0001868275-23-000014 | 10-K | XBRL Viewer | Constellation Energy Corp

$ 422

$ 504

106

Customer accounts receivable (net of allowance for credit losses of $46 and $55 as of December 31, 2022 and December 31, 2021, respectively)

2,585

1,669

Other accounts receivable (net of allowance for credit losses of $5 as of December 31, 2022 and December 31, 2021)

731

592

2,368

2,169

160

Natural gas, oil, and emission allowances

429

284

1,076

1,004

617

520

1,026

1,007

Property, plant, and equipment (net of accumulated depreciation and amortization of $16,726 and $15,873 as of December 31, 2022 and 2021, respectively)

9,360

7,981

19,822

19,612

14,114

15,938

202

174

1,261

949

1,683

2,106

1,717

17,727

20,493

^[1]

46,909

48,086

1,159

2,082

143

1,220

2,828

1,757

906

737

131

1,558

981

901

777

344

311

7,839

7,996

4,466

4,575

319

3,031

3,703

12,699

12,819

605

609

847

1,230

1,210

3,357

2,897

983

513

1,178

1,133

23,232

23,582

^[1]

35,537

36,472

Predecessor Member's Equity

^[2]

11,250

Common stock (No par value, 1,000 shares authorized, 327 shares outstanding as of December 31, 2022)

13,274

Retained deficit

(496)

Total shareholders’ equity

(1,760)

(31)

11,018

11,219

Noncontrolling interests

354

395

Total equity

11,372

11,614

Constellation Energy Generation, LLC

46,909

48,086

403

504

Customer accounts receivable (net of allowance for credit losses of $46 and $55 as of December 31, 2022 and December 31, 2021, respectively)

2,585

1,669

Other accounts receivable (net of allowance for credit losses of $5 as of December 31, 2022 and December 31, 2021)

718

592

2,368

2,169

160

Natural gas, oil, and emission allowances

429

284

1,076

1,004

617

520

1,026

1,007

Property, plant, and equipment (net of accumulated depreciation and amortization of $16,726 and $15,873 as of December 31, 2022 and 2021, respectively)

9,320

7,981

19,822

19,612

14,114

15,938

202

174

1,261

949

1,683

2,106

1,717

17,727

20,493

^[3]

46,869

48,086

1,159

2,082

143

1,220

2,810

1,757

869

737

131

1,558

981

901

777

344

311

7,829

7,996

4,466

4,575

319

3,031

3,703

12,699

12,819

605

609

847

1,230

1,210

3,357

2,897

983

513

1,106

1,133

23,160

23,582

^[3]

35,455

36,472

Predecessor Member's Equity

12,408

10,482

Retained deficit

412

768

(1,760)

(31)

Variable Interest Entity, Primary Beneficiary

46,869

48,086

Customer accounts receivable (net of allowance for credit losses of $46 and $55 as of December 31, 2022 and December 31, 2021, respectively)

Other accounts receivable (net of allowance for credit losses of $5 as of December 31, 2022 and December 31, 2021)

549

405

Property, plant, and equipment (net of accumulated depreciation and amortization of $16,726 and $15,873 as of December 31, 2022 and 2021, respectively)

687

532

1,965

2,027

190

215

2,842

2,774

102

764

822

940

976

Variable Interest Entity, Primary Beneficiary | Nonrecourse

1,042

1,078

Variable Interest Entity, Primary Beneficiary | Nonrecourse | Constellation Energy Generation, LLC

1,041

1,077

Variable Interest Entity, Primary Beneficiary | Asset Pledged as Collateral

1,041

1,077

Variable Interest Entity, Primary Beneficiary | Asset Pledged as Collateral | Constellation Energy Generation, LLC

2,641

2,549

Beginning Balance (in shares) at Dec. 31, 2019

$ 2,641

$ 2,549

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

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

Consolidated Statement of Changes in Shareholders Equity, Parent - USD ($)
$ in Millions

Total

CENG

Common Stock

Retained Deficit

Accumulated Other Comprehensive Loss, net

Noncontrolling Interests

CENG

Predecessor Member's Equity

^[1]

Predecessor Member's Equity

CENG

^[1]

Beginning Balance at Dec. 31, 2019

$ 15,830

$ 0

$ (32)

$ 2,346

$ 13,516

Increase (Decrease) in Stockholders' Equity [Roll Forward]

Net (loss) income

579

(10)

589

Sale of noncontrolling interest

Changes in equity of noncontrolling interest

(59)

Distribution to member of deferred taxes associated with net retirement benefit obligation

(9)

Distribution to member

(1,734)

Contributions from member

Other comprehensive loss, net of income taxes

Ending Balance (in shares) at Dec. 31, 2020

Ending Balance at Dec. 31, 2020

14,676

$ 0

(30)

2,277

12,429

Increase (Decrease) in Stockholders' Equity [Roll Forward]

Net (loss) income

(83)

122

(205)

Changes in equity of noncontrolling interest

(37)

Acquisition of CENG noncontrolling Interest

$ (885)

$ (1,965)

$ 1,080

Deferred tax adjustment related to acquisition of CENG noncontrolling interest

(288)

Distribution to member

(1,832)

Contributions from member

Acquisition of noncontrolling interest

(2)

Other comprehensive loss, net of income taxes

(1)

Ending Balance (in shares) at Dec. 31, 2021

Ending Balance at Dec. 31, 2021

11,614

$ 0

(31)

395

11,250

Increase (Decrease) in Stockholders' Equity [Roll Forward]

Net (loss) income

(167)

Separation-related adjustments

(197)

(2,006)

1,802

Changes in equity of noncontrolling interest

(34)

Consummation of separation (in shares)

326,664,000,000

Consummation of separation

$ 13,203

(13,203)

Employee incentive plans (in shares)

466,000,000

Employee incentive plans

$ 71

Common stock dividends ($0.14/common share)

(185)

Other comprehensive loss, net of income taxes

$ 277

277

Ending Balance (in shares) at Dec. 31, 2022

327,000,000

327,130,000,000

Ending Balance at Dec. 31, 2022

$ 11,372

$ 13,274

$ (496)

$ (1,760)

$ 354

$ 0

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

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

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

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

Consolidated Balance Sheets - USD ($)
$ in Millions

Dec. 31, 2022

Dec. 31, 2021

$ 422

$ 504

106

Customer accounts receivable (net of allowance for credit losses of $46 and $55 as of December 31, 2022 and December 31, 2021, respectively)

2,585

1,669

Other accounts receivable (net of allowance for credit losses of $5 as of December 31, 2022 and December 31, 2021)

731

592

2,368

2,169

160

Natural gas, oil, and emission allowance

429

284

1,076

1,004

617

520

1,026

1,007

Property, plant, and equipment (net of accumulated depreciation and amortization of $16,726 and $15,873 as of December 31, 2022 and 2021, respectively)

9,360

7,981

19,822

19,612

14,114

15,938

202

174

1,261

949

1,683

2,106

1,717

17,727

20,493

^[1]

46,909

48,086

1,159

2,082

143

1,220

2,828

1,757

906

737

131

1,558

981

Other current liabilities

901

777

344

311

7,839

7,996

4,466

4,575

319

3,031

3,703

12,699

12,819

605

609

847

1,230

1,210

3,357

2,897

983

513

1,178

1,133

23,232

23,582

^[1]

35,537

36,472

Membership interest

^[2]

11,250

Undistributed earnings

(496)

(1,760)

(31)

Variable Interest Entity, Primary Beneficiary

46,909

48,086

Customer accounts receivable (net of allowance for credit losses of $46 and $55 as of December 31, 2022 and December 31, 2021, respectively)

Other accounts receivable (net of allowance for credit losses of $5 as of December 31, 2022 and December 31, 2021)

549

405

Property, plant, and equipment (net of accumulated depreciation and amortization of $16,726 and $15,873 as of December 31, 2022 and 2021, respectively)

687

532

1,965

2,027

190

215

2,842

2,774

Other current liabilities

102

764

822

940

976

Variable Interest Entity, Primary Beneficiary | Nonrecourse

1,042

1,078

Variable Interest Entity, Primary Beneficiary | Asset Pledged as Collateral

1,041

1,077

Constellation Energy Generation, LLC

2,641

2,549

403

504

Customer accounts receivable (net of allowance for credit losses of $46 and $55 as of December 31, 2022 and December 31, 2021, respectively)

2,585

1,669

Other accounts receivable (net of allowance for credit losses of $5 as of December 31, 2022 and December 31, 2021)

718

592

2,368

2,169

160

Natural gas, oil, and emission allowance

429

284

1,076

1,004

617

520

1,026

1,007

Property, plant, and equipment (net of accumulated depreciation and amortization of $16,726 and $15,873 as of December 31, 2022 and 2021, respectively)

9,320

7,981

19,822

19,612

14,114

15,938

202

174

1,261

949

1,683

2,106

1,717

17,727

20,493

^[3]

46,869

48,086

1,159

2,082

143

1,220

2,810

1,757

869

737

131

1,558

981

Other current liabilities

901

777

344

311

7,829

7,996

4,466

4,575

319

3,031

3,703

12,699

12,819

605

609

847

1,230

1,210

3,357

2,897

983

513

1,106

1,133

23,160

23,582

^[3]

35,455

36,472

Membership interest

12,408

10,482

Undistributed earnings

412

768

(1,760)

(31)

Total member’s equity

11,060

11,219

Noncontrolling interests

354

395

Total equity

11,414

11,614

Constellation Energy Generation, LLC | Variable Interest Entity, Primary Beneficiary | Nonrecourse

46,869

48,086

Constellation Energy Generation, LLC | Variable Interest Entity, Primary Beneficiary | Asset Pledged as Collateral

1,041

1,077

Mergers, Acquisitions, and Dispositions [Abstract]

$ 2,641

$ 2,549

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

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

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

Basis of Presentation	12 Months Ended
Basis of Presentation	Dec. 31, 2022
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation Description of Business We are a producer of clean energy and a supplier of energy products and services. Our generating capacity includes primarily nuclear, wind, solar, natural gas and hydroelectric assets. Through our integrated business operations, we sell electricity, natural gas, and other energy-related products and sustainable solutions to various types of customers, including distribution utilities, municipalities, cooperatives, and commercial, industrial, governmental, and residential customers in markets across multiple geographic regions. We have five reportable segments: Mid-Atlantic, Midwest, New York, ERCOT and Other Power Regions. Basis of Presentation On February 21, 2021, the Board of Directors of Exelon authorized management to pursue a plan to separate its competitive generation and customer-facing energy businesses, conducted through Constellation Energy Generation, LLC (“Constellation”, formerly Exelon Generation Company, LLC) and its subsidiaries, into an independent, publicly-traded company. CEG Parent, a direct, wholly owned subsidiary of Exelon, was newly formed for the purpose of separation and had not engaged in any business activities nor had any assets or liabilities prior to the separation. On February 1, 2022, the separation was completed and CEG Parent holds all the interests in Constellation previously held by Exelon. As an individual registrant, Constellation has historically filed consolidated financial statements to reflect its financial position and operating results as a stand-alone, wholly owned subsidiary of Exelon. The accompanying Consolidated Financial Statements have been prepared in accordance with GAAP for annual financial statements and in accordance with the instructions to Form 10-K and Regulation S-X promulgated by the SEC. The Consolidated Financial Statements include the accounts of our subsidiaries and all intercompany transactions have been eliminated. CEG Parent's prior period financial statements have been adjusted to reflect the balances of Constellation in accordance with applicable guidance. Amounts disclosed relate to CEG Parent and Constellation unless specifically noted as relating to CEG Parent only. Unless otherwise indicated or the context otherwise requires, references herein to the terms “we,” “us,” and “our” refer collectively to CEG Parent and Constellation. We own 100% of our significant consolidated subsidiaries, either directly or indirectly, except for certain consolidated VIEs, including CRP, of which we hold a 51% interest. The remaining interests in the consolidated VIEs are included in noncontrolling interests on the Consolidated Balance Sheets. See Note 22 — Variable Interest Entities for additional information on consolidated VIEs. We consolidate the accounts of entities in which we have a controlling financial interest, after the elimination of intercompany transactions. Where we do not have a controlling financial interest in an entity, proportionate consolidation, equity method accounting or accounting for investments in equity securities with or without readily determinable fair value is applied. We apply proportionate consolidation when we have an undivided interest in an asset and are proportionately liable for our share of each liability associated with the asset. We proportionately consolidate our undivided ownership interest in jointly owned electric plants. Under proportionate consolidation, we separately record our proportionate share of the assets, liabilities, revenues and expenses related to the undivided interest in the asset. We apply equity method accounting when we have a significant influence over an investee through an ownership in equity, which generally approximates a 20% to 50% voting interest. We apply equity method accounting to certain investments and joint ventures. Under equity method accounting, we report our interest in the entity as an investment and our percentage share of the earnings from the entity as single line items in our consolidated financial statements. We use accounting for investments in equity securities with or without readily determinable fair values if we lack a significant influence, which generally results when we hold less than 20% of the common stock of an entity. Under accounting for investments in equity securities with readily determinable fair values, the investments are reported based on quoted prices in active markets and realized and unrealized gains and losses are included in earnings. Under accounting for investments in equity securities without readily determinable fair values, the investments are reported at cost adjusted for changes from observable transactions for identical or similar investments of the same issuer, less impairment, and changes in measurement are reported in earnings. Separation from Exelon On February 1, 2022, Exelon completed the separation through a pro-rata distribution of all of the outstanding shares of our common stock, no par value, on the basis of one such share for every three shares of Exelon common stock held on January 20, 2022, the record date of the distribution. We are an independent, publicly traded company listed on the Nasdaq Stock Market under the symbol “CEG”, and regular-way trading began on February 2, 2022. Exelon no longer retains any ownership interest in CEG Parent or Constellation. Prior to completion of the separation, our financial statements include certain transactions with affiliates of Exelon, which are disclosed as related party transactions. After February 1, 2022, all transactions with Exelon or its affiliates are no longer related party transactions. In order to govern the ongoing relationships with Exelon after the separation, and to facilitate an orderly transition, we entered into several agreements with Exelon, including the following: •Separation Agreement – sets forth the principal actions to be taken in connection with the separation, including the transfer of assets and assumption of liabilities and establishes certain rights and obligations between us following the distribution • Transition Services Agreement (TSA) – governs all matters relating to the provision of services between us and Exelon on a transitional basis, in addition to providing us with certain services for an expected period of two-years, provided that certain services may be longer than the term and services may be extended with approval from both parties; the services include support for information technology, accounting, finance, human resources, security, and various other administrative and operational services • Employee Matters Agreement (EMA) – addresses certain employment, compensation and benefits matters, including the allocation of employees between us and Exelon and the allocation and treatment of certain assets and liabilities relating to our employees and former employees • Tax Matters Agreement (TMA) - governs the respective rights, responsibilities, and obligations between us and Exelon with respect to all tax matters (excluding employee-related taxes covered under EMA), in addition to certain restrictions which generally prohibit us from taking or failing to take any action in the two-year period following the distribution that would prevent the distribution from qualifying as tax-free for U.S. federal income tax purposes, including limitations on our ability to pursue certain equity issuances, strategic transactions, repurchases or other transactions Pursuant to the Separation Agreement, we received a cash contribution of $1.75 billion from Exelon on January 31, 2022, the proceeds of which were used to settle $258 million of an intercompany loan from Exelon and $200 million of short-term debt outstanding prior to separation, in addition to a $192 million contribution to our pension plans. We also entered into two new five-year credit facility agreements providing $4.5 billion of capacity. See Note 17 — Debt and Credit Agreements for additional information on these facility agreements. Beginning on February 1, 2022, the amounts Exelon billed us for services pursuant to the TSA were $266 million for the year ended December 31, 2022, and the amounts we billed Exelon for services pursuant to the TSA were $43 million for the year ended December 31, 2022. Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Areas in which significant estimates have been made include, but are not limited to, the accounting for nuclear decommissioning costs and other AROs, pension and OPEB plans, inventory reserves, allowance for credit losses, long-lived asset impairment assessments, derivative instruments, unamortized energy contracts, fixed asset depreciation, environmental costs and other loss contingencies, taxes and unbilled energy revenues. Actual results could differ from those estimates. Revenues Operating Revenues. Our operating revenues generally consist of revenues from contracts with customers involving the sale and delivery of energy commodities and related products and services and realized and unrealized revenues recognized under mark-to-market energy commodity derivative contracts. We recognize revenue from contracts with customers to depict the transfer of goods or services to customers in an amount that we expect to be entitled to in exchange for those goods or services. Our primary source of revenue includes competitive sales of power, natural gas, and other energy-related products and services. At the end of each reporting period, we accrue an estimate for the unbilled amount of energy delivered or services provided to customers. Option Contracts, Swaps and Commodity Derivatives. Certain option contracts and swap arrangements that meet the definition of derivative instruments are recorded at fair value with subsequent changes in fair value recognized as revenue or expense. The classification of revenue or expense is based on the intent of the transaction. See Note 16 — Derivative Financial Instruments for additional information. Taxes Directly Imposed on Revenue-Producing Transactions. We collect certain taxes from customers such as sales and gross receipts taxes, along with other taxes, surcharges and fees, that are levied by state or local governments on the sale or distribution of electricity and natural gas. Some of these taxes are imposed on the customer, but paid by us, while others are imposed on us. Where these taxes are imposed on the customer, such as sales taxes, they are reported on a net basis in revenues. However, where these taxes are imposed on us, such as gross receipts taxes, they are reported on a gross basis. Accordingly, revenues are recognized for the taxes collected from customers along with an offsetting expense. See Note 23 — Supplemental Financial Information for the taxes that are presented on a gross basis. Leases We recognize a ROU asset and lease liability for operating leases with a term of greater than one year. Operating lease ROU assets are included in Other deferred debits and other assets and operating lease liabilities are included in Other current liabilities and Other deferred credits and other liabilities on the Consolidated Balance Sheets. The ROU asset is measured as the sum of (1) the present value of all remaining fixed and in-substance fixed payments using the rate implicit in the lease whenever that is readily determinable or our incremental borrowing rate, (2) any lease payments made at or before the commencement date (less any lease incentives received) and (3) any initial direct costs incurred. The lease liability is measured the same as the ROU asset, but excludes any payments made before the commencement date and initial direct costs incurred. Lease terms include options to extend or terminate the lease if it is reasonably certain they will be exercised. We include non-lease components for most asset classes, which are service-related costs that are not integral to the use of the asset, in the measurement of the ROU asset and lease liability. Expense for operating leases and leases with a term of one year or less is recognized on a straight-line basis over the term of the lease, unless another systematic and rational basis is more representative of the derivation of benefit from use of the leased property. Variable lease payments are recognized in the period in which the related obligation is incurred and consist primarily of payments for purchases of electricity under contracted generation that are based on the electricity produced by those generating assets. Operating lease expense and variable lease payments are recorded to Purchased power and fuel expense for contracted generation or Operating and maintenance expense for all other lease agreements in the Consolidated Statements of Operations and Comprehensive Income. Income from operating leases, including subleases, is recognized on a straight-line basis over the term of the lease, unless another systematic and rational basis is more representative of the pattern in which income is earned over the term of the lease. Variable lease payments are recognized in the period in which the related obligation is performed and consist primarily of payments received from sales of electricity under contracted generation that are based on the electricity produced by those generating assets. Operating lease income and variable lease payments are recorded to Operating revenues in the Consolidated Statements of Operations and Comprehensive Income. Our operating leases consist primarily of contracted generation, real estate including office buildings, and vehicles and equipment. We generally account for contracted generation in which the generating asset is not renewable as a lease if the customer has dispatch rights and obtains substantially all the economic benefits. We generally do not account for contracted generation in which the generating asset is renewable as a lease if the customer does not design the generating asset. We account for land right arrangements that provide for exclusive use as leases while shared use land arrangements are generally not leases. See Note 11 — Leases for additional information. Income Taxes Deferred federal and state income taxes are recorded on temporary differences between the book and tax basis of assets and liabilities and for tax benefits carried forward. ITCs have been deferred in the Consolidated Balance Sheets and are recognized in book income over the life of the related property. We account for uncertain income tax positions using a benefit recognition model with a two-step approach; a more-likely-than-not recognition criterion; and a measurement approach that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. If it is not more-likely-than-not that the benefit of the tax position will be sustained on its technical merits, no benefit is recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. We recognize accrued interest related to unrecognized tax benefits in Interest expense, net or Other, net (interest income) and recognize penalties related to unrecognized tax benefits in Other, net in the Consolidated Statements of Operations and Comprehensive Income. Cash and Cash Equivalents We consider investments purchased with an original maturity of three months or less to be cash equivalents. Restricted Cash and Cash Equivalents Restricted cash and cash equivalents represent funds that are restricted to satisfy designated current liabilities. As of December 31, 2022 and 2021, restricted cash and cash equivalents primarily represented the payment of medical, dental, vision, and long-term disability benefits and project-specific nonrecourse financing structures for debt service and financing of operations of the underlying entities. See Note 17 — Debt and Credit Agreements and Note 23 — Supplemental Financial Information for additional information. Allowance for Credit Losses on Accounts Receivables The allowance for credit losses reflects our best estimate of losses on the customers' accounts receivable balances based on historical experience, current information, and reasonable and supportable forecasts. The allowance for credit losses for our retail customers is based on accounts receivable aging historical experience coupled with specific identification through a credit monitoring process, which considers current conditions and forward-looking information such as industry trends, macroeconomic factors, changes in the regulatory environment, external credit ratings, publicly available news, payment status, payment history, and the exercise of collateral calls. The allowance for credit losses for our wholesale customers is developed using a credit monitoring process, like that used for retail customers. When a wholesale customer’s risk characteristics are no longer aligned with the pooled population, we use specific identification to develop an allowance for credit losses. Adjustments to the allowance for credit losses are recorded in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. We have certain non-customer receivables in Other deferred debits and other assets which primarily are with governmental agencies and other high-quality counterparties. As such, the allowance for credit losses related to these receivables is not material. We monitor these balances and will record an allowance if there are indicators of a decline in credit quality. Variable Interest Entities We account for our investments in and arrangements with VIEs based on the following specific requirements: •qualitative assessment of factors determinant in whether we have a controlling financial interest, •ongoing reconsideration of this assessment, and •where we consolidate a VIE (as primary beneficiary), disclosure of (1) the assets of the consolidated VIE, if they can be used to only settle specific obligations of the consolidated VIE, and (2) the liabilities of a consolidated VIE for which creditors do not have recourse to the general credit of the primary beneficiary. See Note 22 — Variable Interest Entities for additional information. Inventories Inventory is recorded at the lower of weighted average cost or net realizable value. Provisions are recorded for excess and obsolete inventory. Natural gas, oil, materials and supplies, and emissions allowances are generally included in inventory when purchased. Natural gas, oil, and emissions allowances are expensed to Purchased power and fuel expense. Materials and supplies generally include items utilized within our generating plants and are expensed to Operating and maintenance or capitalized to Property, plant and equipment, as appropriate, when installed or used. Debt and Equity Security Investments Debt and Equity Investments within NDT funds. We have debt and equity securities held in our NDT funds which are measured and recorded at fair value. Realized and unrealized gains and losses, net of tax, on our NDT funds associated with the Regulatory Agreement Units are included in Noncurrent payables related to Regulatory Agreement Units. Realized and unrealized gains and losses, net of tax, on our NDT funds associated with the Non-Regulatory Agreement Units are included in Other, net in the Consolidated Statements of Operations and Comprehensive Income. For equity securities without readily determinable fair values, we have elected to use the measurement alternative to measure these investments, defined as cost adjusted for changes from observable transactions for identical or similar investments of the same issuer, less impairment. Our NDT funds are classified as current or noncurrent assets, depending on the timing of the decommissioning activities and income taxes on trust earnings. See Note 18 — Fair Value of Financial Assets and Liabilities and Note 10 — Asset Retirement Obligations for additional information. Equity Security Investments without Readily Determinable Fair Values. We have certain equity securities without readily determinable fair values. We have elected to use the measurement alternative to measure these investments, defined as cost adjusted for changes from observable transactions for identical or similar investments of the same issuer, less impairment. Changes in measurement are reported in Other, net in the Consolidated Statements of Operations and Comprehensive Income. See Note 18 — Fair Value of Financial Assets for additional information. Equity Security Investments with Readily Determinable Fair Values. We have certain equity securities with readily determinable fair values. Realized and unrealized gains and losses are included in Other, net in the Consolidated Statements of Operations and Comprehensive Income. See Note 18 — Fair Value of Financial Assets and Liabilities for additional information. Property, Plant and Equipment Property, plant and equipment is recorded at original cost. Original cost includes construction-related direct labor and material costs. When appropriate, original cost also includes capitalized interest. Costs associated with nuclear outages and planned major maintenance activities, are expensed to Operating and maintenance expense or capitalized to Property, plant, and equipment based on the nature of the activities in the period incurred. The cost of repairs and maintenance and minor replacements of property, is charged to Operating and maintenance expense as incurred. Upon retirement, the cost of property is generally charged to accumulated depreciation in accordance with the composite and group methods of depreciation. Upon replacement of an asset, the costs to remove the asset, net of salvage, are capitalized to gross plant when incurred as part of the cost of the newly-installed asset and recorded to depreciation expense over the life of the new asset. Removal costs, net of salvage, incurred for property that will not be replaced is charged to Operating and maintenance expense as incurred. Certain assets follow the unitary method of depreciation and recognize gains and losses in the period of replacement or retirement. These gains and losses are recorded in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. Capitalized Software. Certain costs, such as design, coding, and testing incurred during the application development stage of software projects that are internally developed or purchased for operational use are capitalized in Property, plant and equipment in the Consolidated Balance Sheets. Similar costs incurred for cloud-based solutions treated as service arrangements are capitalized in Other current assets and Deferred debits and other assets in the Consolidated Balance Sheets. Such capitalized amounts are amortized ratably over the expected lives of the projects when they become operational, generally not to exceed five years. Certain other capitalized software costs are being amortized over longer lives based on the expected life. Capitalized Interest. During construction, we capitalize the costs of debt funds. Most projects will use a debt rate calculated using the general corporate debt pool. In some cases, projects are specifically financed and use a project specific debt rate, which is excluded from the general corporate debt pool. Capitalization of debt funds is recorded as a charge to construction work in progress and as a non-cash credit to interest expense. See Note 8 — Property, Plant, and Equipment, Note 9 — Jointly Owned Electric Utility Plant and Note 23 — Supplemental Financial Information for additional information. Nuclear Fuel The cost of nuclear fuel is capitalized in Property, plant and equipment and charged to Purchased power and fuel using the unit-of-production method. Any potential future SNF disposal fees will also be expensed through Purchased power and fuel expense. Additionally, certain on-site SNF storage costs are being reimbursed by the DOE since a DOE (or government-owned) long-term storage facility has not been completed. See Note 19 — Commitments and Contingencies for additional information regarding the cost of SNF storage and disposal. Depreciation and Amortization Except for the amortization of nuclear fuel, depreciation, inclusive of ARC, is generally recorded over the estimated service lives of property, plant and equipment on a straight-line basis using the group, composite or unitary methods of depreciation. The group approach is typically for groups of similar assets that have approximately the same useful lives and the composite approach is used for dissimilar assets that have different lives. Under both methods, a reporting entity depreciates the assets over the average life of the assets in the group. The estimated service lives are based on a combination of depreciation studies, historical retirements, site licenses and management estimates of operating costs and expected future energy market conditions. See Note 7 — Early Plant Retirements for additional information on the impacts of early plant retirements, Note 8 — Property, Plant, and Equipment for additional information regarding depreciation, and Note 23 — Supplemental Financial Information for additional information regarding nuclear fuel. Asset Retirement Obligations We estimate and recognize a liability for our legal obligation to perform asset retirement activities even though the timing and/or methods of settlement may be conditional on future events. We generally update our nuclear decommissioning ARO annually, unless circumstances warrant more frequent updates, based on our annual evaluation of cost escalation factors and probabilities assigned to the multiple outcome scenarios within our probability-weighted discounted cash flow models. Our multiple outcome scenarios are generally based on decommissioning cost studies which are updated, on a rotational basis, for each of our nuclear units at least every five years, unless circumstances warrant more frequent updates. AROs are accreted throughout each year to reflect the time value of money for these present value obligations through a charge to Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income for Non-Regulatory Agreement Units and through a decrease in noncurrent payables related to Regulatory Agreement Units. See Note 10 — Asset Retirement Obligations for additional information. Accounting Implications of the Regulatory Agreement Units with ComEd and PECO Based on the regulatory agreements with the ICC and PAPUC that dictate our obligations related to the shortfall or excess of NDT funds necessary for decommissioning the former ComEd units on a unit-by-unit basis and the former PECO units in total, decommissioning-related activities net of applicable taxes, including realized and unrealized gains and losses on the NDT funds, depreciation of the ARC, and accretion of the decommissioning obligation are generally offset in the Consolidated Statements of Operations and Comprehensive Income and are recorded as noncurrent payables in the Consolidated Balance Sheets (within Payables related to Regulatory Agreement Units). See Note 10 — Asset Retirement Obligations for additional information. Asset Impairments Long-Lived Assets. We regularly monitor and evaluate the carrying value of long-lived assets or asset groups for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the asset, or plans to dispose of a long-lived asset significantly before the end of its useful life. We determine if long-lived assets or asset groups are potentially impaired by comparing the undiscounted expected future cash flows to the carrying value when indicators of impairment exist. When the undiscounted cash flow analysis indicates a long-lived asset or asset group may not be recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. Generally, pre-tax impairment losses are recorded in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. See Note 12 — Asset Impairments for additional information. Equity Method Investments. We regularly monitor and evaluate equity method investments to determine whether they are impaired. An impairment is recorded when the investment has experienced a decline in value that is other-than-temporary in nature. Additionally, if the entity in which we hold an investment recognizes an impairment loss, we would record their proportionate share of that impairment loss and evaluate the investment for an other-than-temporary decline in value. These impairment losses are recorded in Equity in (losses) earnings of unconsolidated affiliates in the Consolidated Statements of Operations and Comprehensive Income. Equity Security Investments. Equity investments with readily determinable fair values are measured and recorded at fair value with any changes in fair value recorded in Other, net in the Consolidated Statements of Operations and Comprehensive Income. Investments in equity securities without readily determinable fair values are qualitatively assessed for impairment each reporting period. If it is determined that the equity security is impaired, an impairment loss will be recognized in Other, net in the Consolidated Statements of Operations and Comprehensive Income to the amount by which the security’s carrying amount exceeds its fair value. Derivative Financial Instruments All derivatives are recognized on the balance sheet at their fair value unless they qualify for certain exceptions, including NPNS. For derivatives intended to serve as economic hedges, changes in fair value are recognized in earnings each period. Amounts classified in earnings are included in Operating revenues, Purchased power and fuel, or Interest expense in the Consolidated Statements of Operations and Comprehensive Income based on the activity the transaction is economically hedging. While most of the derivatives serve as economic hedges, there are also derivatives entered into for proprietary trading purposes, subject to our RMP, and changes in the fair value of those derivatives are recorded in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income. Cash inflows and outflows related to derivative instruments are included as a component of operating, investing, or financing cash flows in the Consolidated Statements of Cash Flows, depending on the nature of each transaction. As part of the energy marketing business, we enter contracts to buy and sell energy to meet the requirements of our customers. These contracts include short-term and long-term commitments to purchase and sell energy and energy-related products in the energy markets with the intent and ability to deliver or take delivery of the underlying physical commodity. NPNS are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period and will not be financially settled. Revenues and expenses on derivative contracts that qualify, and are designated, as NPNS are recognized when the underlying physical transaction is completed. While these contracts are considered derivative financial instruments, they are not required to be recorded at fair value. See Note 16 — Derivative Financial Instruments for additional information. Retirement Benefits Prior to separation, Exelon sponsored defined benefit pension plans and OPEB plans as described in Note 15 — Retirement Benefits . The plan obligations and costs of providing benefits under these plans were measured as of December 31, 2021. We accounted for our participation in Exelon’s pension and OPEB plans by applying multi-employer accounting. Exelon allocated costs related to its pension and OPEB plans to its subsidiaries based on both active and retired employee participation in each plan. We included the service cost and non- service cost components in Operating and maintenance expense and Property, plant, and equipment, net in the consolidated financial statements. Effective upon separation, we sponsor defined benefit pension and OPEB plans as described in Note 15 — Retirement Benefits. The plan obligations and costs of providing benefits under these plans were measured upon separation as of February 1, 2022 and remeasured as of December 31, 2022. The measurement involved various factors, assumptions, and accounting elections. The impact of assumption changes or experience different from that assumed on pension and OPEB obligations is recognized over time rather than immediately recognized in the Consolidated Statements of Operations and Comprehensive Income. Gains or losses more than the greater of ten percent of the PBO or the MRV of plan assets are amortized over the expected average remaining service period of plan participants. Gains or losses more than the greater of ten percent of the APBO or the MRV of plan assets are amortized over the average future remaining lifetime of the current inactive population for the OPEB plans. We report the pension and OPEB service cost and non-service cost (credit) components of net periodic benefit costs (credits) for all plans separately in our Consolidated Statements of Operations and Comprehensive Income. Effective February 1, 2022, the service cost component continues to be included in Operating and maintenance expense and Property, plant, and equipment, net (where criteria for capitalization of direct labor has been met) while the non-service cost (credit) components are included in Other, net, in accordance with single employer plan accounting.

