total Beginning balance $ (8) $ (1,963) $ (21) $ (1,992) OCI before reclassifications — — (6) (6) Amounts reclassified from AOCI (1) 30 — 29 Net current-period OCI (1) 30 (6) 23 Ending balance $ (9) $ (1,933) $ (27) $ (1,969) Three Months Ended September 30, 2021 Losses on Cash Flow Hedges Pension and Non-Pension Postretirement Benefit Plan Items(a) Foreign Currency Items Total Beginning balance $ (7) $ — $ (20) $ (27) OCI before reclassifications (1) — (3) (4) Net current-period OCI (1) — (3) (4) Ending balance $ (8) $ — $ (23) $ (31) Nine Months Ended September 30, 2022 Losses on Cash Flow Hedges Pension and Non-Pension Postretirement Benefit Plan Items(a) Foreign Currency Items Total Beginning balance $ (8) $ — $ (23) $ (31) Separation-related adjustments — (2,006) — (2,006) OCI before reclassifications (1) — (4) (5) Amounts reclassified from AOCI — 73 — 73 Net current-period OCI (1) (1,933) (4) (1,938) Ending balance $ (9) $ (1,933) $ (27) $ (1,969) Nine Months Ended September 30, 2021 Losses on Cash Flow Hedges Pension and Non-Pension Postretirement Benefit Plan Items(a) Foreign Currency Items Total Beginning balance $ (7) $ — $ (23) $ (30) OCI before reclassifications (1) — — (1) Net current-period OCI (1) — — (1) Ending balance $ (8) $ — $ (23) $ (31) __________ (a) AOCI amounts are included in the computation of net periodic pension and OPEB cost. See Note 11 — Retirement Benefits for additional information. See our Statements of Operations and Comprehensive Income for individual components of AOCI. The following table presents income tax benefit (expense) allocated to each component of our other comprehensive loss: Three Months Ended September 30, Nine Months Ended September 30, 2022 2021 2022 2021 Pension and non-pension postretirement benefit plans: Actuarial loss reclassified to periodic benefit cost $ (9) $ — $ (24) $ — Pension and non-pension postretirement benefit plans valuation adjustment — — 680 —

Variable Interest Entities (Tab

Variable Interest Entities (Tables)	9 Months Ended
	Sep. 30, 2022
Variable Interest Entity [Abstract]
Consolidated VIEs- Assets and Liabilities	The table below shows the carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in the consolidated financial statements as of September 30, 2022 and December 31, 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. September 30, 2022 December 31, 2021 Cash and cash equivalents $ 64 $ 35 Restricted cash and cash equivalents 42 48 Accounts receivable Customer 25 24 Other 8 6 Inventories, net Materials and supplies 12 14 Other current assets 1,022 405 Total current assets 1,173 532 Property, plant and equipment, net 1,971 2,027 Other noncurrent assets 195 215 Total noncurrent assets 2,166 2,242 Total assets (a) $ 3,339 $ 2,774 Long-term debt due within one year $ 60 $ 70 Accounts payable 19 10 Accrued expenses 20 21 Other current liabilities 2 1 Total current liabilities 101 102 Long-term debt 775 822 Asset retirement obligations 171 151 Other noncurrent liabilities 3 3 Total noncurrent liabilities 949 976 Total liabilities (b) $ 1,050 $ 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, noncurrent unamortized energy contract assets of $183 million and $202 million, disclosed within other noncurrent assets in the table above as of September 30, 2022 and December 31, 2021, respectively. (b) Our balances include liabilities with recourse of $1 million and $1 million as of September 30, 2022 and December 31, 2021, respectively.
Schedule of Variable Interest Entities	As of September 30, 2022 and December 31, 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. The following table presents summary information about our significant unconsolidated VIE entities: September 30, 2022 December 31, 2021 Commercial Equity Total Commercial Equity Total Total assets (a) $ 716 $ 344 $ 1,060 $ 772 $ 372 $ 1,144 Total liabilities (a) 55 206 261 80 216 296 Our ownership interest in VIE (a) — 122 122 — 139 139 Other ownership interests in VIE (a) 661 16 677 692 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 September 30, 2022 and December 31, 2021. As of September 30, 2022 and December 31, 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. 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 Inform_2

Supplemental Financial Information (Tables)	9 Months Ended
	Sep. 30, 2022
Supplemental Financial Information [Abstract]
Supplemental Statement of Operations Information	The following tables provide additional information about material items recorded within our Consolidated Statements of Operations and Comprehensive Income. Operating revenues Three Months Ended September 30, Nine Months Ended September 30, 2022 2021 2022 2021 Operating lease income $ 29 $ 29 $ 46 $ 44 Variable lease income 77 71 204 207 Taxes other than income taxes Three Months Ended September 30, Nine Months Ended September 30, 2022 2021 2022 2021 Gross receipts (a) $ 39 $ 27 $ 100 $ 73 Property 67 66 206 199 Payroll 36 26 99 83 __________ (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 Three Months Ended September 30, Nine Months Ended September 30, 2022 2021 2022 2021 Decommissioning-related activities: Net realized income on NDT funds (a) Regulatory Agreement Units $ 61 $ 263 $ 333 $ 698 Non-Regulatory Agreement Units 15 102 115 392 Net unrealized (losses) gains on NDT funds Regulatory Agreement Units (386) (195) (1,777) 84 Non-Regulatory Agreement Units (225) (88) (1,077) 38 Regulatory offset to NDT fund-related activities (b) 262 (38) 1,160 (607) Decommissioning-related activities (273) 44 (1,246) 605 Non-service net periodic benefit credit (c) 27 — 79 — Net unrealized (losses) gains on CTV investments (d) (2) (179) (27) (83) __________ (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 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 income taxes related to all NDT fund activity for those 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 of our 2021 Form 10-K 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 11 — Retirement Benefits for additional information. (d) Net unrealized (losses) gains on CTV investments that became publicly traded in the fourth quarter of 2020 and the first half of 2021.
Cash Flow Supplemental Disclosures	The following tables provide additional information about material items recorded within our Consolidated Statements of Cash Flows. Depreciation, amortization and accretion Nine Months Ended September 30, 2022 2021 Property, plant, and equipment (a) $ 798 $ 2,698 Amortization of intangible assets, net (a) 20 37 Amortization of energy contract assets and liabilities (b) 28 23 Nuclear fuel (c) 561 810 ARO accretion (d) 403 383 Total depreciation, amortization, and accretion $ 1,810 $ 3,951 __________ (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. Other non-cash operating activities CEG Parent Constellation Nine Months Ended September 30, Nine Months Ended September 30, 2022 2021 2022 2021 Pension and non-pension postretirement benefit costs $ 12 $ 92 $ 12 $ 92 Allowance for credit losses 12 59 12 59 Other decommissioning-related activity (a) (116) (810) (116) (810) Energy-related options (b) 239 45 239 45 Severance costs — (75) — (75) Long-term incentive plan 35 — — — Amortization of operating ROU asset 65 98 65 98 Loss on sale of receivables 39 26 39 26 Fair value adjustments related to gas imbalances 65 — 65 — 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 of our 2021 Form 10-K 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 15 - Commitments and Contingencies for additional information. The following table provides a reconciliation of cash, restricted cash, and cash equivalents reported within our Consolidated Balance Sheets that sum to the total of the same amounts in the Consolidated Statements of Cash Flows. CEG Parent Constellation September 30, 2022 Cash and cash equivalents $ 1,192 $ 1,131 Restricted cash and cash equivalents 111 83 Total cash, restricted cash, and cash equivalents $ 1,303 $ 1,214 December 31, 2021 Cash and cash equivalents $ 504 $ 504 Restricted cash and cash equivalents 72 72 Total cash, restricted cash, and cash equivalents $ 576 $ 576 September 30, 2021 Cash and cash equivalents $ 1,957 $ 1,957 Restricted cash and cash equivalents 62 62 Total cash, restricted cash, and cash equivalents $ 2,019 $ 2,019 December 31, 2020 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
Supplemental Balance Sheet Information	The following table provides additional information about material items recorded within our Consolidated Balance Sheets. Accrued expenses September 30, 2022 CEG Parent Constellation Compensation-related accruals (a) $ 395 $ 359 Taxes accrued 401 401 December 31, 2021 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)	9 Months Ended
	Sep. 30, 2022
Related Party Transactions [Abstract]
Schedule of Related Party Transactions	The following table presents our Operating revenues from affiliates: Three Months Ended September 30, Nine Months Ended September 30, 2022 2021 2022 (g) 2021 ComEd (a) $ — $ 96 $ 58 $ 249 PECO (b) — 59 33 142 BGE (c) — 65 18 195 PHI — 99 51 276 Pepco (d) — 69 39 199 DPL (e) — 25 10 63 ACE (f) — 5 2 14 Other — 5 — 10 Total operating revenues from affiliates $ — $ 324 $ 160 $ 872 __________ (a) 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. (b) 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. (c) We provide a portion of BGE’s energy requirements under its MDPSC-approved market-based SOS and gas commodity programs. (d) We provide electric supply to Pepco under contracts executed through Pepco's competitive procurement process approved by the MDPSC and DCPSC. (e) We provide a portion of DPL's energy requirements under its MDPSC and DEPSC approved market-based SOS commodity programs. (f) We provide electric supply to ACE under contracts executed through ACE's competitive procurement process. (g) Represents only January 2022 costs prior to separation on February 1, 2022. The following table presents the service company costs allocated to us: Operating and maintenance from Capitalized costs Three Months Ended September 30, Nine Months Ended September 30, Three Months Ended September 30, Nine Months Ended September 30, 2022 2021 2022 (a) 2021 2022 2021 2022 (a) 2021 $ — $ 145 $ 44 $ 424 $ — $ 43 $ 15 $ 76 __________ (a) Represents only January 2022 costs prior to separation on February 1, 2022. The following tables present 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 September 30, 2022, all transactions with Exelon or its affiliates are third party transactions.

Basis of Presentation (Details)

Basis of Presentation (Details) $ in Millions		3 Months Ended	8 Months Ended	9 Months Ended
	Jan. 31, 2022 USD ($)	Sep. 30, 2022 USD ($)	Sep. 30, 2022 USD ($)	Sep. 30, 2022 USD ($)	Sep. 30, 2022 USD ($) segment	Sep. 30, 2022 USD ($) Reportable_segment	Sep. 30, 2021 USD ($)	Jan. 20, 2022	Dec. 31, 2021 USD ($)
Significant Accounting Policies Additional Narrative Information [Line Items]
Number of reportable segments					5	5
Conversion ratio								0.3333
Contribution from Exelon	$ 1,750			$ 1,750			$ 64
Payables to affiliates		$ 0	$ 0	0	$ 0	$ 0			$ 3,357
Short-term borrowings	$ 200	693	693	693	693	693			$ 2,082
Credit facility term	5 years
Credit facility	$ 4,500	5,802	5,802	$ 5,802	$ 5,802	$ 5,802
Billings from related party		68	193
Billings to related party		$ 12	$ 32
Pension Benefits
Significant Accounting Policies Additional Narrative Information [Line Items]
Contribution from Exelon	192
Exelon Consolidation
Significant Accounting Policies Additional Narrative Information [Line Items]
Payables to affiliates	$ 258

