Commonwealth Edison 10-K24 Feb 212020 FY Annual reportFinancial data

Company Profile

Cover Page

Cover Page - USD ($)	12 Months Ended
Cover Page - USD ($)	Dec. 31, 2020	Jan. 31, 2021	Jun. 30, 2020
Document Type	10-K
Amendment Flag	false
Document Annual Report	true
Document Period End Date	Dec. 31, 2020
Document Transition Report	false
Entity File Number	001-16169
Entity Registrant Name	EXELON CORPORATION
Entity Incorporation, State or Country Code	PA
Entity Tax Identification Number	23-2990190
Entity Address, Address Line One	10 South Dearborn Street
Entity Address, Address Line Two	P.O. Box 805379
Entity Address, City or Town	Chicago
Entity Address, State or Province	IL
Entity Address, Postal Zip Code	60680-5379
City Area Code	(800)
Local Phone Number	483-3220
Title of 12(b) Security	Common Stock, without par value
Trading Symbol	EXC
Security Exchange Name	NASDAQ
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Entity Shell Company	false
Entity Public Float			$ 35,402,501,369
Entity Common Stock Shares Outstanding		976,337,799
Documents Incorporated by Reference [Text Block]	Portions of the Exelon Proxy Statement for the 2020 Annual Meeting of Shareholders and the Commonwealth Edison Company 2020 Information Statement are incorporated by reference in Part III.
Entity Central Index Key	0001109357
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	FY
Exelon Generation Co L L C [Member]
Entity File Number	333-85496
Entity Registrant Name	EXELON GENERATION COMPANY, LLC
Entity Incorporation, State or Country Code	PA
Entity Tax Identification Number	23-3064219
Entity Address, Address Line One	300 Exelon Way
Entity Address, City or Town	Kennett Square
Entity Address, State or Province	PA
Entity Address, Postal Zip Code	19348-2473
City Area Code	(610)
Local Phone Number	765-5959
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Central Index Key	0001168165
Commonwealth Edison Co [Member]
Entity File Number	001-01839
Entity Registrant Name	COMMONWEALTH EDISON COMPANY
Entity Incorporation, State or Country Code	IL
Entity Tax Identification Number	36-0938600
Entity Address, Address Line One	440 South LaSalle Street
Entity Address, City or Town	Chicago
Entity Address, State or Province	IL
Entity Address, Postal Zip Code	60605-1028
City Area Code	(312)
Local Phone Number	394-4321
Title of 12(g) Security	Common Stock Purchase Warrants (1971 Warrants and Series B Warrants)
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Common Stock Shares Outstanding		127,021,370
Entity Central Index Key	0000022606
PECO Energy Co [Member]
Entity File Number	000-16844
Entity Registrant Name	PECO ENERGY COMPANY
Entity Incorporation, State or Country Code	PA
Entity Tax Identification Number	23-0970240
Entity Address, Address Line One	P.O. Box 8699
Entity Address, Address Line Two	2301 Market Street
Entity Address, City or Town	Philadelphia
Entity Address, State or Province	PA
Entity Address, Postal Zip Code	19101-8699
City Area Code	(215)
Local Phone Number	841-4000
Title of 12(b) Security	Cumulative Preferred Security, Series D,
Trading Symbol	EXC/28
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Common Stock Shares Outstanding		170,478,507
Entity Central Index Key	0000078100
Baltimore Gas and Electric Company [Member]
Entity File Number	001-01910
Entity Registrant Name	BALTIMORE GAS AND ELECTRIC COMPANY
Entity Incorporation, State or Country Code	MD
Entity Tax Identification Number	52-0280210
Entity Address, Address Line One	2 Center Plaza
Entity Address, Address Line Two	110 West Fayette Street
Entity Address, City or Town	Baltimore
Entity Address, State or Province	MD
Entity Address, Postal Zip Code	21201-3708
City Area Code	(410)
Local Phone Number	234-5000
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Common Stock Shares Outstanding		1,000
Entity Central Index Key	0000009466
Pepco Holdings LLC [Member]
Entity File Number	001-31403
Entity Registrant Name	PEPCO HOLDINGS LLC
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	52-2297449
Entity Address, Address Line One	701 Ninth Street, N.W.
Entity Address, City or Town	Washington, District of Columbia
Entity Address, Postal Zip Code	20068
City Area Code	(202)
Local Phone Number	872-2000
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Central Index Key	0001135971
Potomac Electric Power Company [Member]
Entity File Number	001-01072
Entity Registrant Name	POTOMAC ELECTRIC POWER COMPANY
Entity Tax Identification Number	53-0127880
Entity Address, Address Line One	701 Ninth Street, N.W.
Entity Address, City or Town	Washington, District of Columbia
Entity Address, Postal Zip Code	20068
City Area Code	(202)
Local Phone Number	872-2000
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Common Stock Shares Outstanding		100
Entity Central Index Key	0000079732
Delmarva Power & Light Company [Member]
Entity File Number	001-01405
Entity Registrant Name	DELMARVA POWER & LIGHT COMPANY
Entity Tax Identification Number	51-0084283
Entity Address, Address Line One	500 North Wakefield Drive
Entity Address, City or Town	Newark
Entity Address, State or Province	DE
Entity Address, Postal Zip Code	19702
City Area Code	(202)
Local Phone Number	872-2000
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Common Stock Shares Outstanding		1,000
Entity Central Index Key	0000027879
Atlantic City Electric Company [Member]
Entity File Number	001-03559
Entity Registrant Name	ATLANTIC CITY ELECTRIC COMPANY
Entity Incorporation, State or Country Code	NJ
Entity Tax Identification Number	21-0398280
Entity Address, Address Line One	500 North Wakefield Drive
Entity Address, City or Town	Newark
Entity Address, State or Province	DE
Entity Address, Postal Zip Code	19702
City Area Code	(202)
Local Phone Number	872-2000
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Common Stock Shares Outstanding		8,546,017
Entity Central Index Key	0000008192
VIRGINIA \| Potomac Electric Power Company [Member]
Entity Incorporation, State or Country Code	VA
VIRGINIA \| Delmarva Power & Light Company [Member]
Entity Incorporation, State or Country Code	VA
DELAWARE \| Delmarva Power & Light Company [Member]
Entity Incorporation, State or Country Code	DE
DISTRICT OF COLUMBIA \| Potomac Electric Power Company [Member]
Entity Incorporation, State or Country Code	DC

Consolidated Statements of Oper

Consolidated Statements of Operations and Comprehensive Income - USD ($) shares in Millions, $ in Millions		12 Months Ended
		Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Operating revenues
Revenue from alternative revenue programs		$ 6	$ (155)	$ (69)
Total operating revenues		33,039	34,438	35,978
Operating expenses
Operating and maintenance		9,408	8,615	9,337
Depreciation and Amortization		5,014	4,252	4,353
Taxes other than income		1,714	1,732	1,783
Total operating expenses		30,240	30,096	32,143
Gain on sales of assets and businesses		24	31	56
Gain on deconsolidation of business		0	1	0
Operating income (loss)		2,823	4,374	3,891
Other income and (deductions)
Interest expense, net		(1,610)	(1,591)	(1,529)
Interest expense to affiliates		(25)	(25)	(25)
Other, net		1,145	1,227	(112)
Total other income and (deductions)		(490)	(389)	(1,666)
Income (loss) before income taxes		2,333	3,985	2,225
Income taxes		373	774	118
Equity in losses of unconsolidated affiliates		(6)	(183)	(28)
Net income (loss)		1,954	3,028	2,079
Net income (loss) attributable to common shareholders		1,963	2,936	2,005
Net income (loss) attributable to noncontrolling interests		(9)	92	74
Other comprehensive income (loss), net of income taxes
Prior service benefit reclassified to periodic benefit cost		(40)	(65)	(66)
Actuarial loss reclassified to periodic cost		190	149	247
Pension and non-pension postretirement benefit plan valuation adjustment		(357)	(289)	(143)
Unrealized gain on cash flow hedges		(3)	0	12
Unrealized gain (loss) on investments in unconsolidated affiliates		0	1	2
Unrealized (loss) gain on foreign currency translation		4	6	(10)
Other comprehensive income (loss)		(206)	(198)	42
Comprehensive income (loss)		1,748	2,830	2,121
Comprehensive income attributable to noncontrolling interests		(9)	93	75
Comprehensive income (loss) attributable to common shareholders		$ 1,757	$ 2,737	$ 2,046
Average shares of common stock outstanding:
Weighted Average Number of Shares Outstanding, Basic		976	973	967
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements		1	1	2
Weighted Average Number of Shares Outstanding, Diluted	[1]	977	974	969
Earnings per average common share:
Earnings Per Share, Basic		$ 2.01	$ 3.02	$ 2.07
Earnings Per Share, Diluted		$ 2.01	$ 3.01	$ 2.07
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount		0	0	3
Exelon Generation Co L L C [Member]
Operating revenues
Operating revenues from affiliates		$ 1,211	$ 1,172	$ 1,268
Total operating revenues		17,603	18,924	20,437
Operating expenses
Purchased power and/or fuel from affiliates		(7)	7	14
Operating and maintenance		4,613	4,131	4,803
Operating and maintenance from affiliates		555	587	661
Depreciation and Amortization		2,123	1,535	1,797
Taxes other than income		482	519	556
Total operating expenses		17,358	17,628	19,510
Gain on sales of assets and businesses		11	27	48
Operating income (loss)		256	1,323	975
Other income and (deductions)
Interest expense, net		(328)	(394)	(396)
Interest expense to affiliates		(29)	(35)	(36)
Other, net		937	1,023	(178)
Total other income and (deductions)		580	594	(610)
Income (loss) before income taxes		836	1,917	365
Income taxes		249	516	(108)
Equity in losses of unconsolidated affiliates		(8)	(184)	(30)
Net income (loss)		579	1,217	443
Net income (loss) attributable to noncontrolling interests		(10)	92	73
Net income (loss) attributable to membership interest		589	1,125	370
Other comprehensive income (loss), net of income taxes
Unrealized gain on cash flow hedges		(2)	0	12
Unrealized gain (loss) on investments in unconsolidated affiliates		0	1	1
Unrealized (loss) gain on foreign currency translation		4	6	(10)
Other comprehensive income (loss)		2	7	3
Comprehensive income (loss)		581	1,224	446
Comprehensive income attributable to noncontrolling interests		(10)	93	74
Comprehensive income (loss) attributable to common shareholders		591	1,131	372
Commonwealth Edison Co [Member]
Operating revenues
Revenue from alternative revenue programs		(47)	(133)	(29)
Operating revenues from affiliates		37	30	27
Total operating revenues		5,904	5,747	5,882
Operating expenses
Purchased power and/or fuel from affiliates		345	376	529
Operating and maintenance		1,231	1,041	1,068
Operating and maintenance from affiliates		289	264	267
Depreciation and Amortization		1,133	1,033	940
Taxes other than income		299	301	311
Total operating expenses		4,950	4,580	4,741
Gain on sales of assets and businesses		0	4	5
Operating income (loss)		954	1,171	1,146
Other income and (deductions)
Interest expense, net		(369)	(346)	(334)
Interest expense to affiliates		(13)	(13)	(13)
Other, net		43	39	33
Total other income and (deductions)		(339)	(320)	(314)
Income (loss) before income taxes		615	851	832
Income taxes		177	163	168
Net income (loss)		438	688	664
Other comprehensive income (loss), net of income taxes
Comprehensive income (loss)		438	688	664
PECO Energy Co [Member]
Operating revenues
Revenue from alternative revenue programs		16	(21)	(7)
Operating revenues from affiliates		9	6	8
Total operating revenues		3,058	3,100	3,038
Operating expenses
Purchased power and/or fuel from affiliates		188	157	126
Operating and maintenance		816	707	742
Operating and maintenance from affiliates		159	154	156
Depreciation and Amortization		347	333	301
Taxes other than income		172	165	163
Total operating expenses		2,512	2,388	2,452
Gain on sales of assets and businesses		0	1	1
Operating income (loss)		546	713	587
Other income and (deductions)
Interest expense, net		(136)	(124)	(115)
Interest expense to affiliates		(11)	(12)	(14)
Other, net		18	16	8
Total other income and (deductions)		(129)	(120)	(121)
Income (loss) before income taxes		417	593	466
Income taxes		(30)	65	6
Net income (loss)		447	528	460
Other comprehensive income (loss), net of income taxes
Comprehensive income (loss)		447	528	460
Baltimore Gas and Electric Company [Member]
Operating revenues
Revenue from alternative revenue programs		16	12	(26)
Operating revenues from affiliates		20	26	29
Total operating revenues		3,098	3,106	3,169
Operating expenses
Purchased power and/or fuel from affiliates		311	286	257
Operating and maintenance		617	600	615
Operating and maintenance from affiliates		172	160	162
Depreciation and Amortization		550	502	483
Taxes other than income		268	260	254
Total operating expenses		2,598	2,574	2,696
Gain on sales of assets and businesses		0	0	1
Operating income (loss)		500	532	474
Other income and (deductions)
Interest expense, net		(133)	(121)	(106)
Other, net		23	28	19
Total other income and (deductions)		(110)	(93)	(87)
Income (loss) before income taxes		390	439	387
Income taxes		41	79	74
Net income (loss)		349	360	313
Other comprehensive income (loss), net of income taxes
Comprehensive income (loss)		349	360	313
Pepco Holdings LLC [Member]
Operating revenues
Revenue from alternative revenue programs		21	(14)	(7)
Operating revenues from affiliates		17	14	15
Total operating revenues		4,663	4,806	4,798
Operating expenses
Purchased power and/or fuel from affiliates		366	352	355
Operating and maintenance		940	939	978
Operating and maintenance from affiliates		159	143	152
Depreciation and Amortization		782	754	740
Taxes other than income		450	450	455
Total operating expenses		4,045	4,084	4,156
Gain on sales of assets and businesses		11	0	1
Operating income (loss)		629	722	643
Other income and (deductions)
Interest expense, net		(268)	(263)	(261)
Other, net		57	55	43
Total other income and (deductions)		(211)	(208)	(218)
Income (loss) before income taxes		418	514	425
Income taxes		(77)	38	33
Equity in losses of unconsolidated affiliates		0	1	1
Net income (loss)		495	477	393
Other comprehensive income (loss), net of income taxes
Comprehensive income (loss) attributable to common shareholders		495	477	393
Potomac Electric Power Company [Member]
Operating revenues
Revenue from alternative revenue programs		40	(3)	(7)
Operating revenues from affiliates		7	5	6
Total operating revenues		2,149	2,260	2,232
Operating expenses
Purchased power and/or fuel from affiliates		278	264	206
Operating and maintenance		248	273	275
Operating and maintenance from affiliates		205	209	226
Depreciation and Amortization		377	374	385
Taxes other than income		367	378	379
Total operating expenses		1,799	1,899	1,919
Gain on sales of assets and businesses		9	0	0
Operating income (loss)		359	361	313
Other income and (deductions)
Interest expense, net		(138)	(133)	(128)
Other, net		38	31	31
Total other income and (deductions)		(100)	(102)	(97)
Income (loss) before income taxes		259	259	216
Income taxes		(7)	16	11
Net income (loss)		266	243	205
Other comprehensive income (loss), net of income taxes
Comprehensive income (loss)		266	243	205
Delmarva Power & Light Company [Member]
Operating revenues
Revenue from alternative revenue programs		(7)	(11)	4
Operating revenues from affiliates		9	7	8
Total operating revenues		1,271	1,306	1,332
Operating expenses
Purchased power and/or fuel from affiliates		75	70	120
Operating and maintenance		208	171	182
Operating and maintenance from affiliates		153	152	162
Depreciation and Amortization		191	184	182
Taxes other than income		65	56	56
Total operating expenses		1,120	1,089	1,143
Gain on sales of assets and businesses		0	0	1
Operating income (loss)		151	217	190
Other income and (deductions)
Interest expense, net		(61)	(61)	(58)
Other, net		10	13	10
Total other income and (deductions)		(51)	(48)	(48)
Income (loss) before income taxes		100	169	142
Income taxes		(25)	22	22
Net income (loss)		125	147	120
Other comprehensive income (loss), net of income taxes
Comprehensive income (loss)		125	147	120
Atlantic City Electric Company [Member]
Operating revenues
Revenue from alternative revenue programs		(12)	0	(4)
Operating revenues from affiliates		4	3	3
Total operating revenues		1,245	1,240	1,236
Operating expenses
Purchased power and/or fuel from affiliates		13	19	29
Operating and maintenance		192	187	188
Operating and maintenance from affiliates		134	133	142
Depreciation and Amortization		180	157	136
Taxes other than income		8	4	5
Total operating expenses		1,123	1,089	1,087
Sale and Leaseback Transaction, Gain (Loss), Net		2	0	0
Operating income (loss)		124	151	149
Other income and (deductions)
Interest expense, net		(59)	(58)	(64)
Other, net		6	6	2
Total other income and (deductions)		(53)	(52)	(62)
Income (loss) before income taxes		71	99	87
Income taxes		(41)	0	12
Net income (loss)		112	99	75
Other comprehensive income (loss), net of income taxes
Comprehensive income (loss)		112	99	75
Generation commodities and services [Member]
Operating revenues
Revenue from Contract with Customer, Including Assessed Tax		16,400	17,754	19,168
Operating expenses
Purchased power and/or fuel		9,592	10,849	11,679
Generation commodities and services [Member] \| Exelon Generation Co L L C [Member]
Operating revenues
Revenue from Contract with Customer, Including Assessed Tax		16,392	17,752	19,169
Operating expenses
Purchased power and/or fuel		9,592	10,849	11,679
Rate-regulated utility revenues [Member]
Operating revenues
Revenue from Contract with Customer, Including Assessed Tax		16,633	16,839	16,879
Operating expenses
Purchased power and/or fuel		4,512	4,648	4,991
Electricity, US Regulated [Member] \| Commonwealth Edison Co [Member]
Operating revenues
Revenue from Contract with Customer, Including Assessed Tax		5,914	5,850	5,884
Operating expenses
Purchased power and/or fuel		1,653	1,565	1,626
Electricity, US Regulated [Member] \| PECO Energy Co [Member]
Operating revenues
Revenue from Contract with Customer, Including Assessed Tax		2,519	2,505	2,469
Operating expenses
Purchased power and/or fuel		645	610	734
Electricity, US Regulated [Member] \| Baltimore Gas and Electric Company [Member]
Operating revenues
Revenue from Contract with Customer, Including Assessed Tax		2,323	2,368	2,428
Operating expenses
Purchased power and/or fuel		509	585	671
Electricity, US Regulated [Member] \| Pepco Holdings LLC [Member]
Operating revenues
Revenue from Contract with Customer, Including Assessed Tax		4,463	4,639	4,609
Operating expenses
Purchased power and/or fuel		1,279	1,371	1,387
Electricity, US Regulated [Member] \| Potomac Electric Power Company [Member]
Operating revenues
Revenue from Contract with Customer, Including Assessed Tax		2,102	2,258	2,233
Operating expenses
Purchased power and/or fuel		324	401	448
Electricity, US Regulated [Member] \| Delmarva Power & Light Company [Member]
Operating revenues
Revenue from Contract with Customer, Including Assessed Tax		1,107	1,143	1,139
Operating expenses
Purchased power and/or fuel		359	381	352
Electricity, US Regulated [Member] \| Atlantic City Electric Company [Member]
Operating revenues
Revenue from Contract with Customer, Including Assessed Tax		1,253	1,237	1,237
Operating expenses
Purchased power and/or fuel		596	589	587
Natural Gas, US Regulated [Member] \| PECO Energy Co [Member]
Operating revenues
Revenue from Contract with Customer, Including Assessed Tax		514	610	568
Operating expenses
Purchased power and/or fuel		185	262	230
Natural Gas, US Regulated [Member] \| Baltimore Gas and Electric Company [Member]
Operating revenues
Revenue from Contract with Customer, Including Assessed Tax		739	700	738
Operating expenses
Purchased power and/or fuel		171	181	254
Natural Gas, US Regulated [Member] \| Pepco Holdings LLC [Member]
Operating revenues
Revenue from Contract with Customer, Including Assessed Tax		162	167	181
Operating expenses
Purchased power and/or fuel		69	75	89
Natural Gas, US Regulated [Member] \| Delmarva Power & Light Company [Member]
Operating revenues
Revenue from Contract with Customer, Including Assessed Tax		162	167	181
Operating expenses
Purchased power and/or fuel		$ 69	$ 75	$ 89

[1]	The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was less than 1 million for the years ended December 31, 2020 and December 31, 2019 and approximately 3 million for the year ended December 31, 2018.

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Cash flows from operating activities
Net income (loss)	$ 1,954	$ 3,028	$ 2,079
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization	6,527	5,780	5,971
Asset impairments	591	201	50
Gain on sales of assets and businesses	(24)	(27)	(56)
Deferred income taxes and amortization of investment tax credits	309	681	(108)
Net fair value changes related to derivatives	(268)	222	294
Net realized and unrealized (gains) losses on NDT fund investments	(461)	(663)	303
Unrealized Gain (Loss) on Investments	(186)	0	0
Other non-cash operating activities	592	613	1,131
Changes in assets and liabilities:
Accounts receivable	697	(243)	(565)
Inventories	(85)	(87)	(37)
Accounts payable and accrued expenses	(129)	(425)	551
Option premiums (paid) received, net	(139)	(29)	(43)
Collateral received (posted), net	494	(438)	82
Income taxes	140	(64)	340
Pension and non-pension postretirement benefit contributions	(601)	(408)	(383)
Other assets and liabilities	(5,176)	(1,482)	(965)
Net cash flows provided by operating activities	4,235	6,659	8,644
Cash flows from investing activities
Capital expenditures	(8,048)	(7,248)	(7,594)
Proceeds from NDT fund sales	3,341	10,051	8,762
Investment in NDT funds	(3,464)	(10,087)	(8,997)
Collection of deferred purchase price	3,771	0	0
Acquisitions of assets and businesses, net	0	(41)	(154)
Proceeds from sales of assets and businesses	46	53	91
Other investing activities	18	12	58
Net cash flows used in investing activities	(4,336)	(7,260)	(7,834)
Cash flows from financing activities
Changes in short-term borrowings	161	781	(338)
Proceeds from short-term borrowings with maturities greater than 90 days	500	0	126
Repayments on short-term borrowings with maturities greater than 90 days	0	(125)	(1)
Issuance of long-term debt	7,507	1,951	3,115
Retirement of long-term debt	(6,440)	(1,287)	(1,786)
Dividends paid on common stock	(1,492)	(1,408)	(1,332)
Proceeds from employee stock plans	45	112	105
Other financing activities	(136)	(82)	(108)
Net cash flows provided by (used in) financing activities	145	(58)	(219)
Increase (Decrease) in cash, restricted cash, and cash equivalents	44	(659)	591
Cash, restricted cash, and cash equivalents at beginning of period	1,122	1,781	1,190
Cash, restricted cash, and cash equivalents at end of period	1,166	1,122	1,781
Capital Expenditures Incurred but Not yet Paid	194	(7)	(69)
Increase in Deferred Purchase Price	4,441	0	0
Increase (decrease) in PPE related to ARO update	850	968	(107)
Exelon Generation Co L L C [Member]
Cash flows from operating activities
Net income (loss)	579	1,217	443
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization	3,636	3,063	3,415
Asset impairments	563	201	50
Gain on sales of assets and businesses	(11)	(27)	(48)
Deferred income taxes and amortization of investment tax credits	78	361	(451)
Net fair value changes related to derivatives	(270)	228	307
Net realized and unrealized (gains) losses on NDT fund investments	(461)	(663)	303
Unrealized Gain (Loss) on Investments	(186)	0	0
Other non-cash operating activities	18	(124)	298
Changes in assets and liabilities:
Accounts receivable	1,125	(186)	(359)
Receivables from and payables to affiliates, net	24	(52)	8
Inventories	(77)	(47)	(12)
Accounts payable and accrued expenses	(343)	(248)	376
Option premiums (paid) received, net	(139)	(29)	(43)
Collateral received (posted), net	479	(481)	64
Income taxes	186	302	(193)
Pension and non-pension postretirement benefit contributions	(255)	(175)	(139)
Other assets and liabilities	(4,362)	(467)	(158)
Net cash flows provided by operating activities	584	2,873	3,861
Cash flows from investing activities
Capital expenditures	(1,747)	(1,845)	(2,242)
Proceeds from NDT fund sales	3,341	10,051	8,762
Investment in NDT funds	(3,464)	(10,087)	(8,997)
Collection of deferred purchase price	3,771	0	0
Acquisitions of assets and businesses, net	0	(41)	(154)
Proceeds from sales of assets and businesses	46	52	90
Other investing activities	11	3	10
Net cash flows used in investing activities	1,958	(1,867)	(2,531)
Cash flows from financing activities
Changes in short-term borrowings	20	320	0
Proceeds from short-term borrowings with maturities greater than 90 days	500	0	0
Issuance of long-term debt	3,155	42	15
Retirement of long-term debt	(4,334)	(813)	(141)
Repayment of long term debt to affiliate	(550)	0	0
Distributions to member	(1,734)	(899)	(1,001)
Contributions from member	64	41	155
Changes in Exelon/PHI intercompany money pool	285	(100)	46
Other financing activities	(70)	(51)	(55)
Net cash flows provided by (used in) financing activities	(2,664)	(1,460)	(981)
Increase (Decrease) in cash, restricted cash, and cash equivalents	(122)	(454)	349
Cash, restricted cash, and cash equivalents at beginning of period	449	903	554
Cash, restricted cash, and cash equivalents at end of period	327	449	903
Increase (decrease) in capital expenditures not paid	(88)	(34)	(199)
Increase in Deferred Purchase Price	4,441	0	0
Increase (decrease) in PPE related to ARO update	850	959	(130)
Commonwealth Edison Co [Member]
Cash flows from operating activities
Net income (loss)	438	688	664
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization	1,133	1,033	940
Deferred income taxes and amortization of investment tax credits	228	109	259
Unrealized Gain (Loss) on Investments	0
Other non-cash operating activities	202	265	242
Changes in assets and liabilities:
Accounts receivable	(10)	(34)	(136)
Receivables from and payables to affiliates, net	(1)	(12)	26
Inventories	(13)	(16)	1
Accounts payable and accrued expenses	63	(51)	70
Collateral received (posted), net	14	48	11
Income taxes	8	95	62
Pension and non-pension postretirement benefit contributions	(148)	(77)	(42)
Other assets and liabilities	(590)	(345)	(348)
Net cash flows provided by operating activities	1,324	1,703	1,749
Cash flows from investing activities
Capital expenditures	(2,217)	(1,915)	(2,126)
Other investing activities	2	29	29
Net cash flows used in investing activities	(2,215)	(1,886)	(2,097)
Cash flows from financing activities
Changes in short-term borrowings	193	130	0
Issuance of long-term debt	1,000	700	1,350
Retirement of long-term debt	(500)	(300)	(840)
Dividends paid on common stock	(499)	(508)	(459)
Contributions from parent	712	250	500
Other financing activities	(13)	(16)	(17)
Net cash flows provided by (used in) financing activities	893	256	534
Increase (Decrease) in cash, restricted cash, and cash equivalents	2	73	186
Cash, restricted cash, and cash equivalents at beginning of period	403	330	144
Cash, restricted cash, and cash equivalents at end of period	405	403	330
Increase (decrease) in capital expenditures not paid	109	(37)	11
PECO Energy Co [Member]
Cash flows from operating activities
Net income (loss)	447	528	460
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization	347	333	301
Gain on sales of assets and businesses	0	(1)	0
Deferred income taxes and amortization of investment tax credits	(23)	20	(5)
Unrealized Gain (Loss) on Investments	0
Other non-cash operating activities	24	38	51
Changes in assets and liabilities:
Accounts receivable	(88)	(29)	(74)
Receivables from and payables to affiliates, net	(6)	(5)	7
Inventories	(1)	4	(14)
Accounts payable and accrued expenses	63	(11)	(3)
Income taxes	31	(34)	15
Pension and non-pension postretirement benefit contributions	(18)	(28)	(28)
Other assets and liabilities	1	(64)	29
Net cash flows provided by operating activities	777	751	739
Cash flows from investing activities
Capital expenditures	(1,147)	(939)	(849)
Changes in Exelon/PHI intercompany money pool	68	(68)	0
Other investing activities	7	(1)	9
Net cash flows used in investing activities	(1,072)	(1,008)	(840)
Cash flows from financing activities
Issuance of long-term debt	350	325	700
Retirement of long-term debt	0	0	(500)
Dividends paid on common stock	(340)	(358)	(306)
Contributions from parent	248	188	89
Changes in Exelon/PHI intercompany money pool	40	0	0
Other financing activities	(4)	(6)	(22)
Net cash flows provided by (used in) financing activities	294	149	(39)
Increase (Decrease) in cash, restricted cash, and cash equivalents	(1)	(108)	(140)
Cash, restricted cash, and cash equivalents at beginning of period	27	135	275
Cash, restricted cash, and cash equivalents at end of period	26	27	135
Increase (decrease) in capital expenditures not paid	55	40	(12)
Baltimore Gas and Electric Company [Member]
Cash flows from operating activities
Net income (loss)	349	360	313
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization	550	502	483
Deferred income taxes and amortization of investment tax credits	37	130	76
Unrealized Gain (Loss) on Investments	0
Other non-cash operating activities	97	85	58
Changes in assets and liabilities:
Accounts receivable	(165)	25	8
Receivables from and payables to affiliates, net	(8)	1	12
Inventories	10	(1)	2
Accounts payable and accrued expenses	102	(43)	(1)
Collateral received (posted), net	0	(4)	4
Income taxes	60	(67)	(20)
Pension and non-pension postretirement benefit contributions	(78)	(48)	(54)
Other assets and liabilities	(70)	(192)	(92)
Net cash flows provided by operating activities	884	748	789
Cash flows from investing activities
Capital expenditures	(1,247)	(1,145)	(959)
Other investing activities	2	8	9
Net cash flows used in investing activities	(1,245)	(1,137)	(950)
Cash flows from financing activities
Changes in short-term borrowings	(76)	40	(42)
Issuance of long-term debt	400	400	300
Dividends paid on common stock	(246)	(224)	(209)
Contributions from parent	411	193	109
Other financing activities	(8)	(8)	(2)
Net cash flows provided by (used in) financing activities	481	401	156
Increase (Decrease) in cash, restricted cash, and cash equivalents	120	12	(5)
Cash, restricted cash, and cash equivalents at beginning of period	25	13	18
Cash, restricted cash, and cash equivalents at end of period	145	25	13
Increase (decrease) in capital expenditures not paid	53	6	50
Pepco Holdings LLC [Member]
Cash flows from operating activities
Net income (loss)	495	477	393
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization	782	754	740
Deferred income taxes and amortization of investment tax credits	(97)	(7)	30
Unrealized Gain (Loss) on Investments	0
Other non-cash operating activities	103	161	150
Changes in assets and liabilities:
Accounts receivable	(159)	(39)	(2)
Receivables from and payables to affiliates, net	3	3	8
Inventories	(6)	(27)	(14)
Accounts payable and accrued expenses	49	(17)	45
Income taxes	(25)	16	34
Pension and non-pension postretirement benefit contributions	(39)	(25)	(74)
Other assets and liabilities	(104)	(179)	(178)
Net cash flows provided by operating activities	1,002	1,117	1,132
Cash flows from investing activities
Capital expenditures	(1,604)	(1,355)	(1,375)
Other investing activities	7	(3)	4
Net cash flows used in investing activities	(1,597)	(1,358)	(1,371)
Cash flows from financing activities
Changes in short-term borrowings	160	154	(296)
Proceeds from short-term borrowings with maturities greater than 90 days	0	0	125
Repayments on short-term borrowings with maturities greater than 90 days	0	(125)	0
Issuance of long-term debt	602	485	750
Retirement of long-term debt	(128)	(157)	(299)
Distributions to member	(553)	(526)	(326)
Contributions from member	494	398	385
Changes in Exelon/PHI intercompany money pool	9	12	0
Other financing activities	(10)	(5)	(9)
Net cash flows provided by (used in) financing activities	574	236	330
Increase (Decrease) in cash, restricted cash, and cash equivalents	(21)	(5)	91
Cash, restricted cash, and cash equivalents at beginning of period	181	186	95
Cash, restricted cash, and cash equivalents at end of period	160	181	186
Increase (decrease) in capital expenditures not paid	54	2	93
Potomac Electric Power Company [Member]
Cash flows from operating activities
Net income (loss)	266	243	205
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization	377	374	385
Deferred income taxes and amortization of investment tax credits	(46)	1	(20)
Unrealized Gain (Loss) on Investments	0
Other non-cash operating activities	(23)	56	67
Changes in assets and liabilities:
Accounts receivable	(67)	(22)	(5)
Receivables from and payables to affiliates, net	(12)	5	(17)
Inventories	1	(19)	(6)
Accounts payable and accrued expenses	41	(39)	59
Income taxes	(1)	9	(13)
Pension and non-pension postretirement benefit contributions	(11)	(14)	(17)
Other assets and liabilities	(24)	(82)	(164)
Net cash flows provided by operating activities	501	512	474
Cash flows from investing activities
Capital expenditures	(773)	(626)	(656)
Other investing activities	0	3	2
Net cash flows used in investing activities	(773)	(623)	(654)
Cash flows from financing activities
Changes in short-term borrowings	(47)	42	14
Issuance of long-term debt	300	260	200
Retirement of long-term debt	(3)	(125)	(14)
Dividends paid on common stock	(232)	(213)	(169)
Contributions from parent	262	160	166
Other financing activities	(6)	(3)	(4)
Net cash flows provided by (used in) financing activities	274	121	193
Increase (Decrease) in cash, restricted cash, and cash equivalents	2	10	13
Cash, restricted cash, and cash equivalents at beginning of period	63	53	40
Cash, restricted cash, and cash equivalents at end of period	65	63	53
Increase (decrease) in capital expenditures not paid	1	39	20
Delmarva Power & Light Company [Member]
Cash flows from operating activities
Net income (loss)	125	147	120
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization	191	184	182
Deferred income taxes and amortization of investment tax credits	(13)	(7)	24
Unrealized Gain (Loss) on Investments	0
Other non-cash operating activities	51	27	24
Changes in assets and liabilities:
Accounts receivable	(34)	(5)	8
Receivables from and payables to affiliates, net	8	(5)	(9)
Inventories	(5)	(6)	(3)
Accounts payable and accrued expenses	4	3	11
Income taxes	(25)	12	2
Pension and non-pension postretirement benefit contributions	0	(1)	0
Other assets and liabilities	(30)	(55)	(7)
Net cash flows provided by operating activities	272	294	352
Cash flows from investing activities
Capital expenditures	(424)	(348)	(364)
Other investing activities	(3)	1	2
Net cash flows used in investing activities	(427)	(347)	(362)
Cash flows from financing activities
Changes in short-term borrowings	90	56	(216)
Issuance of long-term debt	178	75	200
Retirement of long-term debt	(80)	(12)	(4)
Dividends paid on common stock	(141)	(139)	(96)
Contributions from parent	112	63	150
Other financing activities	(2)	(1)	(2)
Net cash flows provided by (used in) financing activities	157	42	32
Increase (Decrease) in cash, restricted cash, and cash equivalents	2	(11)	22
Cash, restricted cash, and cash equivalents at beginning of period	13	24	2
Cash, restricted cash, and cash equivalents at end of period	15	13	24
Increase (decrease) in capital expenditures not paid	20	(4)	22
Atlantic City Electric Company [Member]
Cash flows from operating activities
Net income (loss)	112	99	75
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization	180	157	136
Deferred income taxes and amortization of investment tax credits	(37)	3	25
Unrealized Gain (Loss) on Investments	0
Other non-cash operating activities	36	22	24
Changes in assets and liabilities:
Accounts receivable	(55)	(13)	(8)
Receivables from and payables to affiliates, net	6	(6)	1
Inventories	(3)	(1)	(4)
Accounts payable and accrued expenses	5	26	(7)
Income taxes	(1)	2	(2)
Pension and non-pension postretirement benefit contributions	(2)	(1)	(6)
Other assets and liabilities	(42)	(27)	(6)
Net cash flows provided by operating activities	199	261	228
Cash flows from investing activities
Capital expenditures	(401)	(375)	(335)
Other investing activities	6	(1)	1
Net cash flows used in investing activities	(395)	(376)	(334)
Cash flows from financing activities
Changes in short-term borrowings	117	56	(94)
Proceeds from short-term borrowings with maturities greater than 90 days	0	0	125
Repayments on short-term borrowings with maturities greater than 90 days	0	(125)	0
Issuance of long-term debt	123	150	350
Retirement of long-term debt	(44)	(18)	(281)
Dividends paid on common stock	(114)	(124)	(59)
Contributions from parent	117	175	67
Other financing activities	(1)	(1)	(3)
Net cash flows provided by (used in) financing activities	198	113	105
Increase (Decrease) in cash, restricted cash, and cash equivalents	2	(2)	(1)
Cash, restricted cash, and cash equivalents at beginning of period	28	30	31
Cash, restricted cash, and cash equivalents at end of period	30	28	30
Increase (decrease) in capital expenditures not paid	$ 33	$ (29)	$ 46