Mergers, Acquisitions, and Dispositions

12 Months Ended

Dec. 31, 2022

Mergers, Acquisitions, and Dispositions

CENG Put Option

Prior to August 6, 2021, we owned a 50.01% membership interest in CENG, a joint venture with EDF, which wholly owned the Calvert Cliffs and Ginna nuclear stations and Nine Mile Point Unit 1, in addition to an 82% undivided ownership interest in Nine Mile Point Unit 2. CENG is 100% consolidated in our financial statements.

On April 1, 2014, we entered into various agreements with EDF including a NOSA, an amended LLC Operating Agreement, an Employee Matters Agreement, and a Put Option Agreement, among others. Under the amended LLC Operating Agreement, CENG made a $400 million special distribution to EDF and committed to make preferred distributions to us until we had received aggregate distributions of $400 million plus a return of 8.50% per annum.

Under the terms of the Put Option Agreement, EDF had the option to sell its 49.99% equity interest in CENG exercisable beginning on January 1, 2016 and thereafter until June 30, 2022. On November 20, 2019, we received notice of EDF’s intention to exercise the put option, and the put automatically exercised on January 19, 2020 at the end of the sixty-day advance notice period. The transaction required approval by FERC and the NYPSC, which approvals were received on July 30, 2020 and April 15, 2021, respectively. On August 6, 2021, we entered into a settlement agreement pursuant to which we purchased EDF's equity interest in CENG for a net purchase price of $885 million, which included, among other things, an adjustment for EDF's share of the outstanding balance of the preferred distribution payable to us by CENG. The difference between the net purchase price and EDF's noncontrolling interest as of August 6, 2021 was recorded to Membership interest in the Consolidated Balance Sheet. As a result of the transaction, we also recorded deferred tax liabilities of $288 million in Membership interest in the Consolidated Balance Sheet. See Note 14 — Income Taxes for additional information.

The following table summarizes the effects of the changes in our ownership interest in CENG in Member's Equity:


	For the Year Ended December 31, 2021
Net loss attributable to membership interest	$	(205)
Pre-tax increase in membership interest for purchase of EDF's 49.99% equity interest(a)	1,080
Decrease in membership interest due to deferred tax liabilities resulting from purchase of EDF's equity interest(a)	(288)
Change from net loss attributable to membership interest and transfers from noncontrolling interest	$	587

__________

(a)Represents non-cash activity in the consolidated financial statements.

Agreement for Sale of Our Solar Business

On December 8, 2020, we entered into an agreement with an affiliate of Brookfield Renewable, for the sale of a significant portion of our solar business, including 360 MWs of generation in operation or under construction across more than 600 sites across the United States. We retained certain solar assets not included in this agreement, primarily Antelope Valley.

Completion of the transaction contemplated by the sale agreement was subject to the satisfaction of several closing conditions that were satisfied in the first quarter of 2021. The sale was completed on March 31, 2021 for a purchase price of $810 million. We received cash proceeds of $675 million, net of $125 million long-term debt assumed by the buyer and certain working capital and other post-closing adjustments. We recognized a pre-tax gain of $68 million which is included in Gain on sales of assets and businesses in the Consolidated Statement of Operations and Comprehensive Income.

Agreement for Sale of Our Biomass Facility

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 Statement of Operations and Comprehensive Income. Completion of the transaction was subject to the satisfaction of various customary closing conditions that were satisfied in the second quarter of 2021. The sale was completed on June 30, 2021 for a net purchase price of $36 million.

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

Revenue from Contracts with Customers

12 Months Ended

Dec. 31, 2022

Revenue from Contract with Customer [Abstract]

Revenue from Contracts with Customers

We recognize revenue from contracts with customers to depict the transfer of goods or services to customers at an amount that we expect to be entitled to in exchange for those goods or services. Our primary sources of revenue include competitive sales of power, natural gas, and other energy-related products and services. The performance obligations, revenue recognition, and payment terms associated with these sources of revenue are further discussed in the table below. There are no significant financing components for these sources of revenue.

Unless otherwise noted, for each of the significant revenue categories and related performance obligations described below, we have the right to consideration from the customer in an amount that corresponds directly with the value transferred to the customer for the performance completed to date. Therefore, we generally recognize revenue in the amount for which we have the right to invoice the customer. As a result, there are generally no significant judgments used in determining or allocating the transaction price.

Revenue Source

Description

Performance Obligation

Timing of Revenue Recognition

Payment Terms

Competitive Power Sales

Sales of power and other energy-related commodities to wholesale and retail customers across multiple geographic regions through our customer-facing business.

Various, including the delivery of power (generally delivered over time) and other energy-related commodities such as capacity (generally delivered over time), CMCs, ZECs, RECs or other ancillary services (generally delivered at a point in time).

Concurrently as power is generated for bundled power sale contracts. (a)

Within the month following delivery to the customer.

Competitive Natural Gas Sales

Sales of natural gas on a full requirement basis or for an agreed upon volume to commercial and residential customers.

Delivery of natural gas to the customer.

Over time as the natural gas is delivered to the customer.

Within the month following delivery to the customer.

Other Competitive Products and Services

Sales of other energy-related products and services such as long-term construction and installation of energy efficiency assets and new power generating facilities, primarily to commercial and industrial customers.

Construction and/or installation of the asset for the customer.

Revenues and associated costs are recognized throughout the contract term using an input method to measure progress towards completion.(b)

Within 30 or 45 days from the invoice date.

__________

(a)Certain contracts may contain limits on the total amount of revenue we are able to collect over the entire term of the contract. In such cases, we estimate the total consideration expected to be received over the term of the contract net of the constraint and allocate the expected consideration to the performance obligations in the contract such that revenue is recognized ratably over the term of the entire contract as the performance obligations are satisfied.

(b)The method recognizes revenue based on the various inputs used to satisfy the performance obligation, such as costs incurred and total labor hours expended. The total amount of revenue that will be recognized is based on the agreed upon contractually-stated amount. The average contract term for these projects is approximately 18 months.

We incur incremental costs in order to execute certain retail power and gas sales contracts. These costs, which primarily relate to retail broker fees and sales commissions, are capitalized when incurred as contract acquisition costs and were not material as of December 31, 2022 and 2021.

Contract Balances

Contract Assets

We record contract assets for the revenue recognized on the construction and installation of energy efficiency assets and new power generating facilities before we have an unconditional right to bill for and receive the consideration from the customer. These contract assets are subsequently reclassified to receivables when the right to payment becomes unconditional. We record contract assets and contract receivables in Other current assets and Customer accounts receivable, net, respectively, in the Consolidated Balance Sheets.

The following table provides a rollforward of the contract assets reflected in the Consolidated Balance Sheets:


	Contract Assets
Balance as of December 31, 2020	$	144
Amounts reclassified to receivables	(59)
Revenues recognized	52
Amounts previously held-for-sale	12
Balance as of December 31, 2021	149
Amounts reclassified to receivables	(81)
Revenues recognized	62

Balance as of December 31, 2022	$	130

Contract Liabilities

We record contract liabilities when consideration is received or due prior to the satisfaction of the performance obligations. We record contract liabilities in Other current liabilities and Other deferred credits and other liabilities in the Consolidated Balance Sheets. These contract liabilities primarily relate to upfront consideration received or due for equipment service plans and the Illinois ZEC program that introduces an annual cap on the total consideration to be received by us for each delivery period. The ZEC price is established on a per MWh of production basis with a maximum annual cap for total compensation to be received in a delivery period, while requiring delivery of all ZECs produced by our participating facilities during each delivery period. ZECs delivered to Illinois utilities in excess of the annual cost cap may be paid in subsequent years if the payments do not exceed the prescribed annual cost cap for that year.

The following table provides a rollforward of the contract liabilities reflected in the Consolidated Balance Sheets:


	Contract Liabilities
Balance as of December 31, 2019	$	71
Consideration received or due	282
Revenues recognized	(266)
Contracts liabilities reclassified as held for sale	(3)
Balance as of December 31, 2020	84
Consideration received or due	251
Revenues recognized	(263)
Amounts previously held-for-sale	3
Balance as of December 31, 2021	75
Consideration received or due	339
Revenues recognized	(367)

Balance as of December 31, 2022	$	47

The following table reflects revenues recognized in the years ended December 31, 2022, 2021 and 2020, which were included in contract liabilities at December 31, 2021, 2020, and 2019, respectively:


	2022		2021		2020
Revenues recognized	$	71	$	82	$	64

Transaction Price Allocated to Remaining Performance Obligations

The following table shows the amounts of future revenues expected to be recorded in each year for performance obligations that are unsatisfied or partially unsatisfied as of December 31, 2022. This disclosure only includes contracts for which the total consideration is fixed and determinable at contract inception. The average contract term varies by customer type and commodity but ranges from one month to several years. This disclosure excludes our power and gas sales contracts as they contain variable volumes and/or variable pricing.


	2023		2024		2025		2026		2027 and thereafter		Total
Remaining performance obligations	$	221	$	78	$	35	$	15	$	136	$	485

Revenue Disaggregation

We disaggregate the revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. See Note 5 — Segment Information for the presentation of revenue disaggregation.

The entire disclosure of revenue from contract with customer to transfer good or service and to transfer nonfinancial asset. Includes, but is not limited to, disaggregation of revenue, credit loss recognized from contract with customer, judgment and change in judgment related to contract with customer, and asset recognized from cost incurred to obtain or fulfill contract with customer. Excludes insurance and lease contracts.

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Segment Information

12 Months Ended

Dec. 31, 2022

Segment Reporting [Abstract]

Segment Information

Operating segments are determined based on information used by the CODM in deciding how to evaluate performance and allocate resources. We have five reportable segments consisting of the Mid-Atlantic, Midwest, New York, ERCOT, and all other power regions referred to collectively as “Other Power Regions.”

The basis for our reportable segments is the integrated management of our electricity business that is located in different geographic regions, and largely representative of the footprints of ISO/RTO and/or NERC regions, which utilize multiple supply sources to provide electricity through various distribution channels (wholesale and retail). Our hedging strategies and risk metrics are also aligned to these same geographic regions. Descriptions of each of our five reportable segments are as follows:

•Mid-Atlantic represents operations in the eastern half of PJM, which includes New Jersey, Maryland, Virginia, West Virginia, Delaware, the District of Columbia, and parts of Pennsylvania and North Carolina.

•Midwest represents operations in the western half of PJM and the United States footprint of MISO, excluding MISO’s Southern Region.

•New York represents operations within NYISO.

•ERCOT represents operations within Electric Reliability Council of Texas that covers a majority of the state of Texas.

•Other Power Regions:

•New England represents operations within ISO-NE.

•South represents operations in FRCC, MISO’s Southern Region, and the remaining portions of SERC not included within MISO or PJM.

•West represents operations in WECC, which includes CAISO.

•Canada represents operations across the entire country of Canada and includes AESO, OIESO, and the Canadian portion of MISO.

The CODM evaluates the performance of our electric business activities and allocates resources based on Operating revenues less Purchased power and fuel expense (RNF). We believe this is a useful measurement of

operational performance, although it is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report. Our operating revenues include all sales to third parties and affiliated sales to Exelon's utility subsidiaries, prior to the separation. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy, and ancillary services. Fuel expense includes the fuel costs for our owned generation and fuel costs associated with tolling agreements. The results of our other business activities are not regularly reviewed by the CODM and are therefore not classified as operating segments or included in the regional reportable segment amounts. These activities include wholesale and retail sales of natural gas, as well as other miscellaneous business activities that are not significant to our overall results of operations. Further, our unrealized mark-to-market gains and losses on economic hedging activities and our amortization of certain intangible assets and liabilities relating to commodity contracts recorded at fair value from mergers and acquisitions are also excluded from the regional reportable segment amounts. The CODM does not use a measure of total assets in making decisions regarding allocating resources to or assessing the performance of these reportable segments.

The following tables disaggregate the revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. The disaggregation of revenues reflects our two primary products of power sales and natural gas sales, with further disaggregation of power sales provided by geographic region. The following tables also show the reconciliation of reportable segment revenues and RNF to our total revenues and RNF for the years ended December 31, 2022, 2021, and 2020.


	2022
	Revenues from external customers(a)
	Contracts with customers		Other(b)		Total		Intersegment Revenues		Total Revenues
Mid-Atlantic	$	5,264	$	(105)	$	5,159	$	5	$	5,164
Midwest	5,164		(507)		4,657		(7)		4,650
New York	2,004		(408)		1,596		(1)		1,595
ERCOT	954		602		1,556		(13)		1,543
Other Power Regions	5,035		1,681		6,716		16		6,732
Total Competitive Businesses Electric Revenues	$	18,421	$	1,263	$	19,684	$	—	$	19,684
Competitive Businesses Natural Gas Revenues	2,559		2,408		4,967		—		4,967
Competitive Businesses Other Revenues(c)	591		(802)		(211)		—		(211)
Total Consolidated Operating Revenues	$	21,571	$	2,869	$	24,440	$	—	$	24,440


	2021
	Revenues from external customers(a)
	Contracts with customers		Other(b)		Total		Intersegment Revenues		Total Revenues
Mid-Atlantic	$	4,381	$	183	$	4,564	$	20	$	4,584
Midwest	4,265		(205)		4,060		—		4,060
New York	1,633		(57)		1,576		(1)		1,575
ERCOT	896		276		1,172		9		1,181
Other Power Regions	3,937		981		4,918		(28)		4,890
Total Competitive Businesses Electric Revenues	$	15,112	$	1,178	$	16,290	$	—	$	16,290
Competitive Businesses Natural Gas Revenues	1,777		1,602		3,379		—		3,379
Competitive Businesses Other Revenues(c)	365		(385)		(20)		—		(20)
Total Consolidated Operating Revenues	$	17,254	$	2,395	$	19,649	$	—	$	19,649


	2020
	Revenues from external customers(a)
	Contracts with customers		Other(b)		Total		Intersegment Revenues		Total Revenues
Mid-Atlantic	$	4,785	$	(168)	$	4,617	$	28	$	4,645
Midwest	3,717		312		4,029		(5)		4,024
New York	1,444		(12)		1,432		(1)		1,431
ERCOT	735		198		933		25		958
Other Power Regions	3,586		463		4,049		(47)		4,002
Total Competitive Businesses Electric Revenues	$	14,267	$	793	$	15,060	$	—	$	15,060
Competitive Businesses Natural Gas Revenues	1,283		720		2,003		—		2,003
Competitive Businesses Other Revenues(c)	355		185		540		—		540
Total Consolidated Operating Revenues	$	15,905	$	1,698	$	17,603	$	—	$	17,603

__________

(a)Includes all wholesale and retail electric sales to third parties and affiliated sales to Exelon's utility subsidiaries prior to the separation on February 1, 2022. See Note 24 — Related Party Transactions for additional information.

(b)Includes revenues from derivatives and leases.

(c)Represents activities not allocated to a region. See text above for a description of included activities. Includes unrealized mark-to-market losses of $1,188 million and $633 million and gains of $110 million for the years ended December 31, 2022, 2021, and 2020, respectively.


	2022						2021						2020
	RNF from external customers(a)		Intersegment RNF		Total RNF		RNF from external customers(a)		Intersegment RNF		Total RNF		RNF from external customers(a)		Intersegment RNF		Total RNF
Mid-Atlantic	$	2,129	$	9	$	2,138	$	2,247	$	17	$	2,264	$	2,174	$	30	$	2,204
Midwest	2,765		(1)		2,764		2,717		—		2,717		2,902		—		2,902
New York	1,061		6		1,067		1,151		10		1,161		983		14		997
ERCOT	503		(96)		407		(668)		(157)		(825)		407		19		426
Other Power Regions	952		(31)		921		984		(93)		891		759		(94)		665
Total RNF for Reportable Segments	$	7,410	$	(113)	$	7,297	$	6,431	$	(223)	$	6,208	$	7,225	$	(31)	$	7,194
Other(b)	(432)		113		(319)		1,055		223		1,278		793		31		824
Total RNF	$	6,978	$	—	$	6,978	$	7,486	$	—	$	7,486	$	8,018	$	—	$	8,018

__________

(a)Includes purchases and sales from/to third parties and affiliated sales to Exelon's utility subsidiaries prior to the separation on February 1, 2022. See Note 24 — Related Party Transactions for additional information.

(b)Other represents activities not allocated to a region. See text above for a description of included activities. Primarily includes:

•Unrealized mark-to-market losses of $1,013 million, and gains of $565 million, and $295 million for the years ended December 31, 2022, 2021, and 2020, respectively;

•Accelerated nuclear fuel amortization associated with the announced early plant retirements as discussed in Note 7 - Early Plant Retirements of $148 million, and $60 million for the years ended December 31, 2021, and 2020, respectively; and

•The elimination of intersegment RNF.

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

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Implications of Potential Early Plant Retirements [Abstract]

Accounts Receivable

12 Months Ended

Dec. 31, 2022

Receivables [Abstract]

Accounts Receivable

Allowance for Credit Losses on Accounts Receivable

The following table presents the rollforward of Allowance for Credit Losses on Customer Accounts Receivable, which does not include any allowance related to the sales of Customer Accounts Receivable disclosed below. Allowance for Credit Losses on Other Accounts Receivable was not material as of the balance sheet dates.


Balance as of December 31, 2020	$	32
Plus: Current period provision for expected credit losses	30
Less: Write-offs, net of recoveries(a)	7

Balance as of December 31, 2021	55
Plus: Current period provision for expected credit losses	9
Less: Write-offs, net of recoveries(a)	18

Balance as of December 31, 2022	$	46

__________

(a)Recoveries were not material.

Unbilled Customer Revenue

We recorded $564 million and $373 million of unbilled customer revenues in Customer accounts receivables, net in the Consolidated Balance Sheets as of December 31, 2022 and 2021, respectively.

Sales of Customer Accounts Receivable

On April 8, 2020, NER, a bankruptcy remote, special purpose entity, which is wholly owned by us, entered into a revolving accounts receivable financing arrangement with a number of financial institutions and a commercial paper conduit (the "Purchasers") to sell certain customer accounts receivable (the "Facility"). On August 16, 2022, we entered into an amendment on the Facility, which increased the maximum funding limit of the Facility

from $900 million to $1.1 billion and extended the term of the Facility through August 15, 2025, unless renewed by the mutual consent of the parties in accordance with its terms. Under the Facility, NER may sell eligible short-term customer accounts receivable to the Purchasers in exchange for cash and subordinated interest. The transfers are reported as sales of receivables in the consolidated financial statements. The subordinated interest in collections upon the receivables sold to the Purchasers is referred to as the DPP, which is reflected in Other current assets in the Consolidated Balance Sheets.

The Facility requires the balance of eligible receivables to be maintained at or above the balance of cash proceeds received from the Purchasers. To the extent the eligible receivables decrease below such balance, we are required to repay cash to the Purchasers. When eligible receivables exceed cash proceeds, we have the ability to increase the cash received up to the maximum funding limit. These cash inflows and outflows impact the DPP.

The following table summarizes the impact of the sale of certain receivables:


	As of December 31,
	2022		2021
Derecognized receivables transferred at fair value	$	1,615	$	1,265
Cash proceeds received	1,100		900
DPP	515		365


	For the Years Ended December 31,
	2022		2021		2020
Loss on sale of receivables(a)	$	69	$	36	$	30

_________

(a)Reflected in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. This represents the amount by which the accounts receivable sold into the Facility are discounted, limited to credit losses.


	For the Years Ended December 31,
	2022		2021		2020
Proceeds from new transfers(a)	$	6,108	$	6,095	$	2,816
Cash collections received on DPP and reinvested in the Facility(b)	4,764		3,502		3,771
Cash collections reinvested in the Facility	10,872		9,597		6,587

_________

(a)Customer accounts receivable sold into the Facility were $11,274 million and $9,747 million for the years ended December 31, 2022 and 2021, respectively.

(b)Does not include the $200 million in net cash proceeds received from the Purchasers in 2022 and $400 million in cash proceeds received from the Purchasers in 2021.

Our risk of loss following the transfer of accounts receivable is limited to the DPP outstanding. Payment of DPP is not subject to significant risks other than delinquencies and credit losses on accounts receivable transferred. We continue to service the receivables sold in exchange for a servicing fee. We did not record a servicing asset or liability as the servicing fees were immaterial.

We recognize the cash proceeds received upon sale in Net cash provided by operating activities in the Consolidated Statements of Cash Flows. The collection and reinvestment of DPP is recognized in Net cash provided by investing activities in the Consolidated Statements of Cash Flows.

See Note 18 — Fair Value of Financial Assets and Liabilities and Note 22 — Variable Interest Entities for additional information.

Other Sales of Customer Accounts Receivables

We are required, under supplier tariffs, to sell customer receivables to utility companies, which included Exelon's utility subsidiaries prior to the separation. The following table presents the total receivables sold.


	For the Years Ended December 31,
	2022		2021		2020
Total receivables sold	$	423	$	147	$	824
Related party transactions:
Receivables sold to Exelon's utility subsidiaries prior to the separation on February 1, 2022	4		23		252

Early Plant Retirements

12 Months Ended

Dec. 31, 2022

Early Plant Retirements

We continuously evaluate factors that affect the current and expected economic value of our plants, including, but not limited to: market power prices, results of capacity auctions, potential legislative and regulatory solutions to ensure plants are fairly compensated for benefits they provide through their carbon-free emissions, reliability or fuel security, and the impact of potential rules from the EPA requiring reduction of carbon and other emissions and the efforts of states to implement those final rules. We remain committed to continued operations for our nuclear plants receiving state-supported payments under the Illinois CMC (Byron, Dresden, and Braidwood), Illinois ZES (Clinton and Quad Cities), New Jersey ZEC program (Salem), and the New York CES (FitzPatrick, Ginna, and Nine Mile Point), assuming the continued effectiveness of each program. With the passage of the IRA, we expect that many of our nuclear assets will operate at least through the end of the Nuclear PTC period, concluding at the end of 2032. To enable long term operations, we plan to file applications to extend the licenses of our Nuclear fleet to 80 years for the units that receive continued support under federal or state policies or a combination of both. We are currently seeking license renewals for our Clinton and Dresden units. We have updated our depreciation provisions and ARO assumed retirement dates for these assets in the third quarter of 2022 to reflect an additional 20 years of operation. We continuously evaluate factors that affect the current and expected economic value of our plants including current and projected market conditions and policy support.

Nuclear Generation

On August 27, 2020, we announced our intention to permanently cease our operations at Byron in September 2021 and at Dresden in November 2021. On September 15, 2021, we announced that we have reversed our previous decision to retire Byron and Dresden given the opportunity for additional revenue under the Illinois Clean Energy Law. Our Byron, Dresden, and Braidwood nuclear plants participated in the CMC procurement process and were awarded contracts that commit each plant to operate through May 31, 2027. See Note 3 — Regulatory Matters for additional information.

In the third quarter of 2021, we reversed $81 million of severance benefit costs and $13 million of other one-time charges initially recorded in Operating and maintenance expense in the third and fourth quarters of 2020 associated with the early retirements. In addition, we updated the expected economic useful life for both facilities to 2044 and 2046, for Byron Units 1 and 2, respectively, and to 2029 and 2031 for Dresden Units 2 and 3, respectively, the end of the respective NRC operating license for each unit. Depreciation was therefore adjusted beginning September 15, 2021, to reflect these extended useful life estimates. See Note 10 — Asset Retirement Obligations for additional detail on changes to the nuclear decommissioning ARO balances resulting from the initial decision and subsequent reversal of the decision to early retire Byron and Dresden.

The total impact for the years ended December 31, 2021 and 2020 in the Consolidated Statements of Operations and Comprehensive Income resulting from the initial decision and subsequent reversal of the decision to early retire Byron and Dresden is summarized in the table below.


Income statement expense (pre-tax)	2021		2020
Depreciation and amortization
Accelerated depreciation(a)	$	1,805	$	895
Accelerated nuclear fuel amortization	148		60
Operating and maintenance
One-time charges	(94)		255
Other charges(b)	9		34
Contractual offset(c)	(451)		(364)
Total	$	1,417	$	880

_________

(a)Includes the accelerated depreciation of plant assets including any ARC.

(b)For 2020, reflects the net impacts associated with the remeasurement of the ARO. See Note 10 - Asset Retirement Obligations for additional information.

(c)Reflects contractual offset for ARO accretion, ARC depreciation, ARO remeasurement, and excludes any changes in earnings in the NDT funds. Decommissioning-related impacts were not offset for the Byron units starting in the second quarter of 2021 due to the inability to recognize a regulatory asset at ComEd. With our September 15, 2021 reversal of the previous decision to retire Byron, we resumed contractual offset for Byron as of that date. Based on the regulatory agreement with the ICC, decommissioning-related activities are offset in the Consolidated Statements of Operations and Comprehensive Income as long as the net cumulative decommissioning-related activity result in a regulatory liability at ComEd. The offset resulted in an equal adjustment to the noncurrent payables to ComEd. See Note 10 - Asset Retirement Obligations for additional information.

Other Generation

In March 2018, we notified ISO-NE of our plans to early retire, among other assets, the Mystic Generating Station's units 8 and 9 ("Mystic 8 and 9") absent regulatory reforms to properly value reliability and regional fuel security. Thereafter, ISO-NE identified Mystic 8 and 9 as being needed to ensure fuel security for the region and entered into a cost of service agreement with these two units for the period between June 1, 2022 to May 31, 2024. The agreement was approved by FERC in December 2018.

On June 10, 2020, we filed a complaint with FERC against ISO-NE stating that ISO-NE failed to follow its tariff with respect to its evaluation of Mystic 8 and 9 for transmission security for the 2024 to 2025 Capacity Commitment Period and that the modifications that ISO-NE made to its unfiled planning procedures to avoid retaining Mystic 8 and 9 should have been filed with FERC for approval. On August 17, 2020, FERC issued an order denying the complaint. As a result, on August 20, 2020, we announced we will permanently cease generation operations at Mystic 8 and 9 at the expiration of the cost of service commitment in May 2024. See Note 3 — Regulatory Matters for additional discussion of Mystic’s cost of service agreement.

As a result of the decision to early retire Mystic 8 and 9, we recognized $22 million of one-time charges for the year ended December 31, 2020, related to materials and supplies inventory reserve adjustments, among other items. In addition, there are annual financial impacts stemming from shortening the expected economic useful life of Mystic 8 and 9 primarily related to accelerated depreciation of plant assets. We recorded an immaterial amount of incremental Depreciation and amortization expense for the year ended December 31, 2022. We recorded incremental Depreciation and amortization expense of $41 million and $26 million for the years ended December 31, 2021 and 2020, respectively. See Note 12 — Asset Impairments for impairment assessment considerations of the New England Asset Group.

Property, Plant, and Equipment

12 Months Ended

Dec. 31, 2022

Property, Plant and Equipment [Abstract]

Property, Plant, and Equipment

The following table presents a summary of property, plant, and equipment by asset category as of December 31, 2022 and 2021:


Asset Category	December 31, 2022		December 31, 2021
Electric	$	30,804	$	29,910
Nuclear fuel(a)	5,106		5,166
Construction work in progress	630		399
Other property, plant, and equipment	8		10
Total property, plant, and equipment	36,548		35,485
Less: accumulated depreciation(b)	16,726		15,873
Property, plant, and equipment, net	$	19,822	$	19,612

__________

(a)Includes nuclear fuel that is in the fabrication and installation phase of $937 million and $859 million as of December 31, 2022 and 2021, respectively.

(b)Includes accumulated amortization of nuclear fuel in the reactor core of $2,657 million and $2,765 million as of December 31, 2022 and 2021, respectively.

The following table presents the average service life for each asset category in number of years:


Asset Category			Average Service Life (years)
Electric			1-52
Nuclear fuel			1-8
Other property, plant, and equipment			1-10

Depreciation provisions are based on the estimated useful lives of the stations, which generally correspond with the term of the operating licenses, except for Peach Bottom, Conowingo, Clinton, and Dresden. Peach Bottom Units 2 and 3 depreciation provisions are based on an estimated useful life through 2053 and 2054, respectively. Conowingo depreciation provisions are based on an estimated useful life through 2071. These depreciation provisions are in anticipation of the license expiration dates being restored. We are currently seeking license renewals for our Clinton and Dresden units. Clinton depreciation provisions are based on an estimated useful life through 2047. Dresden Units 2 and 3 depreciation provisions are based on an estimated useful life through 2049 and 2051, respectively, in anticipation of the license renewals. Beginning August 2020, Byron, Dresden, and Mystic depreciation provisions were based on their announced shutdown dates of September 2021, November 2021, and May 2024, respectively. On September 15, 2021, we updated the expected useful lives for Byron and Dresden to reflect the end of the available NRC operating license for each unit. See Note 3 — Regulatory Matters for additional information regarding license renewals for Peach Bottom, Conowingo, Clinton, and Dresden. See Note 7 — Early Plant Retirements for additional information on the impacts related to Byron, Dresden and Mystic.

Annual depreciation rates for electric generation were 3.46%, 8.67%, and 6.11% for the years ended December 31, 2022, 2021, and 2020, respectively. Nuclear fuel amortization is charged to fuel expense using the unit-of-production method and not included in the annual depreciation rates.

Capitalized Interest

Capitalized interest was $25 million, $15 million, and $22 million for the years ended December 31, 2022, 2021, and 2020, respectively.

See Note 1 — Basis of Presentation for additional information regarding property, plant, and equipment policies.

Jointly Owned Electric Utility Plant

12 Months Ended

Dec. 31, 2022

Public Utilities, Property, Plant and Equipment [Abstract]

Jointly Owned Electric Utility Plant

Our material undivided ownership interests in jointly owned nuclear plants as of December 31, 2022 and 2021 were as follows:


	Nuclear Generation
	Quad Cities			Peach Bottom			Salem			Nine Mile Point Unit 2
Operator	Constellation			Constellation			PSEG Nuclear			Constellation
Ownership interest	75.00		%	50.00		%	42.59		%	82.00		%
Our share as of December 31, 2022
Plant in service	$	1,243		$	1,534		$	772		$	1,063
Accumulated depreciation	761			659			328			256
Construction work in progress	7			12			23			26
Our share as of December 31, 2021
Plant in service	$	1,211		$	1,515		$	756		$	1,002
Accumulated depreciation	715			628			299			222
Construction work in progress	11			12			20			41

Our undivided ownership interests are financed with our funds and all operations are proportionately consolidated consistent with our ownership interest. Our share of direct expenses of the jointly owned plants are included in Purchased power and fuel and Operating and maintenance expenses in the Consolidated Statements of Operations and Comprehensive Income.

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2022

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

Nuclear Decommissioning Asset Retirement Obligations

We have a legal obligation to decommission our nuclear power plants following the permanent cessation of operations. To estimate our nuclear decommissioning obligations we use a probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models, and discount rates. We update our AROs annually, unless circumstances warrant more frequent updates, based on our review of updated cost studies and our annual evaluation of cost escalation factors and probabilities assigned to various scenarios. We began decommissioning the TMI nuclear plant upon permanently ceasing operations in 2019. See below section for decommissioning of Zion Station.

The financial statement impact for changes in the ARO, on an individual unit basis, due to the changes in and timing of estimated cash flows generally result in a corresponding change in the unit’s ARC in Property, plant, and equipment in the Consolidated Balance Sheets. If the ARO decreases for a Non-Regulatory Agreement unit without any remaining ARC, the corresponding change is recorded as a decrease in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income.

The following table provides a rollforward of the nuclear decommissioning AROs reflected in the Consolidated Balance Sheets from December 31, 2020 to December 31, 2022:


Balance as of December 31, 2020	$	11,922
Net increase due to changes in, and timing of, estimated future cash flows	324
Accretion expense	503
Costs incurred related to decommissioning plants	(73)
Balance as of December 31, 2021(a)	12,676
Net decrease due to changes in, and timing of, estimated future cash flows	(648)
Accretion expense	532
Costs incurred related to decommissioning plants	(60)
Balance as of December 31, 2022(a)	$	12,500

__________

(a)Includes $40 million and $72 million as the current portion of the ARO as of December 31, 2022 and 2021, respectively, which is included in Other current liabilities in the Consolidated Balance Sheets.

The net $648 million decrease in the ARO during 2022 for changes in the amounts and timing of estimated decommissioning cash flows was driven by multiple adjustments, including the following:

•A net decrease of approximately $790 million due to an increase in discount rates partly offset by an increase in cost escalation rates, primarily labor and energy.

•A decrease of approximately $235 million due to changes in assumed retirement dates as a result of the passage of the IRA and useful life extension for Clinton and Dresden plants. See Note 3 - Regulatory Matters and Note 7 - Early Plant Retirements for additional information.

•A increase of approximately $320 million due to revisions to the projected decommissioning schedule for our New York nuclear plants in connection with our separation from Exelon as discussed further below.

•A net increase of approximately $75 million due to higher estimated decommissioning costs resulting from the completion of updated cost studies for our New York nuclear plants, Quad Cities, Calvert Cliffs, and Three Mile Island.

The 2022 ARO updates resulted in a decrease of $226 million in Operating and maintenance expense for the year ended December 31, 2022 in the Consolidated Statement of Operations and Comprehensive Income.

The net $324 million increase in the ARO during 2021 for changes in the amounts and timing of estimated decommissioning cash flows was driven by multiple adjustments throughout the year, including the following:

•An increase of approximately $550 million for updated cost escalation rates, primarily for labor and energy, and a decrease in discount rates.

•An increase of approximately $90 million due to revisions to assumed retirement dates for several nuclear plants.

•A net decrease of approximately $170 million was driven by updates to Byron and Dresden reflecting changes in assumed retirement dates and assumed methods of decommissioning as a result of the reversal of the decision to early retire the plants. See Note 7 — Early Plant Retirements for additional information.

•A net decrease of approximately $150 million due to lower estimated decommissioning costs resulting from the completion of updated cost studies for seven nuclear plants.