Mergers, Acquisitions, and Di_3

Mergers, Acquisitions, and Dispositions - Narrative (Details) $ in Millions					3 Months Ended		9 Months Ended	12 Months Ended
	Aug. 06, 2021 USD ($)	Mar. 31, 2021 USD ($)	Dec. 08, 2020 site MW	Apr. 01, 2014 USD ($)	Sep. 30, 2021 USD ($)	Jun. 30, 2021 USD ($)	Sep. 30, 2021 USD ($)	Dec. 31, 2021 USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Deferred tax adjustment related to acquisition of CENG noncontrolling interest					$ 288
Constellation Energy Generation, LLC
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Deferred tax adjustment related to acquisition of CENG noncontrolling interest					288
Constellation Energy Generation, LLC | CENG
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Equity ownership	50.01%
Constellation Energy Generation, LLC | Nine Mile Point | CENG
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Equity ownership	82%
Constellation Energy Generation, LLC | CENG
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Equity interest	49.99%
CENG | Constellation Energy Generation, LLC
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Special distribution				$ 400
Aggregate distributions due				$ 400
Return per annum				8.50%
Acquisition of CENG noncontrolling interest	$ 885				1,080		$ 1,080
Deferred tax adjustment related to acquisition of CENG noncontrolling interest					$ (288)		$ (288)	$ (288)
Solar Business | Disposal Group, Disposed of by Sale, Not Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [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
Albany Green Energy Biomass Facility | Disposal Group, Disposed of by Sale, Not Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Purchase price						$ 36
Pre-tax impairment charge						$ 140

Mergers, Acquisitions, and Di_4

Mergers, Acquisitions, and Dispositions - Change in Ownership Interest (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended		12 Months Ended
	Aug. 06, 2021	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021	Dec. 31, 2021
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net income (loss) attributable to membership interest		$ (188)	$ 607	$ (194)	$ (247)
Decrease in membership interest due to deferred tax liabilities resulting from purchase of EDF's equity interest			288
Constellation Energy Generation, LLC
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net income (loss) attributable to membership interest		$ (188)	607	$ (194)	(247)
Decrease in membership interest due to deferred tax liabilities resulting from purchase of EDF's equity interest			288
Constellation Energy Generation, LLC | CENG
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net income (loss) attributable to membership interest			607		(247)
Pre-tax increase in membership interest for purchase of EDF's 49.99% equity interest	$ 885		1,080		1,080
Decrease in membership interest due to deferred tax liabilities resulting from purchase of EDF's equity interest			(288)		(288)	$ (288)
Change from net income (loss) attributable to membership interest and transfers from noncontrolling interest.			$ 1,399		$ 545

Regulatory Matters (Details)

Regulatory Matters (Details) - USD ($)				1 Months Ended	9 Months Ended
	Oct. 31, 2021	Feb. 15, 2021	Mar. 06, 2020	Nov. 30, 2021	Sep. 30, 2022	Sep. 30, 2021	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					$ 30,000,000	$ 880,000,000
Defaulting Market Participant and Settlement of Regulatory Matters | Minimum
Regulatory Matters Additional Narrative Information [Line Items]
Term to be paid					62 years
Defaulting Market Participant and Settlement of Regulatory Matters | Maximum
Regulatory Matters Additional Narrative Information [Line Items]
Term to be paid					83 years
Texas-based generating assets | Defaulting Market Participant and Settlement of Regulatory Matters
Regulatory Matters Additional Narrative Information [Line Items]
Market payment shortfall in collections					$ 16,000,000		$ 17,000,000
Peach Bottom Units 2 and 3
Regulatory Matters Additional Narrative Information [Line Items]
Operating license renewal period			20 years
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		$ 2,500,000,000
ERCOT | Extreme Cold Weather Conditions
Regulatory Matters Additional Narrative Information [Line Items]
Administrative price cap		$ 9,000
ERCOT | Public Utility Commission of Texas
Regulatory Matters Additional Narrative Information [Line Items]
Securitized funds allocation					$ 2,100,000,000

Revenue from Contracts with C_3

Revenue from Contracts with Customers - Contract Assets (Details) - USD ($) $ in Millions	3 Months Ended
	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021
Change in Contract with Customer [Roll Forward]
Beginning Balance - Contract Assets	$ 139	$ 142	$ 149	$ 150	$ 153	$ 144
Amounts reclassified to receivables	(5)	(13)	(16)	(15)	(12)	(16)
Revenues recognized	21	10	9	14	9	13
Amounts previously held-for-sale						12
Ending Balance - Contract Assets	$ 155	$ 139	$ 142	$ 149	$ 150	$ 153

Revenue from Contracts with C_4

Revenue from Contracts with Customer - Contract Liabilities (Details) - USD ($) $ in Millions	3 Months Ended
	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021
Contract with Customer, Liability [Roll Forward]
Beginning Balance - Contract Liabilities	$ 26	$ 62	$ 75	$ 25	$ 54	$ 84
Consideration received or due	71	27	50	93	39	31
Revenues recognized	(68)	(63)	(63)	(65)	(68)	(64)
Amounts previously held-for-sale						3
Ending Balance - Contract Liabilities	$ 29	$ 26	$ 62	$ 53	$ 25	$ 54

Revenue from Contracts with C_5

Revenue from Contracts with Customers - Performance Obligations (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenues recognized	$ 6,051	$ 4,406	$ 17,107	$ 14,117
Remaining performance obligations	505		505
Contract Liability
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenues recognized	2	$ 2	70	$ 81
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations	$ 97		$ 97
Remaining performance obligations, timing	3 months		3 months
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	$ 161		$ 161
Remaining performance obligations, timing	1 year		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	$ 63		$ 63
Remaining performance obligations, timing	1 year		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	$ 32		$ 32
Remaining performance obligations, timing	1 year		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	$ 152		$ 152
Remaining performance obligations, timing	1 year		1 year

Segment Information - Narrative

Segment Information - Narrative (Details) - 9 months ended Sep. 30, 2022	segment	Reportable_segment
Segment Reporting [Abstract]
Number of reportable segments	5	5

Segment Information - Generatio

Segment Information - Generation Total Revenues (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021
Segment Reporting Information [Line Items]
Total operating revenues	$ 6,051	$ 4,406	$ 17,107	$ 14,117
Mid-Atlantic
Segment Reporting Information [Line Items]
Total operating revenues	1,659	1,272	3,967	3,527
Midwest
Segment Reporting Information [Line Items]
Total operating revenues	1,047	985	3,345	2,945
New York
Segment Reporting Information [Line Items]
Total operating revenues	423	455	1,178	1,173
ERCOT
Segment Reporting Information [Line Items]
Total operating revenues	490	358	1,210	890
Other Power Regions
Segment Reporting Information [Line Items]
Total operating revenues	1,936	1,260	5,189	3,729
Total Competitive Businesses Electric Revenues
Segment Reporting Information [Line Items]
Total operating revenues	5,555	4,330	14,889	12,264
Competitive Businesses Natural Gas Revenues
Segment Reporting Information [Line Items]
Total operating revenues	1,070	575	3,548	2,408
Competitive Businesses Other Revenues
Segment Reporting Information [Line Items]
Total operating revenues	(574)	(499)	(1,330)	(555)
Total Consolidated Operating Revenues
Segment Reporting Information [Line Items]
Total operating revenues	6,051	4,406	17,107	14,117
Operating Segments | Mid-Atlantic
Segment Reporting Information [Line Items]
Total operating revenues	1,658	1,268	3,964	3,511
Operating Segments | Midwest
Segment Reporting Information [Line Items]
Total operating revenues	1,049	985	3,348	2,944
Operating Segments | New York
Segment Reporting Information [Line Items]
Total operating revenues	426	455	1,178	1,174
Operating Segments | ERCOT
Segment Reporting Information [Line Items]
Total operating revenues	496	356	1,220	879
Operating Segments | Other Power Regions
Segment Reporting Information [Line Items]
Total operating revenues	1,926	1,266	5,179	3,756
Operating Segments | Total Competitive Businesses Electric Revenues
Segment Reporting Information [Line Items]
Total operating revenues	5,555	4,330	14,889	12,264
Operating Segments | Competitive Businesses Natural Gas Revenues
Segment Reporting Information [Line Items]
Total operating revenues	1,070	575	3,548	2,408
Operating Segments | Total Consolidated Operating Revenues
Segment Reporting Information [Line Items]
Total operating revenues	6,051	4,406	17,107	14,117
Intersegment Revenues | Mid-Atlantic
Segment Reporting Information [Line Items]
Total operating revenues	1	4	3	16
Intersegment Revenues | Midwest
Segment Reporting Information [Line Items]
Total operating revenues	(2)	0	(3)	1
Intersegment Revenues | New York
Segment Reporting Information [Line Items]
Total operating revenues	(3)	0	0	(1)
Intersegment Revenues | ERCOT
Segment Reporting Information [Line Items]
Total operating revenues	(6)	2	(10)	11
Intersegment Revenues | Other Power Regions
Segment Reporting Information [Line Items]
Total operating revenues	10	(6)	10	(27)
Intersegment Revenues | Total Competitive Businesses Electric Revenues
Segment Reporting Information [Line Items]
Total operating revenues	0	0	0	0
Intersegment Revenues | Competitive Businesses Natural Gas Revenues
Segment Reporting Information [Line Items]
Total operating revenues	0	0	0	0
Intersegment Revenues | Competitive Businesses Other Revenues
Segment Reporting Information [Line Items]
Total operating revenues	0	0	0	0
Intersegment Revenues | Total Consolidated Operating Revenues
Segment Reporting Information [Line Items]
Total operating revenues	0	0	0	0
Corporate, Non-Segment | Competitive Businesses Other Revenues
Segment Reporting Information [Line Items]
Total operating revenues	(574)	(499)	(1,330)	(555)
Contracts with customers | Operating Segments | Mid-Atlantic
Segment Reporting Information [Line Items]
Total operating revenues	1,561	1,145	3,894	3,377
Contracts with customers | Operating Segments | Midwest
Segment Reporting Information [Line Items]
Total operating revenues	1,182	1,084	3,749	3,067
Contracts with customers | Operating Segments | New York
Segment Reporting Information [Line Items]
Total operating revenues	536	445	1,492	1,204
Contracts with customers | Operating Segments | ERCOT
Segment Reporting Information [Line Items]
Total operating revenues	328	191	744	724
Contracts with customers | Operating Segments | Other Power Regions
Segment Reporting Information [Line Items]
Total operating revenues	1,315	948	3,756	3,043
Contracts with customers | Operating Segments | Total Competitive Businesses Electric Revenues
Segment Reporting Information [Line Items]
Total operating revenues	4,922	3,813	13,635	11,415
Contracts with customers | Operating Segments | Competitive Businesses Natural Gas Revenues
Segment Reporting Information [Line Items]
Total operating revenues	471	266	1,770	1,384
Contracts with customers | Operating Segments | Total Consolidated Operating Revenues
Segment Reporting Information [Line Items]
Total operating revenues	5,547	4,174	15,821	13,090
Contracts with customers | Corporate, Non-Segment | Competitive Businesses Other Revenues
Segment Reporting Information [Line Items]
Total operating revenues	154	95	416	291
Other | Operating Segments | Mid-Atlantic
Segment Reporting Information [Line Items]
Total operating revenues	97	123	70	134
Other | Operating Segments | Midwest
Segment Reporting Information [Line Items]
Total operating revenues	(133)	(99)	(401)	(123)
Other | Operating Segments | New York
Segment Reporting Information [Line Items]
Total operating revenues	(110)	10	(314)	(30)
Other | Operating Segments | ERCOT
Segment Reporting Information [Line Items]
Total operating revenues	168	165	476	155
Other | Operating Segments | Other Power Regions
Segment Reporting Information [Line Items]
Total operating revenues	611	318	1,423	713
Other | Operating Segments | Total Competitive Businesses Electric Revenues
Segment Reporting Information [Line Items]
Total operating revenues	633	517	1,254	849
Other | Operating Segments | Competitive Businesses Natural Gas Revenues
Segment Reporting Information [Line Items]
Total operating revenues	599	309	1,778	1,024
Other | Operating Segments | Total Consolidated Operating Revenues
Segment Reporting Information [Line Items]
Total operating revenues	504	232	1,286	1,027
Other | Corporate, Non-Segment | Competitive Businesses Other Revenues
Segment Reporting Information [Line Items]
Total operating revenues	$ (728)	$ (594)	$ (1,746)	$ (846)