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions		Dec. 31, 2020	Dec. 31, 2019
Current assets
Cash and cash equivalents		$ 663	$ 587
Restricted cash and cash equivalents		438	358
Accounts receivable
Customer accounts receivable		3,597	4,835
Customer allowance for credit losses		(366)	(243)
Customer accounts receivable, net		3,231	4,592
Other accounts receivable		1,469	1,631
Other allowance for credit losses		(71)	(48)
Other accounts receivable, net		1,398	1,583
Mark-to-market derivative assets, current		644	679
Unamortized energy contract assets, current		38	47
Inventories, net
Fossil fuel and emission allowances		297	312
Materials and supplies		1,425	1,456
Regulatory assets, current		1,228	1,170
Renewable energy credits, current		633	348
Assets held for sale		958	0
Other		1,609	905
Total current assets		12,562	12,037
Property, plant and equipment, net		82,584	80,233
Accumulated depreciation and amortization		26,727	23,979
Deferred debits and other assets
Regulatory assets, noncurrent		8,759	8,335
Nuclear decommissioning trust funds		14,464	13,190
Investments		440	464
Goodwill		6,677	6,677
Mark-to-market derivative assets, noncurrent		555	508
Unamortized energy contract assets, noncurrent		294	336
Other		2,982	3,197
Total deferred debits and other assets		34,171	32,707
Total assets	[1]	129,317	124,977
Current liabilities
Short-term borrowings		2,031	1,370
Long-term debt due within one year		1,819	4,710
Accounts payable		3,562	3,560
Accrued expenses		2,078	1,981
Payables to affiliates, current		5	5
Regulatory liabilities, current		581	406
Mark-to-market derivative liabilities, current		295	247
Unamortized energy contract liabilities, current		100	132
Renewable energy credit obligation		661	443
Liabilities held for sale		375	0
Other		1,264	1,331
Total current liabilities		12,771	14,185
Long-term debt		35,093	31,329
Long-term debt to financing trusts		390	390
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		13,035	12,351
Asset retirement obligations, noncurrent		12,300	10,846
Pension obligations		4,503	4,247
Non-pension postretirement benefits obligations		2,011	2,076
Spent nuclear fuel obligation		1,208	1,199
Regulatory liabilities, noncurrent		9,485	9,986
Mark-to-market derivative liabilities, noncurrent		473	393
Unamortized energy contract liabilities, noncurrent		238	338
Other		2,942	3,064
Total deferred credits and other liabilities		46,195	44,500
Total liabilities	[1]	94,449	90,404
Commitments and contingencies
Shareholders’ equity
Common stock		19,373	19,274
Treasury stock, at cost		(123)	(123)
Retained earnings/Undistributed earnings (losses)		16,735	16,267
Accumulated other comprehensive loss, net		(3,400)	(3,194)
Total shareholders’ equity		32,585	32,224
Member’s equity
Noncontrolling interests		2,283	2,349
Total equity		34,868	34,573
Total liabilities and equity		$ 129,317	$ 124,977
Common Stock, Shares Authorized		2,000,000,000	2,000,000,000
Common Stock, Shares, Outstanding		976,000,000	973,000,000
Treasury Stock, Shares		2,000,000	2,000,000
Variable Interest Entity, Primary Beneficiary [Member]
Current assets
Cash and cash equivalents		$ 98	$ 163
Restricted cash and cash equivalents		47	88
Accounts receivable
Customer accounts receivable, net		148	151
Unamortized energy contract assets, current		22	23
Inventories, net
Materials and supplies		244	227
Assets held for sale		101	0
Other		674	32
Total current assets		1,370	723
Property, plant and equipment, net		5,803	6,022
Deferred debits and other assets
Nuclear decommissioning trust funds		3,007	2,741
Unamortized energy contract assets, noncurrent		249	250
Other		52	89
Total assets		10,481	9,825
Current liabilities
Long-term debt due within one year		94	544
Accounts payable		81	106
Accrued expenses		70	70
Unamortized energy contract liabilities, current		4	8
Liabilities held for sale		16	0
Other		5	3
Total current liabilities		270	731
Long-term debt		889	527
Deferred credits and other liabilities
Asset retirement obligations, noncurrent		2,318	2,128
Unamortized energy contract liabilities, noncurrent		0	1
Other		129	89
Total liabilities		3,606	3,476
Variable Interest Entity, Primary Beneficiary [Member] \| Nonrecourse [Member]
Deferred credits and other liabilities
Total liabilities		3,598	3,473
Variable Interest Entity, Primary Beneficiary [Member] \| Asset Pledged as Collateral [Member]
Deferred debits and other assets
Total assets		10,200	9,532
Exelon Generation Co L L C [Member]
Current assets
Cash and cash equivalents		226	303
Restricted cash and cash equivalents		89	146
Accounts receivable
Customer accounts receivable		1,330	2,973
Customer allowance for credit losses		(32)	(80)
Customer accounts receivable, net		1,298	2,893
Other accounts receivable		352	619
Other accounts receivable, net		352	619
Mark-to-market derivative assets, current		644	675
Receivables from affiliates, current		153	190
Unamortized energy contract assets, current		38	47
Inventories, net
Fossil fuel and emission allowances		233	236
Materials and supplies		978	1,026
Renewable energy credits, current		621	336
Assets held for sale		958	0
Other		1,357	605
Total current assets		6,947	7,076
Property, plant and equipment, net		22,214	24,193
Accumulated depreciation and amortization		13,370	12,017
Deferred debits and other assets
Nuclear decommissioning trust funds		14,464	13,190
Investments		184	235
Goodwill		47	47
Mark-to-market derivative assets, noncurrent		555	508
Prepaid pension asset		1,558	1,438
Unamortized energy contract assets, noncurrent		293	336
Deferred income taxes		6	12
Other		1,826	1,960
Total deferred debits and other assets		18,933	17,726
Total assets	[2]	48,094	48,995
Current liabilities
Short-term borrowings		840	320
Long-term debt due within one year		197	2,624
Long-term debt to affiliates due within one year		0	558
Accounts payable		1,253	1,692
Accrued expenses		788	786
Payables to affiliates, current		107	117
Borrowings from Exelon/PHI intercompany money pool		285	0
Mark-to-market derivative liabilities, current		262	215
Unamortized energy contract liabilities, current		7	17
Renewable energy credit obligation		661	443
Liabilities held for sale		375	0
Other		444	517
Total current liabilities		5,219	7,289
Long-term debt		5,566	4,464
Long-term debt to affiliates		324	328
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		3,656	3,752
Asset retirement obligations, noncurrent		12,054	10,603
Non-pension postretirement benefits obligations		858	878
Spent nuclear fuel obligation		1,208	1,199
Payables to affiliates, noncurrent		3,017	3,103
Mark-to-market derivative liabilities, noncurrent		205	123
Unamortized energy contract liabilities, noncurrent		3	11
Other		1,308	1,415
Total deferred credits and other liabilities		22,309	21,084
Total liabilities	[2]	33,418	33,165
Commitments and contingencies
Shareholders’ equity
Retained earnings/Undistributed earnings (losses)		2,805	3,950
Accumulated other comprehensive loss, net		(30)	(32)
Member’s equity
Membership interest		9,624	9,566
Total member’s equity		12,399	13,484
Noncontrolling interests		2,277	2,346
Total equity		14,676	15,830
Total liabilities and equity		48,094	48,995
Exelon Generation Co L L C [Member] \| Variable Interest Entity, Primary Beneficiary [Member]
Current assets
Cash and cash equivalents		98	163
Restricted cash and cash equivalents		44	85
Accounts receivable
Customer accounts receivable, net		148	151
Unamortized energy contract assets, current		22	23
Inventories, net
Materials and supplies		244	227
Assets held for sale		101	0
Other		669	31
Total current assets		1,362	719
Property, plant and equipment, net		5,803	6,022
Deferred debits and other assets
Nuclear decommissioning trust funds		3,007	2,741
Unamortized energy contract assets, noncurrent		249	250
Other		42	73
Total assets		10,463	9,805
Current liabilities
Long-term debt due within one year		68	523
Accounts payable		81	106
Accrued expenses		70	70
Unamortized energy contract liabilities, current		4	8
Liabilities held for sale		16	0
Other		5	3
Total current liabilities		244	710
Long-term debt		889	504
Deferred credits and other liabilities
Asset retirement obligations, noncurrent		2,318	2,128
Unamortized energy contract liabilities, noncurrent		0	1
Other		129	89
Total liabilities		3,580	3,432
Exelon Generation Co L L C [Member] \| Variable Interest Entity, Primary Beneficiary [Member] \| Nonrecourse [Member]
Deferred credits and other liabilities
Total liabilities		3,572	3,429
Exelon Generation Co L L C [Member] \| Variable Interest Entity, Primary Beneficiary [Member] \| Asset Pledged as Collateral [Member]
Deferred debits and other assets
Total assets		10,182	9,512
Commonwealth Edison Co [Member]
Current assets
Cash and cash equivalents		83	90
Restricted cash and cash equivalents		279	150
Accounts receivable
Customer accounts receivable		656	604
Customer allowance for credit losses		(97)	(59)
Customer accounts receivable, net		559	545
Other accounts receivable		239	306
Other allowance for credit losses		(21)	(20)
Other accounts receivable, net		218	286
Receivables from affiliates, current		22	28
Inventories, net
Inventories, net		170	159
Regulatory assets, current		279	281
Other		49	44
Total current assets		1,659	1,583
Property, plant and equipment, net		24,557	23,107
Accumulated depreciation and amortization		5,672	5,168
Deferred debits and other assets
Regulatory assets, noncurrent		1,749	1,480
Investments		6	6
Goodwill		2,625	2,625
Receivable from affiliates, noncurrent		2,541	2,622
Prepaid pension asset		1,022	995
Other		307	347
Total deferred debits and other assets		8,250	8,075
Total assets		34,466	32,765
Current liabilities
Short-term borrowings		323	130
Long-term debt due within one year		350	500
Accounts payable		683	527
Accrued expenses		390	385
Payables to affiliates, current		96	103
Customer deposits		86	118
Regulatory liabilities, current		289	200
Mark-to-market derivative liabilities, current		33	32
Other		143	122
Total current liabilities		2,393	2,117
Long-term debt		8,633	7,991
Long-term debt to financing trusts		205	205
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		4,341	4,021
Asset retirement obligations, noncurrent		126	128
Non-pension postretirement benefits obligations		173	180
Regulatory liabilities, noncurrent		6,403	6,542
Mark-to-market derivative liabilities, noncurrent		268	269
Other		595	635
Total deferred credits and other liabilities		11,906	11,775
Total liabilities		23,137	22,088
Commitments and contingencies
Shareholders’ equity
Common stock		1,588	1,588
Other paid-in capital		8,285	7,572
Retained deficit unappropriated		(1,639)	(1,639)
Retained earnings appropriated		3,095	3,156
Total shareholders’ equity		11,329	10,677
Member’s equity
Total liabilities and equity		$ 34,466	$ 32,765
Commonwealth Edison Co [Member] \| Common Stock [Member]
Shareholders’ equity
Common Stock, Par or Stated Value Per Share		$ 12.50	$ 12.50
Member’s equity
Common Stock, Shares Authorized		250,000,000	250,000,000
Common Stock, Shares, Outstanding		127,000,000	127,000,000
PECO Energy Co [Member]
Current assets
Cash and cash equivalents		$ 19	$ 21
Restricted cash and cash equivalents		7	6
Accounts receivable
Customer accounts receivable		511	412
Customer allowance for credit losses		(116)	(55)
Customer accounts receivable, net		395	357
Other accounts receivable		130	145
Other allowance for credit losses		(8)	(7)
Other accounts receivable, net		122	138
Receivables from affiliates, current		2	1
Receivable from Exelon/PHI intercompany money pool		0	68
Inventories, net
Fossil fuel and emission allowances		33	36
Materials and supplies		38	35
Regulatory assets, current		25	41
Other		21	19
Total current assets		662	722
Property, plant and equipment, net		10,181	9,292
Accumulated depreciation and amortization		3,843	3,718
Deferred debits and other assets
Regulatory assets, noncurrent		776	554
Investments		30	27
Receivable from affiliates, noncurrent		475	480
Prepaid pension asset		375	365
Other		32	29
Total deferred debits and other assets		1,688	1,455
Total assets		12,531	11,469
Current liabilities
Long-term debt due within one year		300	0
Accounts payable		479	387
Accrued expenses		129	101
Payables to affiliates, current		50	55
Borrowings from Exelon/PHI intercompany money pool		40	0
Customer deposits		59	69
Regulatory liabilities, current		121	91
Other		30	19
Total current liabilities		1,208	722
Long-term debt		3,453	3,405
Long-term debt to financing trusts		184	184
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		2,242	2,080
Asset retirement obligations, noncurrent		29	28
Non-pension postretirement benefits obligations		286	288
Regulatory liabilities, noncurrent		503	510
Other		93	74
Total deferred credits and other liabilities		3,153	2,980
Total liabilities		7,998	7,291
Commitments and contingencies
Shareholders’ equity
Common stock		3,014	2,766
Retained earnings/Undistributed earnings (losses)		1,519	1,412
Total shareholders’ equity		4,533	4,178
Member’s equity
Total liabilities and equity		$ 12,531	$ 11,469
PECO Energy Co [Member] \| Common Stock [Member]
Member’s equity
Common Stock, Shares Authorized		500,000,000	500,000,000
Common Stock, Shares, Outstanding		170,000,000	170,000,000
Common Stock, No Par Value		$ 0	$ 0
Baltimore Gas and Electric Company [Member]
Current assets
Cash and cash equivalents		$ 144	$ 24
Restricted cash and cash equivalents		1	1
Accounts receivable
Customer accounts receivable		487	329
Customer allowance for credit losses		(35)	(12)
Customer accounts receivable, net		452	317
Other accounts receivable		117	152
Other allowance for credit losses		(9)	(5)
Other accounts receivable, net		108	147
Receivables from affiliates, current		3	1
Inventories, net
Fossil fuel and emission allowances		41	46
Materials and supplies		25	30
Prepaid utility taxes		0	78
Regulatory assets, current		168	183
Other		6	6
Total current assets		948	833
Property, plant and equipment, net		9,872	8,990
Accumulated depreciation and amortization		4,034	3,834
Deferred debits and other assets
Regulatory assets, noncurrent		481	454
Investments		10	7
Prepaid pension asset		270	264
Other		69	86
Total deferred debits and other assets		830	811
Total assets		11,650	10,634
Current liabilities
Short-term borrowings		0	76
Long-term debt due within one year		300	0
Accounts payable		346	243
Accrued expenses		205	152
Payables to affiliates, current		61	66
Customer deposits		110	120
Regulatory liabilities, current		30	33
Other		91	63
Total current liabilities		1,143	753
Long-term debt		3,364	3,270
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		1,521	1,396
Asset retirement obligations, noncurrent		23	22
Non-pension postretirement benefits obligations		189	199
Regulatory liabilities, noncurrent		1,109	1,195
Other		104	116
Total deferred credits and other liabilities		2,946	2,928
Total liabilities		7,453	6,951
Commitments and contingencies
Shareholders’ equity
Common stock	[3]	2,318	1,907
Retained earnings/Undistributed earnings (losses)		1,879	1,776
Total shareholders’ equity		4,197	3,683
Member’s equity
Total liabilities and equity		$ 11,650	$ 10,634
Baltimore Gas and Electric Company [Member] \| Common Stock [Member]
Member’s equity
Common Stock, Shares Authorized		1,500	1,500
Common Stock, Shares, Outstanding		1,000	1,000
Common Stock, No Par Value		$ 0	$ 0
Pepco Holdings LLC [Member]
Current assets
Cash and cash equivalents		$ 111	$ 131
Restricted cash and cash equivalents		39	36
Accounts receivable
Customer accounts receivable		611	516
Customer allowance for credit losses		(86)	(37)
Customer accounts receivable, net		525	479
Other accounts receivable		260	190
Other allowance for credit losses		(33)	(16)
Other accounts receivable, net		227	174
Receivables from affiliates, current		8	1
Inventories, net
Fossil fuel and emission allowances		6	8
Materials and supplies		198	190
Regulatory assets, current		440	412
Other		45	49
Total current assets		1,599	1,480
Property, plant and equipment, net		15,377	14,296
Accumulated depreciation and amortization		1,811	1,213
Deferred debits and other assets
Regulatory assets, noncurrent		1,933	2,061
Investments		140	135
Goodwill		4,005	4,005
Prepaid pension asset		365	406
Deferred income taxes		10	13
Other		307	323
Total deferred debits and other assets		6,760	6,943
Total assets		23,736	22,719
Current liabilities
Short-term borrowings		368	208
Long-term debt due within one year		347	103
Accounts payable		539	462
Accrued expenses		299	296
Payables to affiliates, current		104	98
Borrowings from Exelon/PHI intercompany money pool		21	12
Customer deposits		106	117
Regulatory liabilities, current		137	70
Unamortized energy contract liabilities, current		92	115
Other		141	131
Total current liabilities		2,154	1,612
Long-term debt		6,659	6,460
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		2,439	2,278
Asset retirement obligations, noncurrent		59	57
Non-pension postretirement benefits obligations		86	93
Regulatory liabilities, noncurrent		1,438	1,707
Unamortized energy contract liabilities, noncurrent		235	327
Other		622	577
Total deferred credits and other liabilities		4,879	5,039
Total liabilities	[4]	13,692	13,111
Commitments and contingencies
Shareholders’ equity
Retained earnings/Undistributed earnings (losses)		(68)	(10)
Member’s equity
Membership interest		10,112	9,618
Total member’s equity		10,044	9,608
Total equity		10,044	9,608
Total liabilities and equity		23,736	22,719
Pepco Holdings LLC [Member] \| Variable Interest Entity, Primary Beneficiary [Member]
Current assets
Cash and cash equivalents		0	0
Restricted cash and cash equivalents		3	3
Accounts receivable
Customer accounts receivable, net		0	0
Unamortized energy contract assets, current		0	0
Inventories, net
Materials and supplies		0	0
Assets held for sale		0	0
Other		5	1
Total current assets		8	4
Property, plant and equipment, net		0	0
Deferred debits and other assets
Nuclear decommissioning trust funds		0	0
Unamortized energy contract assets, noncurrent		0	0
Other		10	16
Total assets		18	20
Current liabilities
Long-term debt due within one year		26	21
Accounts payable		0	0
Accrued expenses		0	0
Unamortized energy contract liabilities, current		0	0
Liabilities held for sale		0	0
Other		0	0
Total current liabilities		26	21
Long-term debt		0	23
Deferred credits and other liabilities
Asset retirement obligations, noncurrent		0	0
Unamortized energy contract liabilities, noncurrent		0	0
Other		0	0
Total liabilities		26	44
Pepco Holdings LLC [Member] \| Variable Interest Entity, Primary Beneficiary [Member] \| Nonrecourse [Member]
Deferred credits and other liabilities
Total liabilities		26	44
Pepco Holdings LLC [Member] \| Variable Interest Entity, Primary Beneficiary [Member] \| Asset Pledged as Collateral [Member]
Deferred debits and other assets
Total assets		18	20
Potomac Electric Power Company [Member]
Current assets
Cash and cash equivalents		30	30
Restricted cash and cash equivalents		35	33
Accounts receivable
Customer accounts receivable		279	244
Customer allowance for credit losses		(32)	(13)
Customer accounts receivable, net		247	231
Other accounts receivable		131	98
Other allowance for credit losses		(13)	(7)
Other accounts receivable, net		118	91
Receivables from affiliates, current		2	0
Inventories, net
Inventories, net		111	112
Regulatory assets, current		214	188
Other		13	11
Total current assets		770	696
Property, plant and equipment, net		7,456	6,909
Accumulated depreciation and amortization		3,697	3,517
Deferred debits and other assets
Regulatory assets, noncurrent		570	584
Investments		115	110
Prepaid pension asset		284	296
Other		69	66
Total deferred debits and other assets		1,038	1,056
Total assets		9,264	8,661
Current liabilities
Short-term borrowings		35	82
Long-term debt due within one year		3	2
Accounts payable		226	195
Accrued expenses		164	156
Payables to affiliates, current		55	66
Customer deposits		51	57
Regulatory liabilities, current		46	8
Merger related obligation		33	39
Current portion of DC PLUG obligation		30	30
Other		31	22
Total current liabilities		674	657
Long-term debt		3,162	2,862
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		1,189	1,131
Asset retirement obligations, noncurrent		39	41
Non-pension postretirement benefits obligations		13	20
Regulatory liabilities, noncurrent		644	746
Other		340	297
Total deferred credits and other liabilities		2,225	2,235
Total liabilities		6,061	5,754
Commitments and contingencies
Shareholders’ equity
Common stock	[5]	2,058	1,796
Retained earnings/Undistributed earnings (losses)		1,145	1,111
Total shareholders’ equity		3,203	2,907
Member’s equity
Total liabilities and equity		$ 9,264	$ 8,661
Potomac Electric Power Company [Member] \| Common Stock [Member]
Shareholders’ equity
Common Stock, Par or Stated Value Per Share		$ 0.01	$ 0.01
Member’s equity
Common Stock, Shares Authorized		200,000,000	200,000,000
Common Stock, Shares, Outstanding		100	100
Delmarva Power & Light Company [Member]
Current assets
Cash and cash equivalents		$ 15	$ 13
Restricted cash and cash equivalents		0	0
Accounts receivable
Customer accounts receivable		176	152
Customer allowance for credit losses		(22)	(11)
Customer accounts receivable, net		154	141
Other accounts receivable		68	42
Other allowance for credit losses		(9)	(4)
Other accounts receivable, net		59	38
Receivables from affiliates, current		1	0
Inventories, net
Fossil fuel and emission allowances		6	8
Materials and supplies		51	44
Prepaid utility taxes		11	18
Regulatory assets, current		58	52
Renewable energy credits, current		10	9
Other		3	2
Total current assets		368	325
Property, plant and equipment, net		4,314	4,035
Accumulated depreciation and amortization		1,533	1,425
Deferred debits and other assets
Regulatory assets, noncurrent		222	222
Investments		0	0
Goodwill		8	8
Prepaid pension asset		162	171
Other		66	69
Total deferred debits and other assets		458	470
Total assets		5,140	4,830
Current liabilities
Short-term borrowings		146	56
Long-term debt due within one year		82	80
Accounts payable		126	112
Accrued expenses		46	46
Payables to affiliates, current		36	32
Customer deposits		32	36
Regulatory liabilities, current		47	37
Other		20	15
Total current liabilities		535	414
Long-term debt		1,595	1,487
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		715	655
Asset retirement obligations, noncurrent		14	12
Non-pension postretirement benefits obligations		15	16
Regulatory liabilities, noncurrent		493	574
Other		97	92
Total deferred credits and other liabilities		1,334	1,349
Total liabilities		3,464	3,250
Commitments and contingencies
Shareholders’ equity
Common stock	[6]	1,089	977
Retained earnings/Undistributed earnings (losses)		587	603
Total shareholders’ equity		1,676	1,580
Member’s equity
Total liabilities and equity		$ 5,140	$ 4,830
Delmarva Power & Light Company [Member] \| Common Stock [Member]
Shareholders’ equity
Common Stock, Par or Stated Value Per Share		$ 2.25	$ 2.25
Member’s equity
Common Stock, Shares Authorized		1,000	1,000
Common Stock, Shares, Outstanding		1,000	1,000
Atlantic City Electric Company [Member]
Current assets
Cash and cash equivalents		$ 17	$ 12
Restricted cash and cash equivalents		3	2
Accounts receivable
Customer accounts receivable		156	121
Customer allowance for credit losses		(32)	(13)
Customer accounts receivable, net		124	108
Other accounts receivable		72	53
Other allowance for credit losses		(11)	(5)
Other accounts receivable, net		61	48
Receivables from affiliates, current		6	4
Inventories, net
Inventories, net		37	34
Regulatory assets, current		75	57
Other		3	5
Total current assets		326	270
Property, plant and equipment, net		3,475	3,190
Accumulated depreciation and amortization		1,303	1,210
Deferred debits and other assets
Regulatory assets, noncurrent		395	368
Investments		0	0
Prepaid pension asset		40	52
Other		50	53
Total deferred debits and other assets		485	473
Total assets	[7]	4,286	3,933
Current liabilities
Short-term borrowings		187	70
Long-term debt due within one year		261	20
Accounts payable		177	144
Accrued expenses		46	42
Payables to affiliates, current		31	25
Customer deposits		23	25
Regulatory liabilities, current		44	25
Other		11	9
Total current liabilities		780	360
Long-term debt		1,152	1,307
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		624	577
Non-pension postretirement benefits obligations		17	17
Regulatory liabilities, noncurrent		274	357
Other		48	39
Total deferred credits and other liabilities		963	990
Total liabilities	[7]	2,895	2,657
Commitments and contingencies
Shareholders’ equity
Common stock		1,271	1,154
Retained earnings/Undistributed earnings (losses)		120	122
Total shareholders’ equity		1,391	1,276
Member’s equity
Total liabilities and equity		$ 4,286	$ 3,933
Atlantic City Electric Company [Member] \| Common Stock [Member]
Shareholders’ equity
Common Stock, Par or Stated Value Per Share		$ 3	$ 3
Member’s equity
Common Stock, Shares Authorized		25,000,000	25,000,000
Common Stock, Shares, Outstanding		9,000,000	9,000,000
Atlantic City Electric Company [Member] \| Variable Interest Entity, Primary Beneficiary [Member]
Current assets
Cash and cash equivalents		$ 0	$ 0
Restricted cash and cash equivalents		3	3
Accounts receivable
Customer accounts receivable, net		0	0
Unamortized energy contract assets, current		0	0
Inventories, net
Materials and supplies		0	0
Assets held for sale		0	0
Other		0	0
Total current assets		3	3
Property, plant and equipment, net		0	0
Deferred debits and other assets
Nuclear decommissioning trust funds		0	0
Unamortized energy contract assets, noncurrent		0	0
Other		10	14
Total assets		13	17
Current liabilities
Long-term debt due within one year		21	20
Accounts payable		0	0
Accrued expenses		0	0
Unamortized energy contract liabilities, current		0	0
Liabilities held for sale		0	0
Other		0	0
Total current liabilities		21	20
Long-term debt		0	21
Deferred credits and other liabilities
Asset retirement obligations, noncurrent		0	0
Unamortized energy contract liabilities, noncurrent		0	0
Other		0	0
Total liabilities		21	41
Atlantic City Electric Company [Member] \| Variable Interest Entity, Primary Beneficiary [Member] \| Nonrecourse [Member]
Deferred credits and other liabilities
Total liabilities		21	41
Atlantic City Electric Company [Member] \| Variable Interest Entity, Primary Beneficiary [Member] \| Asset Pledged as Collateral [Member]
Deferred debits and other assets
Total assets		$ 13	$ 17

[1]	Exelon’s consolidated assets include $10,200 million and $9,532 million at December 31, 2020 and 2019, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $3,598 million and $3,473 million at December 31, 2020 and 2019, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 23–Variable Interest Entities for additional information.
[2]	Generation’s consolidated assets include $10,182 million and $9,512 million at December 31, 2020 and 2019, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $3,572 million and $3,429 million at December 31, 2020 and 2019, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 23–Variable Interest Entities for additional information.
[3]	In millions, shares round to zero. Number of shares is 1,500 authorized and 1,000 outstanding at December 31, 2020 and 2019.
[4]	PHI’s consolidated total assets include $18 million and $20 million at December 31, 2020 and 2019, respectively, of PHI's consolidated VIE that can only be used to settle the liabilities of the VIE. PHI’s consolidated total liabilities include $26 million and $44 million at December 31, 2020 and 2019, respectively, of PHI's consolidated VIE for which the VIE creditors do not have recourse to PHI. See Note 23 - Variable Interest Entities for additional information.
[5]	In millions, shares round to zero. Number of shares is 100 outstanding at December 31, 2020 and 2019.
[6]	In millions, shares round to zero. Number of shares is 1,000 authorized and 1,000 outstanding at December 31, 2020 and 2019.
[7]	ACE’s consolidated assets include $13 million and $17 million at December 31, 2020 and 2019, respectively, of ACE’s consolidated VIE that can only be used to settle the liabilities of the VIE. ACE’s consolidated liabilities include $21 million and $41 million at December 31, 2020 and 2019, respectively, of ACE’s consolidated VIE for which the VIE creditors do not have recourse to ACE. See Note 23 - Variable Interest Entities for additional information.