The 2021 ARO updates resulted in an increase of $51 million in Operating and maintenance expense for the year ended December 31, 2021 in the Consolidated Statement of Operations and Comprehensive Income.

NDT Funds

NDT funds have been established for each of our nuclear units to satisfy our nuclear decommissioning obligations, as required by the NRC, and withdrawals from these funds for reasons other than to pay for decommissioning are restricted pursuant to NRC requirements until all decommissioning activities have been completed. Generally, NDT funds established for a particular unit may not be used to fund the decommissioning obligations of any other unit.

The NDT funds associated with our nuclear units have been funded with amounts collected from the previous owners and their respective utility customers. PECO is authorized to collect funds, in revenues, through regulated rates for decommissioning the former PECO nuclear plants, and these collections are scheduled through the operating lives of these former PECO plants. The amounts collected from PECO customers are remitted to us and deposited into the NDT funds for the unit for which funds are collected. Every five years, PECO files a rate adjustment with the PAPUC that reflects PECO’s calculations of the estimated amount needed to decommission each of the former PECO units based on updated fund balances and estimated decommissioning costs. The rate adjustment is used to determine the amount collectible from PECO customers. On March 31, 2022, PECO filed its Nuclear Decommissioning Cost Adjustment with the PAPUC proposing an

annual recovery from customers of approximately $4 million. On August 19, 2022, the PAPUC approved the filing, and the new rates became effective January 1, 2023.

Any shortfall of funds necessary for decommissioning, determined for each generating station unit, are generally required to be funded by us, with the exception of a shortfall for the current decommissioning activities at Zion Station, where certain decommissioning activities have been transferred to a third-party (see Zion Station Decommissioning below) and the former PECO nuclear plants where, through PECO, we have recourse to collect additional amounts from PECO customers related to a shortfall of NDT funds for those units, subject to certain limitations and thresholds, as prescribed by an order from the PAPUC that limits collection of amounts associated with the first $50 million of any shortfall of trust funds compared to decommissioning costs, as well as 5% of any additional shortfalls, on an aggregate basis for all former PECO units. The initial $50 million and up to 5% of any additional shortfalls would be borne by us. No recourse exists to collect additional amounts from utility customers for any of our other nuclear units.

With respect to the former ComEd and former PECO units, any funds remaining in the NDTs after all decommissioning has been completed are required to be refunded to ComEd’s or PECO’s customers, subject to certain limitations that allow sharing of excess funds with us related to the former PECO units. With respect to our other nuclear units, we retain any funds remaining after decommissioning. However, in connection with CENG's acquisition of the Nine Mile Point and Ginna plants and settlements with certain regulatory agencies, certain conditions pertaining to NDT funds apply that, if met, could possibly result in obligations to make payments to certain third parties (clawbacks). For Nine Mile Point and Ginna, the clawback provisions are triggered only in the event that the required decommissioning activities are discontinued or not started or completed in a timely manner. In the event that the clawback provisions are triggered for Nine Mile Point, then, depending upon the triggering event, an amount equal to 50% of the total amount withdrawn from the funds for non-decommissioning activities as defined in the agreement or 50% of any excess funds in the trust funds above the amounts required for decommissioning (including SNF management and site restoration) is to be paid to the Nine Mile Point sellers. In the event that the clawback provisions are triggered for Ginna, then an amount equal to any estimated cost savings realized by not completing any of the required decommissioning activities is to be paid to the Ginna sellers. We expect to comply with applicable regulations and timely commence and complete all required decommissioning activities.

We had NDT funds totaling $14,127 million and $16,064 million as of December 31, 2022 and 2021, respectively. The NDT funds also include $13 million and $126 million for the current portion of the NDT funds as of December 31, 2022 and 2021, respectively, which are included in Other current assets in the Consolidated Balance Sheets. See Note 23 — Supplemental Financial Information for additional information on activities of the NDT funds.

Accounting Implications of the Regulatory Agreements with ComEd and PECO

See Note 1 — Basis of Presentation for additional information on the accounting policy for Regulatory Agreement Units with ComEd and PECO.

For the former PECO units, given the symmetric settlement provisions that allow for continued recovery of decommissioning costs from PECO customers in the event of a shortfall and the obligation for us to ultimately return excess funds to PECO customers (on an aggregate basis for all seven units), decommissioning-related activities are generally offset in the Consolidated Statements of Operations and Comprehensive Income regardless of whether the NDT funds are expected to exceed or fall short of the total estimated decommissioning obligation. The offset of decommissioning-related activities in the Consolidated Statements of Operations and Comprehensive Income results in an equal adjustment to noncurrent payables or noncurrent receivables. Any changes to the existing PECO regulatory agreements could impact our ability to offset decommissioning-related activities in the Consolidated Statements of Operations and Comprehensive Income, and the potential impact to our consolidated financial statements could be material.

For the former ComEd units, given no further recovery from ComEd customers is permitted and we retain an obligation to ultimately return any unused NDTs to ComEd customers (on a unit-by-unit basis), to the extent the related NDT investment balances are expected to exceed the total estimated decommissioning obligation for each unit, decommissioning-related activities are offset in the Consolidated Statements of Operations and Comprehensive Income which results in us recognizing a noncurrent payable. However, given the asymmetric settlement provision that does not allow for continued recovery from ComEd customers in the event of a shortfall,

recognition of a regulatory asset at ComEd is not permissible and accounting for decommissioning-related activities for that unit would not be offset, and the impact to the Consolidated Statements of Operations and Comprehensive Income could be material during such periods. During the second and third quarter of 2021, a pre-tax charge of $53 million and $140 million, respectively, was recorded in the Consolidated Statement of Operations and Comprehensive Income for decommissioning-related activities that were not offset for the Byron units due to contractual offset being temporarily suspended. With our September 15, 2021 reversal of the previous decision to retire Byron and the corresponding adjustment to the ARO for Byron discussed previously, we resumed contractual offset for Byron as of that date.

The following table presents our noncurrent payables to ComEd and PECO which are recorded as Payables related to Regulatory Agreement Units as of December 31, 2022 and noncurrent Payables to affiliates as of December 31, 2021:


	December 31, 2022		December 31, 2021
ComEd	$	2,660	$	2,760
PECO	237		597

As of December 31, 2022, decommissioning-related activities for all of the former ComEd units, except for Zion (see Zion Station Decommissioning below), are currently offset in the Consolidated Statements of Operations and Comprehensive Income.

The decommissioning-related activities for the Non-Regulatory Agreement Units are reflected in the Consolidated Statements of Operations and Comprehensive Income within Operating and maintenance expense, Depreciation and amortization expense, and in Other, net.

Zion Station Decommissioning

In 2010, we completed an ASA under which ZionSolutions assumed responsibility for decommissioning Zion Station and we transferred to ZionSolutions substantially all the Zion Station’s assets, including the related NDT funds. Following ZionSolutions' completion of its contractual obligations and transfer of the NRC license back to us, we will store the SNF at Zion Station until it is transferred to the DOE for ultimate disposal, and complete all remaining decommissioning activities associated with the SNF dry storage facility.

We had retained our obligation for the SNF upon transfer of the NRC license to us as well as certain NDT assets to fund the obligation to maintain the SNF at Zion Station until transfer to the DOE and to complete all remaining decommissioning activities for the SNF storage facility. Any shortage of funds necessary to maintain the SNF and decommission the SNF storage facility is ultimately required to be funded by us. As of December 31, 2022, the ARO associated with Zion's SNF storage facility is $138 million and the NDT funds available to fund this obligation are $58 million.

NRC Minimum Funding Requirements

NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts to decommission the facility at the end of its life. The estimated decommissioning obligations are calculated using an NRC methodology that is different from the ARO recorded in the Consolidated Balance Sheets primarily due to differences in the type of costs included in the estimates, the basis for estimating such costs, and assumptions regarding the decommissioning alternatives to be used, potential license renewals, decommissioning cost escalation, and the growth rate in the NDT funds. Under NRC regulations, if the minimum funding requirements for radiological decommissioning calculated under the NRC methodology are greater than the future value of the NDT funds, also calculated under the NRC methodology, then the NRC requires resolution of the shortfalls which could include further funding or other financial guarantees.

Key assumptions used in the minimum funding calculation for radiological decommissioning costs using the NRC methodology at December 31, 2022 include: (1) consideration of costs only for the removal of radiological contamination at each unit; (2) the option on a unit-by-unit basis to use generic, non-site specific cost estimates; (3) consideration of only one decommissioning scenario for each unit; (4) the plants cease operation at the end of their current license lives (with no assumed license renewals for those units that have not already received

renewals); (5) the assumption of current nominal dollar cost estimates that are neither escalated through the anticipated period of decommissioning, nor discounted using the CARFR; and (6) assumed annual after-tax returns on the NDT funds of 2% (3% for the former PECO units, as specified by the PAPUC).

In contrast, the key criteria and assumptions used by us to determine the ARO and to forecast the target growth in the NDT funds as of December 31, 2022 include: (1) the use of site specific cost estimates that are updated at least once every five years; (2) the inclusion in the ARO estimate of all legally unavoidable costs required to decommission the unit (e.g., radiological decommissioning and full site restoration for certain units, on-site SNF maintenance and storage subsequent to ceasing operations and until DOE acceptance, and disposal of certain LLRW); (3) as applicable, the consideration of multiple scenarios where decommissioning and site restoration activities, as applicable, are completed under possible scenarios ranging from 10 to 70 years after the cessation of plant operations or the end of the current licensed operating life; (4) the consideration of multiple end of life scenarios; (5) the measurement of the obligation at the present value of the future estimated costs and an annual average accretion of the ARO of approximately 4% through a period of approximately 30 years after the end of the extended lives of the units; and (6) an estimated targeted annual pre-tax return on the NDT funds of 6.2% to 6.9% (as compared to a historical 5-year annual average pre-tax return of approximately 5.3%).

We are required to provide to the NRC a biennial report by unit (annually for units that have been retired or are within five years of license expiration), based on values as of December 31, addressing our ability to meet the NRC minimum funding levels. Depending on the value of the trust funds, we may be required to take steps, such as providing financial guarantees through surety bonds, letters of credit, or parent company guarantees or making additional contributions to the trusts, which could be significant, to ensure that the trusts are adequately funded and that NRC minimum funding requirements are met. As a result, our cash flows and financial position may be significantly adversely affected.

We filed our biennial decommissioning funding status report with the NRC on February 24, 2021 for all units, including our shutdown units, except for Zion Station which is included in a separate report to the NRC submitted by ZionSolutions, LLC. The status report demonstrated adequate decommissioning funding assurance as of December 31, 2020 for all units except for Byron Units 1 and 2. We filed an updated decommissioning funding status report for Byron Units 1 and 2 and Dresden Units 2 and 3 on September 28, 2021 based on their current license expiration dates consistent with our announcements regarding the continued operations of these units. This report demonstrated adequate decommissioning funding assurance as of December 31, 2020 for Byron Units 1 and 2 and Dresden Units 2 and 3.

On March 23, 2022, we filed our annual decommissioning funding status report with the NRC for our shutdown units (excluding Zion station for the reason noted above). The annual status report demonstrated adequate decommissioning funding assurance, based on the value of the trust funds as of December 31, 2021 for all of our shutdown reactors except for Peach Bottom Unit 1. As a former PECO plant, financial assurance for decommissioning Peach Bottom Unit 1 is provided by the NDT fund, collections from PECO customers, and the ability to adjust those collections in accordance with the approved PAPUC tariff. See NDT Funds section above for additional information.

We will file the next decommissioning funding status report with the NRC by March 31, 2023. This report will also reflect the status of decommissioning funding as of December 31, 2022 for all units. We expect the annual status report to demonstrate adequate decommissioning funding assurance, based on the value of trust funds as of December 31, 2022 for all reactors except for Peach Bottom Unit 1 and Clinton. We are currently seeking to renew Clinton’s operating license for an additional 20 years and anticipate NRC approval by 2026. Once approved, we expect that Clinton will demonstrate adequate funding assurance. In the event that Clinton remains underfunded by April 2024, additional financial assurance may be required. Financial assurance for decommissioning of Peach Bottom Unit 1 is provided by the collections from PECO customers as noted above.

As the future values of trust funds change due to market conditions, the NRC minimum funding status of our units will change. In addition, if changes occur to the regulatory agreement with the PAPUC that currently allows amounts to be collected from PECO customers for decommissioning the former PECO units, the NRC minimum funding status of those plants could change at subsequent NRC filing dates.

Impact of Separation from Exelon

Satisfying a condition precedent, on December 16, 2021, the NYPSC authorized our separation from Exelon and accepted the terms of a Joint Proposal that became binding upon closing of the separation on February 1, 2022. As part of the Joint Proposal, among other items, we have projected completion of radiological decommissioning and site restoration activities necessary to achieve a partial site release from the NRC (release of the site for unrestricted use, except for any on-site dry cask storage) within 20 years from the end of licensed life for each of our Ginna and FitzPatrick units and from the end of licensed life for the last of the NMP operating units. While there is flexibility under the Joint Proposal, there was an increase to the AROs, as noted above, associated with our New York nuclear plants during the first quarter of 2022.

The Joint Proposal also required a contribution of $15 million to the NDT for NMP Unit 2 in January 2022 and requires various financial assurance mechanisms through the duration of decommissioning and site restoration, including a minimum NDT balance for each unit, adjusted for specific stages of decommissioning, and a parent guaranty for site restoration costs updated annually as site restoration progresses, which must be replaced with a third-party surety bond or equivalent financial instrument in the event we were to fall below investment grade.

See Note 1 — Basis of Presentation for additional information.

Non-Nuclear Asset Retirement Obligations

We have AROs for plant closure costs associated with our natural gas, oil, and renewable generating facilities, including asbestos abatement, removal of certain storage tanks, restoring leased land to the condition it was in prior to construction of renewable generating stations, and other decommissioning-related activities. See Note 1 — Basis of Presentation for additional information on the accounting policy for AROs.

The following table provides a rollforward of the non-nuclear AROs reflected in the Consolidated Balance Sheets from December 31, 2020 to December 31, 2022:


Balance as of December 31, 2020	$	212
Net increase due to changes in, and timing of, estimated future cash flows	5
Accretion expense	11
Asset divestitures	(19)
Payments	(3)
AROs previously held for sale	10
Balance as of December 31, 2021	216
Net increase due to changes in, and timing of, estimated future cash flows	18

Accretion expense	11
Asset divestitures	(1)
Payments	(5)

Balance as of December 31, 2022	$	239

Leases

12 Months Ended

Dec. 31, 2022

Leases [Abstract]

Leases

Lessee

We have operating leases for which we are the lessee. The significant types of leases are contracted generation, real estate, and vehicles and equipment. The following table outlines other terms and conditions of the lease agreements as of December 31, 2022. We did not have material finance leases in 2022, 2021, or in 2020.


			In Years
Remaining lease terms			1-33
Options to extend the term			2-30
Options to terminate within			1-2

The components of operating lease costs were as follows:


	For the Years Ended December 31,
	2022		2021		2020
Operating lease costs	$	109	$	161	$	194
Variable lease costs	169		168		234

__________

(a)Excludes $49 million, $44 million, $44 million of sublease income recorded for each of the years ended December 31, 2022, 2021, and 2020 respectively.

The following table provides additional information regarding the presentation of operating lease ROU assets and lease liabilities in the Consolidated Balance Sheets:


	As of December 31,
	2022		2021
Operating lease ROU assets(a)
Other deferred debits and other assets	$	545	$	604

Operating lease liabilities(a)
Other current liabilities	67		72
Other deferred credits and other liabilities	643		705
Total operating lease liabilities	$	710	$	777

__________

(a)The operating ROU assets and lease liabilities include $248 million and $377 million, respectively, related to contracted generation as of December 31, 2022, and $293 million and $429 million, respectively, as of December 31, 2021.

The weighted average remaining lease terms, in years, and the weighted average discount rates for operating leases as of December 31, 2022 were as follows:


	As of December 31,
	2022		2021		2020
Weighted average remaining lease term	9.3		10.1		10.5
Weighted average discount rate	5.0	%	5.0	%	4.9	%

The following table reconciles the undiscounted cash flows for our operating leases to the operating lease liabilities recorded on our consolidated balance sheet as of December 31, 2022:


Year	Amount
2023	$	101
2024	99
2025	102
2026	102
2027	100
Thereafter	421
Total lease payments	925
Less: Imputed interest	215
Operating lease liabilities	$	710

Supplemental cash flow information related to operating leases was as follows:


	For the Years Ended December 31,
	2022		2021		2020
Cash paid for amounts included in the measurement of operating lease liabilities	$	114	$	162	$	204
ROU assets obtained in exchange for operating lease obligations	14		2		3

Lessor

We have operating leases for which we are the lessor. The significant types of leases are contracted generation and real estate. The following table outlines other terms and conditions of the lease agreements as of December 31, 2022.


			In Years
Remaining lease terms			1-18
Options to extend the term			1-20

The components of lease income were as follows:


	For the Years Ended December 31,
	2022		2021		2020
Operating lease income	$	51	$	47	$	47
Variable lease income	258		261		282

The following table presents maturity analysis of the lease payments we expect to receive as of December 31, 2022:


Year	Amount
2023	$	48
2024	48
2025	48
2026	49
2027	49
Thereafter	133
Total	$	375

Leases

Lessee


			In Years
Remaining lease terms			1-33
Options to extend the term			2-30
Options to terminate within			1-2

The components of operating lease costs were as follows:


	For the Years Ended December 31,
	2022		2021		2020
Operating lease costs	$	109	$	161	$	194
Variable lease costs	169		168		234

__________

(a)Excludes $49 million, $44 million, $44 million of sublease income recorded for each of the years ended December 31, 2022, 2021, and 2020 respectively.

The following table provides additional information regarding the presentation of operating lease ROU assets and lease liabilities in the Consolidated Balance Sheets:


	As of December 31,
	2022		2021
Operating lease ROU assets(a)
Other deferred debits and other assets	$	545	$	604

Operating lease liabilities(a)
Other current liabilities	67		72
Other deferred credits and other liabilities	643		705
Total operating lease liabilities	$	710	$	777

__________

The weighted average remaining lease terms, in years, and the weighted average discount rates for operating leases as of December 31, 2022 were as follows:


	As of December 31,
	2022		2021		2020
Weighted average remaining lease term	9.3		10.1		10.5
Weighted average discount rate	5.0	%	5.0	%	4.9	%

The following table reconciles the undiscounted cash flows for our operating leases to the operating lease liabilities recorded on our consolidated balance sheet as of December 31, 2022:


Year	Amount
2023	$	101
2024	99
2025	102
2026	102
2027	100
Thereafter	421
Total lease payments	925
Less: Imputed interest	215
Operating lease liabilities	$	710

Supplemental cash flow information related to operating leases was as follows:


	For the Years Ended December 31,
	2022		2021		2020
Cash paid for amounts included in the measurement of operating lease liabilities	$	114	$	162	$	204
ROU assets obtained in exchange for operating lease obligations	14		2		3

Lessor


			In Years
Remaining lease terms			1-18
Options to extend the term			1-20

The components of lease income were as follows:


	For the Years Ended December 31,
	2022		2021		2020
Operating lease income	$	51	$	47	$	47
Variable lease income	258		261		282

The following table presents maturity analysis of the lease payments we expect to receive as of December 31, 2022:


Year	Amount
2023	$	48
2024	48
2025	48
2026	49
2027	49
Thereafter	133
Total	$	375

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

Intangible Assets

12 Months Ended

Dec. 31, 2022

Goodwill and Intangible Assets Disclosure [Abstract]

Intangible Assets

Our intangible assets and liabilities, included in Other current assets, Other deferred debits and other assets, Other current liabilities, Other deferred credits and other liabilities in the Consolidated Balance Sheets, consisted of the following as of December 31, 2022 and 2021. The intangible assets and liabilities shown below are generally amortized on a straight line basis, except for unamortized energy contracts which are amortized in relation to the expected realization of the underlying cash flows:


	December 31, 2022						December 31, 2021
	Gross		Accumulated Amortization		Net		Gross		Accumulated Amortization		Net
Unamortized Energy Contracts	$	1,960	$	(1,708)	$	252	$	1,963	$	(1,673)	$	290
Customer Relationships	356		(265)		91		330		(243)		87
Trade Name	222		(222)		—		222		(218)		4



Total	$	2,538	$	(2,195)	$	343	$	2,515	$	(2,134)	$	381

The following table summarizes the amortization expense related to intangible assets and liabilities for each of the years ended December 31, 2022, 2021, and 2020:


For the Years Ended December 31,	Amortization Expense(a)
2022	$	61
2021	80
2020	81

__________

(a)See Note 23 — Supplemental Financial Information for additional information related to the amortization of unamortized energy contracts.

The following table summarizes the estimated future amortization expense related to intangible assets and liabilities as of December 31, 2022:


For the Years Ending December 31,	Estimated Future Amortization Expense
2023	$	59
2024	56
2025	47
2026	40
2027	27

Renewable Energy Credits

RECs are included in Renewable energy credits in the Consolidated Balance Sheets. Purchased RECs are recorded at cost on the date they are purchased. The cost of RECs purchased on a stand-alone basis is based on the transaction price, while the cost of RECs acquired through PPAs represents the difference between the total contract price and the market price of energy at contract inception. Generally, revenue for RECs that are sold to a counterparty under a contract that specifically identifies a power plant is recognized at a point in time when the power is produced. This includes both bundled and unbundled REC sales. Otherwise, the revenue is recognized upon physical transfer of the REC to the customer.

The following table presents current RECs as of December 31, 2022 and 2021:


	December 31, 2022		December 31, 2021
Current REC's	$	617	$	520

Income Taxes

12 Months Ended

Dec. 31, 2022

Income Tax Disclosure [Abstract]

Income Taxes

Components of Income Tax Expense or Benefit

Income taxes are comprised of the following components:


	For the Years Ended December 31,
	2022(a)		2021(a)		2020(a)
Federal
Current	$	219	$	394	$	130
Deferred	(655)		(153)		150
ITC amortization	(15)		(15)		(25)
State
Current	34		36		40
Deferred	29		(37)		(46)
Total	$	(388)	$	225	$	249

_________

(a)Negative amounts represent income tax benefit. Positive amounts represent income tax expense.

Rate Reconciliation

The effective income tax rate varies from the U.S. federal statutory rate principally due to the following:


	For the Years Ended December 31,
	2022(a)		2021		2020
U.S. federal statutory rate	21.0	%	21.0	%	21.0	%
(Decrease) increase due to:
State income taxes, net of federal income tax benefit(c)	(9.2)		—		0.5
Qualified NDT fund income and losses	46.3		165.1		23.5
Amortization of investment tax credit, including deferred taxes on basis differences	2.2		(9.0)		(2.6)

Production tax credits and other credits	7.7		(28.7)		(5.4)
Noncontrolling interests	(0.3)		(3.0)		3.2
Tax Settlements	—		—		(10.3)

Other(d)	3.9		2.6		(0.1)
Effective income tax rate(b)	71.6	%	148.0	%	29.8	%

_________

(a)Positive percentages represent income tax benefit. Negative percentages represent income tax expense.

(b)The change in effective tax rate in 2022 is primarily due to the impacts of higher unrealized NDT losses on Income before income taxes and one-time income tax adjustments.

(c)Includes $30 million related to state rate changes and certain state tax positions.

(d)Primarily related to a $32 million prior period income tax adjustment recorded in 2022.

Tax Differences and Carryforwards

The tax effects of temporary differences and carryforwards, which give rise to significant portions of the deferred tax (liabilities) assets, as of December 31, 2022 and 2021 are presented below:


	December 31, 2022		December 31, 2021
Plant basis differences	$	(3,005)	$	(2,812)
Accrual based contracts	(35)		(38)
Derivatives and other financial instruments	43		(172)
Deferred pension and postretirement obligation	287		(274)
Nuclear decommissioning activities	(371)		(912)
Deferred debt refinancing costs	—		15
Tax loss carryforward, net of valuation allowances	67		53
Tax credit carryforward	179		778
Investment in partnerships	(205)		(252)
Other, net	407		312
Deferred income tax liabilities (net)	$	(2,633)	$	(3,302)
Unamortized ITCs	(354)		(369)
Total deferred income tax liabilities (net) and unamortized ITCs	$	(2,987)	$	(3,671)

The following table provides our carryforwards, of which the state related items are presented on a post-apportioned basis, and any corresponding valuation allowances as of December 31, 2022:


Federal	December 31, 2022


Federal general business credits carryforwards and other carryforwards	$	178
State
State net operating losses and other carryforwards	939
Deferred taxes on state tax attributes (net)	78
Valuation allowance on state tax attributes	11
Year in which net operating loss or credit carryforwards will begin to expire	2035

Tabular Reconciliation of Unrecognized Tax Benefits

The following table presents changes in unrecognized tax benefits:


	Unrecognized tax benefits
Balance as of December 31, 2019	$	441

Increases based on tax positions related to 2020	1
Increases based on tax positions prior to 2020	23
Decreases based on tax positions prior to 2020(a)	(346)
Decrease from settlements with taxing authorities(a)	(69)
Balance as of December 31, 2020	50
Change to positions that only affect timing	(1)
Increases based on tax positions related to 2021	1
Increases based on tax positions prior to 2021	1
Decreases based on tax positions prior to 2021	(2)
Balance as of December 31, 2021	49
Change to positions that only affect timing	(5)
Increases based on tax positions related to 2022	29
Increases based on tax positions prior to 2022(b)	6
Decreases based on tax positions prior to 2022(b)	(55)
Balance as of December 31, 2022	$	24

__________

(a)Our unrecognized federal and state tax benefits decreased in the first quarter of 2020 by approximately $411 million due to the settlement of a federal refund claim with IRS Appeals. The recognition of these tax benefits resulted in an increase in net income of $73 million in the first quarter of 2020, reflecting a decrease to income tax expense of $67 million.

(b)Tax positions prior to 2022 remained with Exelon and are not reflected in this table as of December 31, 2022. See discussion below under the Tax Matters Agreement for responsibility of taxes for this period.

Recognition of unrecognized tax benefits

The following table presents the unrecognized tax benefits that, if recognized, would decrease the effective tax rate:





December 31, 2022	$	29
December 31, 2021	39
December 31, 2020	39

Reasonably possible the total amount of unrecognized tax benefits could significantly increase or decrease within 12 months after the reporting date

No amounts are expected to significantly increase or decrease within 12 months after the reporting date.

Total amounts of interest and penalties recognized

We did not record material interest and penalty expense related to tax positions reflected in the Consolidated Balance Sheets. Interest expense and penalty expense are recorded in Interest expense, net and Other, net,

respectively, in Other income and deductions in the Consolidated Statements of Operations and Comprehensive Income.

Description of tax years open to assessment by major jurisdiction


Major Jurisdiction			Open Years(a)
Federal consolidated income tax returns			2010-2021
Illinois unitary corporate income tax returns			2012-2021
New Jersey separate corporate income tax returns			2017-2018
New Jersey combined corporate income tax returns			2019-2021
New York combined corporate income tax returns			2015-2021
Pennsylvania separate corporate income tax returns			2019-2021

__________

(a)Tax years open to assessment include years when we were consolidated by Exelon. See discussion below under the Tax Matters Agreement for responsibility of taxes of these open years.

Other Tax Matters

CENG Put Option

On August 6, 2021, we entered into a settlement agreement with EDF pursuant to which we purchased EDF’s equity interest in CENG. We recorded deferred tax liabilities of $288 million against Membership interest in the Consolidated Balance Sheet. The deferred tax liabilities represent the tax effect on the difference between the net purchase price and EDF’s noncontrolling interest as of August 6, 2021. The deferred tax liabilities will reverse during the remaining operating lives and during decommissioning of the CENG nuclear plants. See Note 2 – Mergers, Acquisitions, and Dispositions for additional information.

Allocation of Tax Benefits

Prior to separation, we were a party to an agreement with Exelon and other subsidiaries of Exelon that provided for the allocation of consolidated tax liabilities and benefits (Tax Sharing Agreement). The Tax Sharing Agreement provided that each party was allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. In addition, any net federal and state benefits attributable to Exelon were reallocated to the parties. That allocation was treated as a contribution from Exelon to the party receiving the benefit.

The following table presents the allocation of tax benefits from Exelon to us under the Tax Sharing Agreement:


December 31, 2021			64
December 31, 2020			64

Tax Matters Agreement

In connection with the separation, we entered into a Tax Matters Agreement (“TMA”) with Exelon. The TMA governs the respective rights, responsibilities, and obligations between us and Exelon after the separation with respect to tax liabilities and benefits, tax attributes, tax returns, tax contests and other tax sharing regarding U.S. federal, state, local and foreign income taxes, other tax matters and related tax returns.

Responsibility and Indemnification for Taxes. As a former subsidiary of Exelon, we have joint and several liability with Exelon to the IRS and certain state jurisdictions relating to the taxable periods that we were included in federal and state filings. However, the TMA specifies the portion of this tax liability for which we will bear contractual responsibility, and we and Exelon each agreed to indemnify each other against any amounts for which such indemnified party is not responsible. Specifically, we will be liable for taxes due and payable in connection with tax returns that we are required to file. We will also be liable for our share of certain taxes required to be paid by Exelon with respect to taxable years or periods (or portions thereof) ending on or prior to the separation to the extent that we would have been responsible for such taxes under the Exelon tax sharing agreement then existing. As such, our Consolidated Balance Sheets at separation reflected a payable of $103 million for tax liabilities where we maintain contractual responsibility to Exelon, with $53 million recognized

in Accounts payable and $50 million in Noncurrent other liabilities. As of December 31, 2022, we had $18 million in Other accounts receivable, no payables in Accounts payable and $50 million in Noncurrent other liabilities.

Tax Refunds and Attributes. The TMA provides for the allocation of certain pre-closing tax attributes between us and Exelon. Tax attributes will be allocated in accordance with the principles set forth in the existing Exelon tax sharing agreement, unless otherwise required by law. Under the TMA, we will be entitled to refunds for taxes for which we are responsible. In addition, it is expected that Exelon will have tax attributes that may be used to offset Exelon’s future tax liabilities. A significant portion of such attributes were generated by our business. Upon separation we reclassified $508 million from Deferred income taxes to reflect receivables of $11 million and $497 million in Other accounts receivable and Other deferred debits and other assets, respectively, in the Consolidated Balance Sheets for the tax attributes expected to be utilized by Exelon after separation in accordance with the terms of the TMA. As of December 31, 2022, we had $168 million in Other accounts receivable and $362 million in Other deferred debits and other assets for the reclassified tax attributes.

The entire disclosure for income taxes. Disclosures may include net deferred tax liability or asset recognized in an enterprise's statement of financial position, net change during the year in the total valuation allowance, approximate tax effect of each type of temporary difference and carryforward that gives rise to a significant portion of deferred tax liabilities and deferred tax assets, utilization of a tax carryback, and tax uncertainties information.

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Retirement Benefits

12 Months Ended

Dec. 31, 2022

Retirement Benefits [Abstract]

Retirement Benefits

Defined Benefit Pension and OPEB

Effective February 1, 2022, in connection with the separation, pension and OPEB obligations and the related plan assets for participants (inclusive of employees and certain former employees and their beneficiaries assigned to us from Exelon upon separation) were transferred to pension and OPEB plans established by us as the plan sponsor. Most current employees participate in the defined benefit pension and OPEB plans that we sponsor. Newly hired employees are generally not eligible for either pension or OPEB benefits; instead, these employees are eligible to receive an enhanced non-discretionary fixed employer contribution under our sponsored defined contribution savings plan.

As the plan sponsor, effective February 1, 2022, our Consolidated Balance Sheets reflect underfunded pension and OPEB liabilities equal to an excess of either the PBO or APBO over the fair value of the plan assets, consistent with a single employer benefit plan. We no longer account for our interest in Exelon sponsored pension and OPEB plans under the multi-employer benefit plan guidance as we are no longer participants. That previous approach historically resulted in the recognition of a net prepaid pension asset in our Consolidated Balance Sheets representing an excess of contributions over cumulative costs.

Benefit Obligations, Plan Assets, and Funded Status

As of February 1, 2022, we assumed from Exelon the PBO, APBO, and plan assets for our plan participants in connection with the separation. The defined benefit pension and OPEB plans were remeasured to determine the obligations and related plan assets to be transferred to us as of that date. The pension assets allocated to us were based on the rules prescribed by ERISA for transfers of assets in connection with a pension plan separation. A portion of the Exelon OPEB plan assets, which are held in VEBA trusts, were also allocated to us separately for each funding vehicle based on the ratio of the APBO assumed by us to the total APBO attributed to each funding vehicle.

The remeasurement completed at separation is reflected in the table below as a separation-related adjustment and resulted in the recognition of pension obligations of $953 million, net of pension plan assets of $8,267 million, and OPEB obligations of $876 million, net of OPEB plan assets of $904 million. Additionally, we recognized $2,006 million (after-tax) in Accumulated other comprehensive loss for actuarial losses and prior service costs that had accrued over the lives of the plans prior to separation, primarily based on our proportionate share of the total projected pension and OPEB obligations at Exelon prior to separation.

We use a December 31 measurement date for our pension and OPEB obligations and the related plan assets. The actuarial gains experienced upon remeasurement as of December 31, 2022 were offset against AOCI and attributable to increases in the discount rates used to measure the benefit obligations net of actual investment performance that was less than expected.