Segment Information - Generat_2

Segment Information - Generation Total Revenues Net of Purchased Power and Fuel Expense (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021
Mid-Atlantic
Segment Reporting Information [Line Items]
Revenue Net of Purchase Power And Fuel	$ 555	$ 570	$ 1,612	$ 1,712
Midwest
Segment Reporting Information [Line Items]
Revenue Net of Purchase Power And Fuel	572	655	2,010	2,015
New York
Segment Reporting Information [Line Items]
Revenue Net of Purchase Power And Fuel	267	346	827	880
ERCOT
Segment Reporting Information [Line Items]
Revenue Net of Purchase Power And Fuel	66	179	235	(922)
Other Power Regions
Segment Reporting Information [Line Items]
Revenue Net of Purchase Power And Fuel	257	211	710	564
Total Competitive Businesses Electric Revenues
Segment Reporting Information [Line Items]
Revenue Net of Purchase Power And Fuel	1,717	1,961	5,394	4,249
Other
Segment Reporting Information [Line Items]
Revenue Net of Purchase Power And Fuel	(361)	899	(41)	1,765
Unrealized mark-to-market gains (losses)	(681)	(635)	(1,899)	(958)
Total Consolidated Operating Revenues
Segment Reporting Information [Line Items]
Revenue Net of Purchase Power And Fuel	1,356	2,860	5,353	6,014
Operating Segments | Mid-Atlantic
Segment Reporting Information [Line Items]
RNF from external customers	553	567	1,606	1,698
Operating Segments | Midwest
Segment Reporting Information [Line Items]
RNF from external customers	572	655	2,008	2,014
Operating Segments | New York
Segment Reporting Information [Line Items]
RNF from external customers	268	343	822	873
Operating Segments | ERCOT
Segment Reporting Information [Line Items]
RNF from external customers	104	181	321	(775)
Operating Segments | Other Power Regions
Segment Reporting Information [Line Items]
RNF from external customers	274	233	741	641
Operating Segments | Total Competitive Businesses Electric Revenues
Segment Reporting Information [Line Items]
RNF from external customers	1,771	1,979	5,498	4,451
Operating Segments | Other
Segment Reporting Information [Line Items]
RNF from external customers	(415)	881	(145)	1,563
Unrealized mark-to-market gains (losses)	(524)	754	(571)	1,242
Nuclear Fuel Amortization		42		148
Operating Segments | Total Consolidated Operating Revenues
Segment Reporting Information [Line Items]
RNF from external customers	1,356	2,860	5,353	6,014
Intersegment Revenues | Mid-Atlantic
Segment Reporting Information [Line Items]
Intersegment Revenue Net Of Purchase Power And Fuel	2	3	6	14
Intersegment Revenues | Midwest
Segment Reporting Information [Line Items]
Intersegment Revenue Net Of Purchase Power And Fuel	0	0	2	1
Intersegment Revenues | New York
Segment Reporting Information [Line Items]
Intersegment Revenue Net Of Purchase Power And Fuel	(1)	3	5	7
Intersegment Revenues | ERCOT
Segment Reporting Information [Line Items]
Intersegment Revenue Net Of Purchase Power And Fuel	(38)	(2)	(86)	(147)
Intersegment Revenues | Other Power Regions
Segment Reporting Information [Line Items]
Intersegment Revenue Net Of Purchase Power And Fuel	(17)	(22)	(31)	(77)
Intersegment Revenues | Total Competitive Businesses Electric Revenues
Segment Reporting Information [Line Items]
Intersegment Revenue Net Of Purchase Power And Fuel	(54)	(18)	(104)	(202)
Intersegment Revenues | Other
Segment Reporting Information [Line Items]
Intersegment Revenue Net Of Purchase Power And Fuel	54	18	104	202
Intersegment Revenues | Total Consolidated Operating Revenues
Segment Reporting Information [Line Items]
Intersegment Revenue Net Of Purchase Power And Fuel	$ 0	$ 0	$ 0	$ 0

Accounts Receivable - Narrative

Accounts Receivable - Narrative (Details) - USD ($) $ in Millions	Sep. 30, 2022	Aug. 16, 2022	Jan. 31, 2022	Dec. 31, 2021	Apr. 08, 2020
Accounts, Notes, Loans and Financing Receivable [Line Items]
Unbilled customer revenues	$ 369			$ 373
Credit facility	$ 5,802		$ 4,500
Sale of Accounts Receivable
Accounts, Notes, Loans and Financing Receivable [Line Items]
Credit facility		$ 1,100			$ 900

Accounts Receivable - Allowance

Accounts Receivable - Allowance for Credit Losses Rollforward (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Plus: Current period provision for expected credit losses			$ 12	$ 59
Customer accounts receivable
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Beginning balance	$ 49	$ 75	55	32
Plus: Current period provision for expected credit losses	9	10	12	57
Less: Write-offs, net of recoveries	3	1	12	5
Ending balance	$ 55	$ 84	$ 55	$ 84

Accounts Receivable - Purchases

Accounts Receivable - Purchases and Sales of Accounts Receivable (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021	Dec. 31, 2021	Mar. 31, 2021
Accounts, Notes, Loans and Financing Receivable [Line Items]
Cash proceeds received						$ 400
Loss on sale of receivables	$ 15	$ 1	$ 39	$ 26
Proceeds from new transfers			4,807	4,440
Cash collections received on DPP and reinvested in the Facility			3,295	2,652
Cash collections reinvested in the Facility			8,102	7,092
Net cash payments	200
Total receivables sold			312	117
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	17
Sale of Accounts Receivable
Accounts, Notes, Loans and Financing Receivable [Line Items]
Derecognized receivables transferred at fair value	1,675		1,675		$ 1,265
Cash proceeds received	700		700		900
DPP	$ 975		975		$ 365
Customer accounts receivable sold into the Facility			$ 8,540	$ 7,373

Early Plant Retirements - Narra

Early Plant Retirements - Narrative (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021
Property, Plant and Equipment [Line Items]
Depreciation and amortization	$ 262,000,000	$ 866,000,000	$ 818,000,000	$ 2,735,000,000
Constellation Energy Generation, LLC
Property, Plant and Equipment [Line Items]
Depreciation and amortization	262,000,000	866,000,000	818,000,000	2,735,000,000
Byron Dresden | Facility Closing
Property, Plant and Equipment [Line Items]
Other one-time charges		(4,000,000)		(8,000,000)
Byron Dresden | Facility Closing | Constellation Energy Generation, LLC
Property, Plant and Equipment [Line Items]
Severance costs		(81,000,000)
Other one-time charges		(13,000,000)
Constellation New England
Property, Plant and Equipment [Line Items]
Depreciation and amortization	$ 0	$ 0	$ 0	$ 41,000,000

Early Plant Retirements - Preta

Early Plant Retirements - Pretax Expense (Details) - Facility Closing - Byron Dresden - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2021	Sep. 30, 2021
Restructuring Cost and Reserve [Line Items]
Accelerated depreciation	$ 574	$ 1,805
Accelerated nuclear fuel amortization	42	148
One-time charges	(94)	(94)
Other charges	4	8
Contractual offset	(60)	(451)
Total	$ 466	$ 1,416

Nuclear Decommissioning - Narra

Nuclear Decommissioning - Narrative (Details) - USD ($) $ in Millions	3 Months Ended			9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Jun. 30, 2021	Sep. 30, 2022	Jan. 31, 2022	Dec. 31, 2021
Asset Retirement Obligations [Line Items]
Nuclear decommissioning trust funds	$ 13,453			$ 13,453		$ 15,938
Pre-tax charged for decommissioning-related activities		$ 140	$ 53
Nuclear Decommissioning
Asset Retirement Obligations [Line Items]
Net decrease due to changes in, and timing of, estimated future cash flows				(648)
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
Net increase due to higher estimated decommissioning costs				75
Decrease in operating and maintenance expense	(226)			(226)
Nine Mile Point
Asset Retirement Obligations [Line Items]
Nuclear decommissioning trust funds					$ 15
Assets, Total
Asset Retirement Obligations [Line Items]
Nuclear decommissioning trust funds	13,546			13,546		16,064
Other Current Assets
Asset Retirement Obligations [Line Items]
Nuclear decommissioning trust funds	$ 93			$ 93		$ 126

Nuclear Decommissioning - Nucle

Nuclear Decommissioning - Nuclear Decommissioning Asset Retirement Obligation Rollforward (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Dec. 31, 2021
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Accretion expense	$ 403	$ 383
Nuclear Decommissioning
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
ARO beginning balance	12,676
Net decrease due to changes in, and timing of, estimated future cash flows	(648)
Accretion expense	394
Costs incurred related to decommissioning plants	(50)
ARO ending balance	12,372
Current portion of ARO	$ 45		$ 72

Nuclear Decommissioning - Noncu

Nuclear Decommissioning - Noncurrent Related Party Liabilities (Details) - USD ($) $ in Millions	Sep. 30, 2022	Dec. 31, 2021
Asset Retirement Obligations [Line Items]
Payables to affiliates	$ 0	$ 3,357
ComEd
Asset Retirement Obligations [Line Items]
Payables to affiliates	2,469	2,760
PECO
Asset Retirement Obligations [Line Items]
Payables to affiliates	$ 189	$ 597

Asset Impairments (Details)

Asset Impairments (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Jun. 30, 2021	Sep. 30, 2022	Sep. 30, 2021
Property, Plant and Equipment [Line Items]
Pre-tax impairment charge			$ 0	$ 537
Constellation Energy Generation, LLC
Property, Plant and Equipment [Line Items]
Pre-tax impairment charge			$ 0	$ 537
Constellation Energy Generation, LLC | Constellation New England
Property, Plant and Equipment [Line Items]
Pre-tax impairment charge		$ 350
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

Income Taxes - Reconciliation t

Income Taxes - Reconciliation to Effective Tax Rate (Details)	3 Months Ended		9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021
Income Tax Disclosure [Abstract]
U.S. federal statutory rate	21%	21%	21%	21%
Increase (decrease) due to:
State income taxes, net of federal income tax benefit	(9.50%)	4.40%	(9.00%)	90.20%
Qualified NDT fund income and losses	22.10%	0.90%	48.60%	(1932.60%)
Amortization of investment tax credit, including deferred taxes on basis differences	1.90%	(0.70%)	2%	130.60%
Production tax credits and other credits	8%	(1.40%)	8.30%	425.10%
Noncontrolling interests	(0.50%)	(0.60%)	0%	145.20%
Other	(3.60%)	(1.90%)	2.20%	(229.50%)
Effective income tax rate	39.40%	21.70%	73.10%	(1350.00%)

Income Taxes - Recognition of U

Income Taxes - Recognition of Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	Sep. 30, 2022	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Unrecognized tax benefits that would impact effective tax rate if recognized	$ 29	$ 39