Consolidated Statement of Chang

Consolidated Statement of Changes in Shareholders Equity - USD ($) shares in Thousands, $ in Millions	Total	Common Stock [Member]	Treasury Stock [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss), net	Noncontrolling Interest [Member]	Other Comprehensive Income (Loss) [Member]	Exelon Generation Co L L C [Member]	Exelon Generation Co L L C [Member]Membership Interest [Member]	Exelon Generation Co L L C [Member]Undistributed Earnings [Member]	Exelon Generation Co L L C [Member]Accumulated Other Comprehensive Income (Loss), net	Exelon Generation Co L L C [Member]Noncontrolling Interest [Member]	Exelon Generation Co L L C [Member]Other Comprehensive Income (Loss) [Member]	Commonwealth Edison Co [Member]	Commonwealth Edison Co [Member]Common Stock [Member]	Commonwealth Edison Co [Member]Retained Earnings [Member]	Commonwealth Edison Co [Member]Other Additional Capital [Member]	Commonwealth Edison Co [Member]Retained Earnings, Unappropriated [Member]	Commonwealth Edison Co [Member]Retained Earnings Appropriated [Member]	PECO Energy Co [Member]	PECO Energy Co [Member]Common Stock [Member]	PECO Energy Co [Member]Retained Earnings [Member]	PECO Energy Co [Member]Accumulated Other Comprehensive Income (Loss), net	Baltimore Gas and Electric Company [Member]	Baltimore Gas and Electric Company [Member]Common Stock [Member]	Baltimore Gas and Electric Company [Member]Retained Earnings [Member]	Baltimore Gas and Electric Company [Member]Membership Interest [Member]	Pepco Holdings LLC [Member]	Pepco Holdings LLC [Member]Membership Interest [Member]	Pepco Holdings LLC [Member]Undistributed Earnings [Member]	Potomac Electric Power Company [Member]	Potomac Electric Power Company [Member]Common Stock [Member]	Potomac Electric Power Company [Member]Retained Earnings [Member]	Delmarva Power & Light Company [Member]	Delmarva Power & Light Company [Member]Common Stock [Member]	Delmarva Power & Light Company [Member]Retained Earnings [Member]	Atlantic City Electric Company [Member]	Atlantic City Electric Company [Member]Common Stock [Member]	Atlantic City Electric Company [Member]Retained Earnings [Member]
Beginning Balance (in shares) at Dec. 31, 2017	965,168
Beginning Balance at Dec. 31, 2017	$ 32,169	$ 18,964	$ (123)	$ 14,063	$ (3,026)	$ 2,291
Beginning Balance at Dec. 31, 2017								$ 15,959	$ 9,357	$ 4,349	$ (37)	$ 2,290																$ 8,807	$ 8,835	$ (28)
Beginning Balance at Dec. 31, 2017														$ 9,542	$ 1,588		$ 6,822	$ (1,639)	$ 2,771	$ 3,577	$ 2,489	$ 1,087	$ 1		$ 1,605	$ 1,536	$ 3,141				$ 2,515	$ 1,470	$ 1,045	$ 1,335	$ 764	$ 571	$ 1,043	$ 912	$ 131
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	$ 2,079			2,005		74		443		370		73		664				664		460		460		$ 313		313	313	393		393	205		205	120		120	75		75
Long-Term Incentive Plan Activity (shares)	3,534
Long-Term Incentive Plan Activity	$ 41	41	0	0	0	0
Employee stock purchase plan issuances, shares	1,318
Employee stock purchase plan issuances	$ 105	105	0	0	0	0
Sale of noncontrolling interests	6	6				0		6	6			0
Changes in equity of noncontrolling interests	$ (60)					(60)		(60)				(60)
Common Stock, Dividends, Per Share, Declared	$ 1.38
Common stock dividends	$ (1,339)			(1,339)										(459)					(459)	(306)		(306)				(209)	(209)				(169)		(169)	(96)		(96)	(59)		(59)
Other Comprehensive Income (Loss), Net of Tax	42				41	1	$ 42	3			2	1
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard	4			14	(10)			3		6	(3)									0		1	(1)
Distributions to member								(1,001)		(1,001)																		(326)		(326)
Contributions from parent	$ 0							155	155					500			500			89	89		0		109		109	385	385		166	166		150	150		67	67
Ending Balance (in shares) at Dec. 31, 2018	970,020
Ending Balance at Dec. 31, 2018	$ 33,047	19,116	(123)	14,743	(2,995)	2,306
Ending Balance at Dec. 31, 2018														10,247	1,588		7,322	(1,639)	2,976	3,820	2,578	1,242	0		1,714	1,640	3,354				2,717	1,636	1,081	1,509	914	595	1,126	979	147
Ending Balance at Dec. 31, 2018								15,508	9,518	3,724	(38)	2,304																9,259	9,220	39
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Retained earnings appropriated																$ 0		(664)	664
Net income (loss)	$ 3,028			2,936		92		1,217		1,125		92		688				688		528		528		360		360	360	477		477	243		243	147		147	99		99
Long-Term Incentive Plan Activity (shares)	3,111
Long-Term Incentive Plan Activity	$ 40	40	0	0	0	0
Employee stock purchase plan issuances, shares	1,285
Employee stock purchase plan issuances	$ 112	112	0	0	0	0
Sale of noncontrolling interests	6	6				0		7	7			0
Changes in equity of noncontrolling interests	$ (48)					(48)		(48)				(48)
Common Stock, Dividends, Per Share, Declared	$ 1.45
Common stock dividends	$ (1,412)			(1,412)										(508)					(508)	(358)		(358)				(224)	(224)				(213)		(213)	(139)		(139)	(124)		(124)
Other Comprehensive Income (Loss), Net of Tax	(198)				(199)	(1)	(200)	7			6	(2)	$ 4
Distributions to member								(899)		(899)																		(526)		(526)
Contributions from parent	$ 0							41	41					250			250			188	188		0		193		193	398	398		160	160		63	63		175	175
Ending Balance (in shares) at Dec. 31, 2019	974,416
Ending Balance at Dec. 31, 2019	$ 34,573	19,274	(123)	16,267	(3,194)	2,349
Ending Balance at Dec. 31, 2019	32,224													10,677	1,588		7,572	(1,639)	3,156	4,178	2,766	1,412	0	3,683	1,907	1,776	3,683				2,907	1,796	1,111	1,580	977	603	1,276	1,154	122
Ending Balance at Dec. 31, 2019								15,830	9,566	3,950	(32)	2,346																9,608	9,618	(10)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Retained earnings appropriated														3,156		0		(688)	688
Net income (loss)	$ 1,954			1,963		(9)		579		589		(10)		438				438		447		447		349		349	349	495		495	266		266	125		125	112		112
Long-Term Incentive Plan Activity (shares)	1,570
Long-Term Incentive Plan Activity	$ 40	40	0	0	0	0
Employee stock purchase plan issuances, shares	1,480
Employee stock purchase plan issuances	$ 56	56	0	0	0	0
Sale of noncontrolling interests	3	3				0		3	3			0
Changes in equity of noncontrolling interests	$ (57)	0				(57)		(59)				(59)
Distribution to member of deferred taxes associated with net retirement benefit obligation								(9)	(9)
Common Stock, Dividends, Per Share, Declared	$ 1.53
Common stock dividends	$ (1,495)			(1,495)										(499)					(499)	(340)		(340)				(246)	(246)				(232)		(232)	(141)		(141)	(114)		(114)
Other Comprehensive Income (Loss), Net of Tax	$ (206)				(206)	0	$ (206)	2			2	0	$ 2
Distributions to member								(1,734)		(1,734)																		(553)		(553)
Contributions from parent								64	64					713			713			248	248		0		411	0	411	494	494		262	262		112	112		117	117
Ending Balance (in shares) at Dec. 31, 2020	977,466
Ending Balance at Dec. 31, 2020	$ 34,868	$ 19,373	$ (123)	$ 16,735	$ (3,400)	$ 2,283
Ending Balance at Dec. 31, 2020	$ 32,585													11,329	$ 1,588		$ 8,285	(1,639)	3,095	$ 4,533	$ 3,014	$ 1,519	$ 0	$ 4,197	$ 2,318	$ 1,879	$ 4,197				$ 3,203	$ 2,058	$ 1,145	$ 1,676	$ 1,089	$ 587	$ 1,391	$ 1,271	$ 120
Ending Balance at Dec. 31, 2020								$ 14,676	$ 9,624	$ 2,805	$ (30)	$ 2,277																$ 10,044	$ 10,112	$ (68)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Retained earnings appropriated														$ 3,095		$ 0		$ (438)	$ 438

Significant Accounting Policies

Significant Accounting Policies (All Registrants)	12 Months Ended
Significant Accounting Policies (All Registrants)	Dec. 31, 2020
Accounting Policies [Abstract]
Significant Accounting Policies (All Registrants)	Significant Accounting Policies (All Registrants) Description of Business (All Registrants) Exelon is a utility services holding company engaged in the generation, delivery and marketing of energy through Generation and the energy distribution and transmission businesses through ComEd, PECO, BGE, Pepco, DPL, and ACE. Name of Registrant Business Service Territories Exelon Generation Generation, physical delivery and marketing of power across multiple geographical regions through its customer-facing business, Constellation, which sells electricity to both wholesale and retail customers. Generation also sells natural gas, renewable energy, and other energy-related products and services. Five reportable segments: Mid-Atlantic, Midwest, New York, ERCOT, and Other Power Regions Commonwealth Edison Company Purchase and regulated retail sale of electricity Northern Illinois, including the City of Chicago Transmission and distribution of electricity to retail customers PECO Energy Company Purchase and regulated retail sale of electricity and natural gas Southeastern Pennsylvania, including the City of Philadelphia (electricity) Transmission and distribution of electricity and distribution of natural gas to retail customers Pennsylvania counties surrounding the City of Philadelphia (natural gas) Baltimore Gas and Electric Company Purchase and regulated retail sale of electricity and natural gas Central Maryland, including the City of Baltimore (electricity and natural gas) Transmission and distribution of electricity and distribution of natural gas to retail customers Pepco Holdings LLC Utility services holding company engaged, through its reportable segments Pepco, DPL, and ACE Service Territories of Pepco, DPL, and ACE Potomac Electric Purchase and regulated retail sale of electricity District of Columbia, and major portions of Montgomery and Prince George’s Counties, Maryland. Transmission and distribution of electricity to retail customers Delmarva Power & Light Company Purchase and regulated retail sale of electricity and natural gas Portions of Delaware and Maryland (electricity) Transmission and distribution of electricity and distribution of natural gas to retail customers Portions of New Castle County, Delaware (natural gas) Atlantic City Electric Company Purchase and regulated retail sale of electricity Portions of Southern New Jersey Transmission and distribution of electricity to retail customers Basis of Presentation (All Registrants) This is a combined annual report of all Registrants. The Notes to the Consolidated Financial Statements apply to the Registrants as indicated parenthetically next to each corresponding disclosure. When appropriate, the Registrants are named specifically for their related activities and disclosures. Each of the Registrant’s Consolidated Financial Statements includes the accounts of its subsidiaries. All intercompany transactions have been eliminated. Through its business services subsidiary, BSC, Exelon provides its subsidiaries with a variety of support services at cost, including legal, human resources, financial, information technology, and supply management services. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services at cost, including legal, accounting, engineering, customer operations, distribution and transmission planning, asset management, system operations, and power procurement, to PHI operating companies. The costs of BSC and PHISCO are directly charged or allocated to the applicable subsidiaries. The results of Exelon’s corporate operations are presented as “Other” within the consolidated financial statements and include intercompany eliminations unless otherwise disclosed. Exelon owns 100% of Generation, PECO, BGE, and PHI and more than 99% of ComEd. PHI owns 100% of Pepco, DPL, and ACE. Generation owns 100% of its significant consolidated subsidiaries, either directly or indirectly, except for certain consolidated VIEs, including CENG and EGRP, of which Generation holds a 50.01% and 51% interest, respectively. The remaining interests in these consolidated VIEs are included in noncontrolling interests on Exelon’s and Generation’s Consolidated Balance Sheets. See Note 23 — Variable Interest Entities for additional information of Exelon’s and Generation’s consolidated VIEs. The Registrants consolidate the accounts of entities in which a Registrant has a controlling financial interest, after the elimination of intercompany transactions. Where the Registrants 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. The Registrants apply proportionate consolidation when they have an undivided interest in an asset and are proportionately liable for their share of each liability associated with the asset. The Registrants proportionately consolidate their undivided ownership interests in jointly owned electric plants and transmission facilities. Under proportionate consolidation, the Registrants separately record their proportionate share of the assets, liabilities, revenues, and expenses related to the undivided interest in the asset. The Registrants apply equity method accounting when they have significant influence over an investee through an ownership in common stock, which generally approximates a 20% to 50% voting interest. The Registrants apply equity method accounting to certain investments and joint ventures. Under equity method accounting, the Registrants report their interest in the entity as an investment and the Registrants’ percentage share of the earnings from the entity as single line items in their financial statements. The Registrants use accounting for investments in equity securities with or without readily determinable fair values if they lack significant influence, which generally results when they hold less than 20% of the common stock of an entity. Under accounting for investments in equity securities with readily determinable fair values, the Registrants report their investment values 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 Registrants report their investments 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. 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. COVID-19 (All Registrants) The Registrants have taken steps to mitigate the potential risks posed by the global outbreak (pandemic) of the 2019 novel coronavirus (COVID-19). The Registrants provide a critical service to their customers and have taken measures to keep employees who operate the business safe and minimize unnecessary risk of exposure to the virus, including extra precautions for employees who work in the field. The Registrants have implemented work from home policies where appropriate and imposed travel limitations on employees. In addition, the Registrants have updated their existing business continuity plans. Management makes estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and accompanying notes, and the amounts of revenues and expenses reported during the periods covered by those financial statements and accompanying notes. Management assessed certain accounting matters that require consideration of forecasted financial information, including, but not limited to, the Registrants' allowance for credit losses and the carrying value of goodwill and other long-lived assets, in context with the information reasonably available to the Registrants and the unknown future impacts of COVID-19 as of December 31, 2020 and through the date of this report. The Registrants' future assessment of their current expectations of the magnitude and duration of COVID-19, as well as other factors, could result in material impacts to their consolidated financial statements in future reporting periods. Use of Estimates (All Registrants) The preparation of financial statements of each of the Registrants 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, inventory reserves, allowance for credit losses, goodwill and 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. Accounting for the Effects of Regulation (Exelon and the Utility Registrants) For their regulated electric and gas operations, Exelon and the Utility Registrants reflect the effects of cost-based rate regulation in their financial statements, which is required for entities with regulated operations that meet the following criteria: 1) rates are established or approved by a third-party regulator; (2) rates are designed to recover the entities’ cost of providing services or products; and (3) there is a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. Exelon and the Utility Registrants account for their regulated operations in accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction, principally the ICC, PAPUC, MDPSC, DCPSC, DPSC, and NJBPU, under state public utility laws and the FERC under various Federal laws. Regulatory assets and liabilities are amortized and the related expense or revenue is recognized in the Consolidated Statements of Operations consistent with the recovery or refund included in customer rates. Exelon's regulatory assets and liabilities as of the balance sheet date are probable of being recovered or settled in future rates. If a separable portion of the Registrants' business was no longer able to meet the criteria discussed above, the affected entities would be required to eliminate from their consolidated financial statements the effects of regulation for that portion, which could have a material impact on their financial statements. See Note 3 — Regulatory Matters for additional information. With the exception of income tax-related regulatory assets and liabilities, Exelon and the Utility Registrants classify regulatory assets and liabilities with a recovery or settlement period greater than one year as both current and non-current in their Consolidated Balance Sheets, with the current portion representing the amount expected to be recovered from or refunded to customers over the next twelve-month period as of the balance sheet date. Income tax-related regulatory assets and liabilities are classified entirely as non-current in Exelon's and the Utility Registrants’ Consolidated Balance Sheets to align with the classification of the related deferred income tax balances. Exelon and the Utility Registrants treat the impacts of a final rate order received after the balance sheet date but prior to the issuance of the financial statements as a non-recognized subsequent event, as the receipt of a final rate order is a separate and distinct event that has future impacts on the parties affected by the order. Revenues (All Registrants) Operating Revenues. The Registrants’ operating revenues generally consist of revenues from contracts with customers involving the sale and delivery of energy commodities and related products and services, utility revenues from ARP, and realized and unrealized revenues recognized under mark-to-market energy commodity derivative contracts. The Registrants recognize revenue from contracts with customers to depict the transfer of goods or services to customers in an amount that the entities expect to be entitled to in exchange for those goods or services. Generation’s primary sources of revenue include competitive sales of power, natural gas, and other energy-related products and services. The Utility Registrants’ primary sources of revenue include regulated electric and natural gas tariff sales, distribution, and transmission services. At the end of each month, the Registrants accrue an estimate for the unbilled amount of energy delivered or services provided to customers. ComEd records ARP revenue for its best estimate of the electric distribution, energy efficiency, and transmission revenue impacts resulting from future changes in rates that ComEd believes are probable of approval by the ICC and FERC in accordance with its formula rate mechanisms. BGE, Pepco, and DPL record ARP revenue for their best estimate of the electric and natural gas distribution revenue impacts resulting from future changes in rates that they believe are probable of approval by the MDPSC and/or DCPSC in accordance with their revenue decoupling mechanisms. PECO, BGE, Pepco, DPL, and ACE record ARP revenue for their best estimate of the transmission revenue impacts resulting from future changes in rates that they believe are probable of approval by FERC in accordance with their formula rate mechanisms. See Note 3 — Regulatory Matters for additional information. 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. To the extent a Utility Registrant receives full cost recovery for energy procurement and related costs from retail customers, it records the fair value of its energy swap contracts with unaffiliated suppliers as well as an offsetting regulatory asset or liability in its Consolidated Balance Sheets. See Note 3 — Regulatory Matters and Note 16 — Derivative Financial Instruments for additional information. Taxes Directly Imposed on Revenue-Producing Transactions. The Registrants 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 gas. Some of these taxes are imposed on the customer, but paid by the Registrants, while others are imposed on the Registrants. Where these taxes are imposed on the customer, such as sales taxes, they are reported on a net basis with no impact to the Consolidated Statements of Operations and Comprehensive Income. However, where these taxes are imposed on the Registrants, such as gross receipts taxes or other surcharges or fees, they are reported on a gross basis. Accordingly, revenues are recognized for the taxes collected from customers along with an offsetting expense. Se e Note 24 — Supplemental Financial Information for Generation’s and the Utility Registrants' utility taxes that are presented on a gross basis. Leases (All Registrants) The Registrants adopted new accounting guidance issued by the FASB related to leases as of January 1, 2019. The Registrants recognize a ROU asset and lease liability for operating and finance 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. Finance lease ROU assets are included in Plant, property, and equipment, net and finance lease liabilities are included in Long-term debt due within one year and Long-term debt 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 each Registrant’s 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. The Registrants 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 and 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 on the Registrants’ Statements of Operations and Comprehensive Income. Expense for finance leases is primarily recorded to Operating and maintenance on the Utility Registrants’ 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 and are based on the electricity produced by those generating assets. Operating lease income and variable lease payments are recorded to Operating revenues on the Registrants’ Statements of Operations and Comprehensive Income. The Registrants’ operating and finance leases consist primarily of contracted generation, real estate including office buildings, and vehicles and equipment. The Registrants 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 of the economic benefits. For new agreements entered after January 1, 2019, the Registrants 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. The Registrants account for land right arrangements that provide for exclusive use as leases while shared use land arrangements are generally not leases. The Registrants do not account for secondary use pole attachments as leases. See Note 11 — Leases for additional information. Income Taxes (All Registrants) Deferred Federal and state income taxes are recorded on significant temporary differences between the book and tax basis of assets and liabilities and for tax benefits carried forward. Investment tax credits have been deferred in the Registrants’ Consolidated Balance Sheets and are recognized in book income over the life of the related property. The Registrants 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. The Registrants 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 their Consolidated Statements of Operations and Comprehensive Income. Cash and Cash Equivalents (All Registrants) The Registrants consider investments purchased with an original maturity of three months or less to be cash equivalents. Restricted Cash and Cash Equivalents (All Registrants) Restricted cash and cash equivalents represent funds that are restricted to satisfy designated current liabilities. As of December 31, 2020 and 2019, the Registrants' restricted cash and cash equivalents primarily represented the following items: Registrant Description Exelon Payment of medical, dental, vision, and long-term disability benefits, in addition to the items listed for Generation and the Utility Registrants. Generation Project-specific nonrecourse financing structures for debt service and financing of operations of the underlying entities. ComEd Collateral held from suppliers associated with energy and REC procurement contracts, any over-recovered RPS costs and alternative compliance payments received from RES pursuant to FEJA, and costs for the remediation of an MGP site. PECO Proceeds from the sales of assets that were subject to PECO’s mortgage indenture. BGE Proceeds from the loan program for the completion of certain energy efficiency measures and collateral held from energy suppliers. PHI Payment of merger commitments, collateral held from its energy suppliers associated with procurement contracts, and repayment of Transition Bonds. Pepco Payment of merger commitments and collateral held from energy suppliers. DPL Collateral held from energy suppliers. ACE Repayment of Transition Bonds and collateral held from energy suppliers. Restricted cash and cash equivalents not available to satisfy current liabilities are classified as noncurrent assets. As of December 31, 2020 and 2019, the Registrants' noncurrent restricted cash and cash equivalents primarily represented ComEd’s over-recovered RPS costs and alternative compliance payments received from RES pursuant to FEJA and costs for the remediation of an MGP site, and ACE’s repayment of Transition Bonds. See Note 24 — Supplemental Financial Information for additional information. Allowance for Credit Losses on Accounts Receivables (All Registrants) The allowance for credit losses reflects the Registrants’ best estimates 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 Generation’s 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 Generation wholesale customers is developed using a credit monitoring process, similar to that used for retail customers. When a wholesale customer’s risk characteristics are no longer aligned with the pooled population, Generation uses specific identification to develop an allowance for credit losses. Adjustments to the allowance for credit losses are recorded in Operating and maintenance expense on Generation’s Consolidated Statements of Operations and Comprehensive Income. The allowance for credit losses for the Utility Registrants’ customers is developed by applying loss rates for each Utility Registrant, based on historical loss experience, current conditions, and forward-looking risk factors, to the outstanding receivable balance by customer risk segment. Utility Registrants' customer accounts are written off consistent with approved regulatory requirements. Adjustments to the allowance for credit losses are primarily recorded to Operating and maintenance expense on the Utility Registrants' Consolidated Statements of Operations and Comprehensive Income or Regulatory assets and liabilities on the Utility Registrants' Consolidated Balance Sheets. See Note 3 - Regulatory Matters for additional information regarding the regulatory recovery of credit losses on customer accounts receivable. The Registrants have certain non-customer receivables in Other deferred debits and other assets which primarily are with governmental agencies and other high-quality counterparties with no history of default. As such, the allowance for credit losses related to these receivables is not material. The Registrants monitor these balances and will record an allowance if there are indicators of a decline in credit quality. Variable Interest Entities (Exelon, Generation, PHI, and ACE) Exelon accounts for its investments in and arrangements with VIEs based on the following specific requirements: • requires an entity to qualitatively assess whether it should consolidate a VIE based on whether the entity has a controlling financial interest, • requires an ongoing reconsideration of this assessment instead of only upon certain triggering events, and • requires the entity that consolidates a VIE (the primary beneficiary) to disclose (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 23 — Variable Interest Entities for additional information. Inventories (All Registrants) Inventory is recorded at the lower of weighted average cost or net realizable value. Provisions are recorded for excess and obsolete inventory. Fossil fuel, materials and supplies, and emissions allowances are generally included in inventory when purchased. Fossil fuel and emissions allowances are expensed to purchased power and fuel expense when used or sold. Materials and supplies generally includes transmission, distribution, and generating plant materials 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 (Exelon and Generation) Debt Security Investments. Debt securities are reported at fair value and classified as available-for-sale securities. Unrealized gains and losses, net of tax, are reported in OCI. Equity Security Investments without Readily Determinable Fair Values. Exelon has certain equity securities without readily determinable fair values. Exelon has elected to use the practicability exception 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 earnings. Equity Security Investments with Readily Determinable Fair Values. Exelon has certain equity securities with readily determinable fair values. For equity securities held in NDT funds, realized and unrealized gains and losses, net of tax, on Generation’s NDT funds associated with the Regulatory Agreement Units are included in regulatory liabilities at Exelon, ComEd, and PECO, in Noncurrent payables to affiliates at Generation and in Noncurrent receivables from affiliates at ComEd and PECO. Realized and unrealized gains and losses, net of tax, on Generation’s NDT funds associated with the Non-Regulatory Agreement Units are included in earnings at Exelon and Generation. Exelon's and Generation's NDT funds are classified as current or noncurrent assets, depending on the timing of the decommissioning activities and income taxes on trust earnings. For all other equity securities with readily determinable fair values, realized and unrealized gains and losses are included in earnings at Exelon and Generation. See Note 3 — Regulatory Matters for additional information regarding ComEd’s and PECO’s regulatory assets and liabilities and Note 18 — Fair Value of Financial Assets and Liabilities and Note 10 — Asset Retirement Obligations for additional information. Property, Plant, and Equipment (All Registrants) Property, plant, and equipment is recorded at original cost. Original cost includes construction-related direct labor and material costs. The Utility Registrants also include indirect construction costs including labor and related costs of departments associated with supporting construction activities. When appropriate, original cost also includes capitalized interest for Generation, Exelon Corporate, and PHI and AFUDC for regulated property at the Utility Registrants. The cost of repairs and maintenance, including planned major maintenance activities and minor replacements of property, is charged to Operating and maintenance expense as incurred. Third parties reimburse the Utility Registrants for all or a portion of expenditures for certain capital projects. Such contributions in aid of construction costs (CIAC) are recorded as a reduction to Property, plant, and equipment, net. DOE SGIG and other funds reimbursed to the Utility Registrants have been accounted for as CIAC. For Generation, 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. For the Utility Registrants, upon retirement, the cost of property, net of salvage, is charged to accumulated depreciation consistent with the composite and group methods of depreciation. Depreciation expense at ComEd, BGE, Pepco, DPL, and ACE includes the estimated cost of dismantling and removing plant from service upon retirement. Actual incurred removal costs are applied against a related regulatory liability or recorded to a regulatory asset if in excess of previously collected removal costs. PECO’s removal costs are capitalized to accumulated depreciation when incurred and recorded to depreciation expense over the life of the new asset constructed consistent with PECO’s regulatory recovery method. 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 within Property, plant, and equipment. Similar costs incurred for cloud-based solutions treated as service arrangements are capitalized within Other Current Assets and Deferred Debits and Other Assets. 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 or pursuant to prescribed regulatory requirements. Capitalized Interest and AFUDC. During construction, Exelon and Generation capitalize the costs of debt funds used to finance non-regulated construction projects. Capitalization of debt funds is recorded as a charge to construction work in progress and as a non-cash credit to interest expense. AFUDC is the cost, during the period of construction, of debt and equity funds used to finance construction projects for regulated operations. AFUDC is recorded to construction work in progress and as a non-cash credit to an allowance that is included in interest expense for debt-related funds and other income and deductions for equity-related funds. The rates used for capitalizing AFUDC are computed under a method prescribed by regulatory authorities. See Note 8 — Property, Plant, and Equipment, Note 9 — Jointly Owned Electric Utility Plant and Note 24 — Sup

Mergers, Acquisitions and Dispo

Mergers, Acquisitions and Dispositions (Exelon and Generation)	12 Months Ended
	Dec. 31, 2020
Mergers, Acquisitions and Dispositions [Abstract]
Mergers, Acquisitions, and Dispositions (Exelon and Generation)	Mergers, Acquisitions, and Dispositions (Exelon and Generation) CENG Put Option (Exelon and Generation) Generation owns a 50.01% membership interest in CENG, a joint venture with EDF, which wholly owns the Calvert Cliffs and Ginna nuclear stations and Nine Mile Point Unit 1, in addition to an 82% undivided ownership interest in Nine Mile Point Unit 2. CENG is 100% consolidated in Exelon's and Generation's financial statements. See Note 23 — Variable Interest Entities for additional information. On April 1, 2014, Generation and EDF entered into various agreements 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 Generation until Generation has received aggregate distributions of $400 million plus a return of 8.50% per annum. Under the Put Option Agreement, EDF has the option to sell its 49.99% equity interest in CENG to Generation exercisable beginning on January 1, 2016 and thereafter until June 30, 2022. On November 20, 2019, Generation received notice of EDF’s intention to exercise the put option to sell its interest in CENG to Generation, and the put automatically exercised on January 19, 2020 at the end of the sixty-day advance notice period. Under the terms of the Put Option Agreement, the purchase price is to be determined by agreement of the parties, or absent such agreement, by a third-party arbitration process. The third parties determining fair market value of EDF’s 49.99% interest are to take into consideration all rights and obligations under the LLC Operating Agreement and Employee Matters Agreement including but not limited to Generation’s rights with respect to any unpaid aggregate preferred distributions and the related return. As of December 31, 2020, the total unpaid aggregate preferred distributions and related return owed to Generation is $619 million . At this time, Generation cannot reasonably predict the ultimate purchase price that will be paid to EDF for its interest in CENG. The transaction will require approval by the NYPSC and the FERC. The FERC approval was obtained on July 30, 2020. The process and regulatory approvals are expected to close in the second half of 2021. Agreement for Sale of Generation’s Solar Business (Exelon and Generation) On December 8, 2020, Generation entered into an agreement with an affiliate of Brookfield Renewable, for the sale of a significant portion of Generation’s solar business, including 360 megawatts of generation in operation or under construction across more than 600 sites across the United States. Under the terms of the transaction, the purchase price is $810 million, subject to certain working capital and other post-closing adjustments. Generation will retain certain solar assets not included in this agreement, primarily Antelope Valley. As a result of the transaction, in the fourth quarter of 2020, Exelon and Generation reclassified the solar assets and liabilities on Exelon’s and Generation’s Consolidated Balance Sheets as held for sale. The transaction is expected to result in an estimated pre-tax gain ranging from $75 million to $125 million. The gain will be recorded in Gain on sales of assets and businesses in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income upon completion of the transaction. Completion of the transaction contemplated by the sale agreement is subject to the satisfaction of several closing conditions and is expected to occur in the first half of 2021. See Note 17 — Debt and Credit Agreements for additional information on the SolGen nonrecourse debt included as part of the transaction. Disposition of Oyster Creek (Exelon and Generation) On July 31, 2018, Generation entered into an agreement with Holtec and its indirect wholly owned subsidiary, OCEP, for the sale and decommissioning of Oyster Creek located in Forked River, New Jersey, which permanently ceased generation operations on September 17, 2018. Completion of the transaction contemplated by the sale agreement was subject to the satisfaction of several closing conditions, including approval of the license transfer from the NRC and other regulatory approvals, and a private letter ruling from the IRS, which were satisfied in the second quarter 2019. The sale was completed on July 1, 2019. Exelon and Generation recognized a loss on the sale in the third quarter of 2019, which was immaterial. Under the terms of the transaction, Generation transferred to OCEP substantially all the assets associated with Oyster Creek, including assets held in NDT funds, along with the assumption of liability for all responsibility for the site, including full decommissioning and ongoing management of spent fuel until the spent fuel is moved offsite. The terms of the transaction also include various forms of performance assurance for the obligations of OCEP to timely complete the required decommissioning, including a parental guaranty from Holtec for all performance and payment obligations of OCEP, and a requirement for Holtec to deliver a letter of credit to Generation upon the occurrence of specified events. Upon remeasurement of the Oyster Creek ARO, Exelon and Generation recognized an $84 million and a $9 million pre-tax charge to Operating and maintenance expense in 2018 and in 2019, respectively. See Note 10 — Asset Retirement Obligations for additional information. Disposition of Electrical Contracting Business (Exelon and Generation) On February 28, 2018, Generation completed the sale of its interest in an electrical contracting business that primarily installs, maintains, and repairs underground and high-voltage cable transmission and distribution systems for $87 million, resulting in a pre-tax gain which is included within Gain on sales of assets and businesses in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2018.