The following tables provide a rollforward of the changes in the benefit obligations and plan assets for the year ended December 31, 2022 for all plans combined:


	Pension Benefits		OPEB
Change in benefit obligation:
Benefit obligation as of the beginning of the year	$	—	$	847
Separation-related adjustment	9,220		933
Benefit obligation as of February 1, 2022	9,220		1,780
Service cost	115		23
Interest cost	269		52
Plan participants' contributions	—		20
Actuarial gain, net	(1,756)		(401)

Settlements	(15)		—
Gross benefits paid	(558)		(114)
Benefit obligation as of the end of year	$	7,275	$	1,360


	Pension Benefits		OPEB
Change in plan assets:
Prepaid pension asset as of the beginning of year	$	1,683	$	—
Separation-related adjustment	6,584		904
Fair value of net plan assets as of February 1, 2022	8,267		904
Actual return on plan assets	(1,245)		(99)
Employer contributions	211		—
Plan participants' contributions	—		15
Gross benefits paid	(558)		(86)
Settlements	(15)		—
Fair value of net plan assets as of the end of year	$	6,660	$	734

We present our benefit obligations net of plan assets on our Consolidated Balance Sheets within the following line items:


	Pension Benefits				OPEB
	2022		2021		2022		2021
Prepaid pension asset	$	—	$	1,683	$	—	$	—
Other current liabilities	(10)		—		(17)		—
Pension obligations	(605)		—		—		—
Non-pension postretirement benefit obligations	—		—		(609)		(847)
(Unfunded) funded status (net benefit obligation less plan assets)	$	(615)	$	1,683	$	(626)	$	(847)

The following table provides the ABO and fair value of plan assets for all pension plans with an ABO in excess of plan assets. Information for pension and OPEB plans with projected PBO and APBO, respectively, in excess of plan assets has been disclosed in the Obligations and Plan Assets table above as all pension and OPEB plans are underfunded.


ABO in Excess of Plan Assets	December 31, 2022
ABO	$	(7,121)
Fair value of net plan assets	6,660

Components of Net Periodic Benefit Costs (Credits)

We report the service cost and other non-service cost (credit) components of net periodic benefit costs (credits) for all plans separately in our Consolidated Statements of Operations and Comprehensive Income. Effective February 1, 2022, the service cost component will continue to be included in Operating and maintenance expense and Property, plant, and equipment, net (where criteria for capitalization of direct labor has been met) while the non-service cost (credit) components will now be included in Other, net, 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 majority of the 2022 pension benefit cost for the plan is calculated using an expected long-term rate of return on plan assets of 7.00% and a discount rate of 3.23%. The majority of the 2022 OPEB cost is calculated using an expected long-term rate of return on plan assets of 6.39% for funded plans and a discount rate of 3.21%.

The following table presents the components of our net periodic benefit costs (credits), prior to capitalization and co-owner allocations, for the years ended December 31, 2022, 2021 and 2020:


	Pension Benefits						OPEB						Total Pension Benefits and OPEB
	2022		2021(a)		2020(a)		2022		2021(a)		2020(a)		2022		2021(a)		2020(a)
Components of net periodic benefit cost (credit):
Service cost	$	126	$	145	$	137	$	25	$	29	$	34	$	151	$	174	$	171
Non-service components of pension benefits & OPEB cost (credit):
Interest cost	290		235		280		55		45		61		345		280		341
Expected return on assets	(565)		(493)		(474)		(55)		(58)		(62)		(620)		(551)		(536)
Amortization of:
Prior service cost (credit)	1		1		1		(7)		(9)		(49)		(6)		(8)		(48)
Actuarial loss (gain)	148		199		164		(1)		10		15		147		209		179
Settlement charges	6		20		9		—		—		(1)		6		20		8

Non-service components of pension benefits & OPEB credit(b)	(120)		(38)		(20)		(8)		(12)		(36)		(128)		(50)		(56)
Net periodic benefit cost (credit)(c)(d)(e)	$	6	$	107	$	117	$	17	$	17	$	(2)	$	23	$	124	$	115

__________

(a)Costs recognized for the years ended December 31, 2021 and 2020 were allocated to us by Exelon under the Exelon sponsored pension and OPEB plans prior to separation.

(b)Effective February 1, 2022, these non-service costs (credits) are reflected in Other, net in the Consolidated Statements of Operations and Comprehensive Income.

(c)The pension benefit and OPEB service costs reflected in the Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2022 totaled $131 million. The pension benefit and OPEB non-service credits reflected in the Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2022 totaled ($116) million.

(d)The pension benefit and OPEB service costs reflected in the Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2021 totaled $144 million. The pension benefit and OPEB non-service credits reflected in the Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2021 totaled ($50) million.

(e)The pension benefit and OPEB service costs reflected in the Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2020 totaled $140 million. The pension benefit and OPEB non-service credits reflected in the Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2020 totaled ($43) million.

Components of AOCI

We recognize the overfunded or underfunded status of defined benefit pension and OPEB plans as an asset or liability on our balance sheet, with offsetting entries to AOCI. An updated measurement was performed as of December 31, 2022, the impact of which was recognized in AOCI as an actuarial gain. The following tables provide the pre-tax components of AOCI for the year ended December 31, 2022, for all plans combined:


	Pension Benefits		OPEB
Changes in plan assets and benefit obligations recognized in AOCI:
Separation related adjustment	$	2,664	$	22
Current year actuarial (gain) loss	11		(253)
Amortization of actuarial (loss) gain	(134)		1

Amortization of prior service (cost) credit	(1)		7

Settlements	(6)		—
Total recognized in AOCI	$	2,534	$	(223)

The following table provides the components of gross accumulated other comprehensive loss that have not been recognized as components of periodic benefit cost as of December 31, 2022, for all plans combined:


	Pension Benefits		OPEB
Prior service cost (credit)	$	10	$	(30)
Actuarial loss (gain)	2,524		(193)
Total	$	2,534	$	(223)

Average Remaining Service Period

For pension benefits, we amortize the unrecognized prior service costs (credits) and certain actuarial gains and losses reflected in AOCI, as applicable, based on participants’ average remaining service periods.

For OPEB, we amortize the unrecognized prior service costs (credits) reflected in AOCI over participants’ average remaining service period to benefit eligibility age, and amortize certain actuarial gains and losses reflected in AOCI over participants’ average remaining service period to expected retirement.

The resulting average remaining service periods for pension and OPEB were as follows as of December 31, 2022:


			December 31, 2022
Pension plans			12.2
OPEB plans:
Benefit Eligibility Age			7.4
Expected Retirement			8.3

Assumptions

The measurement of the plan obligations and costs of providing benefits under our defined benefit pension and OPEB plans involves various factors, including the development of valuation assumptions and inputs and

accounting policy elections. The measurement of benefit obligations and costs is impacted by several assumptions and inputs, as shown below, among other factors. When developing the required assumptions, we consider historical information as well as future expectations.

Expected Rate of Return. In determining the EROA, we consider historical economic indicators (including inflation and GDP growth) that impact asset returns, as well as expectation regarding future long-term capital market performance, weighted by our target asset class allocations.

Discount Rate. The discount rates are determined by developing a spot rate curve based on the yield to maturity of a universe of high-quality non-callable (or callable with make whole provisions) bonds with similar maturities to the related pension and OPEB obligations. The spot rates are used to discount the estimated future benefit distribution amounts under the pension and OPEB plans. The discount rate is the single level rate that produces the same result as the spot rate curve. We utilize an analytical tool developed by our actuaries to determine the discount rates.

Mortality. The mortality assumption is composed of a base table that represents the current expectation of life expectancy of the population adjusted by an improvement scale that attempts to anticipate future improvements in life expectancy. At separation and upon remeasurement as of December 31, 2022, we utilized the mortality tables and projection scales released by the SOA.

The following assumptions were used to determine the benefit obligations for the plans as of December 31, 2022 and at separation. Assumptions used to determine year-end benefit obligations are the assumptions used to estimate the subsequent year’s net periodic benefit costs.


	Pension Benefits				OPEB
	December 31, 2022		February 1, 2022		December 31, 2022		February 1, 2022
Discount rate(a)	5.52	%	3.23	%	5.50	%	3.21	%
Investment crediting rate(b)	5.15	%	3.86	%	N/A		N/A
Rate of compensation increase	3.75	%	3.75	%	3.75	%	3.75	%
Mortality table	Pri-2012 table with MP-2021 improvement scale (adjusted)		Pri-2012 table with MP-2021 improvement scale (adjusted)		Pri-2012 table with MP-2021 improvement scale (adjusted)		Pri-2012 table with MP-2021 improvement scale (adjusted)
Healthcare cost trend on covered charges	N/A		N/A		Initial and ultimate rate of 5.00%		Initial and ultimate rate of 5.00%

__________

(a)The discount rates above represent the blended rates used to establish the majority of Constellation's pension and OPEB costs.

(b)The investment crediting rate above represents a weighted average rate.

Contributions

We consider various factors when making qualified pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act, and management of the pension obligation. The Pension Protection Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). The projected contributions below reflect a funding strategy to make levelized annual contributions with the objective of achieving 100% funded status over time. This level funding strategy helps minimize the volatility of future period required pension contributions. Based on this funding strategy and current market conditions, which are both subject to change, we made our annual qualified pension contribution totaling $192 million in February 2022.

Prior to separation, Exelon allocated contributions related to its legacy Exelon sponsored pension and OPEB plans to its subsidiaries based on accounting cost or employee participation (both active and retired). The following tables provide our contributions to the pension and OPEB plans:


Pension benefits				OPEB
2021		2020		2021		2020
$	231	$	236	$	28	$	19

Our non-qualified pension plans are not funded given that they are not subject to statutory minimum contribution requirements. OPEB plans are also not subject to statutory minimum contribution requirements, though we have funded certain plans. For our funded OPEB plans, we consider several factors in determining the level of contributions to these plans, including liabilities management and levels of benefit claims paid. The benefit payments to the non-qualified pension plans in 2022 were $20 million and the contributions to the OPEB plans, including benefit payments to unfunded plans were $26 million.

The following table provides our planned contributions to our qualified pension plans, non-qualified pension plans, and OPEB plans in 2023 (including our benefit payments related to unfunded plans):


	Qualified Pension Plans		Non-Qualified Pension Plans		OPEB
Planned contributions	$	21	$	10	$	17

Estimated Future Benefit Payments

Estimated future benefit payments to participants over the next ten years in all pension and OPEB plans as of December 31, 2022 are as follows:


	Pension Benefits		OPEB
2023	$	525	$	105
2024	531		105
2025	544		105
2026	541		105
2027	547		106
2028 through 2032	2,792		525
Total estimated future benefits payments through 2032	$	5,480	$	1,051

Plan Assets

On a regular basis, we evaluate our investment strategy to ensure that plan assets will be sufficient to pay plan benefits when due. We have developed and implemented a liability hedging investment strategy for our qualified pension plans that has reduced the volatility of these pension assets relative to the associated pension obligations. We are likely to continue to gradually increase the liability hedging portfolio as the funded status of the plans improve. The overall objective is to achieve attractive risk-adjusted returns that will balance with the liquidity requirements of the plans’ liabilities while striving to minimize the risk of significant losses. Trust assets for our OPEB plans are managed in a diversified investment strategy that prioritizes maximizing liquidity and returns while minimizing asset volatility.

Actual asset returns have an impact on the costs reported for the pension and OPEB plans. The actual asset returns across our pension and OPEB plans for the year ended December 31, 2022 were (18.40)% and (11.20)%, respectively, compared to an expected long-term return assumption of 7.00% and 6.39%, respectively. We used an EROA of 6.50% to estimate both our 2023 pension and OPEB costs.

Our pension and OPEB plan target asset allocations as of December 31, 2022 were as follows:


Asset Category	Pension Benefits		OPEB
Equity securities	21	%	43	%
Fixed income securities	54	%	45	%
Alternative investments(a)	25	%	12	%
Total	100	%	100	%

__________

(a)Alternative investments include private equity, hedge funds, real estate, and private credit.

We evaluated our pension and OPEB plans’ asset portfolios for the existence of significant concentrations of credit risk as of December 31, 2022. Types of concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, and individual fund. As of December 31, 2022, our pension and OPEB plans held no credit risk concentrations surpassing 10% of plan assets.

Fair Value Measurements

The following table presents pension and OPEB plan assets measured and recorded at fair value in our Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2022:


	December 31. 2022
	Level 1		Level 2		Level 3		Not subject to leveling		Total
Pension plan assets(a)
Cash equivalents	$	216	$	—	$	—	$	—	$	216
Equities(b)	776		—		—		368		1,144
Fixed income:
U.S. Treasury and agencies	693		128		—		—		821
State and municipal debt	—		44		—		—		44
Corporate debt	—		1,736		8		—		1,744
Other(b)	—		43		—		470		513
Fixed income subtotal	693		1,951		8		470		3,122
Private equity	—		—		180		585		765
Hedge funds	—		—		—		429		429
Real estate	—		—		—		547		547
Private credit	—		—		—		480		480
Pension plan assets subtotal	1,685		1,951		188		2,879		6,703

OPEB plan assets(a)
Cash equivalents	40		—		—		—		40
Equities	152		—		—		146		298
Fixed income:
U.S. Treasury and agencies	10		27		—		—		37
State and municipal debt	—		4		—		—		4
Corporate debt	—		27		—		—		27
Other	57		3		—		111		171
Fixed income subtotal	67		61		—		111		239

Hedge funds	—		—		—		59		59
Real estate	—		—		—		62		62
Private credit	—		—		—		36		36
OPEB plan assets subtotal	259		61		—		414		734
Total pension and OPEB plan assets(c)	$	1,944	$	2,012	$	188	$	3,293	$	7,437

__________

(a)See Note 18 — Fair Value of Financial Assets and Liabilities for a description of levels within the fair value hierarchy.

(b)Includes derivative instruments of $6 million for the year ended December 31, 2022, which have total notional amounts of $1,879 million as of December 31, 2022. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not represent the amount of the company’s exposure to credit or market loss.

(c)Excludes net liabilities of $43 million as of December 31, 2022, which include certain derivative assets that have notional amounts of $41 million as of December 31, 2022. These items are required to reconcile to the fair value of net plan assets and consist primarily of receivables or payables related to pending securities sales and purchases, and interest and dividends receivable.

The following table presents the reconciliation of Level 3 assets and liabilities measured at fair value for pension and OPEB plans for the year ended December 31, 2022:


Pension Assets	Fixed Income		Equities		Private Equity		Total
Balance as of January 1, 2022	$	—	$	—	$	—	$	—
Separation related adjustment	9		—		—		9
Actual return on plan assets:
Relating to assets still held as of the reporting date	(1)		—		(54)		(55)

Purchases and settlements:
Purchases	—		—		18		18

Settlements(a)	—		—		(4)		(4)
Transfers into Level 3(b)	—		—		220		220
Balance as of December 31, 2022	$	8	$	—	$	180	$	188

__________

(a)Represents cash settlements only.

(b)Includes certain private equity investments previously measured at fair value using NAV or its equivalent as a practical expedient at separation transferred to Level 3 primarily due to changes in market liquidity or data.

Valuation Techniques Used to Determine Fair Value

The techniques used to fair value the pension and OPEB assets invested in cash equivalents, equities, fixed income, derivatives, private equity, real estate, and private credit investments are the same as the valuation techniques for these types of investments in NDT funds. See Cash Equivalents and NDT Fund Investments in Note 18 — Fair Value of Financial Assets and Liabilities for further information.

Pension and OPEB assets also include investments in hedge funds. Hedge fund investments include those that employ a broad range of strategies to enhance returns and provide additional diversification. The fair value of hedge funds is determined using NAV or its equivalent as a practical expedient, and therefore, hedge funds are not classified within the fair value hierarchy. We have the ability to redeem these investments at NAV or its equivalent subject to certain restrictions which may include a lock-up period or a gate.

Defined Contribution Savings Plan

We sponsor the Constellation Employee Savings Plan, a 401(k) defined contribution savings plan consistent with those previously sponsored by Exelon. The plan allows employees to contribute a portion of their pre-tax and/or after-tax income in accordance with specified guidelines. We match a percentage of the employee contributions up to certain limits. In addition, certain employees are eligible for a fixed non-discretionary employer contribution in lieu of a pension benefit. The matching contributions to the savings plan were $90 million, $53 million and $63 million for the years ended December 31, 2022, December 31, 2021, and 2020, respectively.

The entire disclosure for retirement benefits.

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Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Financial Instruments

12 Months Ended

Dec. 31, 2022

Derivative Financial Instruments

We use derivative instruments to manage commodity price risk, interest rate risk, and foreign exchange risk related to ongoing business operations.

Authoritative guidance requires that derivative instruments be recognized as either assets or liabilities at fair value, with changes in fair value of the derivative recognized in earnings immediately. Other accounting treatments are available through special election and designation, provided they meet specific, restrictive criteria both at the time of designation and on an ongoing basis. These alternative permissible accounting treatments

include NPNS, cash flow hedges, and fair value hedges. All derivative economic hedges related to commodities, referred to as economic hedges, are recorded at fair value through earnings. For all NPNS derivative instruments, accounts receivable or accounts payable are recorded when derivatives settle and revenue or expense is recognized in earnings as the underlying physical commodity is sold or delivered.

Authoritative guidance about offsetting assets and liabilities requires the fair value of derivative instruments to be shown in the Combined Notes to Consolidated Financial Statements on a gross basis, even when the derivative instruments are subject to legally enforceable master netting agreements and qualify for net presentation in the Consolidated Balance Sheets. A master netting agreement is an agreement between two counterparties that may have derivative and non-derivative contracts with each other providing for the net settlement of all referenced contracts via one payment stream, which takes place as the contracts deliver, when collateral is requested or in the event of default. In the tables below, which present fair value balances, our energy-related economic hedges and proprietary trading derivatives are shown gross. The impact of the netting of fair value balances with the same counterparty that are subject to legally enforceable master netting agreements, as well as netting of cash collateral, including margin on exchange positions, is aggregated in the collateral and netting columns.

Our use of cash collateral is generally unrestricted unless we are downgraded below investment grade.

Commodity Price Risk

We employ established policies and procedures to manage our risks associated with market fluctuations in commodity prices by entering into physical and financial derivative contracts, including swaps, futures, forwards, options, and short-term and long-term commitments to purchase and sell energy and commodity products. We believe these instruments, which are either determined to be non-derivative or classified as economic hedges, mitigate exposure to fluctuations in commodity prices.

To the extent the amount of energy we produce or procure differs from the amount of energy we have contracted to sell, we are exposed to market fluctuations in the prices of electricity, natural gas and oil, and other commodities. We use a variety of derivative and non-derivative instruments to manage the commodity price risk of our electric generation facilities, including power and gas sales, fuel and power purchases, natural gas transportation and pipeline capacity agreements, and other energy-related products marketed and purchased. To manage these risks, we may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from expected sales of power and gas and purchases of power and fuel. The objectives for executing such hedges include fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return. We are also exposed to differences between the locational settlement prices of certain economic hedges and the hedged generating units. This price difference is actively managed through other instruments which include derivative congestion products, whose changes in fair value are recognized in earnings each period, and auction revenue rights, which are accounted for on an accrual basis.

Additionally, we are exposed to certain market risks through our proprietary trading activities. The proprietary trading activities are a complement to our energy marketing portfolio but represent a small portion of our overall energy marketing activities and are subject to limits established by our RMC.

The following tables provide a summary of the derivative fair value balances recorded as of December 31, 2022 and 2021:


December 31, 2022	Economic Hedges		Proprietary Trading		Collateral (a)(b)		Netting(a)		Total
Mark-to-market derivative assets (current assets)	$	15,296	$	10	$	161	$	(13,123)	$	2,344
Mark-to-market derivative assets (noncurrent assets)	5,100		—		217		(4,074)		1,243
Total mark-to-market derivative assets	20,396		10		378		(17,197)		3,587
Mark-to-market derivative liabilities (current liabilities)	(15,049)		(6)		374		13,123		(1,558)
Mark-to-market derivative liabilities (noncurrent liabilities)	(5,203)		—		146		4,074		(983)
Total mark-to-market derivative liabilities	(20,252)		(6)		520		17,197		(2,541)
Total mark-to-market derivative net assets	$	144	$	4	$	898	$	—	$	1,046

December 31, 2021
Mark-to-market derivative assets (current assets)	$	10,915	$	25	$	152	$	(8,923)	$	2,169
Mark-to-market derivative assets (noncurrent assets)	3,224		2		15		(2,298)		943
Total mark-to-market derivative assets	14,139		27		167		(11,221)		3,112
Mark-to-market derivative liabilities (current liabilities)	(10,143)		(19)		262		8,923		(977)
Mark-to-market derivative liabilities (noncurrent liabilities)	(2,893)		(1)		83		2,298		(513)
Total mark-to-market derivative liabilities	(13,036)		(20)		345		11,221		(1,490)
Total mark-to-market derivative net assets	$	1,103	$	7	$	512	$	—	$	1,622

_________

(a)We net all available amounts allowed in our Consolidated Balance Sheets in accordance with authoritative guidance for derivatives. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases we may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, letters of credit and other forms of non-cash collateral. These amounts are not material as of December 31, 2022 and 2021 and not reflected in the table above.

(b)Includes $836 million and $897 million of variation margin held from the exchanges as of December 31, 2022 and 2021, respectively.

Economic Hedges (Commodity Price Risk)

For the years ended December 31, 2022, 2021, and 2020, we recognized the following net pre-tax commodity mark-to-market gains (losses) which are also located in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows.


	Gains (Losses)
Income Statement Location	2022		2021		2020

Operating revenues	$	(1,193)	$	(635)	$	112
Purchased power and fuel	167		1,206		168
Total	$	(1,026)	$	571	$	280

In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on owned and contracted generation positions that have not been hedged. For merchant revenues not already hedged via comprehensive state programs, such as the CMC in Illinois, we typically utilize a three-year ratable sales plan to align our hedging strategy with our financial objectives. The prompt three-year merchant revenues are hedged on an approximate rolling 90%/60%/30% basis. We may also enter into transactions that are outside of this ratable hedging program. As of December 31, 2022, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York, and ERCOT reportable segments is 94%-97% and 75%-78% for 2023 and 2024, respectively.

Proprietary Trading (Commodity Price Risk)

We also execute commodity derivatives for proprietary trading purposes. Proprietary trading includes all contracts executed with the intent of benefiting from shifts or changes in market prices as opposed to those

executed with the intent of hedging or managing risk. Gains and losses associated with proprietary trading are reported as Operating revenues in the Consolidated Statements of Operations and Comprehensive Income and are included in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows. For the years ended December 31, 2022, 2021, and 2020, net pre-tax commodity mark-to-market gains and losses were not material.

Interest Rate and Foreign Exchange Risk

We utilize interest rate swaps to manage our interest rate exposure and foreign currency derivatives to manage foreign exchange rate exposure associated with international commodity purchases in currencies other than U.S. dollars, both of which are treated as economic hedges. The notional amounts were $524 million and $486 million as of December 31, 2022 and 2021, respectively.

The following table provides the mark-to-market derivative assets and liabilities as of December 31, 2022:


December 31, 2022	Economic Hedges		Netting(a)		Total
Mark-to-market derivative assets (current assets)	$	29	$	(5)	$	24
Mark-to-market derivative assets (noncurrent assets)	18		—		18
Total mark-to-market derivative assets	47		(5)		42
Mark-to-market derivative liabilities (current liabilities)	(5)		5		—
Mark-to-market derivative liabilities (noncurrent liabilities)	—		—		—
Total mark-to-market derivative liabilities	(5)		5		—
Total mark-to-market derivative net assets	$	42	$	—	$	42

_________

(a)We net all available amounts in our Consolidated Balance Sheets in accordance with authoritative guidance for derivatives. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements.

The mark-to-market derivative assets and liabilities as of December 31, 2021 were not material.

The mark-to-market gains and losses associated with management of interest rate and foreign currency exchange rate risk for the years ended December 31, 2022, 2021, and 2020 were not material.

Credit Risk

We would be exposed to credit-related losses in the event of non-performance by counterparties on executed derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts as of the reporting date.

For commodity derivatives, we enter into enabling agreements that allow for payment netting with our counterparties, which reduces our exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. Typically, each enabling agreement is for a specific commodity and, with respect to each individual counterparty, netting is limited to transactions involving that specific commodity product, except where master netting agreements exist with a counterparty that allows for cross product netting. In addition to payment netting language in the enabling agreement, our credit department establishes credit limits, margining thresholds and collateral requirements for each counterparty, which are defined in the derivative contracts. Counterparty credit limits are based on an internal credit review process that considers a variety of factors, including the results of a scoring model, leverage, liquidity, profitability, credit ratings by credit rating agencies, and risk management capabilities. To the extent that a counterparty’s margining thresholds are exceeded, the counterparty is required to post collateral with us as specified in each enabling agreement. Our credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis.

The following tables provide information on the credit exposure for all derivative instruments, NPNS and payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of December 31, 2022. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties. The amounts in the tables below exclude

credit risk exposure from individual retail counterparties, nuclear fuel procurement contracts, and exposure through RTOs, ISOs, NYMEX, ICE, NASDAQ, NGX, and Nodal commodity exchanges.


Rating as of December 31, 2022	Total Exposure Before Credit Collateral		Credit Collateral(a)		Net Exposure		Number of Counterparties Greater than 10% of Net Exposure	Net Exposure of Counterparties Greater than 10% of Net Exposure
Investment grade	$	1,304	$	135	$	1,169	—	$	—
Non-investment grade	110		88		22		—	—
No external ratings
Internally rated — investment grade	106		—		106		—	—
Internally rated — non-investment grade	374		40		334		—	—
Total	$	1,894	$	263	$	1,631	—	$	—


Net Credit Exposure by Type of Counterparty	As of December 31, 2022
Investor-owned utilities, marketers, power producers	$	1,311
Energy cooperatives and municipalities	112
Financial Institutions	9
Other	199
Total	$	1,631

__________

(a)As of December 31, 2022, credit collateral held from counterparties where we had credit exposure included $152 million of cash and $111 million of letters of credit. The credit collateral does not include non-liquid collateral.

Credit-Risk-Related Contingent Features

As part of the normal course of business, we routinely enter into physically or financially settled contracts for the purchase and sale of electric capacity, electricity, fuels, emissions allowances, and other energy-related products. Certain of our derivative instruments contain provisions that require us to post collateral. We also enter into commodity transactions on exchanges where the exchanges act as the counterparty to each trade. Transactions on the exchanges must adhere to comprehensive collateral and margining requirements. This collateral may be posted in the form of cash or credit support with thresholds contingent upon our credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit-risk related contingent features stipulate that if we were to be downgraded or lose our investment grade credit rating (based on our senior unsecured debt rating), we would be required to provide additional collateral. This incremental collateral requirement allows for the offsetting of derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. In this case, we believe an amount of several months of future payments (i.e., capacity payments) rather than a calculation of fair value is the best estimate for the contingent collateral obligation, which has been factored into the disclosure below.

The aggregate fair value of all derivative instruments with credit-risk-related contingent features in a liability position that are not fully collateralized (excluding transactions on the exchanges that are fully collateralized) is detailed in the table below:


	As of December 31,
Credit-Risk-Related Contingent Features	2022		2021
Gross fair value of derivative contracts containing this feature(a)	$	(4,736)	$	(3,872)
Offsetting fair value of in-the-money contracts under master netting arrangements(b)	2,048		2,424
Net fair value of derivative contracts containing this feature(c)	$	(2,688)	$	(1,448)

__________

(a)Amount represents the gross fair value of out-of-the-money derivative contracts containing credit-risk-related contingent features ignoring the effects of master netting agreements.

(b)Amount represents the offsetting fair value of in-the-money derivative contracts under legally enforceable master netting agreements with the same counterparty, which reduces the amount of any liability for which we could potentially be required to post collateral.

(c)Amount represents the net fair value of out-of-the-money derivative contracts containing credit-risk-related contingent features after considering the mitigating effects of offsetting positions under master netting arrangements and reflects the actual net liability upon which any potential contingent collateral obligations would be based.

As of December 31, 2022 and 2021, we posted or held the following amounts of cash collateral and letters of credit on derivative contracts with external counterparties, after giving consideration to offsetting derivative and non-derivative positions under master netting agreements.


	As of December 31,
	2022		2021
Cash collateral posted(a)	$	1,636	$	713
Letters of credit posted(a)	947		755
Cash collateral held(a)	765		182
Letters of credit held(a)	115		124
Additional collateral required in the event of a credit downgrade below investment grade (at BB+/Ba1)(b)(c)	3,337		2,113

_________

(a)The cash collateral and letters of credit amounts are inclusive of NPNS contracts.

(b)Certain of our contracts contain provisions that allow a counterparty to request additional collateral when there has been a subjective determination that our credit quality has deteriorated, generally termed “adequate assurance.” Due to the subjective nature of these provisions, we estimate the amount of collateral that we may ultimately be required to post in relation to the maximum exposure with the counterparty.

(c)The downgrade collateral is inclusive of all contracts in a liability position regardless of accounting treatment.

We entered into supply forward contracts with certain utilities with one-sided collateral postings only from us. If market prices fall below the benchmark price levels in these contracts, the utilities are not required to post collateral. However, when market prices rise above the benchmark price levels, counterparty suppliers, including us, are required to post collateral once certain unsecured credit limits are exceeded.

Debt and Credit Agreements

12 Months Ended

Dec. 31, 2022

Debt Disclosure [Abstract]

Debt and Credit Agreements

Short-Term Borrowings

We meet our short-term liquidity requirements primarily through the issuance of commercial paper. We may use our credit facility for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.

Commercial Paper

The following table reflects our commercial paper program supported by the revolving credit agreements as of December 31, 2022 and 2021:


Maximum Program Size at December 31,				Outstanding Commercial Paper at December 31,				Weighted Average Interest Rate on Commercial Paper Borrowings at December 31,
2022(a)(b)(c)		2021(a)(d)		2022		2021		2022		2021
$	3,500	$	5,300	$	959	$	702	4.90	%	0.66	%

__________

(a)Excludes $1,200 million in bilateral credit facilities as of December 31, 2022 and 2021, and $131 million in credit facilities for project finance as of both December 31, 2022 and 2021, respectively. These credit facilities do not back our commercial paper program.

(b)Excludes the liquidity facility, which has a bank commitment of $971 million as of December 31, 2022. This credit facility does not back our commercial paper program.

(c)Excludes customer accounts receivable Facility that has total capacity of $1.1 billion as of December 31, 2022. See Note 6 — Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information.

(d)Excludes $44 million of credit facility agreements arranged at minority and community banks as of December 31, 2021. These facilities expired on October 7, 2022 and were solely utilized to issue letters of credit.

In order to maintain our commercial paper program in the amounts indicated above, we must have a credit facility in place, at least equal to the amount of our commercial paper program. We do not issue commercial paper in an aggregate amount exceeding the then available capacity under our credit facility.

Credit Agreements

In connection with our separation from Exelon, we entered into two new credit agreements that replaced our $5.3 billion syndicated revolving credit facility. On February 1, 2022, we entered into a new credit agreement establishing a $3.5 billion five-year revolving credit facility at a variable interest rate of SOFR plus 1.275% and on February 9, 2022 we entered into a $1 billion five-year liquidity facility with the primary purpose of supporting our letter of credit issuances. Many of our bilateral credit agreements remain in effect. See below for additional details.

As of December 31, 2022, and 2021 we had the following aggregate bank commitments, credit facility borrowings and available capacity under our respective credit facilities:


							Available Capacity as of December 31, 2022
Facility Type	Aggregate Bank Commitment		Facility Draws		Outstanding Letters of Credit		Actual			To Support Additional Commercial Paper
Syndicated Revolver	$	3,500	$	—	$	765	$	2,735		$	1,776
Bilaterals	1,200		—		867		333			—
Liquidity Facility	971		—		732		139		(a)	—
Project Finance	131		—		111		20			—
Total	$	5,802	$	—	$	2,475	$	3,227		$	1,776

__________

(a)The maximum amount of the bank commitment is not to exceed $971 million. The aggregate available capacity of the facility is subject to market fluctuations based on the value of U.S Treasury Securities which determines the amount of collateral held in the trust. We may post additional collateral to borrow up to the maximum bank commitment. As of December 31, 2022, without posting additional collateral, the actual availability of facility, prior to outstanding letters of credit was $871 million.


							Available Capacity as of December 31, 2021
Facility Type	Aggregate Bank Commitment(b)		Facility Draws		Outstanding Letters of Credit		Actual		To Support Additional Commercial Paper
Syndicated Revolver(a)	$	5,300	$	—	$	1,230	$	4,070	$	3,368
Bilaterals	1,200		—		1,029		171		—
Project Finance	131		—		116		15		—
Total	$	6,631	$	—	$	2,375	$	4,256	$	3,368

__________

(a)Our syndicated revolving credit facility was replaced by the $3.5 billion 5-year revolving credit agreement entered into on February 1, 2022 in connection with the separation.

(b)Excludes $44 million of credit facility agreements arranged at minority and community banks. These facilities expired on October 7, 2022 and were solely utilized to issue letters of credit. As of December 31, 2021, letters of credit issued under these facilities totaled $5 million.

Bilateral Credit Agreements

The following table reflects the bilateral credit agreements at December 31, 2022:

Date Initiated

Latest Amendment Date

Maturity Date(a)

Amount

January 5, 2016

(b)

April 2, 2021

April 5, 2023

150

October 25, 2019

(b)

N/A

200

November 20, 2019

(b)

N/A

300

November 21, 2019

(b)

N/A

100

November 21, 2019

(b)

November 15, 2022

November 21, 2024

100

May 15, 2020

(b)(d)

February 9, 2022

N/A

200

August 12, 2022

(b)

N/A

August 24, 2022

(b)(c)

N/A

August 23, 2024

100

__________

(a)Credit facilities that do not contain a maturity date are specific to the agreements set within each contract. In some instances, credit facilities are automatically renewed based on the contingency standards set within the specific agreement.