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) - USD ($)		3 Months Ended
	Aug. 06, 2021	Sep. 30, 2021	Sep. 30, 2022	Mar. 31, 2022	Feb. 01, 2022	Dec. 31, 2021
Income Taxes [Line Items]
Deferred tax adjustment related to acquisition of CENG noncontrolling interest		$ 288,000,000
Deferred income taxes and unamortized investment tax credits			$ 2,647,000,000			$ 3,703,000,000
Other			579,000,000			592,000,000
Other deferred debits and other assets			2,137,000,000			1,717,000,000
Constellation Energy Generation, LLC
Income Taxes [Line Items]
Deferred tax adjustment related to acquisition of CENG noncontrolling interest		$ 288,000,000
Deferred income taxes and unamortized investment tax credits			2,647,000,000			3,703,000,000
Other			555,000,000			592,000,000
Other deferred debits and other assets			2,137,000,000			$ 1,717,000,000
CENG | Constellation Energy Generation, LLC
Income Taxes [Line Items]
Deferred tax adjustment related to acquisition of CENG noncontrolling interest	$ 288,000,000
Separation from Parent
Income Taxes [Line Items]
Payable for tax liabilities upon separation					$ 103,000,000
Deferred income taxes and unamortized investment tax credits					508,000,000
Other			106,000,000		11,000,000
Other deferred debits and other assets			409,000,000		$ 497,000,000
Separation from Parent | Accounts Payable
Income Taxes [Line Items]
Payable for tax liabilities upon separation			55,000,000	$ 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

Retirement Benefits - Narrative

Retirement Benefits - Narrative (Details) - USD ($) $ in Millions		1 Months Ended	3 Months Ended		9 Months Ended
	Feb. 01, 2022	Feb. 28, 2022	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021	Dec. 31, 2021
Defined Contribution Plan Disclosure [Line Items]
Actuarial losses and prior service costs	$ 2,006
Matching contributions to savings plan			$ 16	$ 14	$ 44	$ 40
Pension Benefits
Defined Contribution Plan Disclosure [Line Items]
Pension obligations	953		636		636		$ 0
Pension plan assets	8,267
Annual qualified pension contribution		$ 192
Planned contributions			0		0
OPEB
Defined Contribution Plan Disclosure [Line Items]
Pension obligations	876		0		0		$ 0
Pension plan assets	$ 904
Planned contributions			27		27
Benefit payments			8		21
Nonqualified Pension Plan
Defined Contribution Plan Disclosure [Line Items]
Planned contributions			21		21
Benefit payments			$ 8		$ 16

Retirement Benefits - Benefit O

Retirement Benefits - Benefit Obligations Net of Plan Assets, Balance Sheet (Details) - USD ($) $ in Millions	Sep. 30, 2022	Feb. 01, 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	(9)		0
Pension obligations	(636)	$ (953)	0
Non-pension postretirement benefit obligations	0		0
(Unfunded) funded status (net benefit obligation less plan assets)	(645)		1,683
OPEB
Defined Contribution Plan Disclosure [Line Items]
Prepaid pension asset	0		0
Other current liabilities	(17)		0
Pension obligations	0	$ (876)	0
Non-pension postretirement benefit obligations	(861)		(847)
(Unfunded) funded status (net benefit obligation less plan assets)	$ (878)		$ (847)

Retirement Benefits - Assumptio

Retirement Benefits - Assumptions (Details)	Feb. 01, 2022
Pension Benefits
Defined Contribution Plan Disclosure [Line Items]
Discount rate	3.23%
Investment crediting rate	3.86%
Expected return on plan assets	0.0700
Rate of compensation increase	3.75%
OPEB
Defined Contribution Plan Disclosure [Line Items]
Discount rate	3.21%
Expected return on plan assets	0.0650
Rate of compensation increase	3.75%
Healthcare cost trend on covered charges	5%

Retirement Benefits - Net Benef

Retirement Benefits - Net Benefit Costs (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021
Defined Contribution Plan Disclosure [Line Items]
Service cost	$ 37	$ 44	$ 112	$ 131
Interest cost	88	71	259	211
Expected return on assets	(157)	(138)	(465)	(414)
Prior service cost (credit)	(2)	(3)	(4)	(7)
Actuarial loss (gain)	37	53	110	157
Settlement charges	5	10	5	14
Non-service components of pension benefits & OPEB credit	(29)	(7)	(95)	(39)
Net periodic benefit cost	8	37	17	92
Pension Benefits
Defined Contribution Plan Disclosure [Line Items]
Service cost	31	36	94	109
Interest cost	74	59	217	177
Expected return on assets	(143)	(123)	(423)	(370)
Prior service cost (credit)	0	0	1	0
Actuarial loss (gain)	37	50	111	149
Settlement charges	5	10	5	14
Non-service components of pension benefits & OPEB credit	(27)	(4)	(89)	(30)
Net periodic benefit cost	4	32	5	79
OPEB
Defined Contribution Plan Disclosure [Line Items]
Service cost	6	8	18	22
Interest cost	14	12	42	34
Expected return on assets	(14)	(15)	(42)	(44)
Prior service cost (credit)	(2)	(3)	(5)	(7)
Actuarial loss (gain)	0	3	(1)	8
Settlement charges	0	0	0	0
Non-service components of pension benefits & OPEB credit	(2)	(3)	(6)	(9)
Net periodic benefit cost	4	5	12	13
Pension Plan and Other Postretirement Benefits Plan
Defined Contribution Plan Disclosure [Line Items]
Non-service components of pension benefits & OPEB credit	(27)	(11)	(85)	(36)
Net periodic benefit cost	$ 33	$ 32	$ 98	$ 103

Retirement Benefits - Remaining

Retirement Benefits - Remaining Service Period (Details)	9 Months Ended
	Sep. 30, 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 6 months
Expected Retirement	8 years 3 months 18 days

Retirement Benefits - Estimated

Retirement Benefits - Estimated Future Benefit Payments (Details) $ in Millions	Sep. 30, 2022 USD ($)
Pension Benefits
Defined Contribution Plan Disclosure [Line Items]
2022(a)	$ 532
2023	521
2024	524
2025	536
2026	533
2027 through 2031	2,710
Total estimated future benefits payments through 2031	5,356
OPEB
Defined Contribution Plan Disclosure [Line Items]
2022(a)	108
2023	108
2024	108
2025	107
2026	107
2027 through 2031	540
Total estimated future benefits payments through 2031	$ 1,078

Derivative Financial Instrume_3

Derivative Financial Instruments - Summary of Derivative Fair Value Balances (Details) - USD ($) $ in Millions	Sep. 30, 2022	Dec. 31, 2021
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	$ 2,557	$ 2,169
Mark-to-market derivative assets (noncurrent assets)	1,252	949
Mark-to-market derivative liabilities (current liabilities)	(2,392)	(981)
Mark-to-market derivative liabilities (noncurrent liabilities)	(1,244)	(513)
Variation margin	2,013	897
Commodity Contract
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	2,538	2,169
Mark-to-market derivative assets (noncurrent assets)	1,229	943
Total mark-to-market derivative assets	3,767	3,112
Mark-to-market derivative liabilities (current liabilities)	(2,380)	(977)
Mark-to-market derivative liabilities (noncurrent liabilities)	(1,243)	(513)
Total mark-to-market derivative liabilities	(3,623)	(1,490)
Total mark-to-market derivative net assets (liabilities)	144	1,622
Commodity Contract | Collateral
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	(372)	152
Mark-to-market derivative assets (noncurrent assets)	(27)	15
Total mark-to-market derivative assets	(399)	167
Mark-to-market derivative liabilities (current liabilities)	50	262
Mark-to-market derivative liabilities (noncurrent liabilities)	114	83
Total mark-to-market derivative liabilities	164	345
Total mark-to-market derivative net assets (liabilities)	(235)	512
Commodity Contract | Netting
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	(24,816)	(8,923)
Mark-to-market derivative assets (noncurrent assets)	(5,848)	(2,298)
Total mark-to-market derivative assets	(30,664)	(11,221)
Mark-to-market derivative liabilities (current liabilities)	24,816	8,923
Mark-to-market derivative liabilities (noncurrent liabilities)	5,848	2,298
Total mark-to-market derivative liabilities	30,664	11,221
Total mark-to-market derivative net assets (liabilities)	0	0
Commodity Contract | Not Designated as Hedging Instrument, Economic Hedge
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	27,702	10,915
Mark-to-market derivative assets (noncurrent assets)	7,103	3,224
Total mark-to-market derivative assets	34,805	14,139
Mark-to-market derivative liabilities (current liabilities)	(27,225)	(10,143)
Mark-to-market derivative liabilities (noncurrent liabilities)	(7,205)	(2,893)
Total mark-to-market derivative liabilities	(34,430)	(13,036)
Total mark-to-market derivative net assets (liabilities)	375	1,103
Commodity Contract | Not Designated as Hedging Instrument, Propriety Trading
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	24	25
Mark-to-market derivative assets (noncurrent assets)	1	2
Total mark-to-market derivative assets	25	27
Mark-to-market derivative liabilities (current liabilities)	(21)	(19)
Mark-to-market derivative liabilities (noncurrent liabilities)	0	(1)
Total mark-to-market derivative liabilities	(21)	(20)
Total mark-to-market derivative net assets (liabilities)	4	$ 7
Interest Rate Swap
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	19
Mark-to-market derivative assets (noncurrent assets)	23
Total mark-to-market derivative assets	42
Mark-to-market derivative liabilities (current liabilities)	(12)
Mark-to-market derivative liabilities (noncurrent liabilities)	(1)
Total mark-to-market derivative liabilities	(13)
Total mark-to-market derivative net assets (liabilities)	29
Interest Rate Swap | Netting
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	(8)
Mark-to-market derivative assets (noncurrent assets)	0
Total mark-to-market derivative assets	(8)
Mark-to-market derivative liabilities (current liabilities)	8
Mark-to-market derivative liabilities (noncurrent liabilities)	0
Total mark-to-market derivative liabilities	8
Total mark-to-market derivative net assets (liabilities)	0
Interest Rate Swap | Not Designated as Hedging Instrument, Economic Hedge
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	27
Mark-to-market derivative assets (noncurrent assets)	23
Total mark-to-market derivative assets	50
Mark-to-market derivative liabilities (current liabilities)	(20)
Mark-to-market derivative liabilities (noncurrent liabilities)	(1)
Total mark-to-market derivative liabilities	(21)
Total mark-to-market derivative net assets (liabilities)	$ 29

Derivative Financial Instrume_4

Derivative Financial Instruments - Summary of Economic Hedges (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021
Derivative [Line Items]
Total			$ (544)	$ 1,244
Not Designated as Hedging Instrument, Economic Hedge | Commodity Contract
Derivative [Line Items]
Total	$ (520)	$ 755	(567)	1,248
Not Designated as Hedging Instrument, Economic Hedge | Commodity Contract | Operating revenues
Derivative [Line Items]
Total	(691)	(637)	(1,913)	(961)
Not Designated as Hedging Instrument, Economic Hedge | Commodity Contract | Purchased power and fuel
Derivative [Line Items]
Total	$ 171	$ 1,392	$ 1,346	$ 2,209

Derivative Financial Instrume_5

Derivative Financial Instruments - Narrative (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2022	Dec. 31, 2021
Not Designated as Hedging Instrument, Economic Hedge | Interest Rate Swap
Derivative [Line Items]
Notional amount	$ 563	$ 486
Minimum
Derivative [Line Items]
Expected generation hedged in next twelve months	97%
Expected generation hedged in year two	92%
Maximum
Derivative [Line Items]
Expected generation hedged in next twelve months	100%
Expected generation hedged in year two	95%