Regulatory Matters (All Registr

Regulatory Matters (All Registrants)	12 Months Ended
Regulatory Matters (All Registrants)	Dec. 31, 2020
Regulated Operations [Abstract]
Regulatory Matters (All Registrants)	Regulatory Matters (All Registrants) The following matters below discuss the status of material regulatory and legislative proceedings of the Registrants. Utility Regulatory Matters (Exelon, PHI, and the Utility Registrants) Distribution Base Rate Case Proceedings The following tables show the completed and pending distribution base rate case proceedings in 2020. Completed Distribution Base Rate Case Proceedings Registrant/Jurisdiction Filing Date Service Requested Revenue Requirement (Decrease) Increase Approved Revenue Requirement (Decrease) Increase Approved ROE Approval Date Rate Effective Date ComEd - Illinois (a) April 8, 2019 Electric $ (6) $ (17) 8.91 % December 4, 2019 January 1, 2020 ComEd - Illinois (a) April 16, 2020 Electric (11) (14) 8.38 % December 9, 2020 January 1, 2021 BGE - Maryland (b) May 15, 2020 (amended September 11, 2020) Electric 137 81 9.50 % December 16, 2020 January 1, 2021 Natural Gas 91 21 9.65 % DPL - Maryland December 5, 2019 (amended April 23, 2020) Electric 17 12 9.60 % July 14, 2020 July 16, 2020 DPL - Delaware February 21, 2020 (amended October 9, 2020) Natural Gas 7 2 9.60 % January 6, 2021 September 21, 2020 __________ (a) Pursuant to EIMA and FEJA, ComEd’s electric distribution rates are established through a performance-based formula, which sunsets at the end of 2022. The electric distribution formula rate includes decoupling provisions and, as a result, ComEd's electric distribution formula rate revenues are not impacted by abnormal weather, usage per customer, or number of customers. ComEd is required to file an annual update to its electric distribution formula rate on or before May 1 st , with resulting rates effective in January of the following year. ComEd’s annual electric distribution formula rate update is based on prior year actual costs and current year projected capital additions (initial year revenue requirement). The update also reconciles any differences between the revenue requirement in effect for the prior year and actual costs incurred from the year (annual reconciliation). ComEd’s 2020 approved revenue requirement above reflects an increase of $51 million for the initial year revenue requirement for 2020 and a decrease of $68 million related to the annual reconciliation for 2018. The revenue requirement for 2020 and the revenue requirement for 2018 provides for a weighted average debt and equity return on distribution rate base of 6.51% inclusive of an allowed ROE of 8.91%, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points . ComEd’s 2021 approved revenue requirement above reflects an increase of $50 million for the initial year revenue requirement for 2021 and a decrease of $64 million related to the annual reconciliation for 2019. The revenue requirement for 2021 and the revenue requirement for 2019 provide for a weighted average debt and equity return on distribution rate base of 6.28% inclusive of an allowed ROE of 8.38%, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. See table below for ComEd's regulatory assets associated with its electric distribution formula rate. (b) Reflects a three-year cumulative multi-year plan for 2021 through 2023. The MDPSC awarded BGE electric revenue requirement increases of $59 million, $39 million, and $42 million in 2021, 2022, and 2023, respectively, and natural gas revenue requirement increases of $53 million, $11 million, and $10 million in 2021, 2022, and 2023, respectively. However, the MDPSC utilized certain tax benefits to fully offset the increases in 2021 so that customer rates will remain unchanged from 2020 to 2021. The MDPSC has deferred a decision on whether to use certain tax benefits to offset the revenue requirement increases in 2022 and 2023 and BGE cannot predict the outcome. Pending Distribution Base Rate Case Proceedings Registrant/Jurisdiction Filing Date Service Requested Revenue Requirement Increase Requested ROE Expected Approval Timing PECO - Pennsylvania September 30, 2020 Natural Gas $ 69 10.95 % Second quarter of 2021 Pepco - District of Columbia (a) May 30, 2019 (amended June 1, 2020) Electric 136 9.7 % Second quarter of 2021 Pepco - Maryland (b) October 26, 2020 Electric 110 10.2 % Second quarter of 2021 DPL - Delaware (c) March 6, 2020 (amended February 2, 2021) Electric 23 10.3 % Third quarter of 2021 ACE - New Jersey (d) December 9, 2020 Electric 67 10.3 % Fourth quarter of 2021 _________ (a) Pepco filed the multi-year plan enhanced proposal as an alternative to address the impacts of COVID-19. Reflects a three-year cumulative multi-year plan for 2020 through 2022 and requested revenue requirement increases of $73 million in 2022 and $63 million in 2023, to recover capital investments made during 2018 through 2020 and planned capital investments through the end of 2022. (b) Reflects a three-year cumulative multi-year plan for April 1, 2021 through March 31, 2024 and total requested revenue requirement increases of $56 million effective April 1, 2023 and $54 million effective April 1, 2024 to recover capital investments made in 2019 and 2020 and planned capital investments through March 31, 2024. (c) The rates went into effect on October 6, 2020, subject to refund. (d) Requested increases are before New Jersey sales and use tax. ACE intends to put rates into effect on September 8, 2021, subject to refund. Transmission Formula Rates (Exelon, PHI, and the Utility Registrants) The Utility Registrants' transmission rates are each established based on a FERC-approved formula. ComEd, BGE, Pepco, DPL, and ACE are required to file an annual update to the FERC-approved formula on or before May 15, and PECO is required to file on or before May 31, with the resulting rates effective on June 1 of the same year. The annual update for ComEd, BGE, DPL, and ACE is based on prior year actual costs and current year projected capital additions (initial year revenue requirement). The annual update for PECO is based on prior year actual costs and current year projected capital additions, accumulated depreciation, and accumulated deferred income taxes. The annual update for Pepco is based on prior year actual costs and current year projected capital additions, accumulated depreciation, depreciation and amortization expense, and accumulated deferred income taxes. The update for ComEd, BGE, DPL, and ACE also reconciles any differences between the revenue requirement in effect beginning June 1 of the prior year and actual costs incurred for that year (annual reconciliation). The update for PECO and Pepco also reconciles any differences between the actual costs and actual revenues for the calendar year (annual reconciliation). For 2020, the following total increases/(decreases) were included in the Utility Registrants' electric transmission formula rate updates: Registrant (a) Initial Revenue Requirement Increase/(Decrease) Annual Reconciliation Decrease Total Revenue Requirement Increase/(Decrease) (b) Allowed Return on Rate Base (c) Allowed ROE (d) ComEd $ 18 $ (4) $ 14 8.17 % 11.50 % PECO 5 (28) (23) 7.47 % 10.35 % BGE 16 (3) 4 7.26 % 10.50 % Pepco 2 (46) (44) 7.81 % 10.50 % DPL (4) (40) (44) 7.20 % 10.50 % ACE 5 (25) (20) 7.40 % 10.50 % __________ (a) All rates are effective June 30, 2020 - May 31, 2021, subject to review by interested parties pursuant to review protocols of each Utility Registrant's tariff. (b) The decrease in PECO's transmission revenue requirement relates to refunds from December 1, 2017, in accordance with the settlement agreement dated July 22, 2019. The increase in BGE's transmission revenue requirement includes a $9 million reduction related to a FERC approved dedicated facilities charge to recover the costs of providing transmission service to specifically designated load by BGE. ComEd, BGE, Pepco, DPL, and ACE’s transmission revenue requirement include a decrease related to the April 24, 2020 settlement agreement related to excess deferred income taxes. Refer to Transmission-Related Income Tax Regulatory assets below for additional information. (c) Represents the weighted average debt and equity return on transmission rate bases. (d) As part of the FERC-approved settlement of ComEd’s 2007 and PECO's 2017 transmission rate cases, the rate of return on common equity is 11.50% and 10.35%, respectively inclusive of a 50-basis-point incentive adder for being a member of a RTO, and the common equity component of the ratio used to calculate the weighted average debt and equity return for the transmission formula rate is currently capped at 55% and 55.75%, respectively. As part of the FERC-approved settlement of the ROE complaint against BGE, Pepco, DPL, and ACE, the rate of return on common equity is 10.50%, inclusive of a 50-basis-point incentive adder for being a member of a RTO. Other State Regulatory Matters Illinois Regulatory Matters Energy Efficiency Formula Rate (Exelon and ComEd). FEJA allows ComEd to defer energy efficiency costs (except for any voltage optimization costs which are recovered through the electric distribution formula rate) as a separate regulatory asset that is recovered through the energy efficiency formula rate over the weighted average useful life, as approved by the ICC, of the related energy efficiency measures. ComEd earns a return on the energy efficiency regulatory asset at a rate equal to its weighted average cost of capital, which is based on a year-end capital structure and calculated using the same methodology applicable to ComEd’s electric distribution formula rate. Beginning January 1, 2018 through December 31, 2030, the ROE that ComEd earns on its energy efficiency regulatory asset is subject to a maximum downward or upward adjustment of 200 basis points if ComEd’s cumulative persisting annual MWh savings falls short of or exceeds specified percentage benchmarks of its annual incremental savings goal. ComEd is required to file an update to its energy efficiency formula rate on or before June 1 st each year, with resulting rates effective in January of the following year. The annual update is based on projected current year energy efficiency costs, PJM capacity revenues, and the projected year-end regulatory asset balance less any related deferred income taxes (initial year revenue requirement). The update also reconciles any differences between the revenue requirement in effect for the prior year and actual costs incurred from the year (annual reconciliation). The approved energy efficiency formula rate also provides for revenue decoupling provisions similar to those in ComEd’s electric distribution formula rate. During 2020, the ICC approved the following total increases in ComEd's requested energy efficiency revenue requirement: Filing Date Requested Revenue Requirement Increase Approved Revenue Requirement Increase Approved ROE Approval Date Rate Effective Date May 21, 2020 $ 48 $ 48 (a) 8.38 % December 2, 2020 January 1, 2021 _________ (a) ComEd’s 2021 approved revenue requirement above reflects an increase of $45 million for the initial year revenue r equirement for 2021 and an increase of $3 million related to the annual reconciliation for 2019. The revenue requirement for 2021 provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 6.28% inclusive of an allowed ROE of 8.38%, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. The revenue requirement for 2019 provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 6.56% inclusive of an allowed ROE of 8.96%, which includes an upward performance adjustment that can either increase or decrease the ROE. See table below for ComEd's regulatory assets associated with its energy efficiency formula rate. Maryland Regulatory Matters The Maryland Strategic Infrastructure Development and Enhancement Program (Exelon and BGE). On December 1, 2017 (as amended on January 22, 2018), BGE filed an application with the MDPSC seeking approval for a new gas infrastructure replacement plan and associated surcharge, effective for the five-year period from 2019 through 2023. On May 30, 2018, the MDPSC approved with modifications a new infrastructure plan and associated surcharge, subject to BGE's acceptance of the Order. On June 1, 2018, BGE accepted the MDPSC Order and the associated surcharge became effective January 2019. The five-year plan calls for capital expenditures over the 2019-2023 timeframe of $732 million with an associated revenue requirement of $200 million. Cash Working Capital Order (Exelon and BGE). On November 17, 2016, the MDPSC rendered a decision in the proceeding to review BGE’s request to recover its cash working capital (CWC) requirement for its POLR service, also known as SOS, as well as other components that make up the Administrative Charge, the mechanism that enables BGE to recover its SOS-related costs. The Administrative Charge is comprised of five components: CWC, uncollectibles, incremental costs, return, and an administrative adjustment, which acts as a proxy for retail suppliers’ costs. The MDPSC accepted BGE's positions on recovery of CWC and pass-through recovery of BGE’s actual uncollectibles and incremental costs. The order also grants BGE a return on the SOS. Subsequently, the MDPSC Staff and residential consumer advocate sought clarification and appealed the amount of return awarded to BGE on the SOS. On July 27, 2020, the Maryland Court of Special Appeals affirmed the circuit court’s judgment affirming the MDPSC’s decision. No party appealed the decision to the Maryland Court of Appeals. Also, in BGE’s 2019 electric and gas distribution base rate proceeding, the MDPSC established a normalized administrative adjustment. However, a group of electric suppliers appealed the MDPSC’s decision to the Circuit Court for Baltimore City. BGE cannot predict the outcome of this appeal. New Jersey Regulatory Matters ACE Infrastructure Investment Program Filing (Exelon, PHI, and ACE). On February 28, 2018, ACE filed with the NJBPU the company’s IIP proposing to seek recovery of a series of investments through a new rider mechanism, totaling $338 million, between 2019-2022 to provide safe and reliable service for its customers. The IIP will allow for more timely recovery of investments made to modernize and enhance ACE’s electric system. On April 15, 2019, ACE entered into a settlement agreement with other parties, which allows for a recovery totaling $96 million of reliability related capital investments from July 1, 2019 through June 30, 2023. On April 18, 2019, the NJBPU approved the settlement agreement. Advanced Metering Infrastructure Filing (Exelon, PHI, and ACE). On August 26, 2020, ACE filed an application with the NJBPU as was required seeking approval to deploy a smart energy network in alignment with New Jersey’s Energy Master Plan and Clean Energy Act. The proposal consists of estimated costs totaling $220 million, with deployment taking place over a 3-year implementation period from approximately 2021 to 2024 that involves the installation of an integrated system of smart meters for all customers accompanied by the requisite communications facilities and data management systems. ACE is seeking authority to recover these estimated investments through a combination of the ACE IIP rider mechanism and future distribution base rates. ACE currently expects a decision in this matter in the third quarter of 2021 but cannot predict if the NJBPU will approve the application as filed. New Jersey Clean Energy Legislation (Exelon, PHI, and ACE). On May 23, 2018, New Jersey enacted legislation that established and modified New Jersey’s clean energy and energy efficiency programs and solar and RPS. On the same day, 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. Electric distribution utilities in New Jersey, including ACE, began collecting from retail distribution customers, through a non-bypassable charge, all costs associated with the utility’s procurement of the ZECs effective April 18, 2019. See Generation Regulatory Matters below for additional information. Other Federal Regulatory Matters Transmission-Related Income Tax Regulatory Assets (Exelon, ComEd, BGE, PHI, Pepco, DPL, and ACE). On December 13, 2016 (and as amended on March 13, 2017), BGE filed with FERC to begin recovering certain existing and future transmission-related income tax regulatory assets through its transmission formula rate. BGE’s existing regulatory assets included (1) amounts that, if BGE’s transmission formula rate provided for recovery, would have been previously amortized and (2) amounts that would be amortized and recovered prospectively. On November 16, 2017, FERC issued an order rejecting BGE’s proposed revisions to its transmission formula rate to recover these transmission-related income tax regulatory assets. In the fourth quarter of 2017, ComEd, BGE, Pepco, DPL, and ACE fully impaired their associated transmission-related income tax regulatory assets for the portion of the income tax regulatory assets that would have been previously amortized. On February 23, 2018 (as amended on July 9, 2018), ComEd, Pepco, DPL, and ACE each filed with FERC to revise their transmission formula rate mechanisms to permit recovery of transmission-related income tax regulatory assets, including those amounts that would have been previously amortized and recovered through rates had the transmission formula rate provided for such recovery. On September 7, 2018, FERC issued orders rejecting 1) BGE’s rehearing request of FERC's November 16, 2017 order and 2) the February 23, 2018 (as amended on July 9, 2018) filing by ComEd, Pepco, DPL, and ACE for similar recovery. On November 2, 2018, BGE filed an appeal of FERC's September 7, 2018 order to the U.S. Court of Appeals for the D.C. Circuit. On March 27, 2020, the U.S. Court of Appeals for the D.C. Circuit Court denied BGE’s November 2, 2018 appeal. On October 1, 2018, ComEd, BGE, Pepco, DPL, and ACE submitted filings to recover ongoing non-TCJA amortization amounts and credit TCJA transmission-related income tax regulatory liabilities to customers for the prospective period starting on October 1, 2018. On April 26, 2019, FERC issued an order accepting ComEd's, BGE's, Pepco's, DPL's, and ACE's October 1, 2018 filings, effective October 1, 2018, subject to refund and established hearing and settlement judge procedures. On April 24, 2020, ComEd, BGE, Pepco, DPL, ACE, and other parties filed a settlement agreement with FERC, which FERC approved on September 24, 2020. The settlement agreement provides for the recovery of ongoing transmission-related income tax regulatory assets and establishes the amount and amortization period for excess deferred income taxes resulting from TCJA. The settlement resulted in a reduction to Operating revenues and an offsetting reduction to Income tax expense in the second quarter of 2020. Regulatory Assets and Liabilities Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent the excess recovery of costs or accrued credits that have been deferred because it is probable such amounts will be returned to customers through future regulated rates or represent billings in advance of expenditures for approved regulatory programs. The following tables provide information about the regulatory assets and liabilities of Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE as of December 31, 2020 and December 31, 2019: December 31, 2020 Exelon ComEd PECO BGE PHI Pepco DPL ACE Regulatory assets Pension and OPEB $ 3,010 $ — $ — $ — $ — $ — $ — $ — Pension and OPEB - merger related 1,014 — — — — — — — Deferred income taxes 715 — 705 — 10 10 — — AMI programs - deployment costs 174 — — 109 65 35 30 — AMI programs - legacy meters 219 90 — 37 92 68 24 — Electric distribution formula rate annual reconciliations (14) (14) — — — — — — Electric distribution formula rate significant one-time events 117 117 — — — — — — Energy efficiency costs 982 982 — — — — — — Fair value of long-term debt 598 — — — 478 — — — Fair value of PHI's unamortized energy contracts 328 — — — 328 — — — Asset retirement obligations 135 92 21 18 4 3 — 1 MGP remediation costs 285 271 10 4 — — — — Renewable energy 301 301 — — — — — — Electric energy and natural gas costs 95 — — 23 72 37 5 30 Transmission formula rate annual reconciliations 5 — — 2 3 — 2 1 Energy efficiency and demand response programs 572 — — 289 283 203 80 — Under-recovered revenue decoupling 113 — — 20 93 93 — — Stranded costs 25 — — — 25 — — 25 Removal costs 701 — — 107 594 151 105 339 DC PLUG charge 100 — — — 100 100 — — Deferred storm costs 50 — — — 50 5 4 41 COVID-19 81 22 38 10 11 7 4 — Under-recovered credit loss expense 107 89 — — 18 — — 18 Other 274 78 27 30 147 72 26 15 Total regulatory assets 9,987 2,028 801 649 2,373 784 280 470 Less: current portion 1,228 279 25 168 440 214 58 75 Total noncurrent regulatory assets $ 8,759 $ 1,749 $ 776 $ 481 $ 1,933 $ 570 $ 222 $ 395 December 31, 2020 Exelon ComEd PECO BGE PHI Pepco DPL ACE Regulatory liabilities Deferred income taxes $ 4,502 $ 2,205 $ — $ 1,001 $ 1,296 $ 621 $ 404 $ 271 Nuclear decommissioning 3,016 2,541 475 — — — — — Removal costs 1,649 1,482 — 47 120 20 100 — Electric energy and natural gas costs 175 34 97 6 38 24 10 4 Transmission formula rate annual reconciliations 52 2 12 — 38 23 9 6 Renewable portfolio standards costs 427 427 — — — — — — Stranded costs 24 — — — 24 — — 24 Other 221 1 40 85 59 2 17 13 Total regulatory liabilities 10,066 6,692 624 1,139 1,575 690 540 318 Less: current portion 581 289 121 30 137 46 47 44 Total noncurrent regulatory liabilities $ 9,485 $ 6,403 $ 503 $ 1,109 $ 1,438 $ 644 $ 493 $ 274 December 31, 2019 Exelon ComEd PECO BGE PHI Pepco DPL ACE Regulatory assets Pension and OPEB $ 2,784 $ — $ — $ — $ — $ — $ — $ — Pension and OPEB - merger related 1,138 — — — — — — — Deferred income taxes 528 — 518 — 10 10 — — AMI programs - deployment costs 207 — — 129 78 43 35 — AMI programs - legacy meters 276 113 12 45 106 79 27 — Electric distribution formula rate annual reconciliations 34 34 — — — — — — Electric distribution formula rate significant one-time events 66 66 — — — — — — Energy efficiency costs 746 746 — — — — — — Fair value of long-term debt 650 — — — 523 — — — Fair value of PHI's unamortized energy contracts 443 — — — 443 — — — Asset retirement obligations 127 85 23 16 3 2 — 1 MGP remediation costs 302 287 11 4 — — — — Renewable energy 301 301 — — — — — — Electric energy and natural gas costs 110 — 6 36 68 43 5 20 Transmission formula rate annual reconciliations 11 — — 1 10 1 2 7 Energy efficiency and demand response programs 572 — — 303 269 196 73 — Merger integration costs 32 — — 2 30 15 8 7 Under-recovered revenue decoupling 37 — — 8 29 29 — — Stranded costs 37 — — — 37 — — 37 Removal costs 641 — — 67 574 152 100 324 DC PLUG charge 126 — — — 126 126 — — Other 337 129 25 26 167 76 24 29 Total regulatory assets 9,505 1,761 595 637 2,473 772 274 425 Less: current portion 1,170 281 41 183 412 188 52 57 Total noncurrent regulatory assets $ 8,335 $ 1,480 $ 554 $ 454 $ 2,061 $ 584 $ 222 $ 368 December 31, 2019 Exelon ComEd PECO BGE PHI Pepco DPL ACE Regulatory liabilities Deferred income taxes $ 4,944 $ 2,297 $ — $ 1,089 $ 1,558 $ 725 $ 477 $ 356 Nuclear decommissioning 3,102 2,622 480 — — — — — Removal costs 1,621 1,435 — 58 128 20 108 — Electric energy and natural gas costs 109 45 56 — 8 — 8 — Transmission formula rate annual reconciliations 34 6 28 — — — — — Other 582 337 37 81 83 9 18 26 Total regulatory liabilities 10,392 6,742 601 1,228 1,777 754 611 382 Less: current portion 406 200 91 33 70 8 37 25 Total noncurrent regulatory liabilities $ 9,986 $ 6,542 $ 510 $ 1,195 $ 1,707 $ 746 $ 574 $ 357 Descriptions of the regulatory assets and liabilities included in the tables above are summarized below, including their recovery and amortization periods. Line Item Description End Date of Remaining Recovery/Refund Period Return Pension and OPEB Primarily reflects the Utility Registrants' portion of deferred costs, including unamortized actuarial losses (gains) and prior service costs (credits), associated with Exelon's pension and OPEB plans, which are recovered through customer rates once amortized through net periodic benefit cost. Also, includes the Utility Registrants' non–service cost components capitalized in Property, plant and equipment, net on their Consolidated Balance Sheets. The deferred costs are amortized over the plan participants' average remaining service periods subject to applicable pension and OPEB cost recognition policies. See Note 15 — Retirement Benefits for additional information. The capitalized non–service cost components are amortized over the lives of the underlying assets. No Pension and OPEB - merger related The deferred costs are amortized over the plan participants' average remaining service periods subject to applicable pension and OPEB cost recognition policies. See Note 15 — Retirement Benefits for additional information. The capitalized non–service cost components are amortized over the lives of the underlying assets. Legacy Constellation - 2038 Legacy PHI - 2032 No Deferred income taxes Deferred income taxes that are recoverable or refundable through customer rates, primarily associated with accelerated depreciation, the equity component of AFUDC, and the effects of income tax rate changes, including those resulting from the TCJA. These amounts include transmission-related regulatory liabilities that require FERC approval separate from the transmission formula rate. See Transmission-Related Income Tax Regulatory Assets section above for additional information. Over the period in which the related deferred income taxes reverse, which is generally based on the expected life of the underlying assets. For TCJA, generally refunded over the remaining depreciable life of the underlying assets, except in certain jurisdictions where the commissions have approved a shorter refund period for certain assets not subject to IRS normalization rules. No Line Item Description End Date of Remaining Recovery/Refund Period Return AMI programs - deployment costs Installation costs of new smart meters, including implementation costs at Pepco and DPL of dynamic pricing for energy usage resulting from smart meters. BGE - 2026 Pepco - 2027 DPL - 2030 Yes AMI programs - legacy meters Early retirement costs of legacy meters. ComEd - 2028 BGE - 2026 Pepco - 2027 DPL - 2030 ComEd, Pepco (District of Columbia), DPL (Delaware) - Yes BGE, Pepco (Maryland), DPL (Maryland) - No Electric distribution formula rate annual reconciliations Under/(Over)-recoveries related to electric distribution service costs recoverable through ComEd's performance-based formula rate, which is updated annually with rates effective on January 1 st . 2022 Yes Electric distribution formula rate significant one-time events Deferred distribution service costs related to ComEd's significant one-time events (e.g., storm costs), which are recovered over 5 years from date of the event. 2024 Yes Energy efficiency costs ComEd's costs recovered through the energy efficiency formula rate tariff and the reconciliation of the difference of the revenue requirement in effect for the prior year and the revenue requirement based on actual prior year costs. Deferred energy efficiency costs are recovered over the weighted average useful life of the related energy measure. 2031 Yes Fair value of long-term debt Represents the difference between the carrying value and fair value of long-term debt of PHI and BGE of $478 million and $120 million, respectively, as of December 31, 2020 and $523 million and $127 million, respectively, as of December 31, 2019, as of the PHI and Constellation merger dates. BGE - 2036 No Fair value of PHI’s unamortized energy contracts Represents the regulatory assets recorded at Exelon and PHI offsetting the fair value adjustment related to Pepco's, DPL's, and ACE's electricity and natural gas energy supply contracts recorded at PHI as of the PHI merger date. 2036 No Asset retirement obligations Future legally required removal costs associated with existing AROs. Over the life of the related assets. Yes, once the removal activities have been performed. MGP remediation costs Environmental remediation costs for MGP sites recorded at ComEd, PECO, and BGE. Over the expected remediation period. See Note 19 — Commitments and Contingencies for additional information. No Line Item Description End Date of Remaining Recovery/Refund Period Return Renewable energy Represents the change in fair value of ComEd‘s 20-year floating-to-fixed long-term renewable energy swap contracts. 2032 No Electric energy and natural gas costs Under (over)-recoveries related to energy and gas supply related costs recoverable (refundable) under approved rate riders. 2025 DPL (Delaware), ACE - Yes ComEd, PECO, BGE, Pepco, DPL (Maryland) - No Transmission formula rate annual reconciliations Under (over)-recoveries related to transmission service costs recoverable through the Utility Registrants’ FERC formula rates, which are updated annually with rates effective each June 1 st . 2022 Yes Energy efficiency and demand response programs Includes under (over)-recoveries of costs incurred related to energy efficiency programs and demand response programs and recoverable costs associated with customer direct load control and energy efficiency and conservation programs that are being recovered from customers. PECO - 2021 BGE - 2025 Pepco, DPL - 2035 BGE, Pepco, DPL - Yes PECO - Yes on capital investment recovered through this mechanism Merger integration costs Integration costs to achieve distribution synergies related to the Constellation merger and PHI acquisition. Costs for Pepco (Maryland) and Pepco (District of Columbia) were $3 million and $9 million, respectively as of December 31, 2020, which are included in Other in the table above, and $6 million and $9 million, respectively as of December 31, 2019. BGE - 2021 Pepco - 2021 DPL- 2026 ACE - 2022 BGE, Pepco (Maryland), DPL - Yes Under (over)-recovered revenue decoupling Electric and / or gas distribution costs recoverable from or (refundable) to customers under decoupling mechanisms. BGE and DPL - 2021 Pepco (Maryland) - $16 million - 2021 Pepco (District of Columbia) - $31 million - 2021; $46 million to be determined by the DCPSC BGE, Pepco, DPL - No Stranded costs The regulatory asset represents certain stranded costs associated with ACE's former electricity generation business. The regulatory liability represents overcollection of a customer surcharge collected by ACE to fund principal and interest payments on Transition Bonds of ACE Transition Funding that securitized such costs. Stranded costs - 2022 Stranded costs - Yes Line Item Description End Date of Remaining Recovery/Refund Period Return Removal costs For BGE, Pepco, DPL, and ACE, the regulatory asset represents costs incurred to remove property, plant and equipment in excess of amounts received from customers through depreciation rates. For ComEd, BGE, Pepco, and DPL, the regulatory liability represents amounts received from customers through depreciation rates to cover the future non–legally required cost to remove property, plant and equipment, which reduces rate base for ratemaking purposes. BGE, Pepco, DPL, and ACE - Asset is generally recovered over the life of the underlying assets. Yes DC PLUG charge Costs associated with DC PLUG, which is a projected six year, $500 million project to place underground some of the District of Columbia’s most outage-prone power lines with $250 million of the project costs funded by Pepco and $250 million funded by the District of Columbia. Rates for the DC PLUG initiative went into effect on February 7, 2018. 2021 - $30 million $70 million to be determined based on future biennial plans filed with the DCPSC. Portion of asset funded by Pepco-Yes Deferred storm costs For Pepco, DPL, and ACE amounts represent total incremental storm restoration costs incurred due to major storm events recoverable from customers in the Maryland and New Jersey jurisdictions. Pepco - 2024 DPL - $2 million - 2025; $2 million not currently being recovered ACE - $5 m

Revenue from Contracts with Cus

Revenue from Contracts with Customers Revenue from Contracts with Customers (All Registrants)	12 Months Ended
	Dec. 31, 2020
Revenue from Contract with Customer (All Registrants) [Abstract]
Revenue from Contracts with Customers [Text Block]	Revenue from Contracts with Customers (All Registrants) The Registrants recognize revenue from contracts with customers to depict the transfer of goods or services to customers at an amount that the entities expect to be entitled to in exchange for those goods or services. Generation’s primary sources of revenue include competitive sales of power, natural gas, and other energy-related products and services. The Utility Registrants’ primary sources of revenue include regulated electric and gas tariff sales, distribution, and transmission 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 and no variable consideration for regulated electric and gas tariff sales and regulated transmission services unless noted below. Unless otherwise noted, for each of the significant revenue categories and related performance obligations described below, the Registrants 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, the Registrants generally recognize revenue in the amount for which they 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 (Exelon and Generation) Sales of power and other energy-related commodities to wholesale and retail customers across multiple geographic regions through its customer-facing business, Constellation. Various including the delivery of power (generally delivered over time) and other energy-related commodities such as capacity (generally delivered over time), 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 (Exelon and Generation) 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 and consumed by the customer. Within the month following delivery to the customer. Other Competitive Products and Services (Exelon and Generation) 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. Regulated Electric and Gas Tariff Sales (Exelon and the Utility Registrants) Sales of electricity and electricity distribution services (the Utility Registrants) and natural gas and gas distribution services (PECO, BGE, and DPL) to residential, commercial, industrial, and governmental customers through regulated tariff rates approved by state regulatory commissions. Delivery of electricity and/or natural gas. Over time (each day) as the electricity and/or natural gas is delivered to customers. Tariff sales are generally considered daily contracts as customers can discontinue service at any time. (c) Within the month following delivery of the electricity or natural gas to the customer. Regulated Transmission Services (Exelon and the Utility Registrants) The Utility Registrants provide open access to their transmission facilities to PJM, which directs and controls the operation of these transmission facilities and accordingly compensates the Utility Registrants pursuant to filed tariffs at cost-based rates approved by FERC. Various including (i) Network Integration Transmission Services (NITS), (ii) scheduling, system control and dispatch services, and (iii) access to the wholesale grid. Over time utilizing output methods to measure progress towards completion. (d) Paid weekly by PJM. __________ (a) Certain contracts may contain limits on the total amount of revenue Exelon and Generation are able to collect over the entire term of the contract. In such cases, Exelon and Generation 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. (c) Electric and natural gas utility customers have the choice to purchase electricity or natural gas from competitive electric generation and natural gas suppliers. While the Utility Registrants are required under state legislation to bill their customers for the supply and distribution of electricity and/or natural gas, they recognize revenue related only to the distribution services when customers purchase their electricity or natural gas from competitive suppliers. (d) Passage of time is used for NITS and access to the wholesale grid and MWHs of energy transported over the wholesale grid is used for scheduling, system control and dispatch services. Generation incurs 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 immaterial as of December 31, 2020 and 2019. The Utility Registrants do not incur any material costs to obtain or fulfill contracts with customers. Contract Balances (All Registrants) Contract Assets Generation records contract assets for the revenue recognized on the construction and installation of energy efficiency assets and new power generating facilities before Generation has 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. Generation records contract assets and contract receivables within Other current assets and Customer accounts receivable, net, respectively, within Exelon’s and Generation’s Consolidated Balance Sheets. The following table provides a rollforward of the contract assets reflected in Exelon's and Generation's Consolidated Balance Sheets. The Utility Registrants do not have any contract assets. Exelon Generation Balance as of December 31, 2018 $ 187 $ 187 Amounts reclassified to receivables (143) (143) Revenues recognized 130 130 Balance at December 31, 2019 174 174 Amounts reclassified to receivables (86) (86) Revenues recognized 68 68 Contract assets reclassified as held for sale (a) (12) (12) Balance at December 31, 2020 $ 144 $ 144 __________ (a) Represents contract assets related to Generation's solar business, which were classified as held for sale as a result of the sale agreement. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information. Contract Liabilities The Registrants record contract liabilities when consideration is received or due prior to the satisfaction of the performance obligations. The Registrants record contract liabilities within Other current liabilities and Other noncurrent liabilities within the Registrants' Consolidated Balance Sheets. For Generation, these contract liabilities primarily relate to upfront consideration received or due for equipment service plans, solar panel leases, and the Illinois ZEC program that introduces a cap on the total consideration to be received by Generation. The Generation contract liability related to the Illinois ZEC program includes certain amounts with ComEd that are eliminated in consolidation in Exelon’s Consolidated Statements of Operations and Consolidated Balance Sheets. On July 1, 2020, Pepco, DPL, and ACE each entered into a collaborative arrangement with an unrelated owner and manager of communication infrastructure (the Buyer). Under this arrangement, Pepco, DPL, and ACE sold a 60% undivided interest in their respective portfolios of transmission tower attachment agreements with telecommunications companies to the Buyer, in addition to transitioning management of the day-to-day operations of the jointly-owned agreements to the Buyer for 35 years, while retaining the safe and reliable operation of its utility assets. In return, Pepco, DPL, and ACE will provide the Buyer limited access on the portion of the towers where the equipment resides for the purposes of managing the agreements for the benefit of Pepco, DPL, ACE, and the Buyer. In addition, for an initial period of three years and two, two-year extensions that are subject to certain conditions, the Buyer has the exclusive right to enter into new agreements with telecommunications companies and to receive a 30% undivided interest in those new agreements. PHI, Pepco, DPL, and ACE received cash and recorded contract liabilities as of July 1, 2020 as shown in the table below. The revenue attributable to this arrangement will be recognized as operating revenue over the 35 years under the collaborative arrangement. The following table provides a rollforward of the contract liabilities reflected in Exelon's, Generation's, PHI's, Pepco's, DPL's, and ACE'S Consolidated Balance Sheets. As of December 31, 2020, 2019, and 2018, ComEd's, PECO's, and BGE's contract liabilities were immaterial. Exelon Generation PHI Pepco DPL ACE Balance as of December 31, 2017 $ 35 $ 35 $ — $ — $ — $ — Consideration received or due 179 465 — — — — Revenues recognized (187) (458) — — — — Balance as of December 31, 2018 27 42 — — — — Consideration received or due 94 287 — — — — Revenues recognized (88) (258) — — — — Balance at December 31, 2019 33 71 — — — — Consideration received or due 219 282 122 98 12 12 Revenues recognized (98) (266) (4) (4) — — Contracts liabilities reclassified as held for sale (a) (3) (3) — — — — Balance at December 31, 2020 $ 151 $ 84 $ 118 $ 94 $ 12 $ 12 __________ (a) Represents contract liabilities related to Generation's solar business, which were classified as held for sale as a result of the sale agreement. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information. The following table reflects revenues recognized in the years ended December 31, 2020, 2019 and 2018, which were included in contract liabilities at December 31, 2019, 2018, and 2017, respectively: 2020 2019 2018 Exelon $ 27 $ 18 $ 11 Generation 64 32 11 Transaction Price Allocated to Remaining Performance Obligations (All Registrants) 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, 2020. 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 Generation's power and gas sales contracts as they contain variable volumes and/or variable pricing. This disclosure also excludes the Utility Registrants' gas and electric tariff sales contracts and transmission revenue contracts as they generally have an original expected duration of one year or less and, therefore, do not contain any future, unsatisfied performance obligations to be included in this disclosure. 2021 2022 2023 2024 2025 and thereafter Total Exelon $ 262 $ 93 $ 54 $ 40 $ 330 $ 779 Generation 352 124 55 34 243 808 PHI 9 8 8 6 87 118 Pepco 7 6 6 5 70 94 DPL 1 1 1 — 9 12 ACE 1 1 1 1 8 12 Revenue Disaggregation (All Registrants) The Registrants disaggregate 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 the Registrant's revenue disaggregation.