(b)Bilateral credit agreements solely support the issuance of letters of credit and do not back our commercial paper program.

(c)On January 20, 2023, the bilateral credit agreement decreased to $10 million.

(d)On January 31, 2023, the bilateral credit agreement increased to $250 million.

Borrowings under our revolving credit agreement bear interest at a rate based upon either the Daily Simple SOFR rate or a Term SOFR rate, plus an adder based upon our credit rating. The adders for the Daily Simple SOFR based borrowings and Term SOFR borrowings are 27.5 basis points and 127.5 basis points, respectively.

If we lose our investment grade rating, the maximum adders for Daily Simple SOFR rate borrowings and Term SOFR rate borrowings would be 100 basis points and 200 basis points, respectively. The credit agreements also require us to pay facility fees based upon the aggregate commitments. The fee varies depending upon our credit rating.

Short-Term Loan Agreements

On March 19, 2020, we entered into a term loan agreement for $200 million. The loan agreement was renewed on March 17, 2021 with an expiration of March 16, 2022. Pursuant to the loan agreement, loans made thereunder beared interest at a variable rate equal to LIBOR plus 0.875% and all indebtedness thereunder was unsecured. In connection with the separation, we repaid the term loan on January 26, 2022. The loan agreement was reflected in Short-term borrowings in the Consolidated Balance Sheets as of December 31, 2021.

On March 31, 2020, we entered into a term loan agreement for $300 million. We repaid $100 million of the term loan on March 29, 2022. The remaining $200 million from the loan agreement was renewed on March 29, 2022 and will expire on March 29, 2023. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to SOFR plus 0.80% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Short-term borrowings in the Consolidated Balance Sheets.

On August 6, 2021, we entered into a 364-day term loan agreement for $880 million to fund the purchase of EDF's equity interest in CENG. Pursuant to the loan agreement, loans made thereunder beared interest at a variable rate of LIBOR plus 0.875% until March 31, 2022 and a rate of LIBOR plus 1% thereafter, and all indebtedness thereunder was unsecured. The loan agreement was amended on January 24, 2022 to change the maturity date from August 5, 2022 to June 30, 2022. We repaid the term loan on April 15, 2022. The loan was reflected in Short-term borrowings in the Consolidated Balance Sheets as of December 31, 2021. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information.

On January 26, 2023, we entered into a term loan agreement for $100 million. The loan agreement has an expiration of January 24, 2024. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to SOFR plus 0.8% and all indebtedness thereunder is unsecured.

On February 9, 2023, we entered into a term loan agreement for $400 million. The loan agreement has an expiration of February 8, 2024. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to SOFR plus 1.05% and all indebtedness thereunder is unsecured.

Long-Term Debt

The following table presents the outstanding long-term debt as of December 31, 2022 and 2021:


						Maturity Date	December 31,
	Rates						2022		2021
Long-term debt
Senior unsecured notes	3.25	%	-	6.25	%	2025 - 2042	$	2,938	$	4,219



Notes payable and other	2.10	%	-	6.96	%	2023 - 2028	68		103
Nonrecourse debt:
Fixed rates	2.29	%	-	6.00	%	2031 - 2037	839		909
Variable rates	2.99	%	-	7.24	%	2026 - 2027	805		870
Total long-term debt							4,650		6,101
Unamortized debt discount and premium, net							(5)		(7)
Unamortized debt issuance costs							(36)		(42)
Fair value adjustment							—		62
Long-term debt due within one year							(143)		(1,220)
Long-term debt							$	4,466	$	4,894

Long-term debt maturities in the periods 2023 through 2027 and thereafter are as follows:


2023	$	143
2024	110
2025	986
2026	121
2027	735
Thereafter	2,555
Total	$	4,650

Long-Term Debt from Affiliates

In connection with the debt obligations assumed by Exelon as part of the 2012 merger, Exelon and our subsidiaries assumed intercompany loan agreements that mirror the terms and amounts of the third-party debt obligations of Exelon, resulting in intercompany notes payable to Exelon. As of December 31, 2021, we had $319 million recorded to intercompany notes payable to Exelon. In connection with the separation, on January 31, 2022, we paid cash to Exelon in the amount of $258 million to settle the intercompany loan. See Note 1 — Basis of Presentation for additional information.

Debt Covenants

As of December 31, 2022, we are in compliance with all debt covenants.

Nonrecourse Debt

We have also issued nonrecourse debt, for which approximately $2 billion of generating assets have been pledged as collateral as of December 31, 2022. Borrowings under these agreements are secured by the assets and equity of each respective project. The lenders do not have recourse against us in the event of a default. If a specific project financing entity does not maintain compliance with its specific nonrecourse debt covenants, there could be a requirement to accelerate repayment of the associated debt or other borrowings earlier than the stated maturity dates. In these instances, if such repayment was not satisfied, the lenders or security holders would generally have rights to foreclose against the project-specific assets and related collateral. The potential requirement to satisfy the associated debt or other borrowings earlier than otherwise anticipated could lead to impairments due to a higher likelihood of disposing of the respective project-specific assets significantly before the end of their useful lives.

Antelope Valley Solar Ranch One. In December 2011, the DOE Loan Programs Office issued a guarantee for up to $646 million for a nonrecourse loan from the Federal Financing Bank to support the financing of the construction of the Antelope Valley facility. The project became fully operational in 2014. The loan will mature on January 5, 2037. Interest rates on the loan were fixed upon each advance at a spread of 37.5 basis points above U.S. Treasuries of comparable maturity. The advances were completed as of December 31, 2015 and the outstanding loan balance bears interest at an average blended interest rate of 2.82%. As of December 31, 2022 and 2021, approximately $415 million and $435 million were outstanding, respectively. In addition, we have issued letters of credit to support the equity investment in the project, with $37 million outstanding as of December 31, 2022. In December 2017, our interests in Antelope Valley were contributed to and are pledged as collateral for the CR financing structures referenced below.

Continental Wind, LLC. In September 2013, Continental Wind, our indirect subsidiary, completed the issuance and sale of $613 million senior secured notes. Continental Wind owns and operates a portfolio of wind farms in Idaho, Kansas, Michigan, Oregon, New Mexico and Texas with a total net capacity of 667 MWs. The net proceeds were distributed to us for general business purposes. The notes are scheduled to mature on February 28, 2033. The notes bear interest at a fixed rate of 6.00% with interest payable semi-annually. As of December 31, 2022 and December 31, 2021, approximately $345 million and $380 million were outstanding, respectively.

In addition, Continental Wind has a $122 million letter of credit facility and $4 million working capital revolver facility. Continental Wind has issued letters of credit to satisfy certain of its credit support and security obligations. As of December 31, 2022, the Continental Wind letter of credit facility had $111 million in letters of credit outstanding related to the project.

In 2017, our interests in Continental Wind were contributed to CRP. Refer to Note 22 - Variable Interest Entities for additional information on CRP.

Renewable Power Generation. In March 2016, RPG, our indirect subsidiary, issued $150 million aggregate principal amount of nonrecourse senior secured notes. The net proceeds were distributed to us for paydown of long term debt obligations at Sacramento PV Energy and Constellation Solar Horizons and for general business purposes. The loan is scheduled to mature on March 31, 2035. The term loan bears interest at a fixed rate of 4.11% payable semi-annually. As of December 31, 2022 and December 31, 2021, approximately $80 million and $90 million were outstanding, respectively. In 2017, our interests in RPG were contributed to CRP. Refer to Note 22 - Variable Interest Entities for additional information on CRP.

Constellation Renewables. In November 2017, CR, our indirect subsidiary, entered into an $850 million nonrecourse senior secured term loan credit facility agreement with a maturity date of November 28, 2024. In addition to the financing, CR entered into interest rate swaps with an initial notional amount of $636 million at an interest rate of 2.32% to manage a portion of the interest rate exposure in connection with the financing.

In December 2020, CR entered into a financing agreement for a $750 million nonrecourse senior secured term loan credit facility, scheduled to mature on December 15, 2027. The term loan bears interest at a variable rate equal to LIBOR plus 2.50%, subject to a 1% LIBOR floor with interest payable quarterly. In addition to the financing, CR entered into interest rate swaps with an initial notional amount of $516 million at an interest rate of 1.05% to manage a portion of the interest rate exposure in connection with the financing.

The proceeds were used to repay the November 2017 nonrecourse senior secured term loan credit facility of $850 million, of which $709 million was outstanding as of the retirement date in December 2020, and to settle the November 2017 interest rate swap. Our interests in CRP and Antelope Valley remain contributed to and pledged as collateral for this financing. As of December 31, 2022 and 2021, $690 million and $735 million was outstanding, respectively. See Note 22 — Variable Interest Entities for additional information on CRP and Note 16 — Derivative Financial Instruments for additional information on interest rate swaps.

West Medway II, LLC. On May 13, 2021, West Medway II, LLC (West Medway II), our indirect subsidiary, entered into a financing agreement for a $150 million nonrecourse senior secured term loan credit facility with a maturity date of March 31, 2026. The term loan bears interest at an average blended interest rate of LIBOR plus 3%, paid quarterly. In addition to the financing, West Medway II, entered into interest rate swaps with an initial notional amount of $113 million at an interest rate of 0.61%, paid quarterly, to manage a portion of the interest rate exposure in connection with the financing. We used the net proceeds for general corporate purposes. Our

interests in West Medway II, were pledged as collateral for this financing. As of December 31, 2022 and 2021, approximately $115 million and $135 million was outstanding, respectively. See Note 16 — Derivative Financial Instruments for additional information on interest rate swaps.

The entire disclosure for information about short-term and long-term debt arrangements, which includes amounts of borrowings under each line of credit, note payable, commercial paper issue, bonds indenture, debenture issue, own-share lending arrangements and any other contractual agreement to repay funds, and about the underlying arrangements, rationale for a classification as long-term, including repayment terms, interest rates, collateral provided, restrictions on use of assets and activities, whether or not in compliance with debt covenants, and other matters important to users of the financial statements, such as the effects of refinancing and noncompliance with debt covenants.

Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef
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Reference 2: http://www.xbrl.org/2003/role/disclosureRef
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-Name Accounting Standards Codification
-Topic 470
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-Section 50
-Paragraph 1B
-Subparagraph (h)
-URI https://asc.fasb.org/extlink&oid=123466505&loc=SL123495323-112611

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
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-Name Accounting Standards Codification
-Topic 470
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Reference 4: http://www.xbrl.org/2003/role/disclosureRef
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Reference 5: http://www.xbrl.org/2003/role/disclosureRef
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Reference 6: http://www.xbrl.org/2003/role/disclosureRef
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-Name Accounting Standards Codification
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Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
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-URI https://asc.fasb.org/extlink&oid=123466505&loc=SL123495323-112611

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
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Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
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-Section 50
-Paragraph 1C
-Subparagraph (a)
-URI https://asc.fasb.org/extlink&oid=123466505&loc=SL123495334-112611

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 11: http://www.xbrl.org/2003/role/disclosureRef
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Reference 12: http://www.xbrl.org/2003/role/disclosureRef
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Reference 13: http://www.xbrl.org/2003/role/disclosureRef
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Fair Value of Financial Assets and Liabilities

Fair Value of Financial Assets and Liabilities

12 Months Ended

Dec. 31, 2022

Fair Value Disclosures [Abstract]

We measure and classify fair value measurements in accordance with the hierarchy as defined by GAAP. The hierarchy prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:

•Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that we have the ability to liquidate as of the reporting date.

•Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data.

•Level 3 — unobservable inputs, such as internally developed pricing models or third-party valuations for the asset or liability due to little or no market activity for the asset or liability.

Fair Value of Financial Liabilities Recorded at Amortized Cost

The following tables present the carrying amounts and fair values of the short-term liabilities, long-term debt, and the SNF obligation as of December 31, 2022 and 2021. We have no financial liabilities classified as Level 1.

The carrying amounts of the short-term liabilities as presented in the Consolidated Balance Sheets are representative of their fair value (Level 2) because of the short-term nature of these instruments.


	December 31, 2022								December 31, 2021
	Carrying Amount		Fair Value						Carrying Amount		Fair Value
			Level 2		Level 3		Total				Level 2		Level 3		Total
Long-Term Debt, including amounts due within one year	$	4,609	$	3,688	$	859	$	4,547	$	6,114	$	5,749	$	1,093	$	6,842
SNF Obligation	1,230		1,021		—		1,021		1,210		1,060		—		1,060

We use the following methods and assumptions to estimate fair value of financial liabilities recorded at carrying cost:


Type	Level	Valuation
Long-term Debt, including amounts due within one year
Taxable Debt Securities	2	The fair value is determined by a valuation model that is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. We obtain credit spreads based on trades of our existing debt securities as well as other issuers in the utility sector with similar credit ratings. The yields are then converted into discount rates of various tenors that are used for discounting the respective cash flows of the same tenor for each bond or note.
Variable Rate Financing Debt	2	Debt rates are reset on a regular basis and the carrying value approximates fair value.
Government Backed Fixed Rate Project Financing Debt	3	The fair value is similar to the process for taxable debt securities. Due to the lack of market trading data on similar debt, the discount rates are derived based on the original loan interest rate spread to the applicable U.S. Treasury rate as well as a current market curve derived from government-backed securities.
Non-Government Backed Fixed Rate Nonrecourse Debt	3	Fair value is based on market and quoted prices for its own and other nonrecourse debt with similar risk profiles. Given the low trading volume in the nonrecourse debt market, the price quotes used to determine fair value will reflect certain qualitative factors, such as market conditions, investor demand, new developments that might significantly impact the project cash flows or off-taker credit, and other circumstances related to the project.
SNF Obligation
SNF Obligation	2	The carrying amount is derived from a contract with the DOE to provide for disposal of SNF from certain of our nuclear generating stations. See Note 19 — Commitments and Contingencies for further details. When determining the fair value of the obligation, the future carrying amount of the SNF obligation is calculated by compounding the current book value of the SNF obligation at the 13-week U.S. Treasury rate. The compounded obligation amount is discounted back to present value using our discount rate, which is calculated using the same methodology as described above for the taxable debt securities, and an estimated maturity date of 2035.

Recurring Fair Value Measurements

The following tables present assets and liabilities measured and recorded at fair value in the Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2022 and 2021:


	As of December 31, 2022										As of December 31, 2021
	Level 1		Level 2		Level 3		Not subject to leveling		Total		Level 1		Level 2		Level 3		Not subject to leveling		Total
Assets
Cash equivalents(a)	$	41	$	—	$	—	$	—	$	41	$	113	$	—	$	—	$	—	$	113
NDT fund investments
Cash equivalents(b)	349		88		—		—		437		465		116		—		—		581
Equities	3,462		1,498		—		1,421		6,381		4,564		1,805		—		1,645		8,014
Fixed income
Corporate debt(c)	—		885		264		—		1,149		—		1,145		286		—		1,431
U.S. Treasury and agencies	1,996		46		—		—		2,042		2,193		30		—		—		2,223
Foreign governments	—		39		—		—		39		—		60		—		—		60
State and municipal debt	—		53		—		—		53		—		26		—		—		26
Other	21		21		—		1,649		1,691		29		23		—		1449		1,501
Fixed income subtotal	2,017		1,044		264		1,649		4,974		2,222		1,284		286		1,449		5,241
Private credit	—		—		159		643		802		—		—		178		624		802
Private equity	—		—		—		687		687		—		—		—		673		673
Real estate	—		—		—		1,014		1,014		—		—		—		864		864

NDT fund investments subtotal(d)(e)	5,828		2,630		423		5,414		14,295		7,251		3,205		464		5,255		16,175
Rabbi trust investments
Cash equivalents	1		—		—		—		1		3		—		—		—		3
Mutual funds	39		—		—		—		39		36		—		—		—		36
Life insurance contracts	—		27		1		—		28		—		33		—		—		33
Rabbi trust investments subtotal	40		27		1		—		68		39		33		—		—		72
Investments in equities	6		—		—		—		6		43		—		—		—		43
Commodity derivative assets
Economic hedges	3,505		11,353		5,585		—		20,443		3,017		7,223		3,899		—		14,139
Proprietary trading	—		4		6		—		10		—		19		8		—		27
Effect of netting and allocation of collateral(f)(g)	(2,951)		(10,348)		(3,525)		—		(16,824)		(2,108)		(6,177)		(2769)		—		(11,054)
Commodity derivative assets subtotal	554		1,009		2,066		—		3,629		909		1,065		1,138		—		3,112
DPP consideration	—		515		—		—		515		—		365		—		—		365
Total assets	6,469		4,181		2,490		5,414		18,554		8,355		4,668		1,602		5,255		19,880

Liabilities
Commodity derivative liabilities
Economic hedges	(3,171)		(11,498)		(5,588)		—		(20,257)		(2,201)		(6,870)		(3,965)		—		(13,036)
Proprietary trading	—		(4)		(2)		—		(6)		—		(18)		(2)		—		(20)
Effect of netting and allocation of collateral(f)(g)	3,279		10,700		3,743		—		17,722		2,189		6,642		2,735		—		11,566
Commodity derivative liabilities subtotal	108		(802)		(1,847)		—		(2,541)		(12)		(246)		(1,232)		—		(1,490)
Deferred compensation obligation	—		(57)		—		—		(57)		—		(43)		—		—		(43)
Total liabilities	108		(859)		(1,847)		—		(2,598)		(12)		(289)		(1,232)		—		(1,533)
Total net assets	$	6,577	$	3,322	$	643	$	5,414	$	15,956	$	8,343	$	4,379	$	370	$	5,255	$	18,347

__________

(a)CEG Parent has $49 million of Level 1 cash equivalents as of December 31, 2022. We exclude cash of $390 million and $417 million as of December 31, 2022 and December 31, 2021, respectively, and restricted cash of $70 million and $46 million as of December 31, 2022 and December 31, 2021, respectively. CEG Parent has excluded an additional $19 million of cash as of December 31, 2022.

(b)Includes $99 million and $116 million of cash received from outstanding repurchase agreements as of December 31, 2022 and 2021, respectively, and is offset by an obligation to repay upon settlement of the agreement as discussed in (e) below.

(c)Includes investments in equities sold short of ($45) million and ($55) million as of December 31, 2022 and 2021, respectively, held in an investment vehicle primarily to hedge the equity option component of convertible debt.

(d)Includes net derivative assets of $1 million and net derivative liabilities of $1 million, which have total notional amounts of $494 million and $687 million as of December 31, 2022 and 2021, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the periods ended and do not represent the amount of our exposure to credit or market loss.

(e)Excludes net liabilities of $168 million and $111 million as of December 31, 2022 and 2021, respectively, which include certain derivative assets that have notional amounts of $59 million and $182 million as of December 31, 2022 and 2021, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, repurchase agreement obligations, and payables related to pending securities purchases. The repurchase agreements are generally short-term in nature with durations generally of 30 days or less.

(f)Net collateral posted to counterparties totaled $328 million, $352 million, and $218 million allocated to Level 1, Level 2, and Level 3 mark-to-market derivatives, respectively, as of December 31, 2022. Net collateral posted to/(received from) counterparties totaled $81 million, $465 million, and ($34) million allocated to Level 1, Level 2, and Level 3 mark-to-market derivatives, respectively, as of December 31, 2021.

(g)Includes $836 million and $897 million of variation margin held from the exchanges as of December 31, 2022 and 2021, respectively.

As of December 31, 2022, we have outstanding commitments to invest in private credit, private equity, and real estate investments of $235 million, $139 million, and $392 million, respectively. These commitments will be funded by our existing NDT funds.

We hold investments without readily determinable fair values with carrying amounts of $46 million and $33 million as of December 31, 2022 and 2021, respectively. Changes in fair value, cumulative adjustments, and impairments were not material for the years ended December 31, 2022 and 2021.

Reconciliation of Level 3 Assets and Liabilities

The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2022 and 2021:


	For the Year Ended December 31, 2022
	NDT Fund Investments		Mark-to-Market Derivatives			Life Insurance Contracts		Total
Balance as of January 1, 2022	$	464	$	(94)		$	—	$	370

Total realized / unrealized losses
Included in net income	(2)		(753)		(a)	(2)		(757)
Included in noncurrent payables to affiliates	(10)		—			—		(10)
Change in collateral	—		253			—		253
Impacts of separation	—		—			3		3
Purchases, sales, issuances and settlements
Purchases	5		594			—		599
Sales	—		(50)			—		(50)

Settlements	(35)		(102)			—		(137)
Transfers into Level 3	2		381		(b)	—		383
Transfers out of Level 3	(1)		(10)		(b)	—		(11)
Balance as of December 31, 2022	$	423	$	219		$	1	$	643
The amount of total losses included in income attributed to the change in unrealized losses related to assets and liabilities as of December 31, 2022	$	(2)	$	(1,265)		$	(2)	$	(1,269)


	For the Year Ended December 31, 2021
	NDT Fund Investments		Mark-to-Market Derivatives			Total
Balance as of January 1, 2021	$	497	$	430		$	927

Total realized / unrealized gains (losses)
Included in net income	5		(812)		(a)	(807)
Included in noncurrent payables to affiliates	19		—			19
Change in collateral	—		(196)			(196)
Purchases, sales, issuances and settlements
Purchases	4		162			166
Sales	—		(10)			(10)

Settlements	(61)		—			(61)
Transfers into Level 3	—		19		(b)	19
Transfers out of Level 3	—		313		(b)	313

Balance as of December 31, 2021	$	464	$	(94)		$	370
The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of December 31, 2021	$	5	$	(1,222)		$	(1,217)

__________

(a)Includes an addition of $410 million for realized losses due to the settlement of derivative contracts for both of the years ended December 31, 2022 and 2021, respectively.

(b)Transfers into and out of Level 3 generally occur when the contract tenor becomes less and more observable, respectively, primarily due to changes in market liquidity or assumptions for certain commodity contracts.

The following table presents the income statement classification of the total realized and unrealized (losses) gains included in income for Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2022, 2021, and 2020:


	Operating Revenues						Purchased Power and Fuel						Other, net
	2022		2021		2020		2022		2021		2020		2022		2021		2020
Total (losses) gains included in net income	$	(860)	$	(1,343)	$	(404)	$	5	$	531	$	(10)	$	(4)	$	5	$	2

Total unrealized (losses) gains	(1,330)		(1,577)		(31)		65		355		37		(2)		5		2

Valuation Techniques Used to Determine Fair Value

Cash Equivalents. Investments with original maturities of three months or less when purchased, including mutual and money market funds, are considered cash equivalents. The fair values are based on observable market prices and, therefore, are included in the recurring fair value measurements hierarchy as Level 1.

NDT Fund Investments. The trust fund investments have been established to satisfy our nuclear decommissioning obligations as required by the NRC. The NDT funds hold debt and equity securities directly and indirectly through commingled funds and mutual funds, which are included in equities and fixed income. Our NDT fund investments policies outline investment guidelines for the trusts and limit the trust funds’ exposures to investments in highly illiquid markets and other alternative investments, including private credit, private equity, and real estate. Investments with maturities of three months or less when purchased, including certain short-term fixed income securities are considered cash equivalents and included in the recurring fair value measurements hierarchy as Level 1 or Level 2.

Equities. These investments consist of individually held equity securities, equity mutual funds, and equity commingled funds in domestic and foreign markets. With respect to individually held equity securities, the trustees obtain prices from pricing services, whose prices are generally obtained from direct feeds from market exchanges, which we are able to independently corroborate. Equity securities held individually, including real estate investment trusts, rights, and warrants, are primarily traded on exchanges that contain only actively traded securities due to the volume trading requirements imposed by these exchanges. The equity securities that are held directly by the trust funds are valued based on quoted prices in active markets and categorized as Level 1. Certain equity securities have been categorized as Level 2 because they are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities. Certain private placement equity securities are categorized as Level 3 because they are not publicly traded and are priced using significant unobservable inputs.

Equity commingled funds and mutual funds are maintained by investment companies, and fund investments are held in accordance with a stated set of fund objectives. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For equity commingled funds and mutual funds which are not publicly quoted, the fund administrators value the funds using the NAV per fund share, derived from the quoted prices in active markets on the underlying securities and are not classified within the fair value hierarchy. These investments can typically be redeemed monthly or more frequently, with 30 or less days of notice and without further restrictions.

Fixed income. For fixed income securities, which consist primarily of corporate debt securities, U.S. government securities, foreign government securities, municipal bonds, asset and mortgage-backed securities, commingled funds, mutual funds, and derivative instruments, the trustees obtain multiple prices from pricing vendors whenever possible, which enables cross-provider validations in addition to checks for unusual daily movements. A primary price source is identified based on asset type, class, or issue for each security. With respect to individually held fixed income securities, the trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the portfolio managers challenge an assigned price and the trustees determine that another price source is preferable. We have obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, we selectively corroborate the fair values of securities by comparison to other market-based price sources. Investments in U.S. Treasury securities have been categorized as Level 1 because they trade in highly-liquid and transparent markets. Certain private placement fixed income securities

have been categorized as Level 3 because they are priced using certain significant unobservable inputs and are typically illiquid. The remaining fixed income securities, including certain other fixed income investments, are based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences and are categorized as Level 2.

Other fixed income investments primarily consist of fixed income commingled funds and mutual funds, which are maintained by investment companies and hold fund investments in accordance with a stated set of fund objectives. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For fixed income commingled funds and mutual funds which are not publicly quoted, the fund administrators value the funds using the NAV per fund share, derived from the quoted prices in active markets of the underlying securities and are not classified within the fair value hierarchy. These investments typically can be redeemed monthly or more frequently, with 30 or less days of notice and without further restrictions.

Derivative instruments. These instruments, consisting primarily of futures and swaps to manage risk, are recorded at fair value. Over-the-counter derivatives are valued daily, based on quoted prices in active markets and trade in open markets, and have been categorized as Level 1. Derivative instruments other than over-the-counter derivatives are valued based on external price data of comparable securities and have been categorized as Level 2.

Private credit. Private credit investments primarily consist of investments in private debt strategies. These investments are generally less liquid assets with an underlying term of 3 to 5 years and are intended to be held to maturity. The fair value of these investments is determined by the fund manager or administrator using a combination of valuation models including cost models, market models, and income models and typically cannot be redeemed until maturity of the term loan. Private credit investments held directly by us are categorized as Level 3 because they are based largely on inputs that are unobservable and utilize complex valuation models. For managed private credit funds, the fair value is determined using a combination of valuation models including cost models, market models, and income models and typically cannot be redeemed until maturity of the term loan. Managed private credit fund investments are not classified within the fair value hierarchy because their fair value is determined using NAV or its equivalent as a practical expedient.

Private equity. These investments include those in limited partnerships that invest in operating companies that are not publicly traded on a stock exchange such as leveraged buyouts, growth capital, venture capital, distressed investments, and investments in natural resources. These investments typically cannot be redeemed and are generally liquidated over a period of 8 to 10 years from the initial investment date, which is based on our understanding of the investment funds. Private equity valuations are reported by the fund manager and are based on the valuation of the underlying investments, which include unobservable inputs such as cost, operating results, discounted future cash flows, and market based comparable data. These valuation inputs are unobservable. The fair value of private equity investments is determined using NAV or its equivalent as a practical expedient, and therefore, these investments are not classified within the fair value hierarchy.

Real estate. These investments are funds with a direct investment in pools of real estate properties. These funds are reported by the fund manager and are generally based on independent appraisals of the underlying investments from sources with professional qualifications, typically using a combination of market based comparable data and discounted cash flows. These valuation inputs are unobservable. Certain real estate investments cannot be redeemed and are generally liquidated over a period of 8 to 10 years from the initial investment date, which is based on our understanding of the investments funds. The remaining liquid real estate investments are generally redeemable from the investment vehicle quarterly, with 30 to 90 days of notice. The fair value of real estate investments is determined using NAV or its equivalent as a practical expedient, and therefore, these investments are not classified within the fair value hierarchy.

We evaluated our NDT portfolios for the existence of significant concentrations of credit risk as of December 31, 2022. Types of concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, and individual fund. As of December 31, 2022, there were no significant concentrations (generally defined as greater than 10 percent) of risk in the NDT assets.

See Note 10 — Asset Retirement Obligations for additional information on the NDT fund investments.

Rabbi Trust Investments. The Rabbi trusts were established to hold assets related to deferred compensation plans existing for certain active and retired members of executive management and directors. The Rabbi trusts' assets are included in investments in the Consolidated Balance Sheets and consist primarily of money market funds, mutual funds, and life insurance policies. Money market funds and mutual funds are publicly quoted and have been categorized as Level 1 given the clear observability of the prices. The life insurance policies are valued using the cash surrender value of the policies, net of loans against those policies, which is provided by a third-party. Certain life insurance policies, which consist primarily of mutual funds that are priced based on observable market data, have been categorized as Level 2 because the life insurance policies can be liquidated at the reporting date for the value of the underlying assets.

Deferred Compensation Obligations. Our deferred compensation plans allow participants to defer certain cash compensation into a notional investment account. We include such plans in other current and noncurrent liabilities in the Consolidated Balance Sheets. The value of our deferred compensation obligations is based on the market value of the participants’ notional investment accounts. The underlying notional investments are comprised primarily of equities, mutual funds, commingled funds, and fixed income securities which are based on directly and indirectly observable market prices. Since the deferred compensation obligations themselves are not exchanged in an active market, they are categorized as Level 2 in the fair value hierarchy.

The value of certain employment agreement obligations (which are included with the Deferred Compensation Obligation in the table above) are based on a known and certain stream of payments to be made over time and are categorized as Level 2 within the fair value hierarchy.

Investments in Equities. We hold certain investments in equity securities with readily determinable fair values in addition to those held within the NDT funds. These equity securities are valued based on quoted prices in active markets and are categorized as Level 1.

Deferred Purchase Price Consideration. We have DPP consideration for the sale of certain receivables of retail electricity. This amount is valued based on the sales price of the receivables net of allowance for credit losses based on accounts receivable aging historical experience coupled with specific identification through a credit monitoring process, which considers current conditions and forward-looking information such as industry trends, macroeconomic factors, changes in the regulatory environment, external credit ratings, publicly available news, payment status, payment history, and the exercise of collateral calls. Since the DPP consideration is based on the sales price of the receivables, it is categorized as Level 2 in the fair value hierarchy. See Note 6 — Accounts Receivable for additional information on the sale of certain receivables.

Mark-to-Market Derivatives. Derivative contracts are traded in both exchange-based and non-exchange-based markets. Exchange-based derivatives that are valued using unadjusted quoted prices in active markets are categorized in Level 1 in the fair value hierarchy. Certain derivatives’ pricing is verified using indicative price quotations available through brokers or over-the-counter, on-line exchanges and are categorized in Level 2. These price quotations reflect the average of the bid-ask, mid-point prices and are obtained from sources that we believe provide the most liquid market for the commodity. The price quotations are reviewed and corroborated to ensure the prices are observable and representative of an orderly transaction between market participants. This includes consideration of actual transaction volumes, market delivery points, bid-ask spreads, and contract duration. The remainder of derivative contracts are valued using the Black model, an industry standard option valuation model. The Black model considers inputs such as contract terms, including maturity, and market parameters, including assumptions of the future prices of energy, interest rates, volatility, credit worthiness, and credit spread. For derivatives that trade in liquid markets, such as generic forwards, swaps, and options, model inputs are generally observable. Such instruments are categorized in Level 2. Our derivatives are predominantly at liquid trading points. For derivatives that trade in less liquid markets with limited pricing information, model inputs generally would include both observable and unobservable inputs. These valuations may include an estimated basis adjustment from an illiquid trading point to a liquid trading point for which active price quotations are available. Such instruments are categorized in Level 3.

For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations whose contract tenure extends into unobservable periods. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility, and contract duration. Such instruments are categorized in Level 3 as the model inputs generally are not observable. Forward

price curves for the power market utilized by the front office to manage the portfolio, are reviewed and verified by the middle office, and used for financial reporting by the back office. We consider credit and nonperformance risk in the valuation of derivative contracts categorized in Level 2 and 3, including both historical and current market data, in our assessment of credit and nonperformance risk by counterparty. Due to master netting agreements and collateral posting requirements, the impacts of credit and nonperformance risk were not material to the consolidated financial statements.

Disclosed below is detail surrounding our significant Level 3 valuations. The calculated fair value includes marketability discounts for margining provisions and other attributes. The Level 3 balance generally consists of forward sales and purchases of power and natural gas and certain transmission congestion contracts. We utilize various inputs and factors including market data and assumptions that market participants would use in pricing assets or liabilities as well as assumptions about the risks inherent in the inputs to the valuation technique. The inputs and factors include forward commodity prices, commodity price volatility, contractual volumes, delivery location, interest rates, credit quality of counterparties, and credit enhancements.

For commodity derivatives, the primary input to the valuation models is the forward commodity price curve for each instrument. Forward commodity price curves are derived by risk management for liquid locations and by the traders and portfolio managers for illiquid locations. All locations are reviewed and verified by risk management considering published exchange transaction prices, executed bilateral transactions, broker quotes, and other observable or public data sources. The relevant forward commodity curve used to value each of the derivatives depends on a number of factors, including commodity type, delivery location, and delivery period. Price volatility varies by commodity and location. When appropriate, we discount future cash flows using risk-free interest rates with adjustments to reflect the credit quality of each counterparty for assets and our own credit quality for liabilities. The level of observability of a forward commodity price varies generally due to the delivery location and delivery period. Certain delivery locations including PJM West Hub (for power) and Henry Hub (for natural gas) are more liquid and prices are observable for up to three years in the future. The observability period of volatility is generally shorter than the underlying power curve used in option valuations. The forward curve for a less liquid location is estimated by using the forward curve from the liquid location and applying a spread to represent the cost to transport the commodity to the delivery location. This spread does not typically represent a majority of the instrument’s market price. As a result, the change in fair value is closely tied to liquid market movements and not a change in the applied spread. The change in fair value associated with a change in the spread is generally immaterial. An average spread calculated across all Level 3 power and gas delivery locations is approximately $72.43 and $4.57 for power and natural gas, respectively. Many of the commodity derivatives are short term in nature and thus a majority of the fair value may be based on observable inputs even though the contract as a whole must be classified as Level 3.