Derivative Financial Instrume_6

Derivative Financial Instruments - Summary of Credit Risk Exposure (Details) $ in Millions	9 Months Ended
	Sep. 30, 2022 USD ($) counterparty
Derivative [Line Items]
Cash collateral	$ 530
Letters of credit held	143
Total Exposure Before Credit Collateral
Derivative [Line Items]
Total	1,968
Total Exposure Before Credit Collateral | Internally rated — investment grade
Derivative [Line Items]
Total	109
Total Exposure Before Credit Collateral | Internally rated — non-investment grade
Derivative [Line Items]
Total	330
Total Exposure Before Credit Collateral | Investment grade
Derivative [Line Items]
Total	1,515
Total Exposure Before Credit Collateral | Non-investment grade
Derivative [Line Items]
Total	14
Credit Collateral
Derivative [Line Items]
Total	673
Credit Collateral | Internally rated — investment grade
Derivative [Line Items]
Total	0
Credit Collateral | Internally rated — non-investment grade
Derivative [Line Items]
Total	89
Credit Collateral | Investment grade
Derivative [Line Items]
Total	584
Credit Collateral | Non-investment grade
Derivative [Line Items]
Total	0
Net Exposure
Derivative [Line Items]
Total	1,295
Net Exposure | Investor-owned utilities, marketers, power producers
Derivative [Line Items]
Total	1,057
Net Exposure | Energy cooperatives and municipalities
Derivative [Line Items]
Total	96
Net Exposure | Financial institutions
Derivative [Line Items]
Total	53
Net Exposure | Other
Derivative [Line Items]
Total	89
Net Exposure | Internally rated — investment grade
Derivative [Line Items]
Total	109
Net Exposure | Internally rated — non-investment grade
Derivative [Line Items]
Total	241
Net Exposure | Investment grade
Derivative [Line Items]
Total	931
Net Exposure | Non-investment grade
Derivative [Line Items]
Total	$ 14
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	Sep. 30, 2022	Dec. 31, 2021
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Gross fair value of derivative contracts containing this feature	$ (8,882)	$ (3,872)
Offsetting fair value of in-the-money contracts under master netting arrangements	5,336	2,424
Net fair value of derivative contracts containing this feature	$ (3,546)	$ (1,448)

Derivative Financial Instrume_8

Derivative Financial Instruments - Summary of Cash Collateral and Letters of Credit (Details) - USD ($) $ in Millions	Sep. 30, 2022	Dec. 31, 2021
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Cash collateral posted	$ 1,370	$ 713
Letters of credit posted	1,146	755
Cash collateral held	1,605	182
Letters of credit held	161	124
Additional collateral required in the event of a credit downgrade below investment grade (at BB+/Ba1)	$ 3,115	$ 2,113

Debt and Credit Agreements - Co

Debt and Credit Agreements - Commercial Paper Borrowings (Details) - USD ($) $ in Millions	Sep. 30, 2022	Dec. 31, 2021
Short-term Debt [Line Items]
Outstanding Commercial Paper as of	$ 493	$ 702
Commercial Paper
Short-term Debt [Line Items]
Average Interest Rate on Commercial Paper Borrowings as of	3.95%	0.66%

Debt and Credit Agreements - Na

Debt and Credit Agreements - Narrative (Details) - USD ($) $ in Millions							4 Months Ended
		Mar. 29, 2022	Feb. 01, 2022	Jan. 31, 2022	Aug. 06, 2021	Mar. 19, 2020	Aug. 05, 2022	Sep. 30, 2022	Feb. 09, 2022	Dec. 31, 2021	Mar. 31, 2020
Schedule of line of credit, short term, and long term debt [Line Items]
Syndicated credit facility								$ 0
Credit facility				$ 4,500				5,802
Short term loan agreement				200				693		$ 2,082
Membership interest	[1]							0		11,250
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
Revolving Credit Facility
Schedule of line of credit, short term, and long term debt [Line Items]
Syndicated credit facility			$ 5,300					0
Credit facility			$ 3,500
Liquidity Facility
Schedule of line of credit, short term, and long term debt [Line Items]
Syndicated credit facility								0
Credit facility								$ 971	$ 1,000
Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate | Revolving Credit Facility
Schedule of line of credit, short term, and long term debt [Line Items]
Basis spread			1.275%
Term Loan | Unsecured Debt
Schedule of line of credit, short term, and long term debt [Line Items]
Short term loan agreement		$ 200			$ 880	$ 200					$ 300
Repayments of short-term debt		$ 100
Debt instrument term					364 days
Term Loan | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate | Unsecured Debt
Schedule of line of credit, short term, and long term debt [Line Items]
Basis spread		0.80%
Term Loan | London Interbank Offered Rate (LIBOR) | Unsecured Debt
Schedule of line of credit, short term, and long term debt [Line Items]
Basis spread					0.875%	0.875%	1%
Related Party Debt
Schedule of line of credit, short term, and long term debt [Line Items]
Membership interest				$ 61
[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.

Debt and Credit Agreements - Su

Debt and Credit Agreements - Summary of Bank Commitments, Credit Facility Borrowings and Available Capacity (Details) - USD ($) $ in Millions	Sep. 30, 2022	Aug. 24, 2022	Aug. 12, 2022	Jul. 15, 2022	Jul. 14, 2022	Feb. 09, 2022	Feb. 01, 2022	Jan. 31, 2022
Short-term Debt [Line Items]
Aggregate Bank Commitment	$ 5,802							$ 4,500
Facility Draws	0
Outstanding Letters of Credit	3,509
Actual Available Capacity	2,293
To Support Additional Commercial Paper Available Capacity	1,504
Revolving Credit Facility
Short-term Debt [Line Items]
Aggregate Bank Commitment							$ 3,500
Facility Draws	0						$ 5,300
Outstanding Letters of Credit	1,503
Actual Available Capacity	1,997
To Support Additional Commercial Paper Available Capacity	1,504
Revolving Credit Facility | Community and Minority Facilities
Short-term Debt [Line Items]
Credit facility agreements with minority and community banks	44
Bilateral Credit Agreements
Short-term Debt [Line Items]
Aggregate Bank Commitment	1,200
Facility Draws	0
Outstanding Letters of Credit	1,034
Actual Available Capacity	166			$ 100	$ 150
To Support Additional Commercial Paper Available Capacity	0
Bilateral Credit Agreements | August 12, 2022 Agreement
Short-term Debt [Line Items]
Aggregate Bank Commitment			$ 50
Bilateral Credit Agreements | August 24, 2022 Agreement
Short-term Debt [Line Items]
Aggregate Bank Commitment		$ 100
Liquidity Facility
Short-term Debt [Line Items]
Aggregate Bank Commitment	971					$ 1,000
Facility Draws	0
Outstanding Letters of Credit	861
Actual Available Capacity	110
To Support Additional Commercial Paper Available Capacity	0
Liquidity Facility | No Additional Collateral Posted
Short-term Debt [Line Items]
Actual Available Capacity	877
Secured debt
Short-term Debt [Line Items]
Aggregate Bank Commitment	131
Facility Draws	0
Outstanding Letters of Credit	111
Actual Available Capacity	20
To Support Additional Commercial Paper Available Capacity	$ 0

Debt and Credit Agreements - _2

Debt and Credit Agreements - Summary of Outstanding Long-term Debt (Details) $ in Millions	Sep. 30, 2022 USD ($)
Energy Efficiency Project Financing
Debt Instrument [Line Items]
Amount	$ 9
Minimum | Energy Efficiency Project Financing
Debt Instrument [Line Items]
Interest Rate	2.20%
Maximum | Energy Efficiency Project Financing
Debt Instrument [Line Items]
Interest Rate	2.44%
Senior Notes | Senior Notes, Due March 2022
Debt Instrument [Line Items]
Interest Rate	3.40%
Amount	$ 500
Senior Notes | Senior Notes, Due June 2022
Debt Instrument [Line Items]
Interest Rate	4.25%
Amount	$ 523
Nonrecourse Debt | CR Nonrecourse Debt
Debt Instrument [Line Items]
Interest Rate	2.50%
Amount	$ 41
Nonrecourse Debt | Continental Wind Nonrecourse Debt
Debt Instrument [Line Items]
Interest Rate	6%
Amount	$ 36
Nonrecourse Debt | West Medway II Nonrecourse Debt
Debt Instrument [Line Items]
Interest Rate	2.875%
Amount	$ 17
Nonrecourse Debt | Antelope Valley DOE Nonrecourse Debt
Debt Instrument [Line Items]
Amount	$ 14
Nonrecourse Debt | RPG Nonrecourse Debt
Debt Instrument [Line Items]
Interest Rate	4.11%
Amount	$ 9
Nonrecourse Debt | Energy Efficiency Project Financing Due December 2022
Debt Instrument [Line Items]
Interest Rate	3.71%
Amount	$ 3
Nonrecourse Debt | Minimum | Antelope Valley DOE Nonrecourse Debt
Debt Instrument [Line Items]
Interest Rate	2.29%
Nonrecourse Debt | Maximum | Antelope Valley DOE Nonrecourse Debt
Debt Instrument [Line Items]
Interest Rate	3.56%