Segment Information (All Regist

Segment Information (All Registrants)	12 Months Ended
Segment Information (All Registrants)	Dec. 31, 2020
Segment Reporting [Abstract]
Segment Information (All Registrants)	Segment Information (All Registrants) Operating segments for each of the Registrants are determined based on information used by the CODM in deciding how to evaluate performance and allocate resources at each of the Registrants. Exelon has eleven reportable segments, which include Generation's five reportable segments consisting of the Mid-Atlantic, Midwest, New York, ERCOT, and all other power regions referred to collectively as “Other Power Regions” and ComEd, PECO, BGE, and PHI's three reportable segments consisting of Pepco, DPL, and ACE. ComEd, PECO, BGE, Pepco, DPL, and ACE each represent a single reportable segment, and as such, no separate segment information is provided for these Registrants. Exelon, ComEd, PECO, BGE, Pepco, DPL, and ACE's CODMs evaluate the performance of and allocate resources to ComEd, PECO, BGE, Pepco, DPL, and ACE based on net income. The basis for Generation's reportable segments is the integrated management of its 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). Generation's hedging strategies and risk metrics are also aligned to these same geographic regions. Descriptions of each of Generation’s 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. • Other Power Regions: • New England represents operations within ISO-NE. • South represents operations in the FRCC, MISO’s Southern Region, and the remaining portions of the SERC not included within MISO or PJM. • West represents operations in the WECC, which includes CAISO. • Canada represents operations across the entire country of Canada and includes AESO, OIESO, and the Canadian portion of MISO. The CODMs for Exelon and Generation evaluate the performance of Generation’s electric business activities and allocate resources based on RNF. Generation believes that RNF is a useful measurement of operational performance. RNF 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. Generation’s operating revenues include all sales to third parties and affiliated sales to the Utility Registrants. 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 Generation’s owned generation and fuel costs associated with tolling agreements. The results of Generation's other business activities are not regularly reviewed by the CODM and are therefore not classified as operating segments or included in the regional reportable segment amounts. These activities include natural gas, as well as other miscellaneous business activities that are not significant to Generation's overall operating revenues or results of operations. Further, Generation’s unrealized mark-to-market gains and losses on economic hedging activities and its 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. Exelon and Generation do not use a measure of total assets in making decisions regarding allocating resources to or assessing the performance of these reportable segments. An analysis and reconciliation of the Registrants’ reportable segment information to the respective information in the consolidated financial statements for the years ended December 31, 2020, 2019, and 2018 is as follows: Generation ComEd PECO BGE PHI Other (a) Intersegment Exelon Operating revenues (b) : 2020 Competitive businesses electric revenues $ 15,060 $ — $ — $ — $ — $ — $ (1,196) $ 13,864 Competitive businesses natural gas revenues 2,003 — — — — — (3) 2,000 Competitive businesses other revenues 540 — — — — — (4) 536 Rate-regulated electric revenues — 5,904 2,543 2,336 4,485 — (61) 15,207 Rate-regulated natural gas revenues — — 515 762 162 — (7) 1,432 Shared service and other revenues — — — — 16 2,035 (2,051) — Total operating revenues $ 17,603 $ 5,904 $ 3,058 $ 3,098 $ 4,663 $ 2,035 $ (3,322) $ 33,039 2019 Competitive businesses electric revenues $ 16,285 $ — $ — $ — $ — $ — $ (1,165) $ 15,120 Competitive businesses natural gas revenues 2,148 — — — — — (1) 2,147 Competitive businesses other revenues 491 — — — — — (4) 487 Rate-regulated electric revenues — 5,747 2,490 2,379 4,626 — (47) 15,195 Rate-regulated natural gas revenues — — 610 727 167 — (15) 1,489 Shared service and other revenues — — — — 13 1,921 (1,934) — Total operating revenues $ 18,924 $ 5,747 $ 3,100 $ 3,106 $ 4,806 $ 1,921 $ (3,166) $ 34,438 Generation ComEd PECO BGE PHI Other (a) Intersegment Exelon 2018 Competitive businesses electric revenues $ 17,411 $ — $ — $ — $ — $ — $ (1,256) $ 16,155 Competitive businesses natural gas revenues 2,718 — — — — — (8) 2,710 Competitive businesses other revenues 308 — — — — — (5) 303 Rate-regulated electric revenues — 5,882 2,470 2,428 4,602 — (45) 15,337 Rate-regulated natural gas revenues — — 568 741 181 — (20) 1,470 Shared service and other revenues — — — — 15 1,948 (1,960) 3 Total operating revenues $ 20,437 $ 5,882 $ 3,038 $ 3,169 $ 4,798 $ 1,948 $ (3,294) $ 35,978 Intersegment revenues (c) : 2020 $ 1,211 $ 37 $ 9 $ 20 $ 17 $ 2,024 $ (3,314) $ 4 2019 1,172 30 6 26 14 1,913 (3,159) 2 2018 1,269 27 8 29 15 1,942 (3,289) 1 Depreciation and amortization: 2020 $ 2,123 $ 1,133 $ 347 $ 550 $ 782 $ 79 $ — $ 5,014 2019 1,535 1,033 333 502 754 95 — 4,252 2018 1,797 940 301 483 740 92 — 4,353 Operating expenses: 2020 $ 17,358 $ 4,950 $ 2,512 $ 2,598 $ 4,045 $ 2,047 $ (3,270) $ 30,240 2019 17,628 4,580 2,388 2,574 4,084 1,996 (3,154) 30,096 2018 19,510 4,741 2,452 2,696 4,156 1,929 (3,341) 32,143 Interest expense, net: 2020 $ 357 $ 382 $ 147 $ 133 $ 268 $ 351 $ (3) $ 1,635 2019 429 359 136 121 263 308 — 1,616 2018 432 347 129 106 261 279 — 1,554 Income (loss) before income taxes: 2020 $ 836 $ 615 $ 417 $ 390 $ 418 $ (343) $ — $ 2,333 2019 1,917 851 593 439 514 (327) (2) 3,985 2018 365 832 466 387 425 (249) (1) 2,225 Income taxes: 2020 $ 249 $ 177 $ (30) $ 41 $ (77) $ 13 $ — $ 373 2019 516 163 65 79 38 (87) — 774 2018 (108) 168 6 74 33 (55) — 118 Net income (loss): 2020 $ 579 $ 438 $ 447 $ 349 $ 495 $ (354) $ — $ 1,954 2019 1,217 688 528 360 477 (240) (2) 3,028 Generation ComEd PECO BGE PHI Other (a) Intersegment Exelon 2018 443 664 460 313 393 (193) (1) 2,079 Capital expenditures: 2020 $ 1,747 $ 2,217 $ 1,147 $ 1,247 $ 1,604 $ 86 $ — $ 8,048 2019 1,845 1,915 939 1,145 1,355 49 — 7,248 2018 2,242 2,126 849 959 1,375 43 — 7,594 Total assets: 2020 $ 48,094 $ 34,466 $ 12,531 $ 11,650 $ 23,736 $ 9,005 $ (10,165) $ 129,317 2019 48,995 32,765 11,469 10,634 22,719 8,484 (10,089) 124,977 __________ (a) Other primarily includes Exelon’s corporate operations, shared service entities, and other financing and investment activities. (b) Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 24 — Supplemental Financial Information for additional information on total utility taxes. (c) Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with Generation’s sale of certain products and services by and between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income. See Note 25 - Related Party Transactions for additional information on intersegment revenues. PHI: Pepco DPL ACE Other (a) Intersegment PHI Operating revenues (b) : 2020 Rate-regulated electric revenues $ 2,149 $ 1,109 $ 1,245 $ — $ (18) $ 4,485 Rate-regulated natural gas revenues — 162 — — — 162 Shared service and other revenues — — — 372 (356) 16 Total operating revenues $ 2,149 $ 1,271 $ 1,245 $ 372 $ (374) $ 4,663 2019 Rate-regulated electric revenues $ 2,260 $ 1,139 $ 1,240 $ — $ (13) $ 4,626 Rate-regulated natural gas revenues — 167 — — — 167 Shared service and other revenues — — — 396 (383) 13 Total operating revenues $ 2,260 $ 1,306 $ 1,240 $ 396 $ (396) $ 4,806 2018 Rate-regulated electric revenues $ 2,232 $ 1,151 $ 1,236 $ — $ (17) $ 4,602 Rate-regulated natural gas revenues — 181 — — — 181 Shared service and other revenues — — — 435 (420) 15 Total operating revenues $ 2,232 $ 1,332 $ 1,236 $ 435 $ (437) $ 4,798 Intersegment revenues (c) : 2020 $ 7 $ 9 $ 4 $ 372 $ (375) $ 17 2019 5 7 3 396 (397) 14 2018 6 8 3 435 (437) 15 Depreciation and amortization: 2020 $ 377 $ 191 $ 180 $ 34 $ — $ 782 2019 374 184 157 39 — 754 2018 385 182 136 37 — 740 Operating expenses: 2020 $ 1,799 $ 1,120 $ 1,123 $ 378 $ (375) $ 4,045 2019 1,899 1,089 1,089 403 (396) 4,084 2018 1,919 1,143 1,087 442 (435) 4,156 Interest expense, net: 2020 $ 138 $ 61 $ 59 $ 10 $ — $ 268 2019 133 61 58 10 1 263 2018 128 58 64 11 — 261 Income (loss) before income taxes: 2020 $ 259 $ 100 $ 71 $ (12) $ — $ 418 2019 (d) 259 169 99 (13) — 514 2018 (d) 216 142 87 (20) — 425 Income taxes: 2020 $ (7) $ (25) $ (41) $ (4) $ — $ (77) 2019 16 22 — — — 38 2018 11 22 12 (12) — 33 Pepco DPL ACE Other (a) Intersegment PHI Net income (loss): 2020 $ 266 $ 125 $ 112 $ (8) $ — $ 495 2019 243 147 99 (12) — 477 2018 205 120 75 (7) — 393 Capital expenditures: 2020 $ 773 $ 424 $ 401 $ 6 $ — $ 1,604 2019 626 348 375 6 — 1,355 2018 656 364 335 20 — 1,375 Total assets: 2020 $ 9,264 $ 5,140 $ 4,286 $ 5,079 $ (33) $ 23,736 2019 (d) 8,661 4,830 3,933 5,335 (40) 22,719 __________ (a) Other primarily includes PHI’s corporate operations, shared service entities, and other financing and investment activities. (b) Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 24 — Supplemental Financial Information for additional information on total utility taxes. (c) Includes intersegment revenues with ComEd, BGE, and PECO, which are eliminated at Exelon. (d) The Income (loss) before income taxes in Other and Intersegment Eliminations have been adjusted by an offsetting $489 million and $408 million in 2019 and 2018, respectively, and Total assets amounts in Other and Intersegment Eliminations have been adjusted by an offsetting $5.7 billion in 2019 for consistency with the Exelon consolidating disclosure above. The following tables disaggregate the Registrants' 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. For Generation, the disaggregation of revenues reflects Generation's two primary products of power sales and natural gas sales, with further disaggregation of power sales provided by geographic region. For the Utility Registrants, the disaggregation of revenues reflects the two primary utility services of rate-regulated electric sales and rate-regulated natural gas sales (where applicable), with further disaggregation of these tariff sales provided by major customer groups. Exelon's disaggregated revenues are consistent with Generation and the Utility Registrants, but exclude any intercompany revenues. Competitive Business Revenues (Generation): 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 Generation Consolidated Operating Revenues $ 15,905 $ 1,698 $ 17,603 $ — $ 17,603 2019 Revenues from external customers (a) Contracts with customers Other (b) Total Intersegment Revenues Total Revenues Mid-Atlantic $ 5,053 $ 17 $ 5,070 $ 4 $ 5,074 Midwest 4,095 232 4,327 (34) 4,293 New York 1,571 25 1,596 — 1,596 ERCOT 768 229 997 16 1,013 Other Power Regions 3,687 608 4,295 (49) 4,246 Total Competitive Businesses Electric Revenues $ 15,174 $ 1,111 $ 16,285 $ (63) $ 16,222 Competitive Businesses Natural Gas Revenues 1,446 702 2,148 62 2,210 Competitive Businesses Other Revenues (c) 440 51 491 1 492 Total Generation Consolidated Operating Revenues $ 17,060 $ 1,864 $ 18,924 $ — $ 18,924 2018 Revenues from external customers (a) Contracts with customers Other (b) Total Intersegment Revenues Total Revenues Mid-Atlantic $ 5,241 $ 233 $ 5,474 $ 13 $ 5,487 Midwest 4,527 190 4,717 (11) 4,706 New York 1,723 (36) 1,687 — 1,687 ERCOT 572 560 1,132 1 1,133 Other Power Regions 3,530 871 4,401 (66) 4,335 Total Competitive Businesses Electric Revenues $ 15,593 $ 1,818 $ 17,411 $ (63) $ 17,348 Competitive Businesses Natural Gas Revenues 1,524 1,194 2,718 62 2,780 Competitive Businesses Other Revenues (c) 510 (202) 308 1 309 Total Generation Consolidated Operating Revenues $ 17,627 $ 2,810 $ 20,437 $ — $ 20,437 __________ (a) Includes all wholesale and retail electric sales to third parties and affiliated sales to the Utility Registrants. (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 gains of $110 million and losses of $4 million and $262 million for the years ended December 31, 2020, 2019, and 2018, respectively, and the elimination of intersegment revenues. Revenues net of purchased power and fuel expense (Generation): 2020 2019 2018 RNF from external (a) Intersegment Total RNF from external (a) Intersegment Total RNF from external (a) Intersegment Total Mid-Atlantic $ 2,174 $ 30 $ 2,204 $ 2,637 $ 18 $ 2,655 $ 3,022 $ 51 $ 3,073 Midwest 2,902 — 2,902 2,994 (32) 2,962 3,112 23 3,135 New York 983 14 997 1,081 13 1,094 1,112 10 1,122 ERCOT 407 19 426 338 (30) 308 501 (243) 258 Other Power Regions 759 (94) 665 694 (74) 620 883 (154) 729 Total RNF for Reportable Segments $ 7,225 $ (31) $ 7,194 $ 7,744 $ (105) $ 7,639 $ 8,630 $ (313) $ 8,317 Other (b) 793 31 824 324 105 429 114 313 427 Total Generation RNF $ 8,018 $ — $ 8,018 $ 8,068 $ — $ 8,068 $ 8,744 $ — $ 8,744 __________ (a) Includes purchases and sales from/to third parties and affiliated sales to the Utility Registrants. (b) Other represents activities not allocated to a region. See text above for a description of included activities. Primarily includes: • unrealized mark-to-market gain s of $295 million and losses of $215 million and $319 million for the years ended December 31, 2020, 2019, and 2018, respectively; • accelerated nuclear fuel amortization associated with the announced early plant retirements as discussed in Note 7 - Early Plant Retirements of $60 million , $13 million, and $57 million in for the years ended December 31, 2020, 2019, and 2018, respectively; and • the elimination of intersegment RNF. Electric and Gas Revenue by Customer Class (Utility Registrants): 2020 Revenues from contracts with customers ComEd PECO BGE PHI Pepco DPL ACE Rate-regulated electric revenues Residential $ 3,090 $ 1,656 $ 1,345 $ 2,332 $ 988 $ 652 $ 692 Small commercial & industrial 1,399 386 241 472 132 171 169 Large commercial & industrial 515 228 406 1,001 736 89 176 Public authorities & electric railroads 45 29 27 60 34 13 13 Other (a) 884 225 309 613 218 190 207 Total rate-regulated electric revenues (b) $ 5,933 $ 2,524 $ 2,328 $ 4,478 $ 2,108 $ 1,115 $ 1,257 Rate-regulated natural gas revenues Residential $ — $ 361 $ 504 $ 96 $ — $ 96 $ — Small commercial & industrial — 126 79 42 — 42 — Large commercial & industrial — — 135 4 — 4 — Transportation — 24 — 14 — 14 — Other (c) — 4 29 6 — 6 — Total rate-regulated natural gas revenues (d) $ — $ 515 $ 747 $ 162 $ — $ 162 $ — Total rate-regulated revenues from contracts with customers $ 5,933 $ 3,039 $ 3,075 $ 4,640 $ 2,108 $ 1,277 $ 1,257 Other revenues Revenues from alternative revenue programs $ (47) $ 16 $ 16 $ 21 $ 40 $ (7) $ (12) Other rate-regulated electric revenues (e) 18 3 5 2 1 1 — Other rate-regulated natural gas revenues (e) — — 2 — — — — Total other revenues $ (29) $ 19 $ 23 $ 23 $ 41 $ (6) $ (12) Total rate-regulated revenues for reportable segments $ 5,904 $ 3,058 $ 3,098 $ 4,663 $ 2,149 $ 1,271 $ 1,245 2019 Revenues from contracts with customers ComEd PECO BGE PHI Pepco DPL ACE Rate-regulated electric revenues Residential $ 2,916 $ 1,596 $ 1,326 $ 2,316 $ 1,012 $ 645 $ 659 Small commercial & industrial 1,463 404 254 505 149 186 170 Large commercial & industrial 540 219 436 1,112 833 99 180 Public authorities & electric railroads 47 29 27 61 34 14 13 Other (a) 888 249 321 650 227 204 218 Total rate-regulated electric revenues (b) $ 5,854 $ 2,497 $ 2,364 $ 4,644 $ 2,255 $ 1,148 $ 1,240 Rate-regulated natural gas revenues Residential $ — $ 409 $ 474 $ 96 $ — $ 96 $ — Small commercial & industrial — 169 77 44 — 45 — Large commercial & industrial — 1 132 5 — 5 — Transportation — 25 — 14 — 14 — Other (c) — 6 31 7 — 7 — Total rate-regulated natural gas revenues (d) $ — $ 610 $ 714 $ 166 $ — $ 167 $ — Total rate-regulated revenues from contracts with customers $ 5,854 $ 3,107 $ 3,078 $ 4,810 $ 2,255 $ 1,315 $ 1,240 Other revenues Revenues from alternative revenue programs $ (133) $ (21) $ 12 $ (14) $ (3) $ (11) $ — Other rate-regulated electric revenues (e) 26 13 12 10 8 2 — Other rate-regulated natural gas revenues (e) — 1 4 — — — — Total other revenues $ (107) $ (7) $ 28 $ (4) $ 5 $ (9) $ — Total rate-regulated revenues for reportable segments $ 5,747 $ 3,100 $ 3,106 $ 4,806 $ 2,260 $ 1,306 $ 1,240 2018 Revenues from contracts with customers ComEd PECO BGE PHI Pepco DPL ACE Rate-regulated electric revenues Residential $ 2,942 $ 1,566 $ 1,382 $ 2,351 $ 1,021 $ 669 $ 661 Small commercial & industrial 1,487 404 257 488 140 186 162 Large commercial & industrial 538 223 429 1,124 846 100 178 Public authorities & electric railroads 47 28 28 58 32 14 12 Other (a) 867 243 327 593 193 175 227 Total rate-regulated electric revenues (b) $ 5,881 $ 2,464 $ 2,423 $ 4,614 $ 2,232 $ 1,144 $ 1,240 Rate-regulated natural gas revenues Residential $ — $ 395 $ 491 $ 99 $ — $ 99 $ — Small commercial & industrial — 143 77 44 — 44 — Large commercial & industrial — 1 124 8 — 8 — Transportation — 23 — 16 — 16 — Other (c) — 6 63 13 — 13 — Total rate-regulated natural gas revenues (d) $ — $ 568 $ 755 $ 180 $ — $ 180 $ — Total rate-regulated revenues from contracts with customers $ 5,881 $ 3,032 $ 3,178 $ 4,794 $ 2,232 $ 1,324 $ 1,240 Other revenues Revenues from alternative revenue programs $ (29) $ (7) $ (26) $ (7) $ (7) $ 4 $ (4) Other rate-regulated electric revenues (e) 30 12 13 10 7 3 — Other rate-regulated natural gas revenues (e) — 1 4 1 — 1 — Total other revenues $ 1 $ 6 $ (9) $ 4 $ — $ 8 $ (4) Total rate-regulated revenues for reportable segments $ 5,882 $ 3,038 $ 3,169 $ 4,798 $ 2,232 $ 1,332 $ 1,236 __________ (a) Includes revenues from transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue. (b) Includes operating revenues from affiliates in 2020, 2019, and 2018 respectively of: • $37 million, $30 million, and $27 million at ComEd • $8 million, $5 million, and $7 million at PECO • $10 million, $8 million, and $8 million at BGE • $17 million, $14 million, and $15 million at PHI • $7 million, $5 million, and $6 million at Pepco • $9 million, $7 million, and $8 million at DPL • $4 million, $3 million, and $3 million at ACE (c) Includes revenues from off-system natural gas sales. (d) Includes operating revenues from affiliates in 2020, 2019, and 2018 respectively of: • $1 million, $1 million, and $1 million at PECO • $10 million, $18 million, and $21 million at BGE (e) Includes late payment charge revenues.

Accounts Receivable (All Regist

Accounts Receivable (All Registrants)	12 Months Ended
Accounts Receivable (All Registrants)	Dec. 31, 2020
Credit Loss [Abstract]
Loans, Notes, Trade and Other Receivables Disclosure	Accounts Receivable (All Registrants) Allowance for Credit Losses on Accounts Receivable (All Registrants) The following table presents the rollforward of Allowance for Credit Losses on Customer Accounts Receivable for the year ended December 31, 2020. Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE Balance as of December 31, 2019 $ 243 $ 80 $ 59 $ 55 $ 12 $ 37 $ 13 $ 11 $ 13 Plus: Current Period Provision for Expected Credit Losses (a) 248 13 62 79 30 64 24 15 25 Less: Write-offs, net of recoveries (b) 69 5 24 18 7 15 5 4 6 Less: Sale of customer accounts receivable (c) 56 56 — — — — — — — Balance as of December 31, 2020 $ 366 $ 32 $ 97 $ 116 $ 35 $ 86 $ 32 $ 22 $ 32 _________ (a) For the Utility Registrants, the increase is primarily as a result of increased aging of receivables, the temporary suspension of customer disconnections for non-payment, temporary cessation of new late payment fees, and reconnection of service to customers previously disconnected due to COVID-19. (b) Recoveries were not material to the Registrants. (c) See below for additional information on the sale of customer accounts receivable at Generation in the second quarter of 2020. The following table presents the rollforward of Allowance for Credit Losses on Other Accounts Receivable for the year ended December 31, 2020. Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE Balance as of December 31, 2019 $ 48 $ — $ 20 $ 7 $ 5 $ 16 $ 7 $ 4 $ 5 Plus: Current Period Provision for Expected Credit Losses 33 — 5 3 7 18 6 5 7 Less: Write-offs, net of recoveries (a) 10 — 4 2 3 1 — — 1 Balance as of December 31, 2020 $ 71 $ — $ 21 $ 8 $ 9 $ 33 $ 13 $ 9 $ 11 _________ (a) Recoveries were not material to the Registrants. Unbilled Customer Revenue (All Registrants) The following table provides additional information about unbilled customer revenues recorded in the Registrants' Consolidated Balance Sheets as of December 31, 2020 and 2019. Unbilled customer revenues (a) Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE December 31, 2020 $ 998 $ 258 $ 218 $ 147 $ 197 $ 178 $ 87 $ 62 $ 29 December 31, 2019 1,535 807 218 146 170 194 100 61 33 _________ (a) Unbilled customer revenues are classified in Customer accounts receivables, net in the Registrants' Consolidated Balance Sheets. Sales of Customer Accounts Receivable (Exelon and Generation) On April 8, 2020, NER, a bankruptcy remote, special purpose entity, which is wholly-owned by Generation, 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). The Facility, whose maximum capacity is $750 million, is scheduled to expire on April 7, 2021, 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 Exelon’s and Generation’s 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 on Exelon’s and Generation’s Consolidated Balance Sheet. On April 8, 2020, Generation derecognized and transferred approximately $1.2 billion of receivables at fair value to the Purchasers in exchange for approximately $500 million in cash purchase price and $650 million of DPP. On February 17, 2021, Generation received additional cash of $250 million from the Purchasers for the remaining capacity in the Facility. The following table summarizes the impact of the sale of certain receivables: As of December 31, 2020 Derecognized receivables transferred at fair value (a) $ 1,139 Cash proceeds received 500 DPP 639 _________ (a) Includes additional customer accounts receivable sold into the Facility of $6,608 million since the start of the financing agreement. For the year ended December 31, 2020 Loss on sale of receivables (a) $ 30 _________ (a) Reflected in Operating and maintenance expense on Exelon and Generation's Consolidated Statement of Operations and Comprehensive Income. For the year ended December 31, 2020 Proceeds from new transfers $ 2,816 Cash collections received on DPP 3,771 Cash collections reinvested in the Facility 6,587 Generation’s 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, which have historically been and are expected to be immaterial. Generation continues to service the receivables sold in exchange for a servicing fee. Generation did not record a servicing asset or liability as the servicing fees were immaterial. Generation recognizes the cash proceeds received upon sale in Net cash provided by operating activities in the Consolidated Statement of Cash Flows. The collection and reinvestment of DPP is recognized in Net cash provided by investing activities of the Consolidated Statement of Cash Flows. See Note 18 — Fair Value of Financial Assets and Liabilities and Note 23 — Variable Interest Entities for additional information. Other Purchases and Sales of Customer and Other Accounts Receivables (All Registrants) Generation is required, under supplier tariffs in ISO-NE, MISO, NYISO, and PJM, to sell customer and other receivables to utility companies, which include the Utility Registrants. The Utility Registrants are required, under separate legislation and regulations in Illinois, Pennsylvania, Maryland, District of Columbia, and New Jersey, to purchase certain receivables from alternative retail electric and, as applicable, natural gas suppliers that participate in the utilities' consolidated billing. The following tables present the total receivables purchased and sold for the year ended December 31, 2020. Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE Total Receivables Purchased $ 3,529 $ — $ 1,094 $ 1,020 $ 652 $ 1,015 $ 622 $ 207 $ 186 Total Receivables Sold 572 824 — — — — — — — Related Party Transactions: Receivables purchased from Generation — — 34 67 79 72 51 13 8 Receivables sold to the Utility Registrants — 252 — — — — — — —

Early Plant Retirements (Exelon

Early Plant Retirements (Exelon, Generation)	12 Months Ended
Early Plant Retirements (Exelon, Generation)	Dec. 31, 2020
Implications of Potential Early Plant Retirements [Abstract]
Implications Of Potential Early Retirement Disclosure [Text Block]	Early Plant Retirements (Exelon and Generation) Exelon and Generation continuously evaluate factors that affect the current and expected economic value of Generation’s 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. The precise timing of an early retirement date for any plant, and the resulting financial statement impacts, may be affected by many factors, including the status of potential regulatory or legislative solutions, results of any transmission system reliability study assessments, the nature of any co-owner requirements and stipulations, and NDT fund requirements for nuclear plants, among other factors. However, the earliest retirement date for any plant would usually be the first year in which the unit does not have capacity or other obligations, and where applicable, just prior to its next scheduled nuclear refueling outage. Nuclear Generation In 2015 and 2016, Generation identified the Clinton and Quad Cities nuclear plants in Illinois, Ginna and Nine Mile Point nuclear plants in New York, and TMI nuclear plant in Pennsylvania as having the greatest risk of early retirement based on economic valuation and other factors. In 2017, PSEG made public similar financial challenges facing its New Jersey nuclear plants, including Salem, of which Generation owns a 42.59% ownership interest. PSEG is the operator of Salem and also has the decision-making authority to retire Salem. Assuming the continued effectiveness of the Illinois ZES, New Jersey ZEC program, and the New York CES, Generation and CENG, through its ownership of Ginna and Nine Mile Point, no longer consider Clinton, Quad Cities, Salem, Ginna, or Nine Mile Point to be at heightened risk for early retirement. However, to the extent the Illinois ZES, New Jersey ZEC program, or the New York CES do not operate as expected over their full terms, each of these plants, in addition to FitzPatrick, would be at heightened risk for early retirement, which could have a material impact on Exelon’s and Generation’s future financial statements. In addition, FERC’s December 19, 2019 order on the MOPR in PJM may undermine the continued effectiveness of the Illinois ZES and the New Jersey ZEC program unless Illinois and New Jersey implement an FRR mechanism under which the Generation plants in these states would be removed from PJM’s capacity auction. See Note 3 — Regulatory Matters for additional information on the Illinois ZES, New Jersey ZEC program, New York CES, and FERC's December 19, 2019 order on the MOPR in PJM. In Pennsylvania, the TMI nuclear plant did not clear in the May 2017 PJM capacity auction for the 2020-2021 planning year, the third consecutive year that TMI failed to clear the PJM base residual capacity auction and on May 30, 2017, based on these capacity auction results, prolonged periods of low wholesale power prices, and the absence of federal or state policies that place a value on nuclear energy for its ability to produce electricity without air pollution, Generation announced that it would permanently cease generation operations at TMI. On September 20, 2019, Generation permanently ceased generation operations at TMI. Generation’s Dresden, Byron, and Braidwood nuclear plants in Illinois are also showing increased signs of economic distress, in a market that does not currently compensate them for their unique contribution to grid resiliency and their ability to produce large amounts of energy without carbon and air pollution. The May 2018 PJM capacity auction for the 2021-2022 planning year resulted in the largest volume of nuclear capacity ever not selected in the auction, including all of Dresden, and portions of Byron and Braidwood. While all of LaSalle's capacity did clear in the 2021-2022 planning year auction, Generation has become increasingly concerned about the economic viability of this plant as well in a landscape where energy market prices remain depressed and energy market rules remain fatally flawed. On August 27, 2020, Generation announced that it intends to permanently cease generation operations at Byron in September 2021 and at Dresden in November 2021. The current NRC licenses for Byron Units 1 and 2 expire in 2044 and 2046, respectively, and the licenses for Dresden Units 2 and 3 expire in 2029 and 2031, respectively. As a result of the decision to early retire Byron and Dresden, Exelon and Generation recognized certain one-time charges for the year ended December 31, 2020 related to materials and supplies inventory reserve adjustments, employee-related costs, including severance benefit costs further discussed below, and construction work-in-progress impairments, among other items. In addition, as a result of the decisions to early retire Byron and Dresden, there are ongoing annual financial impacts stemming from shortening the expected economic useful lives of these nuclear plants primarily related to accelerated depreciation of plant assets (including any ARC), accelerated amortization of nuclear fuel, and changes in ARO accretion expense associated with the changes in decommissioning timing and cost assumptions to reflect an earlier retirement date. See Note 10 — Asset Retirement Obligations for additional information on changes to the nuclear decommissioning ARO balance and Note 12 — Asset Impairments for impairment assessment considerations given to the Midwest asset group as a result of the early retirement decision. The total impact on Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income is summarized in the table below. Income statement expense (pre-tax) 2020 (a) 2019 (b) 2018 (c) Depreciation and amortization Accelerated depreciation (d) $ 895 $ 216 $ 539 Accelerated nuclear fuel amortization 60 13 57 Operating and maintenance One-time charges 255 — 32 Other charges (e) 34 (53) — Contractual offset (f) (364) — — Total $ 880 $ 176 $ 628 _________ (a) Reflects expense for Byron and Dresden. (b) Reflects expense for TMI. (c) Reflects expense for TMI and Oyster Creek. (d) Includes the accelerated depreciation of plant assets including any ARC. (e) For Dresden, reflects the net impacts associated with the remeasurement of the ARO. For TMI, primarily reflects the net impacts associated with the remeasurement of the ARO. See Note 10 - Asset Retirement Obligations for additional information. (f) Reflects contractual offset for ARO accretion, ARC depreciation, and net impacts associated with the remeasurement of the ARO. For Byron and Dresden, based on the regulatory agreement with the ICC, decommissioning-related activities in 2020 have been offset within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. The offset in 2020 resulted in an equal adjustment to the noncurrent payables to ComEd at Generation and an adjustment to the regulatory liabilities at ComEd. See Note 10 - Asset Retirement Obligations for additional information. Severance benefit costs will be provided to employees impacted by the early retirements of Byron and Dresden, to the extent they are not redeployed to other nuclear plants. For the year ended December 31, 2020, Exelon and Generation recorded severance expense of $81 million within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income. The final amount of severance benefit costs will depend on the specific employees severed. The following table provides the balance sheet amounts as of December 31, 2020 for Exelon's and Generation's significant assets and liabilities associated with the Braidwood and LaSalle nuclear plants. Current depreciation provisions are based on the estimated useful lives of these nuclear generating stations, which reflect the first renewal of the operating licenses. Braidwood LaSalle Total Asset Balances Materials and supplies inventory, net $ 84 $ 106 $ 190 Nuclear fuel inventory, net 120 285 405 Completed plant, net 1,397 1,590 2,987 Construction work in progress 31 30 61 Liability Balances Asset retirement obligation (570) (954) (1,524) NRC License First Renewal Term 2046 (Unit 1) 2042 (Unit 1) 2047 (Unit 2) 2043 (Unit 2) Exelon continues to work with stakeholders on state policy solutions, while also advocating for broader market reforms at the regional and federal level. The absence of such solutions or reforms could result in future impairments of the Midwest asset group, or accelerated depreciation for specific plants over their shortened estimated useful lives, both of which could have a material unfavorable impact on Exelon's and Generation's future results of operations. Other Generation In March 2018, Generation notified ISO-NE of its plans to early retire, among other assets, the Mystic Generating Station's units 8 and 9 (Mystic 8 and 9) absent regulatory reforms to properly value reliability and regional fuel security. Thereafter, ISO-NE identified Mystic 8 and 9 as being needed to ensure fuel security for the region and entered into a cost of service agreement with these two units for the period between June 1, 2022 - May 31, 2024. The agreement was approved by the FERC in December 2018. On June 10, 2020, Generation 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 (FCA 15) 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, Exelon determined that Generation 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, Exelon and Generation 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.