See Note 16 — Derivative Financial Instruments for additional information on mark-to-market derivatives.

The following table presents the significant inputs to the forward curve used to value these positions:


Type of trade	Fair Value as of December 31, 2022		Fair Value as of December 31, 2021		Valuation Technique	Unobservable Input	2022 Range & Arithmetic Average				2021 Range & Arithmetic Average
Mark-to-market derivatives—Economic hedges(a)(b)	$	(3)	$	(66)	Discounted Cash Flow	Forward power price	$0.63	-	$283	$72	$8.86	-	$481	$55
						Forward gas price	$1.67	-	$26	$4.57	$1.69	-	$17	$3.50
					Option Model	Volatility percentage	97%	-	119%	111%	24%	-	284%	56%

__________

(a)The valuation techniques, unobservable inputs, ranges, and arithmetic averages are the same for the asset and liability positions.

(b)The fair values do not include cash collateral posted (received) on level three positions of $218 million and ($34) million as of December 31, 2022 and December 31, 2021, respectively.

The inputs listed above, which are as of the balance sheet date, would have a direct impact on the fair values of the above instruments if they were adjusted. The significant unobservable inputs used in the fair value measurement of our commodity derivatives are forward commodity prices and for options is price volatility.

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 Disclosure [Abstract]

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

+ References + Details

Commitments and Contingencies

12 Months Ended

Dec. 31, 2022

Commitments and Contingencies

Commercial Commitments. Commercial commitments as of December 31, 2022, representing commitments potentially triggered by future events, were as follows:


			Expiration within
	Total		2023		2024		2025		2026		2027		2028 and beyond
Letters of credit	$	2,475	$	2,465	$	10	$	—	$	—	$	—	$	—
Surety bonds(a)	978		977		1		—		—		—		—
Total commercial commitments	$	3,453	$	3,442	$	11	$	—	$	—	$	—	$	—

__________

(a)Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.

Prior Merger Commitment. Consistent with a 2012 MDPSC order approving a prior merger, certain commitments were made for the development of new generation in Maryland, 55 MW of which remains unsatisfied to date. In 2016, we terminated rights to a development project intended to satisfy the remaining commitment and recorded a pre-tax $50 million loss contingency within Operating and maintenance expense in our Consolidated Statements of Operations and Comprehensive Income, representing the potential liquidated damages payment due for the shortfall, consistent with the terms of the original MDPSC order. In September 2022, a previously executed PPA with a third party became effective upon satisfaction of all conditions precedent (including an extension of time to complete the merger commitment from the MDPSC) and will result in the construction of a wind farm project with an expected commercial operation date (“COD”) of December 31, 2024. The satisfaction of the conditions precedent to the PPA, coupled with the milestones contained in the PPA to ensure the facility is constructed, demonstrate that the merger commitment is likely to be met through support of a PPA enabling the project to be constructed rather than a liquidated damages payment. As a result, we have reversed the previously recognized loss contingency and recorded a pre-tax gain of $50 million within Operating and maintenance expense in our Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2022.

Nuclear Insurance

We are subject to liability, property damage and other risks associated with major incidents at any of our nuclear stations. We have mitigated our financial exposure to these risks through insurance and other industry risk-sharing provisions.

The Price-Anderson Act was enacted to ensure the availability of funds for public liability claims arising from an incident at any of the U.S. licensed nuclear facilities and to limit the liability of nuclear reactor owners for such claims from any single incident. As of December 31, 2022, the current liability limit per incident is $13.7 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors at least once every five years with the last adjustment effective November 1, 2018. In accordance with the Price-Anderson Act, we maintain financial protection at levels equal to the amount of liability insurance available from private sources through the purchase of private nuclear energy liability insurance for public liability claims that could arise in the event of an incident. Effective January 1, 2017, the required amount of nuclear energy liability insurance purchased is $450 million for each operating site. Claims exceeding that amount are covered through mandatory participation in a financial protection pool, as required by the Price Anderson-Act, which provides the additional $13.2 billion per incident in funds available for public liability claims. Participation in this secondary

financial protection pool requires the operator of each reactor to fund its proportionate share of costs for any single incident that exceeds the primary layer of financial protection. Our share of this secondary layer would be approximately $2.8 billion, however any amounts payable under this secondary layer would be capped at $413 million per year.

In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay public liability claims exceeding the $13.7 billion limit for a single incident.

As part of the execution of the NOSA on April 1, 2014, we executed an Indemnity Agreement pursuant to which we agreed to indemnify EDF and its affiliates against third-party claims that may arise from any future nuclear incident (as defined in the Price-Anderson Act) in connection with the Calvert Cliffs, Ginna, and Nine Mile Point nuclear generating units or their operations.

We are required each year to report to the NRC the current levels and sources of property insurance that demonstrates we possess sufficient financial resources to stabilize and decontaminate a reactor and reactor station site in the event of an accident. The insurance maintained for each facility is currently provided through insurance policies purchased from NEIL, an industry mutual insurance company of which we are a member.

NEIL may declare distributions to its members as a result of favorable operating experience. In recent years, NEIL has made distributions to its members. Our portion of the annual distribution declared by NEIL is estimated to be $30 million for 2022, and was $114 million and $75 million for 2021 and 2020, respectively. The distributions were recorded as a reduction to Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income.

Premiums paid to NEIL by its members are also subject to a potential assessment for adverse loss experience in the form of a retrospective premium obligation. NEIL has never assessed this retrospective premium since its formation in 1973, and we cannot predict the level of future assessments, if any. The current maximum aggregate annual retrospective premium obligation for us is approximately $252 million. NEIL requires its members to maintain an investment grade credit rating or to ensure collectability of their annual retrospective premium obligation by providing a financial guarantee, letter of credit, deposit premium, or some other means of assurance.

NEIL provides “all risk” property damage, decontamination and premature decommissioning insurance for each station for losses resulting from damage to its nuclear plants, either due to accidents or acts of terrorism. If the decision is made to decommission the facility, a portion of the insurance proceeds will be allocated to a fund, which we are required by the NRC to maintain, to provide for decommissioning the facility. In the event of an insured loss, we are unable to predict the timing of the availability of insurance proceeds to us and the amount of such proceeds that would be available. In the event that one or more acts of terrorism cause accidental property damage within a twelve-month period from the first accidental property damage under one or more policies for all insured plants, the maximum recovery by us will be an aggregate of $3.2 billion plus such additional amounts as the insurer may recover for all such losses from reinsurance, indemnity and any other source, applicable to such losses.

For our insured losses, we are self-insured to the extent that losses are within the policy deductible or exceed the amount of insurance maintained. Uninsured losses and other expenses, to the extent not recoverable from insurers or the nuclear industry, could also be borne by us. Any such losses could have a material adverse effect on our consolidated financial statements.

Spent Nuclear Fuel Obligation

Under the NWPA, the DOE is responsible for the development of a geologic repository for and the disposal of SNF and high-level radioactive waste. As required by the NWPA, we are a party to contracts with the DOE (Standard Contracts) to provide for disposal of SNF from our nuclear generating stations. In accordance with the NWPA and the Standard Contracts, we had previously paid the DOE one mill ($0.001) per kWh of net nuclear generation for the cost of SNF disposal. Due to the lack of a viable disposal program, the DOE reduced the SNF disposal fee to zero in May 2014. Until a new fee structure is in effect, we will not accrue any further costs related to SNF disposal fees. This fee may be adjusted prospectively to ensure full cost recovery.

We currently assume the DOE will begin accepting SNF in 2035 and use that date for purposes of estimating the nuclear decommissioning AROs. The SNF acceptance date assumption is based on management’s estimate of

the amount of time required for DOE to select a site location and develop the necessary infrastructure for long-term SNF storage.

The NWPA and the Standard Contracts required the DOE to begin taking possession of SNF generated by nuclear generating units no later than January 31, 1998. The DOE, however, failed to meet that deadline and its performance has been, and is expected to remain, delayed significantly. In August 2004, we and the DOJ, in close consultation with the DOE, reached a settlement under which the government agreed to reimburse us, subject to certain damage limitations based on the extent of the government’s breach, for costs associated with storage of SNF at our nuclear stations pending the DOE’s fulfillment of its obligations. Calvert Cliffs, Ginna and Nine Mile Point each have separate settlement agreements in place with the DOE which were extended during 2020 to provide for the reimbursement of SNF storage costs through December 31, 2022. FitzPatrick also has a separate settlement agreement in place with the DOE that was established in 2021 to provide for reimbursement of SNF storage costs through December 31, 2022. We are in the process of extending the agreements for Calvert Cliffs, Ginna, Nine Mile Point, and Fitzpatrick to provide for the reimbursement of SNF storage costs through December 31, 2025.

Under the settlement agreements, we received total cumulative cash reimbursements of $1,731 million through December 31, 2022 for costs incurred. After considering the amounts due to co-owners of certain nuclear stations and to the former owner of Oyster Creek, we received net cumulative cash reimbursements of $1,501 million. As of December 31, 2022 and 2021, the amount of SNF storage costs for which reimbursement has been or will be requested from the DOE under the DOE settlement agreements is as follows:


	December 31, 2022		December 31, 2021
DOE receivable - current(a)	$	125	$	241
DOE receivable - noncurrent(b)	130		85
Amounts owed to co-owners(c)	(12)		(35)

__________

(a)Recorded in Other accounts receivable.

(b)Recorded in Deferred debits and other assets, other.

(c)Recorded in Other accounts receivable. Represents amounts owed to the co-owners of Peach Bottom, Quad Cities, and Nine Mile Point Unit 2 generating facilities.

The Standard Contracts with the DOE also required the payment to the DOE of a one-time fee applicable to nuclear generation through April 6, 1983. The below table outlines the SNF liability recorded as of December 31, 2022 and 2021:


	December 31, 2022		December 31, 2021
Former ComEd units(a)	$	1,100	$	1,083
Fitzpatrick(b)	130		127
Total SNF Obligation	$	1,230	$	1,210

__________

(a)ComEd previously elected to defer payment of the one-time fee of $277 million for its units, with interest to the date of payment, until just prior to the first delivery of SNF to the DOE. The unfunded liabilities for SNF disposal costs, including the one-time fee, were transferred to us as part of Exelon’s 2001 corporate restructuring.

(b)A prior owner of FitzPatrick elected to defer payment of the one-time fee of $34 million, with interest to the date of payment, for the FitzPatrick unit. As part of the FitzPatrick acquisition on March 31, 2017, we assumed a SNF liability for the DOE one-time fee obligation with interest related to FitzPatrick along with an offsetting asset, included in Other deferred debits and other assets, for the contractual right to reimbursement from NYPA, a prior owner of FitzPatrick, for amounts paid for the FitzPatrick DOE one-time fee obligation.

Interest for our SNF liabilities accrues at the 13-week Treasury Rate. The 13-week Treasury Rate in effect for calculation of the interest accrual at December 31, 2022 was 4.169% for the deferred amount transferred from ComEd and 3.415% for the deferred FitzPatrick amount.

The following table summarizes sites for which we do not have an outstanding SNF Obligation:


Description			Sites
Fees have been paid			Former PECO units, Clinton and Calvert Cliffs
Outstanding SNF Obligation remains with former owners			Nine Mile Point, Ginna and TMI

Environmental Remediation Matters

General. Our operations have in the past, and may in the future, require substantial expenditures to comply with environmental laws. Additionally, under Federal and state environmental laws, we are generally liable for the costs of remediating environmental contamination of property now or formerly owned by us and of property contaminated by hazardous substances generated by us. We own or lease several real estate parcels, including parcels on which our operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. In addition, we are currently involved in proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future. Unless otherwise disclosed, we cannot reasonably estimate whether we will incur significant liabilities for additional investigation and remediation costs at these or additional sites identified by us, environmental agencies or others. Additional costs could have a material, unfavorable impact on our consolidated financial statements.

As of December 31, 2022 and 2021, we had accrued undiscounted amounts for environmental liabilities of $119 million and $120 million, respectively, in Accrued expenses and Other deferred credits and other liabilities in the Consolidated Balance Sheets.

Cotter Corporation. The EPA has advised Cotter Corporation (N.S.L.) (Cotter), a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at two sites in Missouri. In 2000, ComEd sold Cotter to an unaffiliated third-party. As part of the sale, ComEd agreed to indemnify Cotter for any liability arising from these two Missouri superfund sites, West Lake Landfill and Latty Avenue. In connection with Exelon’s 2001 corporate restructuring, this responsibility to indemnify Cotter was transferred to us, and ultimately retained by us per the terms of our separation from Exelon. Refer to Note 1 — Basis of Presentation for additional information on the separation.

West Lake Landfill. Including Cotter, there are three PRPs currently participating in the West Lake Landfill remediation proceeding.

In September 2018, the EPA issued its Record of Decision Amendment (RODA) for the selection of a final remedy that requires partial excavation of the radiological materials and capping the landfill. The EPA and the PRPs have entered into a Consent Agreement to perform the Remedial Design, which is expected to be completed in the middle of 2024. In March 2019, the PRPs received Special Notice Letters from the EPA to perform the Remedial Action work. The total estimated cost of the remedy, considering the current EPA technical requirements, is approximately $295 million, including cost escalation on an undiscounted basis. Our investigation has identified several other parties who also may be PRPs and could be liable to contribute to the final remedy. We have determined that a loss associated with the EPA’s partial excavation and landfill cover remedy is probable and have recorded a liability, included in the total amount as discussed above, that reflects management’s best estimate of Cotter’s allocable share of the ultimate cost. Given the joint and several nature of this liability, the magnitude of our ultimate liability will depend on the actual costs incurred to implement the required remedy as well as on the nature and terms of any cost-sharing arrangements with the final group of PRPs. Therefore, it is reasonably possible that the ultimate cost and Cotter's associated allocable share could differ significantly once these uncertainties are resolved, which could have a material impact on our consolidated financial statements.

In September 2018, the three identified PRPs, including Cotter, signed an Administrative Settlement Agreement and Order on Consent for the performance by the PRPs of the groundwater Remedial Investigation Feasibility Study (RI/FS). The purpose of this RI/FS is to define the nature and extent of any groundwater contamination from the West Lake Landfill site and evaluate remedial alternatives. We estimate the undiscounted cost for the groundwater RI/FS to be approximately $50 million. We determined a loss associated with the RI/FS is probable and have recorded a liability, included in the total amount as discussed above, that reflects management’s best estimate of Cotter’s allocable share of the cost among the PRPs. At this time we cannot predict the likelihood, or the extent to which, if any, remediation activities may be required and therefore cannot estimate a reasonably possible range of loss for response costs beyond those associated with the RI/FS component. It is reasonably

possible, however, that resolution of this matter could have a material, unfavorable impact on our consolidated financial statements.

Latty Avenue. In August 2011, Cotter was notified by the DOJ that Cotter is considered a PRP with respect to the government’s clean-up costs for contamination attributable to low level radioactive residues at a former storage and reprocessing facility named Latty Avenue near St. Louis, Missouri. Latty Avenue was investigated and remediated by the United States Army Corps of Engineers pursuant to funding under the Formerly Utilized Sites Remedial Action Program. On August 3, 2020, the DOJ advised Cotter that it is seeking approximately $90 million from all the PRPs. In December 2021, a good faith offer was submitted to the government. After subsequent communications with DOJ, Cotter proposed, and DOJ agreed to consider mediation to facilitate a settlement. Pursuant to a series of agreements since 2011, the DOJ and Cotter have extended the Statute of Limitations through August 31, 2023. We have determined that a loss associated with this matter is probable and have recorded an estimated liability, included in the total amount as discussed above, that reflects management's best estimate of Cotter's allocable share of the cost. It is reasonably possible that Cotter's allocable share could differ significantly, which could have a material impact on our consolidated financial statements.

Litigation and Regulatory Matters

Asbestos Personal Injury Claims. We maintain a reserve for claims associated with asbestos-related personal injury actions at certain facilities that are currently owned by us or were previously owned by ComEd, PECO, or BGE. The estimated liabilities are recorded on an undiscounted basis and exclude the estimated legal costs associated with handling these matters, which could be material.

At December 31, 2022 and 2021, we recorded estimated liabilities of approximately $95 million and $81 million, respectively, in total for asbestos-related bodily injury claims. As of December 31, 2022, approximately $23 million of this amount related to 253 open claims presented to us, while the remaining $72 million is for estimated future asbestos-related bodily injury claims anticipated to arise through 2055, based on actuarial assumptions and analyses, which are updated on an annual basis. On a quarterly basis, we monitor actual experience against the number of forecasted claims to be received and expected claim payments and evaluate whether adjustments to the estimated liabilities are necessary.

Impacts of the February 2021 Extreme Cold Weather Event and Texas-based Generating Assets Outages. Beginning on February 15, 2021, our Texas-based generating assets within the ERCOT market, specifically Colorado Bend II, Wolf Hollow II, and Handley, experienced outages as a result of extreme cold weather conditions. In addition, those weather conditions drove increased demand for service, dramatically increased wholesale power prices, and also increased gas prices in certain regions. See Note 3 — Regulatory Matters for additional information.

Various lawsuits have been filed against us since March 2021 related to these events, including:

•On March 5, 2021, we, along with more than 160 power generators and transmission and distribution companies, were sued by approximately 160 individually named plaintiffs, purportedly on behalf of all Texans who allegedly suffered loss of life or sustained personal injury, property damage or other losses as a result of the weather events. The plaintiffs allege that the defendants failed to properly prepare for the cold weather and failed to properly conduct their operations, seeking compensatory as well as punitive damages. On April 26, 2021, another multi-plaintiff lawsuit was filed on behalf of approximately 90 plaintiffs against more than 300 defendants, including us, involving similar allegations of liability and claims of personal injury and property damage. Since March 2021, approximately 60 additional lawsuits, naming multiple defendants including us, were filed by individual or multiple plaintiffs in different Texas counties, all arising out of the February weather events. These additional lawsuits allege wrongful death, property damage, or other losses. Co-defendants in these lawsuits include ERCOT, transmission and distribution utilities and other generators. On December 28, 2021, approximately 130 insurance companies which insured Texas homeowners and businesses filed a subrogation lawsuit against multiple defendants alleging that defendants were at fault for the energy failure that resulted from the winter storm, causing significant property damage to the insureds. Additionally, as of January 28, 2022, we have been added to approximately 80 additional wrongful death, personal injury, and property damage lawsuits through the Multi-District-Litigation (MDL) pending in Texas state court. The MDL now includes all of the above-described Texas state court matters. We are now defendants in approximately 150 lawsuits in the MDL brought by several hundred plaintiffs and more than 130 insurance companies.

Defendants filed Motions to Dismiss the amended complaints in five bellwether cases in July 2022. Briefing was completed in September 2022, and oral argument was held on October 11 and 12, 2022. On February 3, 2023, the court granted the motions to dismiss in part and denied them in part. As a result, we remain a defendant in the lawsuits. On June 27, 2022, a new group of 24 plaintiff customers filed a petition in Starr County seeking damages and redress for property damage and other injury. One plaintiff household was a customer of Constellation NewEnergy, Inc. as the Retail Electricity Provider (REP). This is the first time that Constellation has been named in a winter storm lawsuit as a REP. We dispute liability and deny that we are responsible for any of plaintiffs’ alleged claims and are vigorously contesting them. No loss contingencies have been reflected in the consolidated financial statements with respect to these matters, as such contingencies are neither probable nor reasonably estimable at this time.

•On March 22, 2021, an LDC filed a lawsuit in Missouri federal court against us for breach of contract and unjust enrichment, seeking damages of approximately $40 million. The plaintiff claims that we failed to deliver gas to our customers in February of 2021, causing the plaintiff to incur damages by forcing it to purchase gas for our customers and by our refusal to pay the resulting penalties. On March 26, 2021, we filed a complaint with the MPSC against the LDC to void the OFO penalties, or alternatively to grant a waiver or variance from the tariff requirements, to prohibit the LDC from billing or otherwise attempting to collect from us or any Missouri customer any portion of the penalties claimed by the LDC until the resolution of the complaint, and to prohibit the LDC from taking any retaliatory measure, including termination of service. On September 1, 2021, the MPSC consolidated our complaint with two other similar complaints from other companies. On January 4, 2022, the court denied our motion to dismiss, but in the alternative granted its motion to stay pending MPSC resolution of our complaint. Based on the penalty provisions within the tariff that was in effect at the relevant time, we have recorded a liability of approximately $40 million as of December 31, 2021. On May 25, 2022, a settlement was approved by the MPSC. In connection with the settlement, the liability was revised to $11 million as of June 30, 2022, and was paid in the third quarter of 2022. On June 14, 2022, the lawsuit in Missouri federal court was dismissed.

General. We are involved in various other litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. We maintain accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of reasonably possible loss, particularly where (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.

Stock-Based Compensation Plans

12 Months Ended

Dec. 31, 2022

Share-Based Payment Arrangement [Abstract]

Stock-Based Compensation Plans

Effective February 1, 2022, we established our own LTIP and began granting cash and stock-based awards that primarily include performance share awards and restricted stock units. Our LTIP authorized 20,000,000 shares of common stock for these awards. The existing, unvested cash and stock-based awards issued through the Exelon LTIP were modified in connection with the separation to align with our performance metrics and maintain an equivalent value immediately before and after separation. The impact of this modification was not material to our stock-based compensation expense for the year ended December 31, 2022.

Our employees were granted stock-based awards through the Exelon LTIP prior to separation, which primarily included performance share awards, restricted stock units, and stock options. We also granted cash awards. Performance share awards were typically settled 50% in common stock and 50% in cash at the end of a three-year performance period, subject to certain ownership thresholds that, if met, may have resulted in cash settlement of the entire award.

The following table presents the stock-based compensation expense included in the Consolidated Statements of Operations and Comprehensive Income. The information does not include expenses related to the cash awards as they are not considered stock-based compensation plans under the applicable authoritative guidance:


	Year Ended December 31,
	2022(a)		2021(b)		2020(b)
Total stock-based compensation expense included in operating and maintenance expense	$	116	$	47	$	27
Income tax benefit	(29)		(12)		(7)
Total after-tax stock-based compensation expense	$	87	$	35	$	20

__________

(a)Costs recognized for the year ended December 31, 2022 are related to the Constellation LTIP.

(b)Costs recognized for the years ended December 31, 2021 and 2020 were allocated to us by Exelon under the Exelon LTIP prior to separation.

We receive a tax deduction based on the intrinsic value of the award on the distribution date for restricted stock units. The tax deduction related to performance share awards was not material for the year ended December 31, 2022. For each award, throughout the requisite service period, we recognize the tax benefit related to compensation costs. The following table presents information regarding our realized tax benefit when distributed:


	December 31, 2022

Restricted stock units	$	2

Performance Share Awards

Performance share awards are granted under the LTIP. The performance share awards are typically settled 50% in common stock and 50% in cash at the end of the three-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.

The following table summarizes our nonvested performance share awards activity:


	Shares	Weighted Average Grant Date Fair Value (per share)
Nonvested at December 31, 2021	—	$	—
Granted	1,575,542	48.33
Change in performance	728,054	47.30

Forfeited	(22,617)	48.55
Undistributed vested awards(a)	(1,431,637)	48.35
Nonvested at December 31, 2022	849,342	$	47.40

__________

(a) Includes 1,272,921 of performance share awards that vested but were not distributed to retirement-eligible employees during 2022.

The following table summarizes the weighted average grant date fair value and the total fair value of performance share awards vested:


	December 31, 2022(a)
Weighted average grant date fair value (per share)	$	48.33
Total fair value of performance shares vested	69

__________

(a)As of December 31, 2022, $28 million of total unrecognized compensation costs related to nonvested performance shares are expected to be recognized over the remaining weighted-average period of 1.7 years.

Restricted Stock Units

Restricted stock units are granted under the LTIP with the majority being settled in a specific number of shares of common stock after the service condition has been met. The corresponding cost is measured based on the grant date fair value of the restricted stock unit issued.

The value of the restricted stock units is expensed over the requisite service period using the straight-line method. The requisite service period for restricted stock units is generally three to five years. However, certain restricted stock unit awards become fully vested upon the employee reaching retirement eligibility. The value of the restricted stock units granted to retirement-eligible employees is either recognized ratably over the first six months in the year of grant if the employee reaches retirement eligibility prior to July 1st of the grant year or through the date of which the employee reaches retirement eligibility. We process forfeitures as they occur for employees who do not complete the requisite service period.

The following table summarizes our nonvested restricted stock unit activity:


	Shares	Weighted Average Grant Date Fair Value (per share)
Nonvested at December 31, 2021	—	$	—
Granted	1,497,651	54.17
Vested	(144,903)	49.82
Forfeited	(62,238)	59.47
Undistributed vested awards(a)	(499,842)	55.16
Nonvested at December 31, 2022	790,668	$	53.72

__________

(a)Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2022.

The following table summarizes the weighted average grant date fair value and the total fair value of restricted stock units vested:


	December 31, 2022(a)
Weighted average grant date fair value (per share)	$	54.17
Total fair value of performance shares vested	35

__________

(a)As of December 31, 2022, $27 million of total unrecognized compensation costs related to nonvested restricted stock units are expected to be recognized over the remaining weighted-average period of 2.0 years.

Changes in Accumulated Other Comprehensive Income

12 Months Ended

Dec. 31, 2022

Equity [Abstract]

Changes in Accumulated Other Comprehensive Income

Changes in Accumulated Other Comprehensive Income The following tables present changes in AOCI, net of tax, by component:


	Losses on Cash Flow Hedges		Pension and Non-Pension Postretirement Benefit Plan Items(a)		Foreign Currency Items		Total
Balance at December 31, 2019	$	(5)	$	—	$	(27)	$	(32)

OCI before reclassifications	(2)		—		4		2
Net current-period OCI	(2)		—		4		2
Balance at December 30, 2020	$	(7)	$	—	$	(23)	$	(30)
OCI before reclassifications	(1)		—		—		(1)
Net current-period OCI	(1)		—		—		(1)
Balance at December 30, 2021	$	(8)	$	—	$	(23)	$	(31)
Separation-related adjustments	—		(2,006)		—		(2,006)
OCI before reclassifications	(1)		186		(3)		182
Amounts reclassified from AOCI	—		95		—		95
Net current-period OCI	(1)		(1,725)		(3)		(1,729)
Balance at December 30, 2022	$	(9)	$	(1,725)	$	(26)	$	(1,760)

__________

(a)AOCI amounts are included in the computation of net periodic pension and OPEB cost. See Note 15 — Retirement Benefits for additional information. See our Statements of Operations and Comprehensive Income for individual components of AOCI.

The following table presents income tax (expense) benefit allocated to each component of our other comprehensive income (loss):


	Year Ended December 31,
	2022		2021		2020
Pension and non-pension postretirement benefit plans:

Actuarial loss reclassified to periodic benefit cost	$	(33)	$	—	$	—
Pension and non-pension postretirement benefit plans valuation adjustment(a)	619		—		—

__________

(a)Includes $680 million of income tax benefit related to the separation adjustment for the year ended December 31, 2022.

Variable Interest Entities

12 Months Ended

Dec. 31, 2022

Variable Interest Entity [Abstract]

Variable Interest Entity

Variable Interest Entities As of December 31, 2022 and 2021, we consolidated several VIEs or VIE groups for which we are the primary beneficiary (see Consolidated VIEs below) and had significant interests in several other VIEs for which we do not have the power to direct the entities’ activities and, accordingly, we were not the primary beneficiary (see Unconsolidated VIEs below). Consolidated and unconsolidated VIEs are aggregated to the extent that the entities have similar risk profiles.

Consolidated VIEs

The table below shows the carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in the consolidated financial statements as of December 31, 2022 and 2021. The assets, except as noted in the footnotes to the table below, can only be used to settle obligations of the VIEs. The liabilities, except as noted in the footnotes to the table below, are such that creditors, or beneficiaries, do not have recourse to our general credit.


	December 31, 2022		December 31, 2021
Cash and cash equivalents	$	51	$	35
Restricted cash and cash equivalents	46		48
Accounts receivable
Customer	20		24
Other	9		6

Inventories, net

Materials and supplies	12		14
Other current assets	549		405
Total current assets	687		532

Property, plant and equipment, net	1,965		2,027


Other noncurrent assets	190		215
Total noncurrent assets	2,155		2,242
Total assets(a)	$	2,842	$	2,774

Long-term debt due within one year	$	60	$	70
Accounts payable	17		10
Accrued expenses	23		21


Other current liabilities	2		1
Total current liabilities	102		102

Long-term debt	764		822

Asset retirement obligations	173		151




Other noncurrent liabilities	3		3
Total noncurrent liabilities	940		976
Total liabilities(b)	$	1,042	$	1,078

_______

(a)Our balances include unrestricted assets for current unamortized energy contract assets of $23 million and $23 million, disclosed within other current assets in the table above and noncurrent unamortized energy contract assets of $178 million and $202 million, disclosed within other noncurrent assets in the table above as of December 31, 2022 and 2021, respectively.

(b)Our balances include liabilities with recourse of $1 million and $1 million as of December 31, 2022 and 2021, respectively.

As of December 31, 2022 and 2021, our consolidated VIEs included the following:


Consolidated VIE or VIE groups:	Reason entity is a VIE:	Reason we are the primary beneficiary:
CRP - A collection of wind and solar project entities. We have a 51% equity ownership in CRP. See additional discussion below.	Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner.	We conduct the operational activities.
Bluestem Wind Energy Holdings, LLC - A Tax Equity structure which is consolidated by CRP.	Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner.	We conduct the operational activities.
Antelope Valley - A solar generating facility, which is 100% owned by us. Antelope Valley sells all of its output to PG&E through a PPA.	The PPA contract absorbs variability through a performance guarantee.	We conduct all activities.
NER - A bankruptcy remote, special purpose entity which is 100% owned by us, which purchases certain of our customer accounts receivable arising from the sale of retail electricity. NER’s assets will be available first and foremost to satisfy the claims of the creditors of NER. Refer to Note 6 —Accounts Receivable for additional information on the sale of receivables.	Equity capitalization is insufficient to support its operations.	We conduct all activities.

CRP - CRP is a collection of wind and solar project entities and some of these project entities are VIEs that are consolidated by CRP. While we or CRP own 100% of the solar entities and 100% of the majority of the wind entities, it has been determined that the wholly owned solar and wind entities are VIEs because the entities' customers absorb price variability from the entities through fixed price power and/or REC purchase agreements. Additionally, for the wind entities that have minority interests, it has been determined that these entities are VIEs because the governance rights of some investors are not proportional to their financial rights. We are the primary beneficiary of these solar and wind entities that qualify as VIEs because we control operations and direct all activities of the facilities. There is limited recourse to us related to certain solar and wind entities.

In 2017, our interests in CRP were contributed to and are pledged for the CR non-recourse debt project financing structure. Refer to Note 17 — Debt and Credit Agreements for additional information.

Unconsolidated VIEs

Our variable interests in unconsolidated VIEs generally include equity investments and energy purchase and sale contracts. For the equity investments, the carrying amount of the investments is reflected in the Consolidated Balance Sheets in Investments. For the energy purchase and sale contracts (commercial agreements), the carrying amount of assets and liabilities in the Consolidated Balance Sheets that relate to our involvement with the VIEs are predominantly related to working capital accounts and generally represent the amounts owed by, or owed to, us for the deliveries associated with the current billing cycles under the commercial agreements.

As of December 31, 2022 and 2021, we had significant unconsolidated variable interests in several VIEs for which we were not the primary beneficiary. These interests include certain equity method investments and certain commercial agreements.

The following table presents summary information about our significant unconsolidated VIE entities:


	December 31, 2022						December 31, 2021
	Commercial Agreement VIEs		Equity Investment VIEs		Total		Commercial Agreement VIEs		Equity Investment VIEs		Total
Total assets(a)	$	715	$	—	$	715	$	772	$	372	$	1,144
Total liabilities(a)	54		—		54		80		216		296
Our ownership interest in VIE(a)	—		—		—		—		139		139
Other ownership interests in VIE(a)	661		—		661		692		17		709

__________

(a)These items represent amounts on the unconsolidated VIE balance sheets, not in the Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs. We do not have any exposure to loss as we do not have a carrying amount in the equity investment VIEs as of December 31, 2022 and 2021.

As of December 31, 2022 and 2021, the unconsolidated VIEs consist of:


Unconsolidated VIE groups:	Reason entity is a VIE:	Reason we are not the primary beneficiary:
Equity investments in distributed energy companies. We have a 90% equity ownership in a distributed energy company. We sold this investment in the fourth quarter of 2022 resulting in it no longer being classified as an unconsolidated VIE .	Similar structures to a limited partnership and the limited partners do not have kick out rights with respect to the general partner.	We do not conduct the operational activities.
Energy Purchase and Sale agreements - We have several energy purchase and sale agreements with generating facilities.	PPA contracts that absorb variability through fixed pricing.	We do not conduct the operational activities.

Supplemental Financial Information

12 Months Ended

Dec. 31, 2022

Supplemental Financial Information [Abstract]

Supplemental Financial Information

Supplemental Statement of Operations Information

The following tables provide additional information about material items recorded in the Consolidated Statements of Operations and Comprehensive Income.