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	Sep. 30, 2022	Dec. 31, 2021
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]
SNF Obligation	$ 1,219	$ 1,210
Carrying Amount
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including amounts due within one year	4,661	6,114
SNF Obligation	1,219	1,210
Fair Value
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including amounts due within one year	4,484	6,842
SNF Obligation	975	1,060
Fair Value | Level 2
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including amounts due within one year	3,577	5,749
SNF Obligation	975	1,060
Fair Value | Level 3
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including amounts due within one year	907	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	Sep. 30, 2022	Dec. 31, 2021
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]
Net derivative assets	$ 1	$ 1
Total notational amounts	432	687
Variation margin	2,013	897
Cash and Cash Equivalents | Constellation Energy Generation, LLC
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents, fair value disclosure	1,123	417
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]
Cash equivalents, fair value disclosure	1,123	417
Cash and Cash Equivalents | CEG Parent
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents, fair value disclosure	44
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]
Cash equivalents, fair value disclosure	44
Restricted cash | Constellation Energy Generation, LLC
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents, fair value disclosure	75	46
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]
Cash equivalents, fair value disclosure	75	46
Cash | CEG Parent
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents, fair value disclosure	61
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]
Cash equivalents, fair value disclosure	61
NDT fund investments subtotal | Maturity Less than 30 Days
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]
Cash	89	116
NDT fund investments subtotal
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]
Investments in equities sold short	(38)	(55)
Net liabilities	178	111
Notional amount	140	182
Fair Value, Recurring
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents, fair value disclosure	16	113
DPP	975	365
Total assets	18,595	19,880
Deferred compensation obligation	(53)	(43)
Total liabilities	(3,689)	(1,533)
Total net assets (liabilities)	14,906	18,347
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]
Cash equivalents, fair value disclosure	16	113
Fair Value, Recurring | Mark-to-market derivative liabilities subtotal
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Mark-to-market derivative liabilities	(3,636)	(1,490)
Fair Value, Recurring | Economic hedges
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Mark-to-market derivative liabilities	(34,451)	(13,036)
Fair Value, Recurring | Proprietary trading
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Mark-to-market derivative liabilities	(21)	(20)
Fair Value, Recurring | Effect of netting and allocation of collateral
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Mark-to-market derivative liabilities	30,836	11,566
Fair Value, Recurring | NDT fund investments subtotal
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	13,724	16,175
Fair Value, Recurring | Cash equivalents NDT
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	588	581
Fair Value, Recurring | Equities NDT
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	5,630	8,014
Fair Value, Recurring | Fixed income subtotal
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	5,017	5,241
Fair Value, Recurring | Corporate debt
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	1,246	1,431
Fair Value, Recurring | U.S. Treasury and agencies
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	1,979	2,223
Fair Value, Recurring | Foreign governments
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	42	60
Fair Value, Recurring | State and municipal debt
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	46	26
Fair Value, Recurring | Other
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	1,704	1,501
Fair Value, Recurring | Private credit
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	804	802
Fair Value, Recurring | Private equity
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	678	673
Fair Value, Recurring | Real estate
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	1,007	864
Fair Value, Recurring | Rabbi trust investments subtotal
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	65	72
Fair Value, Recurring | Cash equivalents
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	1	3
Fair Value, Recurring | Mutual funds
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	36	36
Fair Value, Recurring | Life insurance contracts
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	28	33
Fair Value, Recurring | Investments in equities
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	6	43
Fair Value, Recurring | Mark-to-market derivative assets subtotal
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Mark-to-market derivative assets	3,809	3,112
Fair Value, Recurring | Economic hedges
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Mark-to-market derivative assets	34,855	14,139
Fair Value, Recurring | Proprietary trading
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Mark-to-market derivative assets	25	27
Fair Value, Recurring | Effect of netting and allocation of collateral
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Mark-to-market derivative assets	(31,071)	(11,054)
Level 1
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]
Collateral posted (received) from counterparties	259	81
Level 1 | Fair Value, Recurring
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents, fair value disclosure	16	113
DPP	0	0
Total assets	7,142	8,355
Deferred compensation obligation	0	0
Total liabilities	54	(12)
Total net assets (liabilities)	7,196	8,343
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]
Cash equivalents, fair value disclosure	16	113
Level 1 | Fair Value, Recurring | Mark-to-market derivative liabilities subtotal
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Mark-to-market derivative liabilities	54	(12)
Level 1 | Fair Value, Recurring | Economic hedges
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Mark-to-market derivative liabilities	(5,438)	(2,201)
Level 1 | Fair Value, Recurring | Proprietary trading
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Mark-to-market derivative liabilities	0	0
Level 1 | Fair Value, Recurring | Effect of netting and allocation of collateral
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Mark-to-market derivative liabilities	5,492	2,189
Level 1 | Fair Value, Recurring | NDT fund investments subtotal
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	5,627	7,251
Level 1 | Fair Value, Recurring | Cash equivalents NDT
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	494	465
Level 1 | Fair Value, Recurring | Equities NDT
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	3,153	4,564
Level 1 | Fair Value, Recurring | Fixed income subtotal
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	1,980	2,222
Level 1 | Fair Value, Recurring | Corporate debt
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	0	0
Level 1 | Fair Value, Recurring | U.S. Treasury and agencies
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	1,960	2,193
Level 1 | Fair Value, Recurring | Foreign governments
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	0	0
Level 1 | Fair Value, Recurring | State and municipal debt
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	0	0
Level 1 | Fair Value, Recurring | Other
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	20	29
Level 1 | Fair Value, Recurring | Private credit
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	0	0
Level 1 | Fair Value, Recurring | Private equity
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	0	0
Level 1 | Fair Value, Recurring | Real estate
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	0	0
Level 1 | Fair Value, Recurring | Rabbi trust investments subtotal
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	37	39
Level 1 | Fair Value, Recurring | Cash equivalents
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	1	3
Level 1 | Fair Value, Recurring | Mutual funds
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	36	36
Level 1 | Fair Value, Recurring | Life insurance contracts
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	0	0
Level 1 | Fair Value, Recurring | Investments in equities
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	6	43
Level 1 | Fair Value, Recurring | Mark-to-market derivative assets subtotal
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Mark-to-market derivative assets	1,456	909
Level 1 | Fair Value, Recurring | Economic hedges
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Mark-to-market derivative assets	6,689	3,017
Level 1 | Fair Value, Recurring | Proprietary trading
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Mark-to-market derivative assets	0	0
Level 1 | Fair Value, Recurring | Effect of netting and allocation of collateral
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Mark-to-market derivative assets	(5,233)	(2,108)
Level 2
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]
Collateral posted (received) from counterparties	(149)	465
Level 2 | Fair Value, Recurring
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents, fair value disclosure	0	0
DPP	975	365
Total assets	3,838	4,668
Deferred compensation obligation	(53)	(43)
Total liabilities	(241)	(289)
Total net assets (liabilities)	3,597	4,379
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]
Cash equivalents, fair value disclosure	0	0
Level 2 | Fair Value, Recurring | Mark-to-market derivative liabilities subtotal
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Mark-to-market derivative liabilities	(188)	(246)
Level 2 | Fair Value, Recurring | Economic hedges
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Mark-to-market derivative liabilities	(15,909)	(6,870)
Level 2 | Fair Value, Recurring | Proprietary trading
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Mark-to-market derivative liabilities	(12)	(18)
Level 2 | Fair Value, Recurring | Effect of netting and allocation of collateral
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Mark-to-market derivative liabilities	15,733	6,642
Level 2 | Fair Value, Recurring | NDT fund investments subtotal
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	2,532	3,205
Level 2 | Fair Value, Recurring | Cash equivalents NDT
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	94	116
Level 2 | Fair Value, Recurring | Equities NDT
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	1,330	1,805
Level 2 | Fair Value, Recurring | Fixed income subtotal
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	1,108	1,284
Level 2 | Fair Value, Recurring | Corporate debt
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	982	1,145
Level 2 | Fair Value, Recurring | U.S. Treasury and agencies
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	19	30
Level 2 | Fair Value, Recurring | Foreign governments
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	42	60
Level 2 | Fair Value, Recurring | State and municipal debt
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	46	26
Level 2 | Fair Value, Recurring | Other
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	19	23
Level 2 | Fair Value, Recurring | Private credit
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	0	0
Level 2 | Fair Value, Recurring | Private equity
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	0	0
Level 2 | Fair Value, Recurring | Real estate
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	0	0
Level 2 | Fair Value, Recurring | Rabbi trust investments subtotal
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	27	33
Level 2 | Fair Value, Recurring | Cash equivalents
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	0	0
Level 2 | Fair Value, Recurring | Mutual funds
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	0	0
Level 2 | Fair Value, Recurring | Life insurance contracts
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	27	33
Level 2 | Fair Value, Recurring | Investments in equities
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	0	0
Level 2 | Fair Value, Recurring | Mark-to-market derivative assets subtotal
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Mark-to-market derivative assets	304	1,065
Level 2 | Fair Value, Recurring | Economic hedges
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Mark-to-market derivative assets	16,175	7,223
Level 2 | Fair Value, Recurring | Proprietary trading
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Mark-to-market derivative assets	11	19
Level 2 | Fair Value, Recurring | Effect of netting and allocation of collateral
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Mark-to-market derivative assets	(15,882)	(6,177)
Level 3
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]
Collateral posted (received) from counterparties	(345)	(34)
Level 3 | Fair Value, Recurring
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents, fair value disclosure	0	0
DPP	0	0
Total assets	2,480	1,602
Deferred compensation obligation	0	0
Total liabilities	(3,502)	(1,232)
Total net assets (liabilities)	(1,022)	370
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]
Cash equivalents, fair value disclosure	0	0
Level 3 | Fair Value, Recurring | Mark-to-market derivative liabilities subtotal
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Mark-to-market derivative liabilities	(3,502)	(1,232)
Level 3 | Fair Value, Recurring | Economic hedges
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Mark-to-market derivative liabilities	(13,104)	(3,965)
Level 3 | Fair Value, Recurring | Proprietary trading
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Mark-to-market derivative liabilities	(9)	(2)
Level 3 | Fair Value, Recurring | Effect of netting and allocation of collateral
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Mark-to-market derivative liabilities	9,611	2,735
Level 3 | Fair Value, Recurring | NDT fund investments subtotal
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	430	464
Level 3 | Fair Value, Recurring | Cash equivalents NDT
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	0	0
Level 3 | Fair Value, Recurring | Equities NDT
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	2	0
Level 3 | Fair Value, Recurring | Fixed income subtotal
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	264	286
Level 3 | Fair Value, Recurring | Corporate debt
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	264	286
Level 3 | Fair Value, Recurring | U.S. Treasury and agencies
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	0	0
Level 3 | Fair Value, Recurring | Foreign governments
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	0	0
Level 3 | Fair Value, Recurring | State and municipal debt
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	0	0
Level 3 | Fair Value, Recurring | Other
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	0	0
Level 3 | Fair Value, Recurring | Private credit
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	164	178
Level 3 | Fair Value, Recurring | Private equity
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	0	0
Level 3 | Fair Value, Recurring | Real estate
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	0	0
Level 3 | Fair Value, Recurring | Rabbi trust investments subtotal
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	1	0
Level 3 | Fair Value, Recurring | Cash equivalents
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	0	0
Level 3 | Fair Value, Recurring | Mutual funds
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	0	0
Level 3 | Fair Value, Recurring | Life insurance contracts
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	1	0
Level 3 | Fair Value, Recurring | Investments in equities
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	0	0
Level 3 | Fair Value, Recurring | Mark-to-market derivative assets subtotal
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Mark-to-market derivative assets	2,049	1,138
Level 3 | Fair Value, Recurring | Economic hedges
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Mark-to-market derivative assets	11,991	3,899
Level 3 | Fair Value, Recurring | Proprietary trading
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Mark-to-market derivative assets	14	8
Level 3 | Fair Value, Recurring | Effect of netting and allocation of collateral
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Mark-to-market derivative assets	(9,956)	(2,769)
Not subject to leveling | Fair Value, Recurring
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents, fair value disclosure	0	0
DPP	0	0
Total assets	5,135	5,255
Deferred compensation obligation	0	0
Total liabilities	0	0
Total net assets (liabilities)	5,135	5,255
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]
Cash equivalents, fair value disclosure	0	0
Not subject to leveling | Fair Value, Recurring | Mark-to-market derivative liabilities subtotal
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Mark-to-market derivative liabilities	0	0
Not subject to leveling | Fair Value, Recurring | Economic hedges
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Mark-to-market derivative liabilities	0	0
Not subject to leveling | Fair Value, Recurring | Proprietary trading
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Mark-to-market derivative liabilities	0	0
Not subject to leveling | Fair Value, Recurring | Effect of netting and allocation of collateral
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Mark-to-market derivative liabilities	0	0
Not subject to leveling | Fair Value, Recurring | NDT fund investments subtotal
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	5,135	5,255
Not subject to leveling | Fair Value, Recurring | Cash equivalents NDT
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	0	0
Not subject to leveling | Fair Value, Recurring | Equities NDT
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	1,145	1,645
Not subject to leveling | Fair Value, Recurring | Fixed income subtotal
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	1,665	1,449
Not subject to leveling | Fair Value, Recurring | Corporate debt
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	0	0
Not subject to leveling | Fair Value, Recurring | U.S. Treasury and agencies
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	0	0
Not subject to leveling | Fair Value, Recurring | Foreign governments
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	0	0
Not subject to leveling | Fair Value, Recurring | State and municipal debt
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	0	0
Not subject to leveling | Fair Value, Recurring | Other
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	1,665	1,449
Not subject to leveling | Fair Value, Recurring | Private credit
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	640	624
Not subject to leveling | Fair Value, Recurring | Private equity
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	678	673
Not subject to leveling | Fair Value, Recurring | Real estate
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	1,007	864
Not subject to leveling | Fair Value, Recurring | Rabbi trust investments subtotal
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	0	0
Not subject to leveling | Fair Value, Recurring | Cash equivalents
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	0	0
Not subject to leveling | Fair Value, Recurring | Mutual funds
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	0	0
Not subject to leveling | Fair Value, Recurring | Life insurance contracts
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	0	0
Not subject to leveling | Fair Value, Recurring | Investments in equities
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Investments, fair value disclosure	0	0
Not subject to leveling | Fair Value, Recurring | Mark-to-market derivative assets subtotal
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Mark-to-market derivative assets	0	0
Not subject to leveling | Fair Value, Recurring | Economic hedges
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Mark-to-market derivative assets	0	0
Not subject to leveling | Fair Value, Recurring | Proprietary trading
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Mark-to-market derivative assets	0	0
Not subject to leveling | Fair Value, Recurring | Effect of netting and allocation of collateral
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Mark-to-market derivative assets	$ 0	$ 0