Property, Plant and Equipment (

Property, Plant and Equipment (All Registrants)	12 Months Ended
Property, Plant and Equipment (All Registrants)	Dec. 31, 2020
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment (All Registrants)	Property, Plant, and Equipment (All Registrants) The following tables present a summary of property, plant, and equipment by asset category as of December 31, 2020 and 2019: Asset Category Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE December 31, 2020 Electric—transmission and distribution $ 60,946 $ — $ 29,371 $ 9,462 $ 8,797 $ 15,137 $ 10,264 $ 4,730 $ 4,568 Electric—generation 29,725 29,724 — — — — — — — Gas—transportation and distribution 6,733 — — 3,098 3,315 591 — 751 — Common—electric and gas 2,170 — — 956 1,138 178 — 180 — Nuclear fuel (a) 5,399 5,399 — — — — — — — Construction work in progress 3,576 450 799 474 627 1,174 824 163 182 Other property, plant, and equipment (b) 762 11 59 34 29 108 65 23 28 Total property, plant, and equipment 109,311 35,584 30,229 14,024 13,906 17,188 11,153 5,847 4,778 Less: accumulated depreciation (c) 26,727 13,370 5,672 3,843 4,034 1,811 3,697 1,533 1,303 Property, plant, and equipment, net $ 82,584 $ 22,214 $ 24,557 $ 10,181 $ 9,872 $ 15,377 $ 7,456 $ 4,314 $ 3,475 December 31, 2019 Electric—transmission and distribution $ 56,809 $ — $ 27,566 $ 8,957 $ 8,326 $ 13,809 $ 9,734 $ 4,464 $ 4,207 Electric—generation 29,839 29,839 — — — — — — — Gas—transportation and distribution 6,147 — — 2,899 2,999 525 — 690 — Common—electric and gas 1,907 — — 877 991 146 — 160 — Nuclear fuel (a) 5,656 5,656 — — — — — — — Construction work in progress 3,055 702 662 250 483 921 628 125 166 Other property, plant and equipment (b) 799 13 47 27 25 108 64 21 27 Total property, plant and equipment 104,212 36,210 28,275 13,010 12,824 15,509 10,426 5,460 4,400 Less: accumulated depreciation (c) 23,979 12,017 5,168 3,718 3,834 1,213 3,517 1,425 1,210 Property, plant, and equipment, net $ 80,233 $ 24,193 $ 23,107 $ 9,292 $ 8,990 $ 14,296 $ 6,909 $ 4,035 $ 3,190 __________ (a) Includes nuclear fuel that is in the fabrication and installation phase of $939 million and $1,025 million at December 31, 2020 and 2019, respectively. (b) Primarily composed of land and non-utility property. (c) Includes accumulated amortization of nuclear fuel in the reactor core at Generation of $2,774 million and $2,867 million as of December 31, 2020 and 2019, respectively. The following table presents the average service life for each asset category in number of years: Average Service Life (years) Asset Category Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE Electric - transmission and distribution 5-80 N/A 5-80 5-70 5-80 5-75 5-75 5-70 5-65 Electric - generation 1-58 1-58 N/A N/A N/A N/A N/A N/A N/A Gas - transportation and distribution 5-80 N/A N/A 5-70 5-80 5-75 N/A 5-75 N/A Common - electric and gas 4-75 N/A N/A 5-55 4-50 5-75 N/A 5-75 N/A Nuclear fuel 1-8 1-8 N/A N/A N/A N/A N/A N/A N/A Other property, plant, and equipment 1-50 1-10 33-50 50 20-50 3-50 25-50 8-50 13-15 Depreciation provisions are based on the estimated useful lives of the stations, which reflect the first renewal of the operating licenses for all of Generation's operating nuclear generating stations except for Clinton, Byron, Dresden, and Peach Bottom. Clinton depreciation provisions are based on an estimated useful life through 2027, which is the last year of the Illinois ZES. Peach Bottom depreciation provisions are based on estimated useful life of 2053 and 2054 for Unit 2 and Unit 3, respectively, which reflects the second renewal of its operating licenses. 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. See Note 3 — Regulatory Matters for additional information regarding license renewals and the Illinois ZECs and Note 7 — Early Plant Retirements for additional information on the impacts of early plant retirements. The following table presents the annual depreciation rates for each asset category. Nuclear fuel amortization is charged to fuel expense using the unit-of-production method and not included in the below table. Annual Depreciation Rates Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE December 31, 2020 Electric—transmission and distribution 2.79 % N/A 2.95 % 2.31 % 2.69 % 2.81 % 2.53 % 2.85 % 3.08 % Electric—generation 6.11 % 6.11 % N/A N/A N/A N/A N/A N/A N/A Gas—transportation and distribution 2.14 % N/A N/A 1.85 % 2.56 % 1.50 % N/A 1.50 % N/A Common—electric and gas 7.01 % N/A N/A 6.39 % 7.45 % 7.36 % N/A 6.72 % N/A December 31, 2019 Electric—transmission and distribution 2.80 % N/A 2.99 % 2.36 % 2.60 % 2.77 % 2.47 % 2.86 % 2.94 % Electric—generation 4.35 % 4.35 % N/A N/A N/A N/A N/A N/A N/A Gas—transportation and distribution 2.04 % N/A N/A 1.89 % 2.30 % 1.55 % N/A 1.55 % N/A Common—electric and gas 7.37 % N/A N/A 6.06 % 8.30 % 8.25 % N/A 6.24 % N/A December 31, 2018 Electric—transmission and distribution 2.73 % N/A 2.95 % 2.35 % 2.61 % 2.61 % 2.40 % 2.77 % 2.45 % Electric—generation 5.37 % 5.37 % N/A N/A N/A N/A N/A N/A N/A Gas—transportation and distribution 2.07 % N/A N/A 1.90 % 2.36 % 1.59 % N/A 1.59 % N/A Common—electric and gas 6.98 % N/A N/A 5.44 % 8.50 % 6.30 % N/A 3.70 % N/A Capitalized Interest and AFUDC (All Registrants) The following table summarizes capitalized interest and credits to AFUDC by year: Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE December 31, 2020 Capitalized interest $ 22 $ 22 $ — $ — $ — $ — $ — $ — $ — AFUDC debt and equity 150 — 42 23 30 55 42 6 7 December 31, 2019 Capitalized interest $ 24 $ 24 $ — $ — $ — $ — $ — $ — $ — AFUDC debt and equity 132 — 32 17 29 54 39 6 9 December 31, 2018 Capitalized interest $ 31 $ 31 $ — $ — $ — $ — $ — $ — $ — AFUDC debt and equity 109 — 30 12 24 44 34 4 4 See Note 1 — Significant Accounting Policies for additional information regarding property, plant and equipment policies. See Note 17 — Debt and Credit Agreements for additional information regarding Exelon’s, ComEd’s, PECO's, Pepco's, DPL's, and ACE’s property, plant and equipment subject to mortgage liens.

Jointly Owned Electric Utility

Jointly Owned Electric Utility Plant (Exelon, Generation, PECO, DPL and ACE)	12 Months Ended
	Dec. 31, 2020
Public Utilities, Property, Plant and Equipment [Abstract]
Jointly Owned Electric Utility Plant (Exelon, Generation, PECO, DPL and ACE)	Jointly Owned Electric Utility Plant (Exelon, Generation, PECO, DPL, and ACE) Exelon's, Generation's, PECO's, DPL's, and ACE's material undivided ownership interests in jointly owned electric plants and transmission facilities at December 31, 2020 and 2019 were as follows: Nuclear Generation Transmission Quad Cities Peach Salem Nine Mile Point Unit 2 NJ/DE (a) Operator Generation Generation PSEG Generation PSEG/DPL Ownership interest 75.00 % 50.00 % 42.59 % 82.00 % various Exelon’s share at December 31, 2020: Plant in service $ 1,188 $ 1,506 $ 717 $ 990 $ 103 Accumulated depreciation 670 601 265 187 54 Construction work in progress 13 13 39 25 — Exelon’s share at December 31, 2019: Plant in service $ 1,161 $ 1,466 $ 663 $ 951 $ 102 Accumulated depreciation 627 571 249 156 53 Construction work in progress 13 21 53 27 — __________ (a) PECO, DPL, and ACE own a 42.55%, 1%, and 13.9% share, respectively in 151.3 miles of 500kV lines located in New Jersey and of the Salem generating plant substation. PECO, DPL, and ACE also own a 42.55%, 7.45%, and 7.45% share, respectively, in 2.5 miles of 500kV line located over the Delaware River. ACE also has a 21.78% share in a 500kV New Freedom Switching substation. Exelon’s, Generation’s, PECO's, DPL's, and ACE's undivided ownership interests are financed with their funds and all operations are accounted for as if such participating interests were wholly owned facilities. Exelon’s, Generation’s, PECO's, DPL's, and ACE's share of direct expenses of the jointly owned plants are included in Purchased power and fuel and Operating and maintenance expenses in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income and in Operating and maintenance expenses in PECO's, PHI's, DPL's, and ACE's Consolidated Statements of Operations and Comprehensive Income.

Asset Retirement Obligations (A

Asset Retirement Obligations (All Registrants)	12 Months Ended
Asset Retirement Obligations (All Registrants)	Dec. 31, 2020
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations (All Registrants)	Asset Retirement Obligations (All Registrants) Nuclear Decommissioning Asset Retirement Obligations (Exelon and Generation) Generation has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. To estimate its decommissioning obligation related to its nuclear generating stations for financial accounting and reporting purposes, Generation uses 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. Generation updates its ARO annually unless circumstances warrant more frequent updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios. Generation 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 within Property, plant, and equipment on Exelon’s and Generation’s Consolidated Balance Sheets. If the ARO decreases for a Non-Regulatory Agreement unit without any remaining ARC, the corresponding change is recorded as decrease in Operating and maintenance expense within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. The following table provides a rollforward of the nuclear decommissioning ARO reflected in Exelon’s and Generation’s Consolidated Balance Sheets, from January 1, 2019 to December 31, 2020: Nuclear decommissioning ARO at January 1, 2019 $ 10,005 Net increase due to changes in, and timing of, estimated future cash flows 864 Sale of Oyster Creek (755) Accretion expense 479 Costs incurred related to decommissioning plants (89) Nuclear decommissioning ARO at December 31, 2019 (a) 10,504 Net increase due to changes in, and timing of, estimated future cash flows 1,022 Accretion Expense 489 Costs incurred related to decommissioning plants (93) Nuclear decommissioning ARO at December 31, 2020 (a) $ 11,922 __________ (a) Includes $80 million and $112 million as the current portion of the ARO at December 31, 2020 and 2019, respectively, which is included in Other current liabilities in Exelon’s and Generation’s Consolidated Balance Sheets. The net $1,022 million increase in the ARO during 2020 for changes in the amounts and timing of estimated decommissioning cash flows was driven by multiple adjustments throughout the year. These adjustments primarily include: • A net increase of approximately $800 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 announcement to early retire these plants in 2021. Refer to Note 7 — Early Plant Retirements for additional information. • An increase of approximately $360 million resulting from the change in the assumed DOE spent fuel acceptance date for disposal from 2030 to 2035. • A decrease of approximately $220 million due to lower estimated decommissioning costs primarily for Limerick and Peach Bottom nuclear units resulting from the completion of updated cost studies. The 2020 ARO updates resulted in a increase of $60 million in Operating and maintenance expense for the year ended December 31, 2020 within Exelon and Generation's Consolidated Statements of Operations and Comprehensive Income. The net $864 million increase in the ARO during 2019 for changes in the amounts and timing of estimated decommissioning cash flows was driven by multiple adjustments throughout the year, some with offsetting impacts. These adjustments primarily include: • An increase of approximately $780 million for changes in the assumed retirement timing probabilities for sites including certain economically challenged nuclear plants and the extension of Peach Bottom’s operating life. • An increase of approximately $490 million for other impacts that included updated cost escalation rates, primarily for labor, equipment and materials, and current discount rates. • Lower estimated costs to decommission TMI, Nine Mile Point, Ginna, Braidwood, Byron, and LaSalle nuclear units of approximately $410 million resulting from the completion of updated cost studies. The 2019 ARO updates resulted in a decrease of $150 million in Operating and maintenance expense for the year ended December 31, 2019 within Exelon and Generation's Consolidated Statements of Operations and Comprehensive Income. See Note 7 — Early Plant Retirements for additional information regarding TMI and economically challenged nuclear plants and Note 3 — Regulatory Matters regarding the Peach Bottom second license renewal. NDT Funds NDT funds have been established for each generation station unit to satisfy Generation’s nuclear decommissioning obligations. 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 Generation's 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, for decommissioning the former PECO nuclear plants through regulated rates, and these collections are scheduled through the operating lives of the former PECO plants. The amounts collected from PECO customers are remitted to Generation and deposited into the NDT funds for the unit for which funds are colle cted. 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, 2017, PECO filed its Nuclear Decommissioning Cost Adjustment with the PAPUC proposing an annual recovery from customers of approximately $4 million. This amount reflects a decrease from the previously approved annual collection of approximately $24 million primarily due to the removal of the collections for Limerick Units 1 and 2 as a result of the NRC approving the extension of the operating licenses for an additional 20 years. On August 8, 2017, the PAPUC approved the filing and the new rates became effective January 1, 2018. Any shortfall of funds necessary for decommissioning, determined for each generating station unit, is ultimately required to be funded by Generation, 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 CENG units, where any shortfall is required to be funded by both Generation and EDF. Generation, through PECO, has recourse to collect additional amounts from PECO customers related to a shortfall of NDT funds for the former PECO units, subject to certain limitations and thresholds, as prescribed by an order from the PAPUC. Generally, PECO, and likewise Generation will not be allowed to collect 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 Generation. No recourse exists to collect additional amounts from utility customers for any of Generation's other nuclear units. With respect to the former ComEd and 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 Generation related to the former PECO units. With respect to Generation's other nuclear units, Generation retains 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, CENG is subject to certain conditions pertaining to NDT funds 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 or 50% of any excess funds in the trust funds above the amounts required for decommissioning (including spent fuel management and decommissioning) 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. Generation expects to comply with applicable regulations and timely commence and complete all required decommissioning activities. At December 31, 2020 and 2019, Exelon and Generation had NDT funds totaling $14,599 million and $13,353 million, respectively. The NDT funds include $134 million and $163 million for the current portion of the NDT at December 31, 2020 and 2019, respectively, which are included in Other current assets in Exelon's and Generation's Consolidated Balance Sheets. See Note 24 — Supplemental Financial Information for additional information on activities of the NDT funds. Accounting Implications of the Regulatory Agreements with ComEd and PECO Based on the regulatory agreements with the ICC and PAPUC that dictate Generation’s 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 within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income and are recorded by Generation and the corresponding regulated utility as a component of the intercompany and regulatory balances on the balance sheet. For the purposes of making this determination, the decommissioning obligation referred to is different, as described below, from the calculation used in the NRC minimum funding obligation filings based on NRC guidelines. 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 Generation to ultimately return any excess funds to PECO customers (on an aggregate basis for all seven units), decommissioning-related activities are generally offset within Exelon’s and Generation’s 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 within the Consolidated Statement of Operations and Comprehensive Income results in an equal adjustment to the noncurrent payables or noncurrent receivables to affiliates at Generation with PECO recording an equal noncurrent affiliate receivable from or payable to Generation and a corresponding regulatory liability or regulatory asset. Any changes to the existing PECO regulatory agreements could impact Exelon’s and Generation’s ability to offset decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income, and the impact to Exelon’s and Generation’s financial statements could be material. For the former ComEd units, given no further recovery from ComEd customers is permitted and Generation retains 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, the offset of decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income results with Generation recognizing an intercompany payable to ComEd while ComEd records an intercompany receivable from Generation with a corresponding regulatory liability. 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 at Generation for that unit would not be offset, and the impact to Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income could be material during such periods. As of December 31, 2020, decommissioning-related activities for all of the former ComEd units, except for Zion (see Zion Station Decommissioning below), are currently offset within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. The decommissioning-related activities related to the Non-Regulatory Agreement Units are reflected in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. See Note 3 — Regulatory Matters and Note 25 — Related Party Transactions for additional information regarding regulatory liabilities at ComEd and PECO and intercompany balances between Generation, ComEd, and PECO reflecting the obligation to refund to customers any decommissioning-related assets in excess of the related decommissioning obligations. Zion Station Decommissioning In 2010, Generation completed an ASA under which ZionSolutions assumed responsibility for decommissioning Zion Station and Generation 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 to Generation, Generation will store the SNF at Zion Station until it is transferred to the DOE for ultimate disposal, and will complete all remaining decommissioning activities associated with the SNF dry storage facility. Generation had retained its obligation for the SNF as well as certain NDT assets to fund its 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 Generation. As of December 31, 2020, the ARO associated with Zion's SNF storage facility is $175 million and the NDT funds available to fund this obligation are $66 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 as calculated using the NRC methodology differ from the ARO recorded in Generation’s and Exelon’s 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 calculated under the NRC methodology are less than the future value of the NDT funds, also calculated under the NRC methodology, then the NRC requires either further funding or other financial guarantees. Key assumptions used in the minimum funding calculation using the NRC methodology at December 31, 2020 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 Generation to determine the ARO and to forecast the target growth in the NDT funds at December 31, 2020 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 spent fuel maintenance and storage subsequent to ceasing operations and until DOE acceptance, and disposal of certain LLRW); (3) 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; (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 5.6% to 6.1% (as compared to a historical 5-year annual average pre-tax return of approximately 9.0%). Generation is required to provide to the NRC a biennial report by unit (annually for units that have been retired or are within five years of the current approved license life), based on values as of December 31, addressing Generation’s ability to meet the NRC minimum funding levels. Depending on the value of the trust funds, Generation may be required to take steps, such as providing financial guarantees through 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, Exelon’s and Generation’s cash flows and financial positions may be significantly adversely affected. Generation filed its biennial decommissioning funding status report with the NRC on April 1, 2019 for all units, including its 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, 2018 for all units except for Clinton and Peach Bottom Unit 1. As of February 28, 2019, Clinton demonstrated adequate minimum funding assurance due to market recovery and no further action is required. This demonstration was also included in the April 1, 2019 submittal. On March 31, 2020, Generation filed its annual decommissioning funding status report with the NRC for Generation’s shutdown units (excluding Zion Station for the reason noted above). The annual status report demonstrated adequate decommissioning funding assurance as of December 31, 2019, for all of its 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 ratepayers, and the ability to adjust those collections in accordance with the approved PAPUC tariff. No additional actions are required aside from the PAPUC filing in accordance with the tariff. Generation will file its next decommissioning funding status report with the NRC by March 31, 2021. This report will reflect the status of decommissioning funding assurance as of December 31, 2020 and will include the 2021 early retirements of Byron and Dresden. A shortfall could require Exelon to post parental guarantee for Generation’s share of the funding assurance. However, the amount of any required guarantee will ultimately depend on the decommissioning approach adopted at Byron and Dresden, the associated level of costs, and the decommissioning trust fund investment performance going forward. As the future values of trust funds change due to market conditions, the NRC minimum funding status of Generation’s 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. Non-Nuclear Asset Retirement Obligations (All Registrants) Generation has AROs for plant closure costs associated with its fossil 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. The Utility Registrants have AROs primarily associated with the abatement and disposal of equipment and buildings contaminated with asbestos and PCBs. See Note 1 — Significant Accounting Policies for additional information on the Registrants’ accounting policy for AROs. The following table provides a rollforward of the non-nuclear AROs reflected in the Registrants’ Consolidated Balance Sheets from January 1, 2019 to December 31, 2020: Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE Non-nuclear AROs at January 1, 2019 $ 471 $ 238 $ 121 $ 28 $ 25 $ 52 $ 37 $ 11 $ 4 Net increase (decrease) due to changes in, and timing of, estimated future cash flows 17 7 8 — (2) 4 3 1 — Development projects 2 2 — — — — — — — Accretion expense (a) 16 12 1 1 1 1 1 — — Asset divestitures (42) (42) — — — — — — — Payments (4) (1) (1) (1) (1) — — — — Non-nuclear AROs at December 31, 2019 460 216 129 28 23 57 41 12 4 Net increase (decrease) due to changes in, and timing of, estimated future cash flows 7 2 — 2 1 1 (3) 2 2 Development projects 1 1 — — — — — — — Accretion expense (a) 16 11 1 1 1 1 1 — — Asset divestitures (4) (4) — — — — — — — Payments (9) (4) (1) (2) (2) — — — — AROs reclassified to liabilities held for sale (b) (10) (10) — — — — — — — Non-nuclear AROs at December 31, 2020 $ 461 $ 212 $ 129 $ 29 $ 23 $ 59 $ 39 $ 14 $ 6 __________ (a) For ComEd, PECO, BGE, PHI, Pepco, and DPL, the majority of the accretion is recorded as an increase to a regulatory asset due to the associated regulatory treatment. (b) Represents AROs related to Generation's solar business, which were classified as held for sale as a result of the sale agreement. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information.

Leases (All Registrants)

Leases (All Registrants)	12 Months Ended
Leases (All Registrants)	Dec. 31, 2020
Leases [Abstract]
Leases of Lessee Disclosure [Text Block]	Lessee The Registrants have operating and finance leases for which they are the lessees. The following tables outline the significant types of leases at each registrant and other terms and conditions of the lease agreements as of December 31, 2020. Exelon, Generation, ComEd, PECO, and BGE did not have material finance leases in 2020 or in 2019. PHI, Pepco, DPL, and ACE also did not have material finance leases in 2019. Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE Contracted generation ● ● Real estate ● ● ● ● ● ● ● ● ● Vehicles and equipment ● ● ● ● ● ● ● ● ● (in years) Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE Remaining lease terms 1-85 1-35 1-4 1-13 1-85 1-11 1-11 1-11 1-7 Options to extend the term 2-30 2-30 5 N/A N/A 3-30 5 3-30 5 Options to terminate within 1-12 1-4 2 N/A 1 N/A N/A N/A N/A The components of operating lease costs were as follows: Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE For the year ended December 31, 2020 Operating lease costs $ 292 $ 194 $ 3 $ 1 $ 33 $ 46 $ 11 $ 13 $ 6 Variable lease costs 241 234 1 — 1 2 1 1 — Short-term lease costs 2 2 — — — — — — — Total lease costs (a) $ 535 $ 430 $ 4 $ 1 $ 34 $ 48 $ 12 $ 14 $ 6 For the year ended December 31, 2019 Operating lease costs $ 320 $ 222 $ 3 $ 1 $ 33 $ 48 $ 12 $ 14 $ 7 Variable lease costs 300 282 2 — 2 6 2 2 1 Short-term lease costs 19 19 — — — — — — — Total lease costs (a) $ 639 $ 523 $ 5 $ 1 $ 35 $ 54 $ 14 $ 16 $ 8 __________ (a) Excludes $48 million, $44 million, $4 million, and $4 million of sublease income recorded at Exelon, Generation, PHI, and DPL, respectively, for the year ended December 31, 2020 and $51 million, $44 million, $7 million, and $7 million of sublease income recorded at Exelon, Generation, PHI, and DPL, respectively, for the year ended December 31, 2019. PHI, Pepco, DPL, and ACE recorded finance lease costs of $9 million, $3 million, $4 million, and $2 million, respectively, for the year ended December 31, 2020. The following table presents the Registrants' rental expense under the prior lease accounting guidance for the year ended December 31, 2018: Exelon Generation (a) ComEd PECO BGE PHI Pepco DPL ACE Rent expense $ 670 $ 558 $ 7 $ 10 $ 35 $ 48 $ 10 $ 13 $ 8 __________ (a) Includes contingent operating lease payments associated with contracted generation agreements that are not included in the minimum future operating lease payments table. Payments made under Generation's contracted generation lease agreements totaled $493 million. The following tables provide additional information regarding the presentation of operating and finance lease ROU assets and lease liabilities within the Registrants’ Consolidated Balance Sheets: Operating Leases Exelon (a) Generation (a) ComEd PECO BGE PHI Pepco DPL ACE As of December 31, 2020 Operating lease ROU assets Other deferred debits and other assets $ 1,064 $ 726 $ 7 $ 1 $ 46 $ 241 $ 49 $ 54 $ 15 Operating lease liabilities Other current liabilities 213 132 3 — 45 31 6 9 4 Other deferred credits and other liabilities 1,089 775 5 1 19 224 46 56 11 Total operating lease liabilities $ 1,302 $ 907 $ 8 $ 1 $ 64 $ 255 $ 52 $ 65 $ 15 As of December 31, 2019 Operating lease ROU assets Other deferred debits and other assets $ 1,305 $ 895 $ 9 $ 2 $ 77 $ 273 $ 56 $ 63 $ 18 Operating lease liabilities Other current liabilities 225 157 3 — 32 31 6 9 4 Other deferred credits and other liabilities 1,307 925 8 1 50 254 51 65 14 Total operating lease liabilities $ 1,532 $ 1,082 $ 11 $ 1 $ 82 $ 285 $ 57 $ 74 $ 18 __________ (a) Exelon's and Generation's operating ROU assets and lease liabilities include $387 million and $528 million, respectively, related to contracted generation as of December 31, 2020, and $515 million and $664 million, respectively, as of December 31, 2019. Finance Leases PHI Pepco DPL ACE As of December 31, 2020 Finance lease ROU assets Plant, property and equipment, net $ 50 $ 17 $ 20 $ 13 Finance lease liabilities Long-term debt due within one year 7 2 3 2 Long-term debt 43 15 17 11 Total finance lease liabilities $ 50 $ 17 $ 20 $ 13 The weighted average remaining lease terms, in years, for operating and finance leases were as follows: Operating Leases Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE As of December 31, 2020 10.1 10.5 3.8 4.2 8.3 8.2 9.1 9.1 4.0 As of December 31, 2019 10.1 10.6 4.6 4.4 5.4 9.0 9.8 9.7 4.7 Finance Leases PHI Pepco DPL ACE As of December 31, 2020 6.5 6.3 6.5 6.5 The weighted average discount rates for operating and finance leases were as follows: Operating Leases Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE As of December 31, 2020 4.7 % 4.9 % 3.0 % 2.9 % 3.8 % 4.2 % 4.0 % 4.0 % 3.5 % As of December 31, 2019 4.6 % 4.8 % 3.0 % 3.2 % 3.6 % 4.2 % 4.0 % 4.0 % 3.6 % Finance Leases PHI Pepco DPL ACE As of December 31, 2020 2.5 % 2.6 % 2.4 % 2.4 % Future minimum lease payments for operating and finance leases as of December 31, 2020 were as follows: Operating Leases Year Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE 2021 $ 239 $ 145 $ 3 $ 1 $ 46 $ 40 $ 8 $ 11 $ 5 2022 177 113 2 — 16 39 8 10 4 2023 146 100 1 — 1 38 7 9 3 2024 141 98 1 — — 36 6 8 2 2025 140 99 1 — — 33 6 7 2 Remaining years 834 640 — — 18 120 28 35 — Total 1,677 1,195 8 1 81 306 63 80 16 Interest 375 288 — — 17 51 11 15 1 Total operating lease liabilities $ 1,302 $ 907 $ 8 $ 1 $ 64 $ 255 $ 52 $ 65 $ 15 Finance Leases Year PHI Pepco DPL ACE 2021 $ 8 $ 3 $ 3 $ 2 2022 8 3 3 2 2023 8 3 3 2 2024 8 3 3 2 2025 8 3 3 2 Remaining years 13 3 6 4 Total 53 18 21 14 Interest 3 1 1 1 Total finance lease liabilities $ 50 $ 17 $ 20 $ 13 Cash paid for amounts included in the measurement of operating and finance lease liabilities were as follows: Operating cash flows from operating leases Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE For the year ended December 31, 2020 $ 271 $ 204 $ 3 $ 1 $ 20 $ 39 $ 8 $ 9 $ 4 For the year ended December 31, 2019 287 206 3 — 33 37 9 6 5 Financing cash flows from finance leases PHI Pepco DPL ACE For the year ended December 31, 2020 $ 6 $ 2 $ 3 $ 1 ROU assets obtained in exchange for operating and finance lease obligations were as follows: Operating Leases Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE For the year ended December 31, 2020 $ 1 $ 3 $ — $ 1 $ — $ (1) $ — $ (1) $ — For the year ended December 31, 2019 52 14 6 — 2 (3) (1) (2) (1) Finance Leases PHI Pepco DPL ACE For the year ended December 31, 2020 $ 29 $ 8 $ 14 $ 7
Leases of Lessor Disclosure [Text Block]	Lessor The Registrants have operating leases for which they are the lessors. The following tables outline the significant types of leases at each registrant and other terms and conditions of their lease agreements as of December 31, 2020. Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE Contracted generation ● ● Real estate ● ● ● ● ● ● ● ● ● (in years) Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE Remaining lease terms 1-82 1-31 1-16 1-82 22 1-12 1-5 11-12 1 Options to extend the term 1-79 1-5 5-79 5-50 N/A 5 N/A N/A N/A The components of lease income were as follows: Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE For the year ended December 31, 2020 Operating lease income $ 52 $ 47 $ — $ — $ — $ 3 $ — $ 3 $ — Variable lease income 283 282 — — — 1 — 1 — For the year ended December 31, 2019 Operating lease income $ 54 $ 47 $ — $ — $ — $ 5 $ — $ 4 $ — Variable lease income 261 258 — — — 3 — 3 — Future minimum lease payments to be recovered under operating leases as of December 31, 2020 were as follows: Year Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE 2021 $ 51 $ 45 $ — $ — $ — $ 4 $ 1 $ 3 $ — 2022 50 45 — — — 4 — 3 — 2023 49 45 — — — 4 — 4 — 2024 49 45 — — — 3 — 3 — 2025 48 45 — — — 4 — 4 — Remaining years 217 182 1 4 1 31 — 31 — Total $ 464 $ 407 $ 1 $ 4 $ 1 $ 50 $ 1 $ 48 $ —

Asset Impairments (Exelon and G

Asset Impairments (Exelon and Generation)	12 Months Ended
Asset Impairments (Exelon and Generation)	Dec. 31, 2020
Impairment or Disposal of Tangible Assets Disclosure [Abstract]
Asset Impairments (Exelon and Generation)	Asset Impairments (Exelon and Generation) The Registrants 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, specific regulatory disallowance, or plans to dispose of a long-lived asset significantly before the end of its useful life. The Registrants determine if long-lived assets or asset groups are impaired by comparing the undiscounted expected future cash flows to the carrying value. When the undiscounted cash flow analysis indicates a long-lived asset or asset group is not 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 the Registrant's long-lived assets. Antelope Valley Solar Facility Generation’s Antelope Valley, a 242 MW solar facility in Lancaster, CA, sells all of its output to PG&E through a PPA. As a result of the PG&E bankruptcy filing in the first quarter of 2019, Generation completed a comprehensive review of Antelope Valley's estimated undiscounted future cash flows and no impairment charge was recorded. The United States Bankruptcy Court entered an order on June 20, 2020 confirming PG&E’s plan of reorganization. On July 1, 2020 the plan became effective, and PG&E emerged from bankruptcy. Under the confirmed plan, PG&E will continue to honor the existing PPA agreement with Antelope Valley. See Note 17 - Debt and Credit Agreements for additional informatio n. New England Asset Group During the first quarter of 2018, Mystic Unit 9 did not clear in the ISO-NE capacity auction for the 2021 - 2022 planning year. On March 29, 2018, Generation notified grid operator ISO-NE of its plans to early retire its Mystic Units 8 and 9 absent regulatory reforms on June 1, 2022. These events suggested that the carrying value of the New England asset group may be impaired. In the first quarter of 2018, Generation completed a comprehensive review of the estimated undiscounted future cash flows of the New England asset group and no impairment charge was required. In the third quarter of 2020, in conjunction with the retirement announcement of Mystic Units 8 and 9, Generation 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 within Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. See Note 7 - Early Plant Retirements for additional information. Midwest Asset Group In the third quarter of 2020, in conjunction with the retirement announcements of the Byron and Dresden nuclear plants, Generation completed a comprehensive review of the estimated undiscounted future cash flows of the Midwest asset group and no impairment charge was required. Generation will continue to monitor the recoverability of the carrying value of the Midwest asset group as certain other nuclear plants in Illinois are also showing increased signs of economic distress, which could lead to an early retirement. See Note 7 - Early Plant Retirements for additional information. Equity Method Investments in Certain Distributed Energy Companies In the third quarter of 2019, Generation’s equity method investments in certain distributed energy companies were fully impaired due to an other-than-temporary decline in market conditions and underperforming projects.