	Taxes other than income taxes
	For the Years Ended December 31,
	2022		2021		2020
Gross receipts(a)	$	130	$	99	$	99
Property	274		268		265
Payroll	130		109		113

__________

(a)Represent gross receipts taxes related to our retail operations. The offsetting collection of gross receipts taxes from customers is recorded in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income.


	Other, net
	For the Years Ended December 31,
	2022		2021		2020
Decommissioning-related activities:
Net realized income on NDT funds(a)
Regulatory Agreement Units	$	333	$	817	$	185
Non-Regulatory Agreement Units	97		449		160
Net unrealized (losses) gains on NDT funds
Regulatory Agreement Units	(1,354)		351		724
Non-Regulatory Agreement Units	(798)		209		391
Regulatory offset to NDT fund-related activities(b)	820		(917)		(729)
Decommissioning-related activities	(902)		909		731
Investment income	58		—		—
Non-service net periodic benefit credit(c)	110		—		—
Net realized and unrealized (losses) gains from equity investments(d)	(13)		(160)		186
Return to provision adjustment(e)	(49)		—		—

__________

(a)Realized income includes interest, dividends and realized gains and losses on sales of NDT fund investments.

(b)Includes the elimination of decommissioning-related activities and the elimination of income taxes related to all NDT fund activity for the Regulatory Agreement Units except for decommissioning-related impacts that were not offset for the Byron units starting in the second quarter of 2021. With our September 15, 2021 reversal of the previous decision to retire Byron, we resumed contractual offset for Byron as of that date. See Note 10 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning and the contractual offset suspension for the Byron units.

(c)Historically, we were allocated our portion of pension and OPEB non-service credits (costs) from Exelon, which was included in Operating and maintenance expense. Effective February 1, 2022, the non-service credit (cost) components will now be included in Other, net, in accordance with single employer plan accounting. See Note 15 — Retirement Benefits for additional information.

(d)For 2022, represents Net realized and unrealized (losses) gains from equity investments. For 2021 and 2020, represents Net unrealized (losses) gains from equity investments.

(e)This reflects amounts contractually owed to Exelon under the tax matters agreement, which is offset in Income taxes. See Note 14 — Income Taxes for additional information.

Supplemental Cash Flow Information

The following tables provide additional information about material items recorded in the Consolidated Statements of Cash Flows.


	Depreciation, amortization and accretion
	For the Years Ended December 31,
	2022		2021		2020
Property, plant, and equipment(a)	$	1,065	$	2,954	$	2,070
Amortization of intangible assets, net(a)	26		49		53
Amortization of energy contract assets and liabilities(b)	35		31		30
Nuclear fuel(c)	758		992		983
ARO accretion(d)	543		514		500
Total depreciation, amortization, and accretion	$	2,427	$	4,540	$	3,636

_________

(a)Included in Depreciation and amortization expense in the Consolidated Statements of Operations and Comprehensive Income.

(b)Included in Operating revenues or Purchased power and fuel expense in the Consolidated Statements of Operations and Comprehensive Income.

(c)Included in Purchased power and fuel expense in the Consolidated Statements of Operations and Comprehensive Income.

(d)Included in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income.


	Cash paid during the year
	For the Years Ended December 31,
	2022		2021		2020
Interest (net of amount capitalized)	$	230	$	275	$	331
Income taxes (net of refunds)	287		426		70


	Other non-cash operating activities
	CEG Parent						Constellation
	For the Years Ended December 31,						For the Years Ended December 31,
	2022		2021		2020		2022		2021		2020
Pension and non-pension postretirement benefit costs	$	17	$	123	$	115	$	17	$	123	$	115

Other decommissioning-related activity(a)	(263)		(946)		(659)		(263)		(946)		(659)
Energy-related options(b)	293		125		104		293		125		104
Severance costs	(1)		(73)		90		(1)		(73)		90
Long-term incentive plan	44		—		—		—		—		—
Provision for excess and obsolete inventory	(12)		(13)		128		(12)		(13)		128
Amortization of operating ROU asset	75		119		155		75		119		155
Loss on sale of receivables	69		36		30		69		36		30
Fair value adjustments related to gas imbalances	37		—		—		37		—		—
Prior merger commitment(c)	(50)		—		—		(50)		—		—

__________

(a)Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units except for decommissioning-related impacts that were not offset for the Byron units starting in the second quarter of 2021, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income, and income taxes related to all NDT fund activity for these units. With our September 15, 2021 reversal of the previous decision to retire Byron, we resumed contractual offset for Byron as of that date. See Note 10 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning and the contractual offset suspension for the Byron units.

(b)Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations.

(c)Reversal of a charge related to a prior 2012 merger commitment. See Note 19 - Commitments and Contingencies for additional information.

The following table provides a reconciliation of cash, restricted cash, and cash equivalents reported in the Consolidated Balance Sheets that sum to the total of the same amounts in the Consolidated Statements of Cash Flows.


December 31, 2022	CEG Parent		Constellation
Cash and cash equivalents	$	422	$	403
Restricted cash and cash equivalents	106		98

Total cash, restricted cash, and cash equivalents	$	528	$	501


December 31, 2021	CEG Parent		Constellation
Cash and cash equivalents	$	504	$	504
Restricted cash and cash equivalents	72		72
Total cash, restricted cash, and cash equivalents	$	576	$	576


December 31, 2020	CEG Parent		Constellation
Cash and cash equivalents	$	226	$	226
Restricted cash and cash equivalents	89		89
Cash, restricted cash, and cash equivalents - Held for Sale	12		12
Total cash, restricted cash, and cash equivalents	$	327	$	327


December 31, 2019	CEG Parent		Constellation
Cash and cash equivalents	$	303	$	303
Restricted cash and cash equivalents	146		146
Total cash, restricted cash, and cash equivalents	$	449	$	449

For additional information on restricted cash, see Note 1 — Basis of Presentation.

Supplemental Balance Sheet Information

The following tables provide additional information about material items recorded in the Consolidated Balance Sheets.


	Investments
	December 31, 2022		December 31, 2021

Equity method investments	$	82	$	62

Other investments:
Employee benefit trusts and investments(a)	68		72

Equity investments without readily determinable fair values	46		33
Other available for sale debt security investments	6		7
Total investments	$	202	$	174

__________

(a)Debt and equity security investments are recorded at fair market value.


	Accrued expenses
December 31, 2022	CEG Parent		Constellation
Compensation-related accruals(a)	$	540	$	502
Taxes accrued	257		257


	Accrued expenses
December 31, 2021	CEG Parent		Constellation
Compensation-related accruals(a)	$	356	$	356
Taxes accrued	272		272

__________

(a)Primarily includes accrued payroll, bonuses and other incentives, vacation, and benefits.

Related Party Transactions

12 Months Ended

Dec. 31, 2022

Related Party Transactions

Prior to completion of the separation on February 1, 2022, we engaged in transactions with affiliates of Exelon in the normal course of business, these affiliate transactions are summarized in the tables below. After February 1, 2022, all transactions with Exelon or its affiliates are no longer related party transactions.

Operating revenues from affiliates

The following table presents our Operating revenues from affiliates:


	For the Years Ended December 31,
	2022(a)		2021		2020
ComEd(b)	$	58	$	376	$	330
PECO(c)	33		196		190
BGE(d)	18		236		315
PHI	51		366		367
Pepco(e)	39		270		279
DPL(f)	10		79		75
ACE(g)	2		17		13
Other	—		14		9
Total operating revenues from affiliates	$	160	$	1,188	$	1,211

__________

(a)Represents only January 2022 costs prior to separation on February 1, 2022.

(b)We have an ICC-approved RFP contract with ComEd to provide a portion of ComEd’s electricity supply requirements. We also sell RECs and ZECs to ComEd.

(c)We provide electric supply to PECO under contracts executed through PECO’s competitive procurement process. In addition, we have a ten-year agreement with PECO to sell solar AECs.

(d)We provide a portion of BGE’s energy requirements under its MDPSC-approved market-based SOS and gas commodity programs.

(e)We provide electric supply to Pepco under contracts executed through Pepco's competitive procurement process approved by the MDPSC and DCPSC.

(f)We provide a portion of DPL's energy requirements under its MDPSC and DEPSC approved market-based SOS commodity programs.

(g)We provide electric supply to ACE under contracts executed through ACE's competitive procurement process.

Service Company Costs for Corporate Support

We received a variety of corporate support services from Exelon. Through its business services subsidiary, BSC, Exelon provided support services at cost, including legal, human resources, financial, information technology, and supply management services. The costs of BSC were directly charged or allocated to us. Certain of these services will continue after the separation and are covered by the TSA. See Note 1 — Basis of Presentation for additional information.

The following table presents the service company costs allocated to us:


Operating and maintenance from affiliates						Capitalized costs
For the Years Ended December 31,						For the Years Ended December 31,
2022(a)		2021		2020		2022(a)		2021		2020
$	44	$	588	$	552	$	15	$	129	$	54

__________

(a)Represents only January 2022 costs prior to separation on February 1, 2022.

Current Receivables from/Payables to affiliates

The following table presents Current receivables from affiliates and Current payables to affiliates:


	December 31, 2021
	Receivables from affiliates:		Payables to affiliates:
ComEd	$	84	$	13
PECO	30		—
BGE	4		—
Pepco	20		—
DPL	4		—
ACE	7		—
BSC	—		102
Other	11		16
Total(a)	$	160	$	131

__________

(a)Prior to the completion of the separation on February 1, 2022, we engaged in transactions with affiliates of Exelon in the normal course of business. As of December 31, 2022, all transactions with Exelon or its affiliates are third-party transactions.

Payables Related to Regulatory Agreement Units

We have Noncurrent payables to ComEd and PECO as a result of the nuclear decommissioning contractual construct whereby, to the extent NDT funds are greater than the underlying ARO at the end of decommissioning, such amounts are due back to ComEd and PECO, as applicable, for payment to their respective customers. See Note 10 — Asset Retirement Obligations for additional information.

Schedule II - Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2022

SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract]

Valuation and Qualifying Accounts

Constellation Energy Corporation and Subsidiary Companies

Constellation Energy Generation, LLC and Subsidiary Companies

Schedule II – Valuation and Qualifying Accounts


			Additions and adjustments
Description	Balance at Beginning of Period		Charged to Costs and Expenses			Charged to Other Accounts		Deductions			Balance at End of Period
(In millions)
For the year ended December 31, 2022
Allowance for credit losses	$	59	$	10		$	—	$	18	(a)	$	51
Deferred tax valuation allowance	22		—			(11)		—			11
Reserve for obsolete materials	250		11			(6)		17			238
For the year ended December 31, 2021
Allowance for credit losses	$	32	$	34		$	—	$	7	(a)	$	59
Deferred tax valuation allowance	23		—			(1)		—			22
Reserve for obsolete materials	265		(6)			(2)		7			250
For the year ended December 31, 2020
Allowance for credit losses	$	81	$	12		$	(56)	$	5	(a)	$	32
Deferred tax valuation allowance	24		—			(1)		—			23
Reserve for obsolete materials	143		123		(b)	(1)		—			265

__________

(a)Write-offs, net of recoveries of individual accounts receivable.

(b)Primarily reflects expense resulting from materials and supplies inventory reserve adjustments as a result of the decision to early retire Byron, Dresden, and Mystic 8 and 9. See Note 7—Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information.

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

Mergers, Acquisitions, and Dispositions (Tables)

12 Months Ended

Dec. 31, 2022

Mergers, Acquisitions, and Dispositions [Abstract]

Schedule of Changes in Ownership Interest

The following table summarizes the effects of the changes in our ownership interest in CENG in Member's Equity:


	For the Year Ended December 31, 2021
Net loss attributable to membership interest	$	(205)
Pre-tax increase in membership interest for purchase of EDF's 49.99% equity interest(a)	1,080
Decrease in membership interest due to deferred tax liabilities resulting from purchase of EDF's equity interest(a)	(288)
Change from net loss attributable to membership interest and transfers from noncontrolling interest	$	587

__________

(a)Represents non-cash activity in the consolidated financial statements.

Revenue from Contracts with Customers (Tables)

12 Months Ended

Dec. 31, 2022

Revenue from Contract with Customer [Abstract]

Contract with Customer, Contract Asset, Contract Liability, and Receivable

The following table provides a rollforward of the contract assets reflected in the Consolidated Balance Sheets:


	Contract Assets
Balance as of December 31, 2020	$	144
Amounts reclassified to receivables	(59)
Revenues recognized	52
Amounts previously held-for-sale	12
Balance as of December 31, 2021	149
Amounts reclassified to receivables	(81)
Revenues recognized	62

Balance as of December 31, 2022	$	130

The following table provides a rollforward of the contract liabilities reflected in the Consolidated Balance Sheets:


	Contract Liabilities
Balance as of December 31, 2019	$	71
Consideration received or due	282
Revenues recognized	(266)
Contracts liabilities reclassified as held for sale	(3)
Balance as of December 31, 2020	84
Consideration received or due	251
Revenues recognized	(263)
Amounts previously held-for-sale	3
Balance as of December 31, 2021	75
Consideration received or due	339
Revenues recognized	(367)

Balance as of December 31, 2022	$	47

Contract with Customer, Prior Year Contract Revenues Recognized in Current Year

The following table reflects revenues recognized in the years ended December 31, 2022, 2021 and 2020, which were included in contract liabilities at December 31, 2021, 2020, and 2019, respectively:


	2022		2021		2020
Revenues recognized	$	71	$	82	$	64

Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction


	2023		2024		2025		2026		2027 and thereafter		Total
Remaining performance obligations	$	221	$	78	$	35	$	15	$	136	$	485

Segment Information (Tables)

12 Months Ended

Dec. 31, 2022

Segment Reporting [Abstract]

Revenue from External Customers by Geographic Areas


	2022
	Revenues from external customers(a)
	Contracts with customers		Other(b)		Total		Intersegment Revenues		Total Revenues
Mid-Atlantic	$	5,264	$	(105)	$	5,159	$	5	$	5,164
Midwest	5,164		(507)		4,657		(7)		4,650
New York	2,004		(408)		1,596		(1)		1,595
ERCOT	954		602		1,556		(13)		1,543
Other Power Regions	5,035		1,681		6,716		16		6,732
Total Competitive Businesses Electric Revenues	$	18,421	$	1,263	$	19,684	$	—	$	19,684
Competitive Businesses Natural Gas Revenues	2,559		2,408		4,967		—		4,967
Competitive Businesses Other Revenues(c)	591		(802)		(211)		—		(211)
Total Consolidated Operating Revenues	$	21,571	$	2,869	$	24,440	$	—	$	24,440


	2021
	Revenues from external customers(a)
	Contracts with customers		Other(b)		Total		Intersegment Revenues		Total Revenues
Mid-Atlantic	$	4,381	$	183	$	4,564	$	20	$	4,584
Midwest	4,265		(205)		4,060		—		4,060
New York	1,633		(57)		1,576		(1)		1,575
ERCOT	896		276		1,172		9		1,181
Other Power Regions	3,937		981		4,918		(28)		4,890
Total Competitive Businesses Electric Revenues	$	15,112	$	1,178	$	16,290	$	—	$	16,290
Competitive Businesses Natural Gas Revenues	1,777		1,602		3,379		—		3,379
Competitive Businesses Other Revenues(c)	365		(385)		(20)		—		(20)
Total Consolidated Operating Revenues	$	17,254	$	2,395	$	19,649	$	—	$	19,649


	2020
	Revenues from external customers(a)
	Contracts with customers		Other(b)		Total		Intersegment Revenues		Total Revenues
Mid-Atlantic	$	4,785	$	(168)	$	4,617	$	28	$	4,645
Midwest	3,717		312		4,029		(5)		4,024
New York	1,444		(12)		1,432		(1)		1,431
ERCOT	735		198		933		25		958
Other Power Regions	3,586		463		4,049		(47)		4,002
Total Competitive Businesses Electric Revenues	$	14,267	$	793	$	15,060	$	—	$	15,060
Competitive Businesses Natural Gas Revenues	1,283		720		2,003		—		2,003
Competitive Businesses Other Revenues(c)	355		185		540		—		540
Total Consolidated Operating Revenues	$	15,905	$	1,698	$	17,603	$	—	$	17,603

__________

(b)Includes revenues from derivatives and leases.


	2022						2021						2020
	RNF from external customers(a)		Intersegment RNF		Total RNF		RNF from external customers(a)		Intersegment RNF		Total RNF		RNF from external customers(a)		Intersegment RNF		Total RNF
Mid-Atlantic	$	2,129	$	9	$	2,138	$	2,247	$	17	$	2,264	$	2,174	$	30	$	2,204
Midwest	2,765		(1)		2,764		2,717		—		2,717		2,902		—		2,902
New York	1,061		6		1,067		1,151		10		1,161		983		14		997
ERCOT	503		(96)		407		(668)		(157)		(825)		407		19		426
Other Power Regions	952		(31)		921		984		(93)		891		759		(94)		665
Total RNF for Reportable Segments	$	7,410	$	(113)	$	7,297	$	6,431	$	(223)	$	6,208	$	7,225	$	(31)	$	7,194
Other(b)	(432)		113		(319)		1,055		223		1,278		793		31		824
Total RNF	$	6,978	$	—	$	6,978	$	7,486	$	—	$	7,486	$	8,018	$	—	$	8,018

__________

(b)Other represents activities not allocated to a region. See text above for a description of included activities. Primarily includes:

•Unrealized mark-to-market losses of $1,013 million, and gains of $565 million, and $295 million for the years ended December 31, 2022, 2021, and 2020, respectively;

•The elimination of intersegment RNF.

Accounts Receivable (Tables)

12 Months Ended

Dec. 31, 2022

Receivables [Abstract]

Allowance for Credit Losses Rollforward


Balance as of December 31, 2020	$	32
Plus: Current period provision for expected credit losses	30
Less: Write-offs, net of recoveries(a)	7

Balance as of December 31, 2021	55
Plus: Current period provision for expected credit losses	9
Less: Write-offs, net of recoveries(a)	18

Balance as of December 31, 2022	$	46

__________

(a)Recoveries were not material.

Purchases and Sales of Accounts Receivable

The following table summarizes the impact of the sale of certain receivables:


	As of December 31,
	2022		2021
Derecognized receivables transferred at fair value	$	1,615	$	1,265
Cash proceeds received	1,100		900
DPP	515		365


	For the Years Ended December 31,
	2022		2021		2020
Loss on sale of receivables(a)	$	69	$	36	$	30

_________


	For the Years Ended December 31,
	2022		2021		2020
Proceeds from new transfers(a)	$	6,108	$	6,095	$	2,816
Cash collections received on DPP and reinvested in the Facility(b)	4,764		3,502		3,771
Cash collections reinvested in the Facility	10,872		9,597		6,587

_________

(a)Customer accounts receivable sold into the Facility were $11,274 million and $9,747 million for the years ended December 31, 2022 and 2021, respectively.

(b)Does not include the $200 million in net cash proceeds received from the Purchasers in 2022 and $400 million in cash proceeds received from the Purchasers in 2021.

The following table presents the total receivables sold.


	For the Years Ended December 31,
	2022		2021		2020
Total receivables sold	$	423	$	147	$	824
Related party transactions:
Receivables sold to Exelon's utility subsidiaries prior to the separation on February 1, 2022	4		23		252

Early Plant Retirements (Tables)

12 Months Ended

Dec. 31, 2022

Implications of Potential Early Plant Retirements [Abstract]

Restructuring and Related Costs


Income statement expense (pre-tax)	2021		2020
Depreciation and amortization
Accelerated depreciation(a)	$	1,805	$	895
Accelerated nuclear fuel amortization	148		60
Operating and maintenance
One-time charges	(94)		255
Other charges(b)	9		34
Contractual offset(c)	(451)		(364)
Total	$	1,417	$	880

_________

(a)Includes the accelerated depreciation of plant assets including any ARC.

(b)For 2020, reflects the net impacts associated with the remeasurement of the ARO. See Note 10 - Asset Retirement Obligations for additional information.

Property, Plant, and Equipment (Tables)

12 Months Ended

Dec. 31, 2022

Property, Plant and Equipment [Abstract]

Property, Plant, and Equipment

The following table presents a summary of property, plant, and equipment by asset category as of December 31, 2022 and 2021:


Asset Category	December 31, 2022		December 31, 2021
Electric	$	30,804	$	29,910
Nuclear fuel(a)	5,106		5,166
Construction work in progress	630		399
Other property, plant, and equipment	8		10
Total property, plant, and equipment	36,548		35,485
Less: accumulated depreciation(b)	16,726		15,873
Property, plant, and equipment, net	$	19,822	$	19,612

__________

(a)Includes nuclear fuel that is in the fabrication and installation phase of $937 million and $859 million as of December 31, 2022 and 2021, respectively.

(b)Includes accumulated amortization of nuclear fuel in the reactor core of $2,657 million and $2,765 million as of December 31, 2022 and 2021, respectively.

The following table presents the average service life for each asset category in number of years:


Asset Category			Average Service Life (years)
Electric			1-52
Nuclear fuel			1-8
Other property, plant, and equipment			1-10

Jointly Owned Electric Utility Plant (Tables)

12 Months Ended

Dec. 31, 2022

Public Utilities, Property, Plant and Equipment [Abstract]

Schedule of Jointly Owned Utility Plants

Our material undivided ownership interests in jointly owned nuclear plants as of December 31, 2022 and 2021 were as follows:


	Nuclear Generation
	Quad Cities			Peach Bottom			Salem			Nine Mile Point Unit 2
Operator	Constellation			Constellation			PSEG Nuclear			Constellation
Ownership interest	75.00		%	50.00		%	42.59		%	82.00		%
Our share as of December 31, 2022
Plant in service	$	1,243		$	1,534		$	772		$	1,063
Accumulated depreciation	761			659			328			256
Construction work in progress	7			12			23			26
Our share as of December 31, 2021
Plant in service	$	1,211		$	1,515		$	756		$	1,002
Accumulated depreciation	715			628			299			222
Construction work in progress	11			12			20			41

Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2022

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligation Rollforward

The following table provides a rollforward of the nuclear decommissioning AROs reflected in the Consolidated Balance Sheets from December 31, 2020 to December 31, 2022:


Balance as of December 31, 2020	$	11,922
Net increase due to changes in, and timing of, estimated future cash flows	324
Accretion expense	503
Costs incurred related to decommissioning plants	(73)
Balance as of December 31, 2021(a)	12,676
Net decrease due to changes in, and timing of, estimated future cash flows	(648)
Accretion expense	532
Costs incurred related to decommissioning plants	(60)
Balance as of December 31, 2022(a)	$	12,500

__________

The following table provides a rollforward of the non-nuclear AROs reflected in the Consolidated Balance Sheets from December 31, 2020 to December 31, 2022:


Balance as of December 31, 2020	$	212
Net increase due to changes in, and timing of, estimated future cash flows	5
Accretion expense	11
Asset divestitures	(19)
Payments	(3)
AROs previously held for sale	10
Balance as of December 31, 2021	216
Net increase due to changes in, and timing of, estimated future cash flows	18

Accretion expense	11
Asset divestitures	(1)
Payments	(5)

Balance as of December 31, 2022	$	239


	December 31, 2022		December 31, 2021
ComEd	$	2,660	$	2,760
PECO	237		597

Leases (Tables)

12 Months Ended

Dec. 31, 2022

Leases [Abstract]

Components of Lease Cost

The following table outlines other terms and conditions of the lease agreements as of December 31, 2022. We did not have material finance leases in 2022, 2021, or in 2020.


			In Years
Remaining lease terms			1-33
Options to extend the term			2-30
Options to terminate within			1-2

The components of operating lease costs were as follows:


	For the Years Ended December 31,
	2022		2021		2020
Operating lease costs	$	109	$	161	$	194
Variable lease costs	169		168		234

__________

(a)Excludes $49 million, $44 million, $44 million of sublease income recorded for each of the years ended December 31, 2022, 2021, and 2020 respectively.

The weighted average remaining lease terms, in years, and the weighted average discount rates for operating leases as of December 31, 2022 were as follows:


	As of December 31,
	2022		2021		2020
Weighted average remaining lease term	9.3		10.1		10.5
Weighted average discount rate	5.0	%	5.0	%	4.9	%

The following table outlines other terms and conditions of the lease agreements as of December 31, 2022.


			In Years
Remaining lease terms			1-18
Options to extend the term			1-20

Supplemental Balance Sheet Information Related to Lessee Right-of-Use Assets and Lease Liabilities

The following table provides additional information regarding the presentation of operating lease ROU assets and lease liabilities in the Consolidated Balance Sheets:


	As of December 31,
	2022		2021
Operating lease ROU assets(a)
Other deferred debits and other assets	$	545	$	604

Operating lease liabilities(a)
Other current liabilities	67		72
Other deferred credits and other liabilities	643		705
Total operating lease liabilities	$	710	$	777

__________

Lessee, Operating Lease, Liability, Maturity

The following table reconciles the undiscounted cash flows for our operating leases to the operating lease liabilities recorded on our consolidated balance sheet as of December 31, 2022:


Year	Amount
2023	$	101
2024	99
2025	102
2026	102
2027	100
Thereafter	421
Total lease payments	925
Less: Imputed interest	215
Operating lease liabilities	$	710

Lessee, Operating Lease, Supplemental Cash Flow Information

Supplemental cash flow information related to operating leases was as follows:


	For the Years Ended December 31,
	2022		2021		2020
Cash paid for amounts included in the measurement of operating lease liabilities	$	114	$	162	$	204
ROU assets obtained in exchange for operating lease obligations	14		2		3

Components of Operating Lease Income

The components of lease income were as follows:


	For the Years Ended December 31,
	2022		2021		2020
Operating lease income	$	51	$	47	$	47
Variable lease income	258		261		282

Lessor, Operating Lease, Payment to be Received, Fiscal Year Maturity

The following table presents maturity analysis of the lease payments we expect to receive as of December 31, 2022:


Year	Amount
2023	$	48
2024	48
2025	48
2026	49
2027	49
Thereafter	133
Total	$	375

Intangible Assets (Tables)

12 Months Ended

Dec. 31, 2022

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Finite-Lived Intangible Assets


	December 31, 2022						December 31, 2021
	Gross		Accumulated Amortization		Net		Gross		Accumulated Amortization		Net
Unamortized Energy Contracts	$	1,960	$	(1,708)	$	252	$	1,963	$	(1,673)	$	290
Customer Relationships	356		(265)		91		330		(243)		87
Trade Name	222		(222)		—		222		(218)		4



Total	$	2,538	$	(2,195)	$	343	$	2,515	$	(2,134)	$	381

Schedule Of Finite-Lived Intangible Assets Amortization Expense

The following table summarizes the amortization expense related to intangible assets and liabilities for each of the years ended December 31, 2022, 2021, and 2020:


For the Years Ended December 31,	Amortization Expense(a)
2022	$	61
2021	80
2020	81

__________

(a)See Note 23 — Supplemental Financial Information for additional information related to the amortization of unamortized energy contracts.

Schedule of Finite-Lived Intangible Assets, Future Amortization Expense [Table Text Block]

The following table summarizes the estimated future amortization expense related to intangible assets and liabilities as of December 31, 2022:


For the Years Ending December 31,	Estimated Future Amortization Expense
2023	$	59
2024	56
2025	47
2026	40
2027	27

Schedule of Alternative or Renewable Energy Credits [Table Text Block]

The following table presents current RECs as of December 31, 2022 and 2021:


	December 31, 2022		December 31, 2021
Current REC's	$	617	$	520

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2022

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Expense (Benefit)

Income taxes are comprised of the following components:


	For the Years Ended December 31,
	2022(a)		2021(a)		2020(a)
Federal
Current	$	219	$	394	$	130
Deferred	(655)		(153)		150
ITC amortization	(15)		(15)		(25)
State
Current	34		36		40
Deferred	29		(37)		(46)
Total	$	(388)	$	225	$	249

_________

(a)Negative amounts represent income tax benefit. Positive amounts represent income tax expense.

Effective Income Tax Rate Reconciliation

The effective income tax rate varies from the U.S. federal statutory rate principally due to the following:


	For the Years Ended December 31,
	2022(a)		2021		2020
U.S. federal statutory rate	21.0	%	21.0	%	21.0	%
(Decrease) increase due to:
State income taxes, net of federal income tax benefit(c)	(9.2)		—		0.5
Qualified NDT fund income and losses	46.3		165.1		23.5
Amortization of investment tax credit, including deferred taxes on basis differences	2.2		(9.0)		(2.6)

Production tax credits and other credits	7.7		(28.7)		(5.4)
Noncontrolling interests	(0.3)		(3.0)		3.2
Tax Settlements	—		—		(10.3)

Other(d)	3.9		2.6		(0.1)
Effective income tax rate(b)	71.6	%	148.0	%	29.8	%

_________

(a)Positive percentages represent income tax benefit. Negative percentages represent income tax expense.

(b)The change in effective tax rate in 2022 is primarily due to the impacts of higher unrealized NDT losses on Income before income taxes and one-time income tax adjustments.

(c)Includes $30 million related to state rate changes and certain state tax positions.

(d)Primarily related to a $32 million prior period income tax adjustment recorded in 2022.

Tax Effects of Temporary Differences

The tax effects of temporary differences and carryforwards, which give rise to significant portions of the deferred tax (liabilities) assets, as of December 31, 2022 and 2021 are presented below:


	December 31, 2022		December 31, 2021
Plant basis differences	$	(3,005)	$	(2,812)
Accrual based contracts	(35)		(38)
Derivatives and other financial instruments	43		(172)
Deferred pension and postretirement obligation	287		(274)
Nuclear decommissioning activities	(371)		(912)
Deferred debt refinancing costs	—		15
Tax loss carryforward, net of valuation allowances	67		53
Tax credit carryforward	179		778
Investment in partnerships	(205)		(252)
Other, net	407		312
Deferred income tax liabilities (net)	$	(2,633)	$	(3,302)
Unamortized ITCs	(354)		(369)
Total deferred income tax liabilities (net) and unamortized ITCs	$	(2,987)	$	(3,671)

Summary of Loss Carryforwards

The following table provides our carryforwards, of which the state related items are presented on a post-apportioned basis, and any corresponding valuation allowances as of December 31, 2022:


Federal	December 31, 2022


Federal general business credits carryforwards and other carryforwards	$	178
State
State net operating losses and other carryforwards	939
Deferred taxes on state tax attributes (net)	78
Valuation allowance on state tax attributes	11
Year in which net operating loss or credit carryforwards will begin to expire	2035

Schedule of Unrecognized Tax Benefits Roll Forward

The following table presents changes in unrecognized tax benefits:


	Unrecognized tax benefits
Balance as of December 31, 2019	$	441

Increases based on tax positions related to 2020	1
Increases based on tax positions prior to 2020	23
Decreases based on tax positions prior to 2020(a)	(346)
Decrease from settlements with taxing authorities(a)	(69)
Balance as of December 31, 2020	50
Change to positions that only affect timing	(1)
Increases based on tax positions related to 2021	1
Increases based on tax positions prior to 2021	1
Decreases based on tax positions prior to 2021	(2)
Balance as of December 31, 2021	49
Change to positions that only affect timing	(5)
Increases based on tax positions related to 2022	29
Increases based on tax positions prior to 2022(b)	6
Decreases based on tax positions prior to 2022(b)	(55)
Balance as of December 31, 2022	$	24

__________

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 effective tax rate:





December 31, 2022	$	29
December 31, 2021	39
December 31, 2020	39

Summary of Income Tax Examinations

Description of tax years open to assessment by major jurisdiction


Major Jurisdiction			Open Years(a)
Federal consolidated income tax returns			2010-2021
Illinois unitary corporate income tax returns			2012-2021
New Jersey separate corporate income tax returns			2017-2018
New Jersey combined corporate income tax returns			2019-2021
New York combined corporate income tax returns			2015-2021
Pennsylvania separate corporate income tax returns			2019-2021

__________

(a)Tax years open to assessment include years when we were consolidated by Exelon. See discussion below under the Tax Matters Agreement for responsibility of taxes of these open years.