Fair Value of Financial Asset_5

Fair Value of Financial Assets and Liabilities - Narrative (Details) - USD ($) $ in Millions	Sep. 30, 2022	Dec. 31, 2021
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments without determinable fair values	$ 45	$ 33
Private credit
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Outstanding commitments	242
Private equity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Outstanding commitments	144
Real estate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Outstanding commitments	$ 412

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) - Level 3 - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Abstract]
Beginning Balance	$ (311)	$ (4)	$ 370	$ 927
Total realized / unrealized (losses) gains
Included in net income	(925)	(967)	(1,827)	(1,602)
Included in Payable related to Regulatory Agreement Units	(2)	11	(11)	18
Change in collateral	(58)	(413)	(312)	(751)
Impacts of separation			3
Purchases, sales, issuances and settlements
Purchases	333	8	504	123
Sales	(7)	6	(44)	7
Settlements	0	(2)	(58)	(48)
Transfers into Level 3	2	2	420	4
Transfers out of Level 3	(54)	(27)	(67)	(64)
Ending Balance	(1,022)	(1,386)	(1,022)	(1,386)
The amount of total (losses) gains included in income attributed to the change in unrealized (losses) gains related to assets and liabilities	(890)	(1,001)	(1,955)	(1,523)
NDT fund investments subtotal
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Abstract]
Beginning Balance	431	461	464	497
Total realized / unrealized (losses) gains
Included in net income	0	3	(2)	4
Included in Payable related to Regulatory Agreement Units	(2)	11	(11)	18
Change in collateral	0	0	0	0
Impacts of separation			0
Purchases, sales, issuances and settlements
Purchases	0	2	5	3
Sales	0	0	0	0
Settlements	0	(2)	(28)	(48)
Transfers into Level 3	1	0	2	1
Transfers out of Level 3	0	0	0	0
Ending Balance	430	475	430	475
The amount of total (losses) gains included in income attributed to the change in unrealized (losses) gains related to assets and liabilities	(1)	3	(2)	4
Mark-to-Market Derivatives
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Abstract]
Beginning Balance	(743)	(465)	(94)	430
Total realized / unrealized (losses) gains
Included in net income	(925)	(970)	(1,823)	(1,606)
Included in Payable related to Regulatory Agreement Units	0	0	0	0
Change in collateral	(58)	(413)	(312)	(751)
Impacts of separation			0
Purchases, sales, issuances and settlements
Purchases	333	6	499	120
Sales	(7)	6	(44)	7
Settlements	0	0	(30)	0
Transfers into Level 3	1	2	418	3
Transfers out of Level 3	(54)	(27)	(67)	(64)
Ending Balance	(1,453)	(1,861)	(1,453)	(1,861)
The amount of total (losses) gains included in income attributed to the change in unrealized (losses) gains related to assets and liabilities	(889)	(1,004)	(1,951)	(1,527)
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]
Realized gains (losses)	35	$ (34)	(98)	$ 80
Life insurance contracts
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Abstract]
Beginning Balance	1		0
Total realized / unrealized (losses) gains
Included in net income	0		(2)
Included in Payable related to Regulatory Agreement Units	0		0
Change in collateral	0		0
Impacts of separation			3
Purchases, sales, issuances and settlements
Purchases	0		0
Sales	0		0
Settlements	0		0
Transfers into Level 3	0		0
Transfers out of Level 3	0		0
Ending Balance	1		1
The amount of total (losses) gains included in income attributed to the change in unrealized (losses) gains related to assets and liabilities	$ 0		$ (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) - Level 3 - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021
Fair Value Assets and Liabilities Measured on a Recurring Basis Gain Loss Included in Earnings [Line Items]
Total (losses) gains included in net income	$ 925	$ 967	$ 1,827	$ 1,602
Total unrealized (losses) gains	(890)	(1,001)	(1,955)	(1,523)
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	(545)	(1,274)	(1,786)	(1,944)
Total unrealized (losses) gains	(768)	(1,361)	(2,353)	(1,969)
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	(380)	304	(67)	338
Total unrealized (losses) gains	(121)	357	402	443
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	0	3	(4)	4
Total unrealized (losses) gains	$ (1)	$ 3	$ (4)	$ 4

Fair Value of Financial Asset_8

Fair Value of Financial Assets and Liabilities - Fair Value Inputs Assets Quantitative Information (Details) - Level 3 $ in Millions	Sep. 30, 2022 USD ($)	Dec. 31, 2021 USD ($)
Fair Value Measurement Inputs and Valuation Techniques [Abstract]
Cash collateral received	$ 345	$ 34
Economic Hedges
Fair Value Measurement Inputs and Valuation Techniques [Abstract]
Mark-to-market derivatives—Economic hedges	$ (1,113)	$ (66)
Economic Hedges | Minimum | Discounted Cash Flow
Fair Value Measurement Inputs and Valuation Techniques [Abstract]
Forward power price	9.26	8.86
Forward gas price	2.55	1.69
Economic Hedges | Minimum | Option  Model
Fair Value Measurement Inputs and Valuation Techniques [Abstract]
Volatility percentage	1	0.24
Economic Hedges | Maximum | Discounted Cash Flow
Fair Value Measurement Inputs and Valuation Techniques [Abstract]
Forward power price	1,108	481
Forward gas price	31	17
Economic Hedges | Maximum | Option  Model
Fair Value Measurement Inputs and Valuation Techniques [Abstract]
Volatility percentage	1.28	2.84
Economic Hedges | Average | Discounted Cash Flow
Fair Value Measurement Inputs and Valuation Techniques [Abstract]
Forward power price	100	55
Forward gas price	5.25	3.50
Economic Hedges | Average | Option  Model
Fair Value Measurement Inputs and Valuation Techniques [Abstract]
Volatility percentage	1.13	0.56

Commitments and Contingencies -

Commitments and Contingencies - Schedule of Commercial Commitments (Details) $ in Millions	Sep. 30, 2022 USD ($)
Guarantor Obligations [Line Items]
Total	$ 4,487
2022	2,381
2023	2,106
2024	0
2025	0
2026	0
2027 and beyond	0
Letters of credit
Guarantor Obligations [Line Items]
Total	3,509
2022	2,125
2023	1,384
2024	0
2025	0
2026	0
2027 and beyond	0
Surety bonds
Guarantor Obligations [Line Items]
Total	978
2022	256
2023	722
2024	0
2025	0
2026	0
2027 and beyond	$ 0

Commitments and Contingencies_2

Commitments and Contingencies - Narrative (Details) $ in Millions		3 Months Ended	9 Months Ended		12 Months Ended
	Mar. 22, 2021 USD ($)	Sep. 30, 2022 USD ($) Open_claim	Sep. 30, 2022 USD ($) Open_claim	Sep. 30, 2021 USD ($)	Dec. 31, 2016 USD ($)	Jun. 30, 2022 USD ($)	Dec. 31, 2021 USD ($)	Aug. 03, 2020 USD ($)	Mar. 31, 2019 USD ($)	Sep. 30, 2018 USD ($)
Commitments and Contingencies [Line Items]
Gain (loss) recognized			$ 50	$ 0
Accrued undiscounted amounts		$ 122	122				$ 120
Estimated liabilities for asbestos-related bodily injury claims		97	97				81
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]
Damages sought	$ 40
Litigation liability						$ 11	$ 40
Open Claims
Commitments and Contingencies [Line Items]
Estimated liabilities for asbestos-related bodily injury claims		$ 24	$ 24
Number of claims | Open_claim		257	257
Estimated Future Claims
Commitments and Contingencies [Line Items]
Estimated liabilities for asbestos-related bodily injury claims		$ 73	$ 73
West Lake
Commitments and Contingencies [Line Items]
Accrued undiscounted amounts									$ 295	$ 50
Latty Avenue
Commitments and Contingencies [Line Items]
Environmental loss contingencies								$ 90

Stock-Based Compensation Plan_2

Stock-Based Compensation Plans - Narrative (Details) - LTIP - USD ($) $ / shares in Units, $ in Millions	9 Months Ended
	Sep. 30, 2022	Feb. 01, 2022
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares authorized (in shares)		20,000,000
Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage to be settled as common stock	50%
Percentage to be settled as cash	50%
Performance period	3 years
Vesting period	3 years
Shares granted (in shares)	1,501,673
Weighted average grant date fair value (in shares)	$ 47.23
Total unrecognized compensation costs	$ 31
Remaining weighted average period	2 years
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted (in shares)	1,371,997
Weighted average grant date fair value (in shares)	$ 45.22
Total unrecognized compensation costs	$ 29
Remaining weighted average period	2 years 3 months 18 days
Restricted Stock | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Requisite service period	3 years
Restricted Stock | 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	3 Months Ended		9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021
Share-Based Payment Arrangement [Abstract]
Total stock-based compensation expense included in operating and maintenance expense	$ 53	$ 8	$ 85	$ 30
Income tax benefit	(13)	(2)	(21)	(8)
Total after-tax stock-based compensation expense	$ 40	$ 6	$ 64	$ 22

Changes in Accumulated Other _3

Changes in Accumulated Other Comprehensive Loss - Schedule of Changes in AOCI (Details) - USD ($) $ in Millions	1 Months Ended	2 Months Ended	3 Months Ended						9 Months Ended
	Jan. 31, 2022	Mar. 31, 2022	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Sep. 30, 2022	Sep. 30, 2021
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	$ 11,614		$ 11,389	$ 11,505	$ 11,614				$ 11,614
Separation-related adjustments	(197)
Other comprehensive income (loss), net of income taxes		$ 21	23	24		$ (4)	$ 2	$ 1	68	$ (1)
Ending balance		$ 11,505	11,169	11,389	11,505				11,169
Losses on Cash Flow Hedges
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	(8)		(8)		(8)	(7)		(7)	(8)	(7)
Separation-related adjustments									0
OCI before reclassifications			0			(1)			(1)	(1)
Amounts reclassified from AOCI			(1)						0
Other comprehensive income (loss), net of income taxes			(1)			(1)			(1)	(1)
Ending balance			(9)	(8)		(8)	(7)		(9)	(8)
Pension and Non-Pension Postretirement Benefit Plan Items
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	0		(1,963)		0	0		0	0	0
Separation-related adjustments									(2,006)
OCI before reclassifications			0			0			0	0
Amounts reclassified from AOCI			30						73
Other comprehensive income (loss), net of income taxes			30			0			(1,933)	0
Ending balance			(1,933)	(1,963)		0	0		(1,933)	0
Foreign Currency Items
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	(23)		(21)		(23)	(20)		(23)	(23)	(23)
Separation-related adjustments									0
OCI before reclassifications			(6)			(3)			(4)	0
Amounts reclassified from AOCI			0						0
Other comprehensive income (loss), net of income taxes			(6)			(3)			(4)	0
Ending balance			(27)	(21)		(23)	(20)		(27)	(23)
Total
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	$ (31)		(1,992)		$ (31)	(27)		$ (30)	(31)	(30)
Separation-related adjustments									(2,006)
OCI before reclassifications			(6)			(4)			(5)	(1)
Amounts reclassified from AOCI			29						73
Other comprehensive income (loss), net of income taxes			23			(4)			(1,938)	(1)
Ending balance			$ (1,969)	$ (1,992)		$ (31)	$ (27)		$ (1,969)	$ (31)

Changes in Accumulated Other _4

Changes in Accumulated Other Comprehensive Loss - Income Taxes Allocated to Other Comprehensive Income (Loss) Components (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021
Actuarial loss reclassified to periodic benefit cost
Accumulated Other Comprehensive Income (Loss) [Line Items]
Pension and non-pension postretirement benefit plans valuation adjustment	$ (9)	$ 0	$ (24)	$ 0
Pension and Non-Pension Postretirement Benefit Plan Items
Accumulated Other Comprehensive Income (Loss) [Line Items]
Pension and non-pension postretirement benefit plans valuation adjustment	$ 0	$ 0	$ 680	$ 0