Intangible Assets (Exelon, Gene

Intangible Assets (Exelon, Generation, ComEd, PHI, Pepco, DPL, and ACE)	12 Months Ended
	Dec. 31, 2020
Goodwill and Intangible Assets Disclosure [Abstract]
Intangible Assets (All Registrants)	Intangible Assets (Exelon, Generation, ComEd, PHI, Pepco, DPL, and ACE) Goodwill The following table presents the gross amount, accumulated impairment loss, and carrying amount of goodwill at Exelon, ComEd, and PHI as of December 31, 2020 and 2019. There were no additions or impairments during the years ended December 31, 2020 and 2019. Gross Amount Accumulated Impairment Loss Carrying Amount Exelon $ 8,660 $ 1,983 $ 6,677 ComEd (a) 4,608 1,983 2,625 PHI (b) 4,005 — 4,005 __________ (a) Reflects goodwill recorded in 2000 from the PECO/Unicom merger (predecessor parent company of ComEd). (b) Reflects goodwill recorded in 2016 from the PHI merger. Goodwill is not amortized, but is subject to an assessment for impairment at least annually, or more frequently if events occur or circumstances change that would more likely than not reduce the fair value of ComEd's and PHI's reporting units below their carrying amounts. A reporting unit is an operating segment or one level below an operating segment (known as a component) and is the level at which goodwill is assessed for impairment. A component of an operating segment is a reporting unit if the component constitutes a business for which discrete financial information is available and its operating results are regularly reviewed by segment management. ComEd has a single operating segment. PHI's operating segments are Pepco, DPL, and ACE. See Note 5 — Segment Information for additional information. There is no level below these operating segments for which operating results are regularly reviewed by segment management. Therefore, the ComEd, Pepco, DPL, and ACE operating segments are also considered reporting units for goodwill impairment assessment purposes. Exelon's and ComEd's $2.6 billion of goodwill has been assigned entirely to the ComEd reporting unit, while Exelon's and PHI's $4.0 billion of goodwill has been assigned to the Pepco, DPL, and ACE reporting units in the amounts of $2.1 billion, $1.4 billion, and $0.5 billion, respectively. Entities assessing goodwill for impairment have the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary. As part of the qualitative assessments, Exelon, ComEd, and PHI evaluate, among other things, management's best estimate of projected operating and capital cash flows for their businesses, outcomes of recent regulatory proceedings, changes in certain market conditions, including the discount rate and regulated utility peer EBITDA multiples, and the passing margin from their last quantitative assessments performed. If an entity bypasses the qualitative assessment, a quantitative, fair value-based assessment is performed, which compares the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, the entity recognizes an impairment charge, which is limited to the amount of goodwill allocated to the reporting unit. Application of the goodwill impairment assessment requires management judgment, including the identification of reporting units and determining the fair value of the reporting unit, which management estimates using a weighted combination of a discounted cash flow analysis and a market multiples analysis. Significant assumptions used in these fair value analyses include discount and growth rates, utility sector market performance and transactions, projected operating and capital cash flows for ComEd's, Pepco's, DPL's, and ACE's businesses, and the fair value of debt. 2020 and 2019 Goodwill Impairment Assessment. ComEd and PHI qualitatively determined that it was more likely than not that the fair values of their reporting units exceeded their carrying values and, therefore, did not perform quantitative assessments as of November 1, 2020 and 2019 for ComEd and PHI. The last quantitative assessments performed were as of November 1, 2016 for ComEd and November 1, 2018 for PHI. While the annual assessments indicated no impairments, certain assumptions used to estimate reporting unit fair values are highly sensitive to changes. Adverse regulatory actions or changes in significant assumptions could potentially result in future impairments of Exelon's, ComEd's, and PHI’s goodwill, which could be material. Other Intangible Assets and Liabilities Exelon’s, Generation’s, ComEd’s, and PHI's other intangible assets and liabilities, included in Unamortized energy contract assets and liabilities and Other deferred debits and other assets in their Consolidated Balance Sheets, consisted of the following as of December 31, 2020 and 2019. The intangible assets and liabilities shown below are 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, 2020 December 31, 2019 Gross Accumulated Amortization Net Gross Accumulated Amortization Net Generation Unamortized Energy Contracts $ 1,963 $ (1,642) $ 321 $ 1,967 $ (1,612) $ 355 Customer Relationships 326 (215) 111 343 (190) 153 Trade Name 222 (197) 25 243 (193) 50 ComEd Chicago Settlement Agreements 162 (162) — 162 (155) 7 PHI Unamortized Energy Contracts (1,515) 1,188 (327) (1,515) 1,073 (442) Exelon Corporate Software License 95 (53) 42 95 (44) 51 Exelon $ 1,253 $ (1,081) $ 172 $ 1,295 $ (1,121) $ 174 The following table summarizes the amortization expense related to intangible assets and liabilities for each of the years ended December 31, 2020, 2019, and 2018: For the Years Ended December 31, Exelon (a)(b) Generation (a) ComEd PHI (b) 2020 $ (17) $ 81 $ 7 $ (115) 2019 (28) 74 7 (119) 2018 (109) 63 7 (188) __________ (a) At Exelon and Generation, amortization of unamortized energy contracts totaling $30 million, $21 million, and $14 million for the years ended December 31, 2020, 2019, and 2018, respectively, was recorded in Operating revenues or Purchased power and fuel expense in their Consolidated Statements of Operations and Comprehensive Income. (b) At Exelon and PHI, amortization of the unamortized energy contract fair value adjustment amounts and the corresponding offsetting regulatory asset and liability amounts are amortized through Purchased power and fuel expense in their Consolidated Statements of Operations and Comprehensive Income. The following table summarizes the estimated future amortization expense related to intangible assets and liabilities as of December 31, 2020: For the Years Ending December 31, Exelon Generation PHI 2021 $ (1) $ 81 $ (92) 2022 (22) 57 (89) 2023 (20) 51 (81) 2024 20 48 (38) 2025 40 41 (5) Renewable Energy Credits (Exelon and Generation) Exelon’s and Generation’s RECs are included in Other current assets and Other deferred debits and other assets 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 the current and noncurrent RECs as of December 31, 2020 and 2019: As of December 31, 2020 As of December 31, 2019 Exelon Generation Exelon Generation Current REC's $ 632 $ 621 $ 345 $ 336 Noncurrent REC's — — 86 86

Income Taxes (All Registrants)

Income Taxes (All Registrants)	12 Months Ended
Income Taxes (All Registrants)	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Income Taxes (All Registrants)	Income Taxes (All Registrants) Components of Income Tax Expense or Benefit Income tax expense (benefit) from continuing operations is comprised of the following components: For the Year Ended December 31, 2020 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE Included in operations: Federal Current $ 26 $ 130 $ (24) $ (7) $ 4 $ 25 $ 40 $ (13) $ (4) Deferred 156 150 112 1 10 (129) (62) (20) (43) Investment tax credit amortization (28) (25) (2) — — (1) — — — State Current 42 40 (27) — — (5) — — — Deferred 177 (46) 118 (24) 27 33 15 8 6 Total $ 373 $ 249 $ 177 $ (30) $ 41 $ (77) $ (7) $ (25) $ (41) For the Year Ended December 31, 2019 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE Included in operations: Federal Current $ 85 $ 147 $ 59 $ 45 $ (51) $ 43 $ 16 $ 29 $ (3) Deferred 489 346 15 20 95 (34) (6) (21) (6) Investment tax credit amortization (72) (69) (2) — — (1) — — — State Current 5 10 (5) — — 3 — — — Deferred 267 82 96 — 35 27 6 14 9 Total $ 774 $ 516 $ 163 $ 65 $ 79 $ 38 $ 16 $ 22 $ — For the Year Ended December 31, 2018 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE Included in operations: Federal Current $ 226 $ 337 $ (63) $ 11 $ (5) $ (4) $ 28 $ (3) $ (14) Deferred (99) (347) 145 10 47 23 (22) 13 18 Investment tax credit amortization (24) (21) (2) — — (1) — — — State Current (1) 6 (29) 1 — 7 — — — Deferred 16 (83) 117 (16) 32 8 5 12 8 Total $ 118 $ (108) $ 168 $ 6 $ 74 $ 33 $ 11 $ 22 $ 12 Rate Reconciliation The effective income tax rate from continuing operations varies from the U.S. federal statutory rate principally due to the following: For the Year Ended December 31, 2020 (a) Exelon Generation ComEd (b) PECO (c) BGE (d) PHI (d) Pepco (d) DPL (d) ACE (d) U.S. federal statutory rate 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % Increase (decrease) due to: State income taxes, net of Federal income tax benefit 7.8 0.5 11.6 (4.5) 5.5 5.1 4.5 6.6 7.0 Qualified NDT fund income 8.4 23.5 — — — — — — — Deferred Prosecution Agreement payments 1.8 — 6.8 — — — — — — Amortization of investment tax credit, including deferred taxes on basis difference (1.1) (2.6) (0.3) — (0.1) (0.2) (0.1) (0.3) (0.5) Plant basis differences (4.0) — (0.6) (18.7) (1.5) (1.6) (1.7) (0.4) (3.0) Production tax credits and other credits (2.2) (5.4) (0.3) — (0.4) (0.3) (0.3) (0.3) (0.5) Noncontrolling interests 1.1 3.2 — — — — — — — Excess deferred tax amortization (13.6) — (11.2) (4.6) (13.9) (42.0) (25.4) (51.7) (82.1) Tax settlements (3.7) (10.3) — — — — — — — Other 0.5 (0.1) 1.8 (0.4) (0.1) (0.4) (0.7) 0.1 0.4 Effective income tax rate 16.0 % 29.8 % 28.8 % (7.2) % 10.5 % (18.4) % (2.7) % (25.0) % (57.7) % For the Year Ended December 31, 2019 (a) Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE U.S. federal statutory rate 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % Increase (decrease) due to: State income taxes, net of Federal income tax benefit 5.4 3.8 8.5 — 6.4 4.7 2.0 6.8 7.0 Qualified NDT fund income 5.9 12.3 — — — — — — — Amortization of investment tax credit, including deferred taxes on basis difference (1.5) (3.0) (0.2) — (0.1) (0.2) (0.1) (0.2) (0.3) Plant basis differences (1.4) — — (7.2) (1.2) (1.2) (1.8) (0.4) (0.7) Production tax credits and other credits (3.1) (4.8) (1.2) — (1.3) (0.2) (0.1) — (0.1) Noncontrolling interests (0.6) (1.2) — — — — — — — Excess deferred tax amortization (5.5) — (9.7) (2.8) (6.8) (17.5) (15.1) (14.2) (27.0) Other (0.8) (1.2) 0.8 — — 0.8 0.3 — 0.1 Effective income tax rate 19.4 % 26.9 % 19.2 % 11.0 % 18.0 % 7.4 % 6.2 % 13.0 % — % For the Year Ended December 31, 2018 (a) Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE U.S. federal statutory rate 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % Increase (decrease) due to: State income taxes, net of Federal income tax benefit 0.5 (16.6) 8.3 (2.6) 6.6 2.9 2.0 6.7 7.4 Qualified NDT fund income (1.9) (11.8) — — — — — — — Amortization of investment tax credit, including deferred taxes on basis difference (1.2) (6.5) (0.2) (0.1) (0.1) (0.2) (0.1) (0.3) (0.4) Plant basis differences (3.5) — (0.2) (14.1) (1.3) (1.6) (2.8) (0.3) (0.5) Production tax credits and other credits (2.2) (13.5) — — — — — — — Noncontrolling interests (1.0) (6.1) — — — — — — — Excess deferred tax amortization (8.3) — (9.1) (3.2) (8.0) (14.8) (15.3) (12.0) (14.9) Tax Cuts and Jobs Act of 2017 0.9 2.7 (0.1) — — 0.1 — — — Other 1.0 1.3 0.5 0.3 0.9 0.4 0.3 0.4 1.2 Effective income tax rate 5.3 % (29.5) % 20.2 % 1.3 % 19.1 % 7.8 % 5.1 % 15.5 % 13.8 % __________ (a) Positive percentages represent income tax expense. Negative percentages represent income tax benefit. (b) At ComEd, the higher effective tax rate is primarily related to the nondeductible Deferred Prosecution Agreement payments. See Note 19 — Commitments and Contingencies for additional information. (c) At PECO, the negative effective tax rate is primarily related to an increase in plant basis differences attributable to tax repair deductions related to an increase in storms and qualifying projects. (d) At BGE, the lower effective tax rate, and at PHI, Pepco, DPL, and ACE, the negative effective tax rate is primarily attributable to accelerated amortization of transmission related income tax regulatory liabilities as a result of regulatory settlements. See Note 3 — Regulatory Matters for additional information. Tax Differences and Carryforwards The tax effects of temporary differences and carryforwards, which give rise to significant portions of the deferred tax assets (liabilities), as of December 31, 2020 and 2019 are presented below: As of December 31, 2020 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE Plant basis differences $ (13,868) $ (2,592) $ (4,432) $ (2,131) $ (1,711) $ (2,822) $ (1,259) $ (806) $ (725) Accrual based contracts 40 (37) — — — 77 — — — Derivatives and other financial instruments 41 (41) 84 — — 2 — — — Deferred pension and postretirement obligation 1,559 (236) (288) (30) (33) (80) (74) (40) (7) Nuclear decommissioning activities (742) (742) — — — — — — — Deferred debt refinancing costs 169 16 (6) — (2) 131 (3) (1) (1) Regulatory assets and liabilities (1,107) — 87 (231) 142 (41) 38 67 46 Tax loss carryforward 286 55 — 47 57 90 4 49 38 Tax credit carryforward 841 838 — — — — — — — Investment in partnerships (835) (813) — — — — — — — Other, net 1,070 347 223 104 29 220 107 18 27 Deferred income tax liabilities (net) $ (12,546) $ (3,205) $ (4,332) $ (2,241) $ (1,518) $ (2,423) $ (1,187) $ (713) $ (622) Unamortized investment tax credits (a) (464) (445) (9) (1) (3) (6) (2) (2) (3) Total deferred income tax liabilities (net) and unamortized investment tax credits $ (13,010) $ (3,650) $ (4,341) $ (2,242) $ (1,521) $ (2,429) $ (1,189) $ (715) $ (625) __________ (a) Does not include unamortized investment tax credits reclassified to liabilities held for sale. As of December 31, 2019 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE Plant basis differences $ (13,413) $ (2,814) $ (4,197) $ (1,978) $ (1,578) $ (2,681) $ (1,204) $ (753) $ (687) Accrual based contracts 61 (43) — — — 104 — — — Derivatives and other financial instruments 165 88 84 — — 2 — — — Deferred pension and postretirement obligation 1,504 (220) (270) (28) (28) (89) (75) (42) (10) Nuclear decommissioning activities (503) (503) — — — — — — — Deferred debt refinancing costs 183 20 (7) — (3) 142 (3) (2) (1) Regulatory assets and liabilities (884) — 183 (169) 157 (10) 55 88 77 Tax loss carryforward 240 55 — 25 49 93 13 44 31 Tax credit carryforward 892 897 — — — — — — — Investment in partnerships (830) (808) — — — — — — — Other, net 926 236 196 70 10 181 85 12 16 Deferred income tax liabilities (net) $ (11,659) $ (3,092) $ (4,011) $ (2,080) $ (1,393) $ (2,258) $ (1,129) $ (653) $ (574) Unamortized investment tax credits (668) (648) (10) (1) (3) (7) (2) (2) (3) Total deferred income tax liabilities (net) and $ (12,327) $ (3,740) $ (4,021) $ (2,081) $ (1,396) $ (2,265) $ (1,131) $ (655) $ (577) The following table provides Exelon’s, Generation’s, PECO’s, BGE’s, PHI’s, Pepco’s, DPL’s, and ACE’s carryforwards, which are presented on a post-apportioned basis, and any corresponding valuation allowances as of December 31, 2020. ComEd does not have net operating losses or credit carryforwards for the year ended December 31, 2020. Exelon Generation PECO BGE PHI Pepco DPL ACE Federal Federal general business credits carryforwards and other carryforwards $ 858 $ 852 $ — $ — $ — $ — $ — $ — State State net operating losses and other carryforwards 5,202 1,118 616 902 1,436 63 728 531 Deferred taxes on state tax attributes (net) 324 76 49 59 98 4 49 38 Valuation allowance on state tax attributes 27 23 1 — — — — — Year in which net operating loss or credit carryforwards will begin to expire (a) 2034 2034 2032 2033 2029 2029 2032 2031 __________ (a) Generation's state net operating loss carryforwards will begin expiring in 2029. PECO's Pennsylvania charitable contribution carryforwards and BGE's Maryland charitable deduction and capital loss carryforwards will begin expiring in 2021. ACE's New Jersey tax credit carryforward has an indefinite carryforward period. These amounts are not material. Tabular Reconciliation of Unrecognized Tax Benefits The following table presents changes in unrecognized tax benefits, by Registrant. Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE Balance at January 1, 2018 $ 743 $ 468 $ 2 $ — $ 120 $ 125 $ 59 $ 21 $ 14 Change to positions that only affect timing 15 15 — — — — — — — Increases based on tax positions prior to 2018 30 21 — — — 8 7 1 — Decreases based on tax positions prior to 2018 (a) (251) (36) — — (120) (88) (66) (22) — Decrease from settlements with taxing authorities (53) (53) — — — — — — — Decreases from expiration of statute of limitations (7) (7) — — — — — — — Balance at December 31, 2018 477 408 2 — — 45 — — 14 Change to positions that only affect timing 26 12 3 1 4 3 2 1 — Increases based on tax positions related to 2019 2 1 — — — — — — — Increases based on tax positions prior to 2019 34 19 3 2 3 — — — — Decreases based on tax positions prior to 2019 (3) (3) — — — — — — — Decrease from settlements with taxing authorities (29) 4 (2) — — — — — — Balance at December 31, 2019 507 441 6 3 7 48 2 1 14 Change to positions that only affect timing 6 — 2 3 3 3 1 — 1 Increases based on tax positions related to 2020 3 1 — — — — — — — Increases based on tax positions prior to 2020 26 23 1 — — 1 — — — Decreases based on tax positions prior to 2020 (b) (348) (346) — — — — — — — Decrease from settlements with taxing authorities (b) (69) (69) — — — — — — — Balance at December 31, 2020 $ 125 $ 50 $ 9 $ 6 $ 10 $ 52 $ 3 $ 1 $ 15 __________ (a) Exelon, Generation, BGE, PHI, Pepco, and DPL decreased their unrecognized state tax benefits primarily due to the receipt of favorable guidance with respect to the deductibility of certain depreciable fixed assets. The recognition of the tax benefits related to BGE, PHI, Pepco, and DPL was offset by corresponding regulatory liabilities and that portion had no immediate impact to their effective tax rate. (b) Exelon's and Generation's 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 to Exelon's and Generation’s net income of $76 million and $73 million, respectively, in the first quarter of 2020, reflecting a decrease to Exelon's and Generation's income tax expense of $67 million. Like-Kind Exchange In 2016, the Tax Court held that Exelon was not entitled to defer a gain on its 1999 like-kind exchange transaction. In addition to the tax and interest related to the gain deferral, the Tax Court also ruled that Exelon was liable for penalties and interest on the penalties. Exelon had fully paid the amounts assessed resulting from the Tax Court decision in 2017. In September 2017, Exelon appealed the Tax Court decision to the U.S. Court of Appeals for the Seventh Circuit. In October 2018, the U.S. Court of Appeals for the Seventh Circuit affirmed the Tax Court’s decision. Exelon filed a petition seeking rehearing of the Seventh Circuit’s decision, but the Seventh Circuit denied that petition in December 2018. In the first quarter of 2019, Exelon elected not to seek a further review by the U.S. Supreme Court. As a result, Exelon's and ComEd's unrecognized tax benefits decreased by approximately $33 million and $2 million, respectively, in the first quarter of 2019. Recognition of unrecognized tax benefits The following table presents Exelon's, Generation's, and PHI's unrecognized tax benefits that, if recognized, would decrease the effe ctive tax rate. ComEd's, PECO's, BGE's, Pepco's, DPL's, and ACE's amounts are not material. Exelon Generation PHI (a) December 31, 2020 $ 73 $ 39 $ 33 December 31, 2019 462 429 32 December 31, 2018 463 408 31 __________ (a) PHI has $ 21 million of unrecognized state tax benefits that, if recognized, $ 14 million would be in the form of a net operating loss carryforward, which is expected to require a full valuation allowance based on present circumstances. ACE has $14 million of unrecognized tax benefits as of December 31, 2020, 2019 and 2018 that, if recognized, may be included in future base rates and that portion would have no impact on the effective tax rate. Exelon's, Generation's, ComEd's, PECO's, BGE's, PHI's, Pepco's, and DPL's amounts are not material. Reasonably possible the total amount of unrecognized tax benefits could significantly increase or decrease within 12 months after the reporting date As of December 31, 2020, ACE has approximately $14 million of unrecognized state tax benefits that could significantly decrease within the 12 months after the reporting date based on the outcome of pending court cases involving other taxpayers. The unrecognized tax benefit, if recognized, may be included in future base rates and that portion would have no impact to the effective tax rate. Total amounts of interest and penalties recognized The following table represents the net interest and penalties receivable (payable) related to tax positions reflected in Exelon's Consolidated Balance Sheets. Generation's and the Utility Registrants' amounts are not material. Net interest and penalties receivable as of Exelon December 31, 2020 $ 314 December 31, 2019 318 The Registrants did not record material interest and penalty expense related to tax positions reflected in their Consolidated Balance Sheets. Interest expense and penalty expense are recorded in Interest expense, net and Other, net, respect ively, in Other income and deductions in the Registrants' Consolidated Statements of Operations and Comprehensive Income. Description of tax years open to assessment by major jurisdiction Major Jurisdiction Open Years Registrants Impacted Federal consolidated income tax returns (a) 2010-2019 All Registrants Delaware separate corporate income tax returns Same as federal DPL District of Columbia combined corporate income tax returns 2017-2019 Exelon, PHI, Pepco Illinois unitary corporate income tax returns 2012-2019 Exelon, Generation, ComEd Maryland separate company corporate net income tax returns Same as federal BGE, Pepco, DPL New Jersey separate corporate income tax returns 2013-2019 Exelon, Generation New Jersey separate corporate income tax returns 2014-2019 ACE New York combined corporate income tax returns 2010-March 2012 Exelon, Generation New York combined corporate income tax returns 2011-2019 Exelon, Generation Pennsylvania separate corporate income tax returns 2011-2019 Exelon, Generation Pennsylvania separate corporate income tax returns 2017-2019 PECO __________ (a) Certain registrants are only open to assessment for tax years since joining the Exelon federal consolidated group; BGE beginning in 2012 and PHI, Pepco, DPL, and ACE beginning in 2016. Other Tax Matters Long-Term Marginal State Income Tax Rate (All Registrants) Quarterly, Exelon reviews and updates its marginal state income tax rates for changes in state apportionment. The Registrants remeasure their existing deferred income tax balances to reflect the changes in marginal rates, which results in either an increase or a decrease to their net deferred income tax liability balances. Utility Registrants record corresponding regulatory liabilities or assets to the extent such amounts are probable of settlement or recovery through customer rates and an adjustment to income tax expense for all other amounts. The impacts to the Utility Registrants for the years ended December 31, 2020, 2019, and 2018 were not material. December 31, 2020 Exelon Generation Increase (decrease) to Deferred Income Tax Liability and Income Tax Expense, Net of Federal Taxes $ 66 $ (26) December 31, 2019 Increase to Deferred Income Tax Liability and Income Tax Expense, Net of Federal Taxes $ 23 $ 9 December 31, 2018 Decrease to Deferred Income Tax Liability and Income Tax Expense, Net of Federal Taxes $ (50) $ (53) Allocation of Tax Benefits (All Registrants) Generation and the Utility Registrants are all party to an agreement with Exelon and other subsidiaries of Exelon that provides for the allocation of consolidated tax liabilities and benefits (Tax Sharing Agreement). The Tax Sharing Agreement provides that each party is 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 is reallocated to the other Registrants. That allocation is treated as a contribution to the capital of the party receiving the benefit. The following table presents the allocation of tax benefits from Exelon under the Tax Sharing Agreement. Generation ComEd PECO BGE PHI Pepco DPL ACE December 31, 2020 (a) $ 64 $ 14 $ 17 $ — $ 17 $ 8 $ 6 $ 1 December 31, 2019 (b) 41 — 14 3 7 6 1 — December 31, 2018 (c) 155 1 48 26 2 — — — __________ (a) BGE did not record an allocation of federal tax benefits from Exelon under the Tax Sharing Agreement as a result of a tax net operating loss. (b) ACE did not record an allocation of federal tax benefits from Exelon under the Tax Sharing Agreement as a result of a tax net operating loss. (c) Pepco, DPL, and ACE did not record an allocation of federal tax benefits from Exelon under the Tax Sharing Agreement as a result of a tax net operating loss. Research and Development Activities In the fourth quarter of 2019, Exelon and Generation recognized additional tax benefits related to certain research and development activities that qualify for federal and state tax incentives for the 2010 through 2018 tax years, which resulted in an increase to Exelon’s and Generation’s net income of $108 million and $75 million, respectively, for the year ended December 31, 2019, reflecting a decrease to Exelon’s and Generation’s Income tax expense of $97 million and $66 million, respectively.