Allocation of Federal Tax Benefit Under Tax Sharing Agreement

The following table presents the allocation of tax benefits from Exelon to us under the Tax Sharing Agreement:


December 31, 2021			64
December 31, 2020			64

Retirement Benefits (Tables)

12 Months Ended

Dec. 31, 2022

Retirement Benefits [Abstract]

Defined Benefit Plan, Plan with Projected Benefit Obligation in Excess of Plan Assets

The following tables provide a rollforward of the changes in the benefit obligations and plan assets for the year ended December 31, 2022 for all plans combined:


	Pension Benefits		OPEB
Change in benefit obligation:
Benefit obligation as of the beginning of the year	$	—	$	847
Separation-related adjustment	9,220		933
Benefit obligation as of February 1, 2022	9,220		1,780
Service cost	115		23
Interest cost	269		52
Plan participants' contributions	—		20
Actuarial gain, net	(1,756)		(401)

Settlements	(15)		—
Gross benefits paid	(558)		(114)
Benefit obligation as of the end of year	$	7,275	$	1,360


	Pension Benefits		OPEB
Change in plan assets:
Prepaid pension asset as of the beginning of year	$	1,683	$	—
Separation-related adjustment	6,584		904
Fair value of net plan assets as of February 1, 2022	8,267		904
Actual return on plan assets	(1,245)		(99)
Employer contributions	211		—
Plan participants' contributions	—		15
Gross benefits paid	(558)		(86)
Settlements	(15)		—
Fair value of net plan assets as of the end of year	$	6,660	$	734

Schedule of Defined Benefit Plans Disclosures

We present our benefit obligations net of plan assets on our Consolidated Balance Sheets within the following line items:


	Pension Benefits				OPEB
	2022		2021		2022		2021
Prepaid pension asset	$	—	$	1,683	$	—	$	—
Other current liabilities	(10)		—		(17)		—
Pension obligations	(605)		—		—		—
Non-pension postretirement benefit obligations	—		—		(609)		(847)
(Unfunded) funded status (net benefit obligation less plan assets)	$	(615)	$	1,683	$	(626)	$	(847)


ABO in Excess of Plan Assets	December 31, 2022
ABO	$	(7,121)
Fair value of net plan assets	6,660


	Pension Benefits		OPEB
Changes in plan assets and benefit obligations recognized in AOCI:
Separation related adjustment	$	2,664	$	22
Current year actuarial (gain) loss	11		(253)
Amortization of actuarial (loss) gain	(134)		1

Amortization of prior service (cost) credit	(1)		7

Settlements	(6)		—
Total recognized in AOCI	$	2,534	$	(223)


	Pension Benefits		OPEB
Prior service cost (credit)	$	10	$	(30)
Actuarial loss (gain)	2,524		(193)
Total	$	2,534	$	(223)

The resulting average remaining service periods for pension and OPEB were as follows as of December 31, 2022:


			December 31, 2022
Pension plans			12.2
OPEB plans:
Benefit Eligibility Age			7.4
Expected Retirement			8.3


	Pension Benefits				OPEB
	December 31, 2022		February 1, 2022		December 31, 2022		February 1, 2022
Discount rate(a)	5.52	%	3.23	%	5.50	%	3.21	%
Investment crediting rate(b)	5.15	%	3.86	%	N/A		N/A
Rate of compensation increase	3.75	%	3.75	%	3.75	%	3.75	%
Mortality table	Pri-2012 table with MP-2021 improvement scale (adjusted)		Pri-2012 table with MP-2021 improvement scale (adjusted)		Pri-2012 table with MP-2021 improvement scale (adjusted)		Pri-2012 table with MP-2021 improvement scale (adjusted)
Healthcare cost trend on covered charges	N/A		N/A		Initial and ultimate rate of 5.00%		Initial and ultimate rate of 5.00%

__________

(a)The discount rates above represent the blended rates used to establish the majority of Constellation's pension and OPEB costs.

(b)The investment crediting rate above represents a weighted average rate.

Estimated future benefit payments to participants over the next ten years in all pension and OPEB plans as of December 31, 2022 are as follows:


	Pension Benefits		OPEB
2023	$	525	$	105
2024	531		105
2025	544		105
2026	541		105
2027	547		106
2028 through 2032	2,792		525
Total estimated future benefits payments through 2032	$	5,480	$	1,051

Our pension and OPEB plan target asset allocations as of December 31, 2022 were as follows:


Asset Category	Pension Benefits		OPEB
Equity securities	21	%	43	%
Fixed income securities	54	%	45	%
Alternative investments(a)	25	%	12	%
Total	100	%	100	%

__________

(a)Alternative investments include private equity, hedge funds, real estate, and private credit.

Calculation of Net Periodic Benefit Costs

The following table presents the components of our net periodic benefit costs (credits), prior to capitalization and co-owner allocations, for the years ended December 31, 2022, 2021 and 2020:


	Pension Benefits						OPEB						Total Pension Benefits and OPEB
	2022		2021(a)		2020(a)		2022		2021(a)		2020(a)		2022		2021(a)		2020(a)
Components of net periodic benefit cost (credit):
Service cost	$	126	$	145	$	137	$	25	$	29	$	34	$	151	$	174	$	171
Non-service components of pension benefits & OPEB cost (credit):
Interest cost	290		235		280		55		45		61		345		280		341
Expected return on assets	(565)		(493)		(474)		(55)		(58)		(62)		(620)		(551)		(536)
Amortization of:
Prior service cost (credit)	1		1		1		(7)		(9)		(49)		(6)		(8)		(48)
Actuarial loss (gain)	148		199		164		(1)		10		15		147		209		179
Settlement charges	6		20		9		—		—		(1)		6		20		8

Non-service components of pension benefits & OPEB credit(b)	(120)		(38)		(20)		(8)		(12)		(36)		(128)		(50)		(56)
Net periodic benefit cost (credit)(c)(d)(e)	$	6	$	107	$	117	$	17	$	17	$	(2)	$	23	$	124	$	115

__________

(a)Costs recognized for the years ended December 31, 2021 and 2020 were allocated to us by Exelon under the Exelon sponsored pension and OPEB plans prior to separation.

(b)Effective February 1, 2022, these non-service costs (credits) are reflected in Other, net in the Consolidated Statements of Operations and Comprehensive Income.

Schedule of Allocation of Plan Assets


	December 31. 2022
	Level 1		Level 2		Level 3		Not subject to leveling		Total
Pension plan assets(a)
Cash equivalents	$	216	$	—	$	—	$	—	$	216
Equities(b)	776		—		—		368		1,144
Fixed income:
U.S. Treasury and agencies	693		128		—		—		821
State and municipal debt	—		44		—		—		44
Corporate debt	—		1,736		8		—		1,744
Other(b)	—		43		—		470		513
Fixed income subtotal	693		1,951		8		470		3,122
Private equity	—		—		180		585		765
Hedge funds	—		—		—		429		429
Real estate	—		—		—		547		547
Private credit	—		—		—		480		480
Pension plan assets subtotal	1,685		1,951		188		2,879		6,703

OPEB plan assets(a)
Cash equivalents	40		—		—		—		40
Equities	152		—		—		146		298
Fixed income:
U.S. Treasury and agencies	10		27		—		—		37
State and municipal debt	—		4		—		—		4
Corporate debt	—		27		—		—		27
Other	57		3		—		111		171
Fixed income subtotal	67		61		—		111		239

Hedge funds	—		—		—		59		59
Real estate	—		—		—		62		62
Private credit	—		—		—		36		36
OPEB plan assets subtotal	259		61		—		414		734
Total pension and OPEB plan assets(c)	$	1,944	$	2,012	$	188	$	3,293	$	7,437

__________

(a)See Note 18 — Fair Value of Financial Assets and Liabilities for a description of levels within the fair value hierarchy.

Pension And Other Postretirement Benefit Contributions

The following tables provide our contributions to the pension and OPEB plans:


Pension benefits				OPEB
2021		2020		2021		2020
$	231	$	236	$	28	$	19

The following table provides our planned contributions to our qualified pension plans, non-qualified pension plans, and OPEB plans in 2023 (including our benefit payments related to unfunded plans):


	Qualified Pension Plans		Non-Qualified Pension Plans		OPEB
Planned contributions	$	21	$	10	$	17

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation

The following table presents the reconciliation of Level 3 assets and liabilities measured at fair value for pension and OPEB plans for the year ended December 31, 2022:


Pension Assets	Fixed Income		Equities		Private Equity		Total
Balance as of January 1, 2022	$	—	$	—	$	—	$	—
Separation related adjustment	9		—		—		9
Actual return on plan assets:
Relating to assets still held as of the reporting date	(1)		—		(54)		(55)

Purchases and settlements:
Purchases	—		—		18		18

Settlements(a)	—		—		(4)		(4)
Transfers into Level 3(b)	—		—		220		220
Balance as of December 31, 2022	$	8	$	—	$	180	$	188

__________

(a)Represents cash settlements only.

Derivative Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2022

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Summary of the Derivative Fair Value

The following tables provide a summary of the derivative fair value balances recorded as of December 31, 2022 and 2021:


December 31, 2022	Economic Hedges		Proprietary Trading		Collateral (a)(b)		Netting(a)		Total
Mark-to-market derivative assets (current assets)	$	15,296	$	10	$	161	$	(13,123)	$	2,344
Mark-to-market derivative assets (noncurrent assets)	5,100		—		217		(4,074)		1,243
Total mark-to-market derivative assets	20,396		10		378		(17,197)		3,587
Mark-to-market derivative liabilities (current liabilities)	(15,049)		(6)		374		13,123		(1,558)
Mark-to-market derivative liabilities (noncurrent liabilities)	(5,203)		—		146		4,074		(983)
Total mark-to-market derivative liabilities	(20,252)		(6)		520		17,197		(2,541)
Total mark-to-market derivative net assets	$	144	$	4	$	898	$	—	$	1,046

December 31, 2021
Mark-to-market derivative assets (current assets)	$	10,915	$	25	$	152	$	(8,923)	$	2,169
Mark-to-market derivative assets (noncurrent assets)	3,224		2		15		(2,298)		943
Total mark-to-market derivative assets	14,139		27		167		(11,221)		3,112
Mark-to-market derivative liabilities (current liabilities)	(10,143)		(19)		262		8,923		(977)
Mark-to-market derivative liabilities (noncurrent liabilities)	(2,893)		(1)		83		2,298		(513)
Total mark-to-market derivative liabilities	(13,036)		(20)		345		11,221		(1,490)
Total mark-to-market derivative net assets	$	1,103	$	7	$	512	$	—	$	1,622

_________

(b)Includes $836 million and $897 million of variation margin held from the exchanges as of December 31, 2022 and 2021, respectively.

The following table provides the mark-to-market derivative assets and liabilities as of December 31, 2022:


December 31, 2022	Economic Hedges		Netting(a)		Total
Mark-to-market derivative assets (current assets)	$	29	$	(5)	$	24
Mark-to-market derivative assets (noncurrent assets)	18		—		18
Total mark-to-market derivative assets	47		(5)		42
Mark-to-market derivative liabilities (current liabilities)	(5)		5		—
Mark-to-market derivative liabilities (noncurrent liabilities)	—		—		—
Total mark-to-market derivative liabilities	(5)		5		—
Total mark-to-market derivative net assets	$	42	$	—	$	42

_________

Economic Hedges (Commodity Price Risk)


	Gains (Losses)
Income Statement Location	2022		2021		2020

Operating revenues	$	(1,193)	$	(635)	$	112
Purchased power and fuel	167		1,206		168
Total	$	(1,026)	$	571	$	280

Disclosure of Credit Derivatives

credit risk exposure from individual retail counterparties, nuclear fuel procurement contracts, and exposure through RTOs, ISOs, NYMEX, ICE, NASDAQ, NGX, and Nodal commodity exchanges.


Rating as of December 31, 2022	Total Exposure Before Credit Collateral		Credit Collateral(a)		Net Exposure		Number of Counterparties Greater than 10% of Net Exposure	Net Exposure of Counterparties Greater than 10% of Net Exposure
Investment grade	$	1,304	$	135	$	1,169	—	$	—
Non-investment grade	110		88		22		—	—
No external ratings
Internally rated — investment grade	106		—		106		—	—
Internally rated — non-investment grade	374		40		334		—	—
Total	$	1,894	$	263	$	1,631	—	$	—


Net Credit Exposure by Type of Counterparty	As of December 31, 2022
Investor-owned utilities, marketers, power producers	$	1,311
Energy cooperatives and municipalities	112
Financial Institutions	9
Other	199
Total	$	1,631

__________

Fair Value of Derivatives with Credit- Risk Related Contingent Features


	As of December 31,
Credit-Risk-Related Contingent Features	2022		2021
Gross fair value of derivative contracts containing this feature(a)	$	(4,736)	$	(3,872)
Offsetting fair value of in-the-money contracts under master netting arrangements(b)	2,048		2,424
Net fair value of derivative contracts containing this feature(c)	$	(2,688)	$	(1,448)

__________

(a)Amount represents the gross fair value of out-of-the-money derivative contracts containing credit-risk-related contingent features ignoring the effects of master netting agreements.

Cash Collateral and Letters of Credit on Derivative Contracts


	As of December 31,
	2022		2021
Cash collateral posted(a)	$	1,636	$	713
Letters of credit posted(a)	947		755
Cash collateral held(a)	765		182
Letters of credit held(a)	115		124
Additional collateral required in the event of a credit downgrade below investment grade (at BB+/Ba1)(b)(c)	3,337		2,113

_________

(a)The cash collateral and letters of credit amounts are inclusive of NPNS contracts.

(c)The downgrade collateral is inclusive of all contracts in a liability position regardless of accounting treatment.

Schedule of Commercial Paper, Credit Facilities and Borrowing Rates

Tabular disclosure of credit derivatives which includes information by sellers of credit derivatives, about each credit derivative, or each group of similar credit derivatives, including (a) the nature of the credit derivative - its term, how it arose, the events or circumstances that would require the seller to perform under the credit derivative, and the current status of the payment/performance risk of the credit derivative; (b) the maximum potential amount of future payments (undiscounted) the seller could be required to make under the credit derivative; (c) the current fair value of the credit derivative; and (d) the nature of any recourse provisions under the credit derivative, and any assets held either as collateral or by third parties. A credit derivative is a derivative instrument (1) in which one or more of its underlyings are related to the credit risk of a specified entity (or a group of entities) or an index based on the credit risk of a group of entities and (2) that exposes the seller to potential loss from credit-risk-related events specified in the contract. Examples of credit derivatives within the scope of this paragraph include, but are not limited to, credit default swaps, credit spread options, and credit index products; also includes a hybrid instrument that has an embedded credit derivative (for example, but not limited to, a credit-linked note).

+ References + Details

Debt and Credit Agreements (Tables)

12 Months Ended

Dec. 31, 2022

Debt Disclosure [Abstract]

The following table reflects our commercial paper program supported by the revolving credit agreements as of December 31, 2022 and 2021:


Maximum Program Size at December 31,				Outstanding Commercial Paper at December 31,				Weighted Average Interest Rate on Commercial Paper Borrowings at December 31,
2022(a)(b)(c)		2021(a)(d)		2022		2021		2022		2021
$	3,500	$	5,300	$	959	$	702	4.90	%	0.66	%

__________

(b)Excludes the liquidity facility, which has a bank commitment of $971 million as of December 31, 2022. This credit facility does not back our commercial paper program.

As of December 31, 2022, and 2021 we had the following aggregate bank commitments, credit facility borrowings and available capacity under our respective credit facilities:


							Available Capacity as of December 31, 2022
Facility Type	Aggregate Bank Commitment		Facility Draws		Outstanding Letters of Credit		Actual			To Support Additional Commercial Paper
Syndicated Revolver	$	3,500	$	—	$	765	$	2,735		$	1,776
Bilaterals	1,200		—		867		333			—
Liquidity Facility	971		—		732		139		(a)	—
Project Finance	131		—		111		20			—
Total	$	5,802	$	—	$	2,475	$	3,227		$	1,776

__________


							Available Capacity as of December 31, 2021
Facility Type	Aggregate Bank Commitment(b)		Facility Draws		Outstanding Letters of Credit		Actual		To Support Additional Commercial Paper
Syndicated Revolver(a)	$	5,300	$	—	$	1,230	$	4,070	$	3,368
Bilaterals	1,200		—		1,029		171		—
Project Finance	131		—		116		15		—
Total	$	6,631	$	—	$	2,375	$	4,256	$	3,368

__________

(a)Our syndicated revolving credit facility was replaced by the $3.5 billion 5-year revolving credit agreement entered into on February 1, 2022 in connection with the separation.

Schedule of Bilateral Credit Agreements

Bilateral Credit Agreements

The following table reflects the bilateral credit agreements at December 31, 2022:

Date Initiated

Latest Amendment Date

Maturity Date(a)

Amount

January 5, 2016

(b)

April 2, 2021

April 5, 2023

150

October 25, 2019

(b)

N/A

200

November 20, 2019

(b)

N/A

300

November 21, 2019

(b)

N/A

100

November 21, 2019

(b)

November 15, 2022

November 21, 2024

100

May 15, 2020

(b)(d)

February 9, 2022

N/A

200

August 12, 2022

(b)

N/A

August 24, 2022

(b)(c)

N/A

August 23, 2024

100

__________

(b)Bilateral credit agreements solely support the issuance of letters of credit and do not back our commercial paper program.

(c)On January 20, 2023, the bilateral credit agreement decreased to $10 million.

(d)On January 31, 2023, the bilateral credit agreement increased to $250 million.

Schedule of Long-term Debt Instruments

Long-Term Debt

The following table presents the outstanding long-term debt as of December 31, 2022 and 2021:


						Maturity Date	December 31,
	Rates						2022		2021
Long-term debt
Senior unsecured notes	3.25	%	-	6.25	%	2025 - 2042	$	2,938	$	4,219



Notes payable and other	2.10	%	-	6.96	%	2023 - 2028	68		103
Nonrecourse debt:
Fixed rates	2.29	%	-	6.00	%	2031 - 2037	839		909
Variable rates	2.99	%	-	7.24	%	2026 - 2027	805		870
Total long-term debt							4,650		6,101
Unamortized debt discount and premium, net							(5)		(7)
Unamortized debt issuance costs							(36)		(42)
Fair value adjustment							—		62
Long-term debt due within one year							(143)		(1,220)
Long-term debt							$	4,466	$	4,894

Schedule of Maturities of Long-term Debt

Long-term debt maturities in the periods 2023 through 2027 and thereafter are as follows:


2023	$	143
2024	110
2025	986
2026	121
2027	735
Thereafter	2,555
Total	$	4,650

Tabular disclosure of long-debt instruments or arrangements, including identification, terms, features, collateral requirements and other information necessary to a fair presentation. These are debt arrangements that originally required repayment more than twelve months after issuance or greater than the normal operating cycle of the entity, if longer.

Fair Value of Financial Liabilities Recorded at Amortized Cost

Fair Value of Financial Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2022

Fair Value Disclosures [Abstract]


	December 31, 2022								December 31, 2021
	Carrying Amount		Fair Value						Carrying Amount		Fair Value
			Level 2		Level 3		Total				Level 2		Level 3		Total
Long-Term Debt, including amounts due within one year	$	4,609	$	3,688	$	859	$	4,547	$	6,114	$	5,749	$	1,093	$	6,842
SNF Obligation	1,230		1,021		—		1,021		1,210		1,060		—		1,060

Assets and Liabilities Measured and Recorded at Fair Value on Recurring Basis


	As of December 31, 2022										As of December 31, 2021
	Level 1		Level 2		Level 3		Not subject to leveling		Total		Level 1		Level 2		Level 3		Not subject to leveling		Total
Assets
Cash equivalents(a)	$	41	$	—	$	—	$	—	$	41	$	113	$	—	$	—	$	—	$	113
NDT fund investments
Cash equivalents(b)	349		88		—		—		437		465		116		—		—		581
Equities	3,462		1,498		—		1,421		6,381		4,564		1,805		—		1,645		8,014
Fixed income
Corporate debt(c)	—		885		264		—		1,149		—		1,145		286		—		1,431
U.S. Treasury and agencies	1,996		46		—		—		2,042		2,193		30		—		—		2,223
Foreign governments	—		39		—		—		39		—		60		—		—		60
State and municipal debt	—		53		—		—		53		—		26		—		—		26
Other	21		21		—		1,649		1,691		29		23		—		1449		1,501
Fixed income subtotal	2,017		1,044		264		1,649		4,974		2,222		1,284		286		1,449		5,241
Private credit	—		—		159		643		802		—		—		178		624		802
Private equity	—		—		—		687		687		—		—		—		673		673
Real estate	—		—		—		1,014		1,014		—		—		—		864		864

NDT fund investments subtotal(d)(e)	5,828		2,630		423		5,414		14,295		7,251		3,205		464		5,255		16,175
Rabbi trust investments
Cash equivalents	1		—		—		—		1		3		—		—		—		3
Mutual funds	39		—		—		—		39		36		—		—		—		36
Life insurance contracts	—		27		1		—		28		—		33		—		—		33
Rabbi trust investments subtotal	40		27		1		—		68		39		33		—		—		72
Investments in equities	6		—		—		—		6		43		—		—		—		43
Commodity derivative assets
Economic hedges	3,505		11,353		5,585		—		20,443		3,017		7,223		3,899		—		14,139
Proprietary trading	—		4		6		—		10		—		19		8		—		27
Effect of netting and allocation of collateral(f)(g)	(2,951)		(10,348)		(3,525)		—		(16,824)		(2,108)		(6,177)		(2769)		—		(11,054)
Commodity derivative assets subtotal	554		1,009		2,066		—		3,629		909		1,065		1,138		—		3,112
DPP consideration	—		515		—		—		515		—		365		—		—		365
Total assets	6,469		4,181		2,490		5,414		18,554		8,355		4,668		1,602		5,255		19,880

Liabilities
Commodity derivative liabilities
Economic hedges	(3,171)		(11,498)		(5,588)		—		(20,257)		(2,201)		(6,870)		(3,965)		—		(13,036)
Proprietary trading	—		(4)		(2)		—		(6)		—		(18)		(2)		—		(20)
Effect of netting and allocation of collateral(f)(g)	3,279		10,700		3,743		—		17,722		2,189		6,642		2,735		—		11,566
Commodity derivative liabilities subtotal	108		(802)		(1,847)		—		(2,541)		(12)		(246)		(1,232)		—		(1,490)
Deferred compensation obligation	—		(57)		—		—		(57)		—		(43)		—		—		(43)
Total liabilities	108		(859)		(1,847)		—		(2,598)		(12)		(289)		(1,232)		—		(1,533)
Total net assets	$	6,577	$	3,322	$	643	$	5,414	$	15,956	$	8,343	$	4,379	$	370	$	5,255	$	18,347

__________

(g)Includes $836 million and $897 million of variation margin held from the exchanges as of December 31, 2022 and 2021, respectively.

Fair Value Reconciliation of Level 3 Assets and Liabilities Measured at Fair Value on a Recurring Basis

The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2022 and 2021:


	For the Year Ended December 31, 2022
	NDT Fund Investments		Mark-to-Market Derivatives			Life Insurance Contracts		Total
Balance as of January 1, 2022	$	464	$	(94)		$	—	$	370

Total realized / unrealized losses
Included in net income	(2)		(753)		(a)	(2)		(757)
Included in noncurrent payables to affiliates	(10)		—			—		(10)
Change in collateral	—		253			—		253
Impacts of separation	—		—			3		3
Purchases, sales, issuances and settlements
Purchases	5		594			—		599
Sales	—		(50)			—		(50)

Settlements	(35)		(102)			—		(137)
Transfers into Level 3	2		381		(b)	—		383
Transfers out of Level 3	(1)		(10)		(b)	—		(11)
Balance as of December 31, 2022	$	423	$	219		$	1	$	643
The amount of total losses included in income attributed to the change in unrealized losses related to assets and liabilities as of December 31, 2022	$	(2)	$	(1,265)		$	(2)	$	(1,269)


	For the Year Ended December 31, 2021
	NDT Fund Investments		Mark-to-Market Derivatives			Total
Balance as of January 1, 2021	$	497	$	430		$	927

Total realized / unrealized gains (losses)
Included in net income	5		(812)		(a)	(807)
Included in noncurrent payables to affiliates	19		—			19
Change in collateral	—		(196)			(196)
Purchases, sales, issuances and settlements
Purchases	4		162			166
Sales	—		(10)			(10)

Settlements	(61)		—			(61)
Transfers into Level 3	—		19		(b)	19
Transfers out of Level 3	—		313		(b)	313

Balance as of December 31, 2021	$	464	$	(94)		$	370
The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of December 31, 2021	$	5	$	(1,222)		$	(1,217)

__________

(a)Includes an addition of $410 million for realized losses due to the settlement of derivative contracts for both of the years ended December 31, 2022 and 2021, respectively.

Total Realized and Unrealized Gains (Losses) Included in Income for Level 3 Assets and Liabilities Measured at Fair Value on a Recurring Basis


	Operating Revenues						Purchased Power and Fuel						Other, net
	2022		2021		2020		2022		2021		2020		2022		2021		2020
Total (losses) gains included in net income	$	(860)	$	(1,343)	$	(404)	$	5	$	531	$	(10)	$	(4)	$	5	$	2

Total unrealized (losses) gains	(1,330)		(1,577)		(31)		65		355		37		(2)		5		2

Fair Value Reconciliation of Level 3 Assets and Liabilities Measured at Fair Value on a Recurring Basis, Valuation Technique

The following table presents the significant inputs to the forward curve used to value these positions:


Type of trade	Fair Value as of December 31, 2022		Fair Value as of December 31, 2021		Valuation Technique	Unobservable Input	2022 Range & Arithmetic Average				2021 Range & Arithmetic Average
Mark-to-market derivatives—Economic hedges(a)(b)	$	(3)	$	(66)	Discounted Cash Flow	Forward power price	$0.63	-	$283	$72	$8.86	-	$481	$55
						Forward gas price	$1.67	-	$26	$4.57	$1.69	-	$17	$3.50
					Option Model	Volatility percentage	97%	-	119%	111%	24%	-	284%	56%

__________

(a)The valuation techniques, unobservable inputs, ranges, and arithmetic averages are the same for the asset and liability positions.

(b)The fair values do not include cash collateral posted (received) on level three positions of $218 million and ($34) million as of December 31, 2022 and December 31, 2021, respectively.

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2022

Commitments and Contingencies Disclosure [Abstract]

Other Commitments

Commercial commitments as of December 31, 2022, representing commitments potentially triggered by future events, were as follows:


			Expiration within
	Total		2023		2024		2025		2026		2027		2028 and beyond
Letters of credit	$	2,475	$	2,465	$	10	$	—	$	—	$	—	$	—
Surety bonds(a)	978		977		1		—		—		—		—
Total commercial commitments	$	3,453	$	3,442	$	11	$	—	$	—	$	—	$	—

__________

(a)Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.

Schedule of Government Settlement Agreements

As of December 31, 2022 and 2021, the amount of SNF storage costs for which reimbursement has been or will be requested from the DOE under the DOE settlement agreements is as follows:


	December 31, 2022		December 31, 2021
DOE receivable - current(a)	$	125	$	241
DOE receivable - noncurrent(b)	130		85
Amounts owed to co-owners(c)	(12)		(35)

__________

(a)Recorded in Other accounts receivable.

(b)Recorded in Deferred debits and other assets, other.

(c)Recorded in Other accounts receivable. Represents amounts owed to the co-owners of Peach Bottom, Quad Cities, and Nine Mile Point Unit 2 generating facilities

Spent Nuclear Fuel Obligation

The below table outlines the SNF liability recorded as of December 31, 2022 and 2021:


	December 31, 2022		December 31, 2021
Former ComEd units(a)	$	1,100	$	1,083
Fitzpatrick(b)	130		127
Total SNF Obligation	$	1,230	$	1,210

__________

Stock-Based Compensation Plans (Tables)

12 Months Ended

Dec. 31, 2022

Share-Based Payment Arrangement [Abstract]

Share-based Payment Arrangement, Cost by Plan


	Year Ended December 31,
	2022(a)		2021(b)		2020(b)
Total stock-based compensation expense included in operating and maintenance expense	$	116	$	47	$	27
Income tax benefit	(29)		(12)		(7)
Total after-tax stock-based compensation expense	$	87	$	35	$	20

__________

(a)Costs recognized for the year ended December 31, 2022 are related to the Constellation LTIP.

(b)Costs recognized for the years ended December 31, 2021 and 2020 were allocated to us by Exelon under the Exelon LTIP prior to separation.

Stock Based Compensation Tax Benefit

The following table presents information regarding our realized tax benefit when distributed:


	December 31, 2022

Restricted stock units	$	2

Share-Based Payment Arrangement, Performance Shares, Activity

The following table summarizes our nonvested performance share awards activity:


	Shares	Weighted Average Grant Date Fair Value (per share)
Nonvested at December 31, 2021	—	$	—
Granted	1,575,542	48.33
Change in performance	728,054	47.30

Forfeited	(22,617)	48.55
Undistributed vested awards(a)	(1,431,637)	48.35
Nonvested at December 31, 2022	849,342	$	47.40

__________

(a) Includes 1,272,921 of performance share awards that vested but were not distributed to retirement-eligible employees during 2022.

The following table summarizes the weighted average grant date fair value and the total fair value of performance share awards vested:


	December 31, 2022(a)
Weighted average grant date fair value (per share)	$	48.33
Total fair value of performance shares vested	69

__________

The following table summarizes our nonvested restricted stock unit activity:


	Shares	Weighted Average Grant Date Fair Value (per share)
Nonvested at December 31, 2021	—	$	—
Granted	1,497,651	54.17
Vested	(144,903)	49.82
Forfeited	(62,238)	59.47
Undistributed vested awards(a)	(499,842)	55.16
Nonvested at December 31, 2022	790,668	$	53.72

__________

(a)Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2022.

The following table summarizes the weighted average grant date fair value and the total fair value of restricted stock units vested:


	December 31, 2022(a)
Weighted average grant date fair value (per share)	$	54.17
Total fair value of performance shares vested	35

__________

Changes in Accumulated Other Comprehensive Income (Tables)

12 Months Ended

Dec. 31, 2022

Equity [Abstract]

Schedule Of Changes In Accumulated Other Comprehensive Income (Loss)

The following tables present changes in AOCI, net of tax, by component:


	Losses on Cash Flow Hedges		Pension and Non-Pension Postretirement Benefit Plan Items(a)		Foreign Currency Items		Total
Balance at December 31, 2019	$	(5)	$	—	$	(27)	$	(32)

OCI before reclassifications	(2)		—		4		2
Net current-period OCI	(2)		—		4		2
Balance at December 30, 2020	$	(7)	$	—	$	(23)	$	(30)
OCI before reclassifications	(1)		—		—		(1)
Net current-period OCI	(1)		—		—		(1)
Balance at December 30, 2021	$	(8)	$	—	$	(23)	$	(31)
Separation-related adjustments	—		(2,006)		—		(2,006)
OCI before reclassifications	(1)		186		(3)		182
Amounts reclassified from AOCI	—		95		—		95
Net current-period OCI	(1)		(1,725)		(3)		(1,729)
Balance at December 30, 2022	$	(9)	$	(1,725)	$	(26)	$	(1,760)

__________

The following table presents income tax (expense) benefit allocated to each component of our other comprehensive income (loss):


	Year Ended December 31,
	2022		2021		2020
Pension and non-pension postretirement benefit plans:

Actuarial loss reclassified to periodic benefit cost	$	(33)	$	—	$	—
Pension and non-pension postretirement benefit plans valuation adjustment(a)	619		—		—

__________

(a)Includes $680 million of income tax benefit related to the separation adjustment for the year ended December 31, 2022.

Variable Interest Entities (Tables)

12 Months Ended

Dec. 31, 2022

Variable Interest Entity [Abstract]

Consolidated VIEs - Assets and Liabilities


	December 31, 2022		December 31, 2021
Cash and cash equivalents	$	51	$	35
Restricted cash and cash equivalents	46		48
Accounts receivable
Customer	20		24
Other	9		6

Inventories, net

Materials and supplies	12		14
Other current assets	549		405
Total current assets	687		532

Property, plant and equipment, net	1,965		2,027


Other noncurrent assets	190		215
Total noncurrent assets	2,155		2,242
Total assets(a)	$	2,842	$	2,774

Long-term debt due within one year	$	60	$	70
Accounts payable	17		10
Accrued expenses	23		21


Other current liabilities	2		1
Total current liabilities	102		102

Long-term debt	764		822

Asset retirement obligations	173		151




Other noncurrent liabilities	3		3
Total noncurrent liabilities	940		976
Total liabilities(b)	$	1,042	$	1,078

_______

(b)Our balances include liabilities with recourse of $1 million and $1 million as of December 31, 2022 and 2021, respectively.

Schedule of Variable Interest Entities

As of December 31, 2022 and 2021, our consolidated VIEs included the following:


Consolidated VIE or VIE groups:	Reason entity is a VIE:	Reason we are the primary beneficiary:
CRP - A collection of wind and solar project entities. We have a 51% equity ownership in CRP. See additional discussion below.	Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner.	We conduct the operational activities.
Bluestem Wind Energy Holdings, LLC - A Tax Equity structure which is consolidated by CRP.	Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner.	We conduct the operational activities.
Antelope Valley - A solar generating facility, which is 100% owned by us. Antelope Valley sells all of its output to PG&E through a PPA.	The PPA contract absorbs variability through a performance guarantee.	We conduct all activities.
NER - A bankruptcy remote, special purpose entity which is 100% owned by us, which purchases certain of our customer accounts receivable arising from the sale of retail electricity. NER’s assets will be available first and foremost to satisfy the claims of the creditors of NER. Refer to Note 6 —Accounts Receivable for additional information on the sale of receivables.	Equity capitalization is insufficient to support its operations.	We conduct all activities.

As of December 31, 2022 and 2021, the unconsolidated VIEs consist of:


Unconsolidated VIE groups:	Reason entity is a VIE:	Reason we are not the primary beneficiary:
Equity investments in distributed energy companies. We have a 90% equity ownership in a distributed energy company. We sold this investment in the fourth quarter of 2022 resulting in it no longer being classified as an unconsolidated VIE .	Similar structures to a limited partnership and the limited partners do not have kick out rights with respect to the general partner.	We do not conduct the operational activities.
Energy Purchase and Sale agreements - We have several energy purchase and sale agreements with generating facilities.	PPA contracts that absorb variability through fixed pricing.	We do not conduct the operational activities.

Schedule of Variable Interest Entities

The following table presents summary information about our significant unconsolidated VIE entities:


	December 31, 2022						December 31, 2021
	Commercial Agreement VIEs		Equity Investment VIEs		Total		Commercial Agreement VIEs		Equity Investment VIEs		Total
Total assets(a)	$	715	$	—	$	715	$	772	$	372	$	1,144
Total liabilities(a)	54		—		54		80		216		296
Our ownership interest in VIE(a)	—		—		—		—		139		139
Other ownership interests in VIE(a)	661		—		661		692		17		709

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