Variable Interest Entities - As

Variable Interest Entities - Assets and Liabilities of Consolidated VIEs (Details) - USD ($) $ in Millions		Sep. 30, 2022	Dec. 31, 2021	Sep. 30, 2021	Dec. 31, 2020
Current assets
Cash and cash equivalents		$ 1,192	$ 504	$ 1,957	$ 226
Restricted cash and cash equivalents		111	72	$ 62	$ 89
Accounts receivable
Customer		1,819	1,669
Other		579	592
Inventories, net
Materials and supplies		1,042	1,004
Other current assets		1,607	1,007
Total current assets		9,853	7,981
Property, plant and equipment, net		19,705	19,612
Other noncurrent assets		2,137	1,717
Total assets	[1]	46,616	48,086
Current liabilities
Long-term debt due within one year		181	1,220
Accounts payable		2,597	1,757
Accrued expenses		933	737
Other current liabilities		318	311
Total current liabilities		7,887	7,996
Long-term debt		4,480	4,575
Other noncurrent liabilities		1,251	1,133
Total deferred credits and other liabilities		23,080	23,582
Total liabilities	[1]	35,447	36,472
Recourse
Current liabilities
Total liabilities		1	1
Variable Interest Entity, Primary Beneficiary
Current assets
Cash and cash equivalents		64	35
Restricted cash and cash equivalents		42	48
Accounts receivable
Customer		25	24
Other		8	6
Inventories, net
Materials and supplies		12	14
Other current assets		1,022	405
Total current assets		1,173	532
Property, plant and equipment, net		1,971	2,027
Other noncurrent assets		195	215
Total noncurrent assets		2,166	2,242
Total assets		3,339	2,774
Current liabilities
Long-term debt due within one year		60	70
Accounts payable		19	10
Accrued expenses		20	21
Other current liabilities		2	1
Total current liabilities		101	102
Long-term debt		775	822
Asset retirement obligations		171	151
Other noncurrent liabilities		3	3
Total deferred credits and other liabilities		949	976
Total liabilities		1,050	1,078
Unamortized energy contract assets, current		23	23
Unamortized energy contract assets, noncurrent		$ 183	$ 202
[1]Our consolidated assets include $3,133 million and $2,549 million at September 30, 2022 and December 31, 2021, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Our consolidated liabilities include $1,049 million and $1,077 million at September 30, 2022 and December 31, 2021, respectively, of certain VIEs for which the VIE creditors do not have recourse to us. See Note 18 — Variable Interest Entities for additional information.

Variable Interest Entities - Na

Variable Interest Entities - Narrative (Details) - Constellation Energy Generation, LLC	Sep. 30, 2022	Dec. 31, 2021
EGRP
Variable Interest Entity [Line Items]
Equity ownership	51%	51%
Antelope Valley
Variable Interest Entity [Line Items]
Equity ownership	100%	100%
NER
Variable Interest Entity [Line Items]
Equity ownership	100%	100%
Solar project entities
Variable Interest Entity [Line Items]
Equity ownership	100%
Wind project entities
Variable Interest Entity [Line Items]
Equity ownership	100%

Variable Interest Entities - Su

Variable Interest Entities - Summary of Significant Unconsolidated VIEs (Details) - USD ($) $ in Millions		Sep. 30, 2022	Dec. 31, 2021
Variable Interest Entity [Line Items]
Total assets	[1]	$ 46,616	$ 48,086
Total liabilities	[1]	35,447	36,472
Variable Interest Entity, Not Primary Beneficiary
Variable Interest Entity [Line Items]
Total assets		1,060	1,144
Total liabilities		261	296
Our ownership interest in VIE		122	139
Other ownership interests in VIE		677	709
Commercial Agreement VIEs | Variable Interest Entity, Not Primary Beneficiary
Variable Interest Entity [Line Items]
Total assets		716	772
Total liabilities		55	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		344	372
Total liabilities		206	216
Our ownership interest in VIE		122	139
Other ownership interests in VIE		$ 16	$ 17
[1]Our consolidated assets include $3,133 million and $2,549 million at September 30, 2022 and December 31, 2021, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Our consolidated liabilities include $1,049 million and $1,077 million at September 30, 2022 and December 31, 2021, respectively, of certain VIEs for which the VIE creditors do not have recourse to us. See Note 18 — Variable Interest Entities for additional information.

Supplemental Financial Inform_3

Supplemental Financial Information - Summary of Taxes other than income (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021
Supplemental Financial Information [Abstract]
Operating lease income	$ 29	$ 29	$ 46	$ 44
Variable lease income	77	71	204	207
Gross receipts	39	27	100	73
Property	67	66	206	199
Payroll	$ 36	$ 26	$ 99	$ 83

Supplemental Financial Inform_4

Supplemental Financial Information - Summary of Other Income (Expense) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021
Decommissioning-related activities:
Regulatory Agreement Units	$ 61	$ 263	$ 333	$ 698
Non-Regulatory Agreement Units	15	102	115	392
Regulatory Agreement Units	(386)	(195)	(1,777)	84
Non-Regulatory Agreement Units	(225)	(88)	(1,077)	38
Regulatory offset to NDT fund-related activities	262	(38)	1,160	(607)
Decommissioning-related activities	(273)	44	(1,246)	605
Non-service net periodic benefit credit	27	0	79	0
Net unrealized (losses) gains from equity investments	$ (2)	$ (179)	$ (27)	$ (83)

Supplemental Financial Inform_5

Supplemental Financial Information - Supplemental Cash Flow Information (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021	Dec. 31, 2021	Dec. 31, 2020
Depreciation, amortization and accretion
Property, plant, and equipment			$ 798	$ 2,698
Amortization of intangible assets, net			20	37
Nuclear fuel			561	810
ARO accretion			403	383
Total depreciation, amortization, and accretion			1,810	3,951
Other non-cash operating activities
Pension and non-pension postretirement benefit costs			12	92
Allowance for credit losses			12	59
Other decommissioning related-activity			(116)	(810)
Energy-related options			239	45
Severance costs			0	(75)
Long-term incentive plan			35	0
Amortization of operating ROU asset			65	98
Loss on sale of receivables	$ 15	$ 1	39	26
Fair value adjustments related to gas imbalances			65	0
Prior merger commitment			(50)	0
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]
Cash and cash equivalents	1,192	1,957	1,192	1,957	$ 504	$ 226
Restricted cash and cash equivalents	111	62	111	62	72	89
Cash, restricted cash, and cash equivalents - Held for Sale						12
Total cash, restricted cash, and cash equivalents	1,303	2,019	1,303	2,019	576	327
Constellation Energy Generation, LLC
Depreciation, amortization and accretion
Total depreciation, amortization, and accretion			1,810	3,951
Other non-cash operating activities
Pension and non-pension postretirement benefit costs			12	92
Allowance for credit losses			12	59
Other decommissioning related-activity			(116)	(810)
Energy-related options			239	45
Severance costs			0	(75)
Long-term incentive plan			0	0
Amortization of operating ROU asset			65	98
Loss on sale of receivables			39	26
Fair value adjustments related to gas imbalances			65	0
Prior merger commitment			(50)	0
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]
Cash and cash equivalents	1,131	1,957	1,131	1,957	504	226
Restricted cash and cash equivalents	83	62	83	62	72	89
Cash, restricted cash, and cash equivalents - Held for Sale						12
Total cash, restricted cash, and cash equivalents	$ 1,214	$ 2,019	1,214	2,019	$ 576	$ 327
Unamortized Energy Contracts
Depreciation, amortization and accretion
Amortization of energy contract assets and liabilities			$ 28	$ 23

Supplemental Financial Inform_6

Supplemental Financial Information - Supplemental Balance Sheet Information (Details) - USD ($) $ in Millions	Sep. 30, 2022	Dec. 31, 2021
Supplemental Balance Sheet Information [Line Items]
Compensation-related accruals	$ 395	$ 356
Taxes accrued	401	272
Constellation Energy Generation, LLC
Supplemental Balance Sheet Information [Line Items]
Compensation-related accruals	359	356
Taxes accrued	$ 401	$ 272

Related Party Transactions - Op

Related Party Transactions - Operating Revenues and Purchased Power and Fuel From Affiliates (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021
Related Party Transaction [Line Items]
Total operating revenues from affiliates	$ 0	$ 324	$ 160	$ 872
ComEd
Related Party Transaction [Line Items]
Total operating revenues from affiliates	0	96	58	249
PECO
Related Party Transaction [Line Items]
Total operating revenues from affiliates	0	59	33	142
BGE
Related Party Transaction [Line Items]
Total operating revenues from affiliates	0	65	18	195
PHI
Related Party Transaction [Line Items]
Total operating revenues from affiliates	0	99	51	276
Pepco
Related Party Transaction [Line Items]
Total operating revenues from affiliates	0	69	39	199
DPL
Related Party Transaction [Line Items]
Total operating revenues from affiliates	0	25	10	63
ACE
Related Party Transaction [Line Items]
Total operating revenues from affiliates	0	5	2	14
Other
Related Party Transaction [Line Items]
Total operating revenues from affiliates	$ 0	$ 5	$ 0	$ 10

Related Party Transactions - BS

Related Party Transactions - BSC Service Companies (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021
Related Party Transaction [Line Items]
Operating and maintenance from affiliates	$ 0	$ 177	$ 44	$ 458
Other
Related Party Transaction [Line Items]
Operating and maintenance from affiliates	0	145	44	424
Capitalized costs	$ 0	$ 43	$ 15	$ 76

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

Uncategorized Items - ceg-20220

Label	Element	Value
Noncontrolling Interest, Period Increase (Decrease)	us-gaap_MinorityInterestPeriodIncreaseDecrease	$ (7,000,000)
Shares Issued, Value, Share-Based Payment Arrangement, after Forfeiture	us-gaap_StockIssuedDuringPeriodValueShareBasedCompensation	9,000,000
Dividends, Common Stock	us-gaap_DividendsCommonStock	46,000,000
AOCI Attributable to Parent [Member]
Adjustments to Additional Paid in Capital, Separation From Parent	ceg_AdjustmentsToAdditionalPaidInCapitalSeparationFromParent	(2,006,000,000)
Other Comprehensive Income (Loss), Net of Tax	us-gaap_OtherComprehensiveIncomeLossNetOfTax	21,000,000
Common Stock [Member]
Adjustments, Consummation of Separation	ceg_AdjustmentsConsummationOfSeparation	$ 13,203,000,000
Shares Issued, Shares, Share-Based Payment Arrangement, after Forfeiture	us-gaap_StockIssuedDuringPeriodSharesShareBasedCompensation	35,000,000
Adjustments, Consummation of Separation, Shares Issued	ceg_AdjustmentsConsummationOfSeparationSharesIssued	326,664,000,000
Shares Issued, Value, Share-Based Payment Arrangement, after Forfeiture	us-gaap_StockIssuedDuringPeriodValueShareBasedCompensation	$ 9,000,000
Retained Earnings [Member]
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	us-gaap_ProfitLoss	(45,000,000)
Dividends, Common Stock	us-gaap_DividendsCommonStock	46,000,000
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	5,000,000
Adjustments to Additional Paid in Capital, Separation From Parent	ceg_AdjustmentsToAdditionalPaidInCapitalSeparationFromParent	7,000,000
Predecessor Member's Equity [Member]
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	us-gaap_ProfitLoss	151,000,000	[1]
Adjustments, Consummation of Separation	ceg_AdjustmentsConsummationOfSeparation	(13,203,000,000)	[1]
Adjustments to Additional Paid in Capital, Separation From Parent	ceg_AdjustmentsToAdditionalPaidInCapitalSeparationFromParent	$ 1,802,000,000	[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.