Retirement Benefits (All Regist

Retirement Benefits (All Registrants)	12 Months Ended
Retirement Benefits (All Registrants)	Dec. 31, 2020
Retirement Benefits [Abstract]
Retirement Benefits (All Registrants)	Retirement Benefits (All Registrants) Exelon sponsors defined benefit pension plans and OPEB plans for essentially all current employees. Substantially all non-union employees and electing union employees hired on or after January 1, 2001 participate in cash balance pension plans. Effective January 1, 2009, substantially all newly-hired union-represented employees participate in cash balance pension plans. Effective February 1, 2018 for most newly-hired Generation and BSC non-represented, non-craft, employees and January 1, 2021 for most newly-hired utility management employees, these newly-hired employees are not eligible for pension benefits, and will instead be eligible to receive an enhanced non-discretionary employer contribution in an Exelon defined contribution savings plan. Effective January 1, 2018, most newly-hired non-represented, non-craft, employees are not eligible for OPEB benefits and employees represented by Local 614 are not eligible for retiree health care benefits. Effective January 1, 2021, most non-represented, non-craft, employees who are under the age of 40 are not eligible for retiree health care benefits. Effective January 1, 2019, Exelon merged the Exelon Corporation Cash Balance Pension Plan (CBPP) into the Exelon Corporation Retirement Program (ECRP). The merging of the plans did not change the benefits offered to the plan participants and, thus, had no impact on Exelon's pension obligation. However, beginning in 2019, actuarial losses and gains related to the CBPP and ECRP are amortized over participants’ average remaining service period of the merged ECRP rather than each individual plan. The table below shows the pension and OPEB plans in which employees of each operating company participated at December 31, 2020: Operating Company (e) Name of Plan: Generation ComEd PECO BGE PHI Pepco DPL ACE Qualified Pension Plans: Exelon Corporation Retirement Program (a) X X X X X X X X Exelon Corporation Pension Plan for Bargaining Unit Employees (a) X X Exelon New England Union Employees Pension Plan (a) X Exelon Employee Pension Plan for Clinton, TMI, and Oyster Creek (a) X X X X X X Pension Plan of Constellation Energy Group, Inc. (b) X X X X X X X Pension Plan of Constellation Energy Nuclear Group, LLC (c) X X X X X Nine Mile Point Pension Plan (c) X Constellation Mystic Power, LLC Union Employees Pension Plan Including Plan A and Plan B (b) X Pepco Holdings LLC Retirement Plan (d) X X X X X X X X Non-Qualified Pension Plans: Exelon Corporation Supplemental Pension Benefit Plan and 2000 Excess Benefit Plan (a) X X X X Exelon Corporation Supplemental Management Retirement Plan (a) X X X X X X X Constellation Energy Group, Inc. Senior Executive Supplemental Plan (b) X X X Constellation Energy Group, Inc. Supplemental Pension Plan (b) X X X Constellation Energy Group, Inc. Benefits Restoration Plan (b) X X X X Constellation Energy Nuclear Plan, LLC Executive Retirement Plan (c) X X Constellation Energy Nuclear Plan, LLC Benefits Restoration Plan (c) X X Baltimore Gas & Electric Company Executive Benefit Plan (b) X X Baltimore Gas & Electric Company Manager Benefit Plan (b) X X X Pepco Holdings LLC 2011 Supplemental Executive Retirement Plan (d) X X X X X Conectiv Supplemental Executive Retirement Plan (d) X X X X Pepco Holdings LLC Combined Executive Retirement Plan (d) X X Atlantic City Electric Director Retirement Plan (d) X Operating Company (e) Name of Plan: Generation ComEd PECO BGE PHI Pepco DPL ACE OPEB Plans: PECO Energy Company Retiree Medical Plan (a) X X X X X X X X Exelon Corporation Health Care Program (a) X X X X X X X Exelon Corporation Employees’ Life Insurance Plan (a) X X X X Exelon Corporation Health Reimbursement Arrangement Plan (a) X X X X Constellation Energy Group, Inc. Retiree Medical Plan (b) X X X X X X Constellation Energy Group, Inc. Retiree Dental Plan (b) X X Constellation Energy Group, Inc. Employee Life Insurance Plan and Family Life Insurance Plan (b) X X X X X X Constellation Mystic Power, LLC Post-Employment Medical Account Savings Plan (b) X X Exelon New England Union Post-Employment Medical Savings Account Plan (a) X Retiree Medical Plan of Constellation Energy Nuclear Group, LLC (c) X X X X Retiree Dental Plan of Constellation Energy Nuclear Group, LLC (c) X X X X Nine Mile Point Nuclear Station, LLC Medical Care and Prescription Drug Plan for Retired Employees (c) X Pepco Holdings LLC Welfare Plan for Retirees (d) X X X X X X X X __________ (a) These plans are collectively referred to as the legacy Exelon plans. (b) These plans are collectively referred to as the legacy Constellation Energy Group (CEG) Plans. (c) These plans are collectively referred to as the legacy CENG plans. (d) These plans are collectively referred to as the legacy PHI plans. (e) Employees generally remain in their legacy benefit plans when transferring between operating companies. Exelon’s traditional and cash balance pension plans are intended to be tax-qualified defined benefit plans. Exelon has elected that the trusts underlying these plans be treated as qualified trusts under the IRC. If certain conditions are met, Exelon can deduct payments made to the qualified trusts, subject to certain IRC limitations. Benefit Obligations, Plan Assets, and Funded Status During the first quarter of 2020, Exelon received an updated valuation of its pension and OPEB to reflect actual census data as of January 1, 2020. This valuation resulted in an increase to the pension and OPEB obligations of $8 million and $31 million, respectively. Additionally, accumulated other comprehensive loss increased by $7 million (after-tax) and regulatory assets and liabilities increased by $19 million and decreased by $10 million, respectively. The following tables provide a rollforward of the changes in the benefit obligations and plan assets of Exelon for the most recent two years for all plans combined: Pension Benefits OPEB 2020 2019 2020 2019 Change in benefit obligation: Net benefit obligation at beginning of year $ 22,868 $ 20,692 $ 4,658 $ 4,369 Service cost 387 357 90 93 Interest cost 757 883 154 188 Plan participants’ contributions — — 49 44 Actuarial loss (a) 2,217 2,322 49 250 Plan amendments — 68 (111) — Curtailments — (3) — — Settlements (45) (35) (5) (4) Contractual termination benefits — 1 — — Gross benefits paid (1,290) (1,417) (280) (282) Net benefit obligation at end of year $ 24,894 $ 22,868 $ 4,604 $ 4,658 Pension Benefits OPEB 2020 2019 2020 2019 Change in plan assets: Fair value of net plan assets at beginning of year $ 18,590 $ 16,678 $ 2,541 $ 2,408 Actual return on plan assets 2,547 3,008 190 324 Employer contributions 542 356 59 51 Plan participants’ contributions — — 49 44 Gross benefits paid (1,290) (1,417) (280) (282) Settlements (45) (35) (5) (4) Fair value of net plan assets at end of year $ 20,344 $ 18,590 $ 2,554 $ 2,541 __________ (a) The pension and OPEB actuarial losses in 2020 and 2019 primarily reflect a decrease in the discount rate. OPEB losses in 2020 were offset by gains related to plan changes. Exelon presents its benefit obligations and plan assets net on its balance sheet within the following line items: Pension Benefits OPEB 2020 2019 2020 2019 Other current liabilities $ 47 $ 31 $ 42 $ 41 Pension obligations 4,503 4,247 — — Non-pension postretirement benefit obligations — — 2,008 2,076 Unfunded status (net benefit obligation less plan assets) $ 4,550 $ 4,278 $ 2,050 $ 2,117 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 benefit obligations (PBO) and accumulated postretirement benefit obligation (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 Exelon 2020 2019 ABO $ 23,514 $ 21,727 Fair value of net plan assets 20,344 18,590 Components of Net Periodic Benefit Costs The majority of the 2020 pension benefit cost for the Exelon-sponsored plans is calculated using an expected long-term rate of return on plan assets of 7.00% and a discount rate of 3.34%. The majority of the 2020 OPEB cost is calculated using an expected long-term rate of return on plan assets of 6.69% for funded plans and a discount rate of 3.31%. A portion of the net periodic benefit cost for all plans is capitalized within the Consolidated Balance Sheets. The following table presents the components of Exelon’s net periodic benefit costs, prior to capitalization, for the years ended December 31, 2020, 2019, and 2018. Pension Benefits OPEB 2020 2019 2018 2020 2019 2018 Components of net periodic benefit cost: Service cost $ 387 $ 357 $ 405 $ 90 $ 93 $ 112 Interest cost 757 883 802 154 188 175 Expected return on assets (1,270) (1,225) (1,252) (163) (153) (173) Amortization of: Prior service cost (credit) 4 — 2 (124) (179) (186) Actuarial loss 512 414 629 49 45 66 Curtailment benefits — — — (1) — — Settlement and other charges 14 17 3 1 1 1 Contractual termination benefits — 1 — — — — Net periodic benefit cost $ 404 $ 447 $ 589 $ 6 $ (5) $ (5) Cost Allocation to Exelon Subsidiaries All Registrants account for their participation in Exelon’s pension and OPEB plans by applying multi-employer accounting. Exelon allocates costs related to its pension and OPEB plans to its subsidiaries based on both active and retired employee participation in each plan. The amounts below represent the Registrants' allocated pension and OPEB costs. For Exelon, the service cost component is included in Operating and maintenance expense and Property, plant, and equipment, net while the non-service cost components are included in Other, net and Regulatory assets. For Generation and the Utility Registrants, the service cost and non-service cost components are included in Operating and maintenance expense and Property, plant, and equipment, net in their consolidated financial statements. For the Years Ended December 31, Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE 2020 $ 411 $ 115 $ 114 $ 5 $ 64 $ 70 $ 15 $ 7 $ 14 2019 442 135 96 12 61 95 25 15 16 2018 583 204 177 18 60 67 15 6 12 Components of AOCI and Regulatory Assets Exelon recognizes the overfunded or underfunded status of defined benefit pension and OPEB plans as an asset or liability on its balance sheet, with offsetting entries to AOCI and regulatory assets (liabilities). A portion of current year actuarial (gains) losses and prior service costs (credits) is capitalized within Exelon’s Consolidated Balance Sheets to reflect the expected regulatory recovery of these amounts, which would otherwise be recorded to AOCI. The following tables provide the components of AOCI and regulatory assets (liabilities) for Exelon for the years ended December 31, 2020, 2019, and 2018 for all plans combined. Pension Benefits OPEB 2020 2019 2018 2020 2019 2018 Changes in plan assets and benefit obligations recognized in AOCI and regulatory assets (liabilities): Current year actuarial loss (gain) $ 941 $ 538 $ 635 $ 22 $ 80 $ (232) Amortization of actuarial loss (512) (414) (629) (49) (45) (66) Current year prior service cost (credit) — 68 (4) (111) — — Amortization of prior service (cost) credit (4) — (2) 124 179 186 Curtailments — (3) — 1 — — Settlements (14) (17) (3) (1) (1) — Total recognized in AOCI and regulatory assets (liabilities) $ 411 $ 172 $ (3) $ (14) $ 213 $ (112) Total recognized in AOCI $ 271 $ 169 $ 3 $ 6 $ 107 $ (55) Total recognized in regulatory assets (liabilities) $ 140 $ 3 $ (6) $ (20) $ 106 $ (57) The following table provides the components of gross accumulated other comprehensive loss and regulatory assets (liabilities) for Exelon that have not been recognized as components of periodic benefit cost at December 31, 2020 and 2019, respectively, for all plans combined: Pension Benefits OPEB 2020 2019 2020 2019 Prior service cost (credit) $ 35 $ 39 $ (145) $ (158) Actuarial loss 8,077 7,662 538 565 Total $ 8,112 $ 7,701 $ 393 $ 407 Total included in AOCI $ 4,339 $ 4,068 $ 183 $ 177 Total included in regulatory assets (liabilities) $ 3,773 $ 3,633 $ 210 $ 230 Average Remaining Service Period For pension benefits, Exelon amortizes its unrecognized prior service costs (credits) and certain actuarial (gains) losses, as applicable, based on participants’ average remaining service periods. For OPEB, Exelon amortizes its unrecognized prior service costs (credits) over participants’ average remaining service period to benefit eligibility age and amortizes certain actuarial (gains) losses over participants’ average remaining service period to expected retirement. The resulting average remaining service periods for pension and OPEB were as follows: 2020 2019 2018 Pension plans 12.3 11.7 12.0 OPEB plans: Benefit Eligibility Age 9.0 8.7 8.8 Expected Retirement 10.2 9.3 9.5 Assumptions The measurement of the plan obligations and costs of providing benefits under Exelon’s defined benefit 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, Exelon considers historical information as well as future expectations. Expected Rate of Return. In determining the EROA, Exelon considers historical economic indicators (including inflation and GDP growth) that impact asset returns, as well as expectations regarding future long-term capital market performance, weighted by Exelon’s target asset class allocations. 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. For the year ended December 31, 2020, Exelon’s mortality assumption utilizes the SOA 2019 base table (Pri-2012) and MP-2020 improvement scale adjusted to use Proxy SSA ultimate improvement rates. For the year ended December 31, 2019, Exelon's mortality assumption utilizes the SOA 2019 base table (Pri-2012) and MP-2019 improvement scale adjusted to a 0.75% long-term rate reached in 2035. For Exelon, the following assumptions were used to determine the benefit obligations for the plans at December 31, 2020 and 2019. 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 2020 2019 2020 2019 Discount rate 2.58 % (a) 3.34 % (a) 2.51 % (a) 3.31 % (a) Investment crediting rate 3.72 % (b) 3.82 % (b) N/A N/A Rate of compensation increase 3.75 % (c) 3.75 % (c) Mortality table Pri-2012 table with MP- 2020 improvement scale (adjusted) Pri-2012 table with MP- 2019 improvement scale (adjusted) Pri-2012 table with MP- 2020 improvement scale (adjusted) Pri-2012 table with MP- 2019 improvement scale (adjusted) Health care cost trend on covered charges N/A N/A Initial and ultimate rate of 5.00% 5.00% with ultimate trend of 5.00% in 2017 __________ (a) The discount rates above represent the blended rates used to determine the majority of Exelon’s pension and OPEB obligations. Certain benefit plans used individual rates, which range from 2.11% - 2.73% and 2.45% - 2.63% for pension and OPEB plans, respectively, as of December 31, 2020 and 3.02% - 3.44% and 3.27% - 3.40% for pension and OPEB plans, respectively, as of December 31, 2019. (b) The investment crediting rate above represents a weighted average rate. (c) 3.25% through 2019 and 3.75% thereafter. The following assumptions were used to determine the net periodic benefit cost for Exelon for the years ended December 31, 2020, 2019 and 2018: Pension Benefits OPEB 2020 2019 2018 2020 2019 2018 Discount rate 3.34 % (a) 4.31 % (a) 3.62 % (a) 3.31 % (a) 4.30 % (a) 3.61 % (a) Investment crediting rate 3.82 % (b) 4.46 % (b) 4.00 % (b) N/A N/A N/A Expected return on plan assets 7.00 % (c) 7.00 % (c) 7.00 % (c) 6.69 % (c) 6.67 % (c) 6.60 % (c) Rate of compensation increase (d) (d) (d) (d) (d) (d) Mortality table Pri-2012 table with MP- 2019 improvement scale (adjusted) RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted) RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted) Pri-2012 table with MP- 2019 improvement scale (adjusted) RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted) RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted) Health care cost trend on covered charges N/A N/A N/A Initial and ultimate rate of 5.00% 5.00% with ultimate trend of 5.00% in 2017 5.00% with ultimate trend of 5.00% in 2017 __________ (a) The discount rates above represent the blended rates used to establish the majority of Exelon’s pension and OPEB costs. Certain benefit plans used individual rates, which range from 3.02%-3.44% and 3.27%-3.40% for pension and OPEB plans, respectively, for the year ended December 31, 2020; 4.13%-4.36% and 4.27%-4.38% for pension and OPEB plans; respectively, for the year ended December 31, 2019; and 3.49%-3.65% and 3.57%-3.68% for pension and OPEB plans, respectively, for the year ended December 31, 2018. (b) The investment crediting rate above represents a weighted average rate. (c) Not applicable to pension and OPEB plans that do not have plan assets. (d) 3.25% through 2019 and 3.75% thereafter. Contributions Exelon allocates contributions related to its legacy Exelon pension and OPEB plans to its subsidiaries based on accounting cost. For legacy CEG, CENG, FitzPatrick, and PHI plans, pension and OPEB contributions are allocated to the subsidiaries based on employee participation (both active and retired). The following tables provide contributions to the pension and OPEB plans: Pension Benefits OPEB 2020 2019 2018 2020 2019 2018 Exelon $ 542 $ 356 $ 337 $ 59 $ 51 $ 46 Generation 236 160 128 19 15 11 ComEd 143 72 38 5 5 4 PECO 18 27 28 — 1 — BGE 56 34 40 22 14 14 PHI 30 10 62 9 15 12 Pepco 2 2 6 9 12 11 DPL — 1 — — — — ACE 2 — 6 — 1 — Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006 (the Act), management of the pension obligation, and regulatory implications. The Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). The projected contributions below reflect a funding strategy to make levelized annual contributions with the objective of achieving 100% funded status on an ABO basis over time. This level funding strategy helps minimize volatility of future period required pension contributions. Based on this funding strategy and current market conditions, which are subject to change, Exelon’s estimated annual qualified pension contributions will be approximately $500 million in 2021. Unlike the qualified pension plans, Exelon’s non-qualified pension plans are not funded, given that they are not subject to statutory minimum contribution requirements. While OPEB plans are also not subject to statutory minimum contribution requirements, Exelon does fund certain of its plans. For Exelon's funded OPEB plans, contributions generally equal accounting costs, however, Exelon’s management has historically considered several factors in determining the level of contributions to its OPEB plans, including liabilities management, levels of benefit claims paid, and regulatory implications (amounts deemed prudent to meet regulatory expectations and best assure continued rate recovery). The amounts below include benefit payments related to unfunded plans. The following table provides all Registrants' planned contributions to the qualified pension plans, planned benefit payments to non-qualified pension plans, and planned contributions to OPEB plans in 2021: Qualified Pension Plans Non-Qualified Pension Plans OPEB Exelon $ 505 $ 51 $ 75 Generation 196 27 24 ComEd 170 2 23 PECO 14 1 — BGE 57 1 16 PHI 29 9 7 Pepco 1 2 6 DPL — 1 — ACE 3 — — Estimated Future Benefit Payments Estimated future benefit payments to participants in all of the pension plans and postretirement benefit plans at December 31, 2020 were: Pension OPEB 2021 $ 1,279 $ 257 2022 1,280 259 2023 1,315 261 2024 1,325 262 2025 1,338 265 2026 through 2030 6,759 1,320 Total estimated future benefit payments through 2030 $ 13,296 $ 2,624 Plan Assets Investment Strategy. On a regular basis, Exelon evaluates its investment strategy to ensure that plan assets will be sufficient to pay plan benefits when due. As part of this ongoing evaluation, Exelon may make changes to its targeted asset allocation and investment strategy. Exelon has developed and implemented a liability hedging investment strategy for its qualified pension plans that has reduced the volatility of its pension assets relative to its pension liabilities. Exelon is likely to continue to gradually increase the liability hedging portfolio as the funded status of its plans improves. The overall objective is to achieve attractive risk-adjusted returns that will balance the liquidity requirements of the plans’ liabilities while striving to minimize the risk of significant losses. Trust assets for Exelon’s 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 Exelon-sponsored pension and OPEB plans. The actual asset returns across Exelon’s pension and OPEB plans for the year ended December 31, 2020 were 14.45% and 9.14%, respectively, compared to an expected long-term return assumption of 7.00% and 6.69%, respectively. Exelon used an EROA of 7.00% and 6.46% to estimate its 2021 pension and OPEB costs, respectively. Exelon’s pension and OPEB plan target asset allocations at December 31, 2020 and 2019 were as follows: December 31, 2020 December 31, 2019 Asset Category Pension Benefits OPEB Pension Benefits OPEB Equity securities 34 % 45 % 33 % 46 % Fixed income securities 43 % 39 % 44 % 32 % Alternative investments (a) 23 % 16 % 23 % 22 % Total 100 % 100 % 100 % 100 % __________ (a) Alternative investments include private equity, hedge funds, real estate, and private credit. Concentrations of Credit Risk. Exelon evaluated its pension and OPEB plans’ asset portfolios for the existence of significant concentrations of credit risk as of December 31, 2020. 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, 2020, there were no significant concentrations (defined as greater than 10% of plan assets) of risk in Exelon’s pension and OPEB plan assets. Fair Value Measurements The following tables present pension and OPEB plan assets measured and recorded at fair value in Exelon's Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy at December 31, 2020 and 2019: December 31, 2020 December 31, 2019 Level 1 Level 2 Level 3 Not subject to leveling Total Level 1 Level 2 Level 3 Not subject to leveling Total Pension plan assets (a) Cash equivalents $ 408 $ 121 $ — $ — $ 529 $ 258 $ 107 $ — $ — $ 365 Equities (b) 4,255 — 2 2,552 6,809 3,616 1 5 2,589 6,211 Fixed income: U.S. Treasury and agencies 1,137 367 — — 1,504 1,294 280 — — 1,574 State and municipal debt — 85 — — 85 — 56 — — 56 Corporate debt (c) — 4,873 573 — 5,446 — 4,390 245 — 4,635 Other (b) — 239 21 537 797 — 305 — 851 1,156 Fixed income subtotal 1,137 5,564 594 537 7,832 1,294 5,031 245 851 7,421 Private equity — — — 1,632 1,632 — — — 1,391 1,391 Hedge funds — — — 1,314 1,314 — — — 1,126 1,126 Real estate — — — 1,080 1,080 — — — 1,030 1,030 Private credit — — 234 1,046 1,280 — — 237 929 1,166 Pension plan assets subtotal 5,800 5,685 830 8,161 20,476 5,168 5,139 487 7,916 18,710 OPEB plan assets (a) Cash equivalents 50 52 — — 102 39 49 — — 88 Equities 618 2 — 569 1,189 473 5 — 719 1,197 Fixed income: U.S. Treasury and agencies 16 66 — — 82 17 64 — — 81 State and municipal debt — 89 — — 89 — 107 — — 107 Corporate debt (c) — 89 — — 89 — 71 — — 71 Other 285 3 — 179 467 258 5 — 201 464 Fixed income subtotal 301 247 — 179 727 275 247 — 201 723 Hedge funds — — — 308 308 — — — 293 293 Real estate — — — 111 111 — — — 109 109 Private credit — — — 117 117 — — — 131 131 OPEB plan assets subtotal 969 301 — 1,284 2,554 787 301 — 1,453 2,541 Total pension and OPEB plan assets (d) $ 6,769 $ 5,986 $ 830 $ 9,445 $ 23,030 $ 5,955 $ 5,440 $ 487 $ 9,369 $ 21,251 __________ (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 $2 million for the years ended December 31, 2020 and 2019, which have total notional amounts of $6,879 million and $6,668 million at December 31, 2020 and 2019, respectively. 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) Includes investments in equities sold short held in investment vehicles primarily to hedge the equity option component of its convertible debt. Pension equities sold short totaled $(96) million and $(75) million as of December 31, 2020 and 2019, respectively. OPEB equities sold short totaled $(42) million and $(35) million as of December 31, 2020 and 2019, respectively. (d) Excludes net liabilities of $132 million and $120 million at December 31, 2020 and 2019, respectively, which include certain derivative assets that have notional amounts of $239 million and $632 million at December 31, 2020 and 2019, respectively. 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 for Exelon measured at fair value for pension and OPEB plans for the years ended December 31, 2020 and 2019: Fixed Income Equities Private Total Pension Assets Balance as of January 1, 2020 $ 245 $ 5 $ 237 $ 487 Actual return on plan assets: Relating to assets still held at the 19 (3) 15 31 Purchases, sales and settlements: Purchases 34 — 24 58 Settlements (a) (3) — (42) (45) Transfers into Level 3 (b) 299 — — 299 Balance as of December 31, 2020 $ 594 $ 2 $ 234 $ 830 Fixed Income Equities Private Total Pension Assets Balance as of January 1, 2019 $ 216 $ 2 $ 268 $ 486 Actual return on plan assets: Relating to assets still held at the reporting date 28 3 28 59 Relating to assets sold during the period (7) — — (7) Purchases, sales and settlements: Purchases 26 — 41 67 Sales (4) — — (4) Settlements (a) (2) — (100) (102) Transfers out of Level 3 (12) — — (12) Balance as of December 31, 2019 $ 245 $ 5 $ 237 $ 487 __________ (a) Represents cash settlements only. (b) In 2020, a contract was terminated for a certain fixed income commingled fund resulting in the ownership of certain fixed income securities which led to a transfer into Level 3 from not subject to leveling of $299 million. 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 NDTFs. 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. Exelon has 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 (All Registrants) The Registrants participate in various 401(k) defined contribution savings plans that are sponsored by Exelon. The plans are qualified under applicable sections of the IRC and allow employees to contribute a portion of their pre-tax and/or after-tax income in accordance with specified guidelines. All Registrants match a percentage of the employee contributions up to certain limits. The following table presents matching contributions to the savings plan for the years ended December 31, 2020, 2019, and 2018: For the Years Ended December 31, Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE 2020 $ 158 $ 63 $ 36 $ 12 $ 13 14 $ 4 $ 3 $ 3 2019 161 73 35 11 12 13 3 3 2 2018 179 86 37 9 12 13 3 2 2

Derivative Financial Instrument

Derivative Financial Instruments (All Registrants)	12 Months Ended
Derivative Financial Instruments (All Registrants)	Dec. 31, 2020
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Financial Instruments (All Registrants)	Derivative Financial Instruments (All Registrants) The Registrants 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 at Generation and are offset by a corresponding regulatory asset or liability at ComEd. For all NPNS derivative instruments, accounts receivable or accounts payable are recorded when derivative settles and revenue or expense is recognized in earnings as the underlying physical commodity is sold or consumed. Authoritative guidance about offsetting assets and liabilities requires the fair value of derivative instruments to be shown in the Combined Notes to Consolidated Financial Statements on a gross basis, even when the derivative instruments are subject to legally enforceable master netting agreements and qualify for net presentation in the Consolidated Balance Sheets. A master netting agreement is an agreement between two counterparties that may have derivative and non-derivative contracts with each other providing for the net settlement of all referenced contracts via one payment stream, which takes place as the contracts deliver, when collateral is requested or in the event of default. In the tables below, which present fair value balances, Generation’s 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. Generation’s and ComEd’s use of cash collateral is generally unrestricted unless Generation or ComEd are downgraded below investment grade. Cash collateral held by PECO, BGE, Pepco, DPL, and ACE must be deposited in an unaffiliated major U.S. commercial bank or foreign bank with a U.S. branch office that meet certain qualifications. Commodity Price Risk (All Registrants) Each of the Registrants employ established policies and procedures to manage their 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. The Registrants believe these instruments, which are either determined to be non-derivative or classified as economic hedges, mitigate exposure to fluctuations in commodity prices. Generation. To the extent the amount of energy Generation produces differs from the amount of energy it has contracted to sell, Exelon and Generation are exposed to market fluctuations in the prices of electricity, fossil fuels, and other commodities. Within Exelon, Generation has the most exposure to commodity price risk. As such, Generation uses a variety of derivative and non-derivative instruments to manage the commodity price risk of its 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, Generation 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. Generation is 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, Generation is exposed to certain market risks through its proprietary trading activities. The proprietary trading activities are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s overall energy marketing activities and are subject to limits established by Exelon’s RMC. Utility Registrants. The Utility Registrants procure electric and natural gas supply through a competitive procurement process approved by each of the respective state utility commissions. The Utility Registrants’ hedging programs are intended to reduce exposure to energy and natural gas price volatility and have no direct earnings impact as the costs are fully recovered from customers through regulatory-approved recovery mechanisms. The following table provides a summary of the Utility Registrants’ primary derivative hedging instruments, listed by commodity and accounting treatment. Registrant Commodity Accounting Treatment Hedging Instrument ComEd Electricity NPNS Fixed price contracts based on all requirements in the IPA procurement plans. Electricity Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability (a) 20-year floating-to-fixed energy swap contracts beginning June 2012 based on the renewable energy resource procurement requirements in the Illinois Settlement Legislation of approximately 1.3 million MWhs per year. PECO (b) Gas NPNS Fixed price contracts to cover about 10% of planned natural gas purchases in support of projected firm sales. BGE Electricity NPNS Fixed price contracts for all SOS requirements through full requirements contracts. Gas NPNS Fixed price contracts for between 10-20% of forecasted system supply requirements for flowing (i.e., non-storage) gas for the November through March period. Pepco Electricity NPNS Fixed price contracts for all SOS requirements through full requirements contracts. DPL Electricity NPNS Fixed price contracts for all SOS requirements through full requirements contracts. Gas NPNS Fixed and Index priced contracts through full requirements contracts. Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability (c) Exchange traded future contracts for up to 50% of estimated monthly purchase requirements each month, including purchases for storage injections. ACE Electricity NPNS Fixed price contracts for all BGS requirements through full requirements contracts. _________ (a) See Note 3—Regulatory Matters for additional information. (b) As part of its hedging program, PECO enters into electric supply procurement contracts that do not meet the definition of a derivative instrument. (c) The fair value of the DPL economic hedge is not material as of December 31, 2020 and 2019 and is not presented in the fair value tables below. The following table provides a summary of the derivative fair value balances recorded by Exelon, Generation, and ComEd as of December 31, 2020 and 2019: Exelon Generation ComEd December 31, 2020 Total Economic Proprietary Collateral (a)(b) Netting (a) Subtotal Economic Mark-to-market derivative assets (current assets) $ 639 $ 2,757 $ 40 $ 103 $ (2,261) $ 639 $ — Mark-to-market derivative assets (noncurrent assets) 554 1,501 4 64 (1,015) 554 — Total mark-to-market derivative assets 1,193 4,258 44 167 (3,276) 1,193 — Mark-to-market derivative liabilities (current liabilities) (293) (2,629) (23) 131 2,261 (260) (33) Mark-to-market derivative liabilities (noncurrent liabilities) (472) (1,335) (2) 118 1,015 (204) (268) Total mark-to-market derivative liabilities (765) (3,964) (25) 249 3,276 (464) (301) Total mark-to-market derivative net assets (liabilities) $ 428 $ 294 $ 19 $ 416 $ — $ 729 $ (301) December 31, 2019 Mark-to-market derivative assets (current assets) $ 675 $ 3,506 $ 72 $ 287 $ (3,190) $ 675 $ — Mark-to-market derivative assets (noncurrent assets) 508 1,238 25 122 (877) 508 — Total mark-to-market derivative assets 1,183 4,744 97 409 (4,067) 1,183 — Mark-to-market derivative liabilities (current liabilities) (236) (3,713) (38) 357 3,190 (204) (32) Mark-to-market derivative liabilities (noncurrent liabilities) (380) (1,140) (11) 163 877 (111) (269) Total mark-to-market derivative liabilities (616) (4,853) (49) 520 4,067 (315) (301) Total mark-to-market derivative net assets (liabilities) $ 567 $ (109) $ 48 $ 929 $ — $ 868 $ (301) _________ (a) Exelon and Generation net all available amounts allowed under the derivative authoritative guidance in the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation 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 and not reflected in the table above. (b) Of the collateral posted, $209 million and $511 million represents variation margin on the exchanges at December 31, 2020 and 2019, respectively. Economic Hedges (Commodity Price Risk) Generation. For the years ended December 31, 2020, 2019, and 2018, Exelon and Generation 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. Gain (Loss) Income Statement Location 2020 2019 2018 Operating revenues $ 112 $ — $ (270) Purchased power and fuel 168 (204) (47) Total Exelon and Generation $ 280 $ (204) $ (317) In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on Generation’s owned and contracted generation positions that have not been hedged. Generation hedges commodity price risk on a ratable basis over three-year periods. As of December 31, 2020, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York, and ERCOT reportable segments is 94%-97% for 2021. Proprietary Trading (Commodity Price Risk) Generation also executes 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 Exelon’s and Generation’s 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, 2020, 2019, and 2018, net pre-tax commodity mark-to-market gains and losses for Exelon and Generation were not material. The Utility Registrants do not execute derivatives for proprietary trading purposes. Interest Rate and Foreign Exchange Risk (Exelon and Generation) Exelon and Generation utilize interest rate swaps, which are treated as economic hedges, to manage their interest rate exposure. On July 1, 2018, Exelon de-designated its fair value hedges related to interest rate risk and Generation de-designated its cash flow hedges related to interest rate risk. The notional amounts were $516 million and $1,269 million at December 31, 2020 and 2019, respectively, for Exelon and $516 million and $569 million at December 31, 2020 and 2019, respectively, for Generation. Generation utilizes foreign currency derivatives to manage foreign exchange rate exposure associated with international commodity purchases in currencies other than U.S. dollars, which are treated as economic hedges. The notional amounts were $149 million and $231 million at December 31, 2020 and 2019, respectively. The mark-to-market derivative assets and liabilities as of December 31, 2020 and 2019 and the mark-to-market gains and losses for the years ended December 31, 2020, 2019, and 2018 were not material for Exelon and Generation. Credit Risk (All Registrants) The Registrants 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 at the reporting date. Generation. For commodity derivatives, Generation enters into enabling agreements that allow for payment netting with its counterparties, which reduces Generation’s 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 so, 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 allow for cross product netting. In addition to payment netting language in the enabling agreement, Generation’s 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 Generation as specified in each enabling agreement. Generation’s 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 Generation’s 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, 2020. 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 figures 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, 2020 Total Credit Collateral (a) Net Number of Net Exposure of Investment grade $ 577 $ 27 $ 550 — $ — Non-investment grade 32 — 32 No external ratings Internally rated — investment grade 165 1 164 Internally rated — non-investment grade 80 28 52 Total $ 854 $ 56 $ 798 — $ — Net Credit Exposure by Type of Counterparty As of December 31, 2020 Financial institutions $ 15 Investor-owned utilities, marketers, power producers 607 Energy cooperatives and municipalities 138 Other 38 Total $ 798 __________ (a) As of December 31, 2020, credit collateral held from counterparties where Generation had credit exposure included $31 million of cash and $25 million of letters of credit. The credit collateral does not include non-liquid collateral. Utility Registrants. The Utility Registrants have contracts to procure electric and natural gas supply that provide suppliers with a certain amount of unsecured credit. If the exposure on the supply contract exceeds the amount of unsecured credit, the suppliers may be required to post collateral. The net credit exposure is mitigated primarily by the ability to recover procurement costs through customer rates. As of December 31, 2020, the Utility Registrants’ counterparty credit risk with suppliers was not material. Credit-Risk-Related Contingent Features (All Registrants) Generation. As part of the normal course of business, Generation routinely enters 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 Generation’s derivative instruments contain provisions that require Generation to post collateral. Generation also enters 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 Generation’s 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 Generation were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it 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, Generation believes 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 2020 2019 Gross fair value of derivative contracts containing this feature (a) $ (834) $ (956) Offsetting fair value of in-the-money contracts under master netting arrangements (b) 537 649 Net fair value of derivative contracts containing this feature (c) $ (297) $ (307) __________ (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 Generation 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, 2020 and 2019, Exelon and Generation 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, 2020 2019 Cash collateral posted $ 511 $ 982 Letters of credit posted 226 264 Cash collateral held 110 103 Letters of credit held 40 112 Additional collateral required in the event of a credit downgrade below investment grade 1,432 1,509 Generation entered into supply forward contracts with certain utilities, including PECO and BGE, with one-sided collateral postings only from Generation. 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 Generation, are required to post collateral once certain unsecured credit limits are exceeded. Utility Registrants The Utility Registrants’ electric supply procurement contracts do not contain provisions that would require them to post collateral. PECO’s, BGE’s, and DPL’s natural gas procurement contracts contain provisions that could require PECO, BGE, and DPL to post collateral in the form of cash or credit support, which vary by contract and counterparty, with thresholds contingent upon PECO’s, BGE's, and DPL’s credit rating. As of December 31, 2020, PECO, BGE, and DPL were not required to post collateral for any of these agreements. If PECO, BGE, or DPL lost their investment grade credit rating as of December 31, 2020, they could have been required to post incremental collateral to their counterparties of $34 million, $54 million, and $9 million, respectively.

Debt and Credit Agreements (All

Debt and Credit Agreements (All Registrants)	12 Months Ended
Debt and Credit Agreements (All Registrants)	Dec. 31, 2020
Debt Disclosure [Abstract]
Debt and Credit Agreements (All Registrants)	Debt and Credit Agreements (All Registrants) Short-Term Borrowings Exelon Corporate, ComEd, and BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. Generation and PECO meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the Exelon intercompany money pool. Pepco, DPL, and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the PHI intercompany money pool. PHI Corporate meets its short-term liquidity requirements primarily through the issuance of short-term notes and borrowings from the Exelon intercompany money pool. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit. Commercial Paper The following table reflects the Registrants' commercial paper programs supported by the revolving credit agreements and bilateral credit agreements at December 31, 2020 and 2019: Maximum Outstanding Average Interest Rate on Commercial Paper Issuer 2020 (a)(b)(c) 2019 (a)(b)(c) 2020 2019 2020 2019 Exelon (d) $ 9,000 $ 9,000 $ 1,031 $ 870 0.25 % 2.25 % Generation 5,300 5,300 340 320 0.27 % 1.84 % ComEd 1,000 1,000 323 130 0.23 % 2.38 % PECO 600 600 — — — % 2.39 % BGE 600 600 — 76 — % 2.46 % PHI (e) 900 900 368 208 0.24 % N/A Pepco 300 300 35 82 0.22 % 2.56 % DPL 300 300 146 56 0.24 % 2.02 % ACE 300 300 187 70 0.25 % 2.43 % __________ (a) Excludes $1,500 million and $1,400 million in bilateral credit facilities at December 31, 2020 and 2019, respectively, and $144 million and $159 million in credit facilities for project finance at December 31, 2020 and 2019, respectively. These credit facilities do not back Generation's commercial paper program. (b) At December 31, 2020, excludes $135 million of credit facility agreements arranged at minority and community banks at Generation, ComEd, PECO, BGE, Pepco, DPL, and ACE with aggregate commitments of $38 million, $32 million, $33 million, $8 million, $8 million, $8 million, and $8 million, respectively. These facilities expire on October 8, 2021. These facilities are solely utilized to issue letters of credit. At December 31, 2019, excludes $142 million of credit facility agreements arranged at minority and community banks at Generation, ComEd, PECO, BGE, Pepco, DPL, and ACE with aggregate commitments of $44 million, $33 million, $33 million, $8 million, $8 million, $8 million, and $8 million, respectively. (c) Pepco, DPL, and ACE's revolving credit facility has the ability to flex to $500 million, $500 million, and $350 million, respectively. The borrowing capacity may be increased or decreased during the term of the facility, except that (i) the sum of the borrowing capacity must equal the total amount of the facility, and (ii) the aggregate amount of credit used at any given time by each of Pepco, DPL, or ACE may not exceed $900 million or the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the borrowing reallocations may not exceed eight per year during the term of the facility. (d) Includes revolving credit agreement at Exelon Corporate with a maximum program size of $600 million at both December 31, 2020 and 2019, respectively. Exelon Corporate had no outstanding commercial paper as of December 31, 2020 and $136 million at 2019 with an average interest rate on commercial paper borrowings of 1.92%. (e) Represents the consolidated amounts of Pepco, DPL, and ACE. In order to maintain their respective commercial paper programs in the amounts indicated above, each Registrant must have credit facilities in place, at least equal to the amount of its commercial paper program. A registrant does not issue commercial paper in an aggregate amount exceeding the then available capacity under its credit facility. At December 31, 2020, the Registrants had the following aggregate bank commitments, credit facility borrowings, and available capacity under their respective credit facilities: Available Capacity at December 31, 2020 Borrower (a) Facility Type Aggregate Bank (b) Facility Draws Outstanding Actual To Support Additional Commercial (c) Exelon (c) Syndicated Revolver / Bilaterals / Project Finance $ 10,644 $ — $ 1,230 $ 9,414 $ 7,698 Generation Syndicated Revolver 5,300 — 262 5,038 4,698 Generation Bilaterals 1,500 — 840 660 — Generation Project Finance 144 — 119 25 — ComEd Syndicated Revolver 1,000 — 2 998 675 PECO Syndicated Revolver 600 — — 600 600 BGE Syndicated Revolver 600 — — 600 600 PHI Syndicated Revolver 900 — 1 899 531 Pepco Syndicated Revolver 300 — 1 299 264 DPL Syndicated Revolver 300 — — 300 154 ACE Syndicated Revolver 300 — — 300 113 __________ (a) On May 26, 2018, each of the Registrants' respective syndicated revolving credit facilities had their maturity dates extended to May 26, 2023. (b) Excludes $135 million of credit facility agreements arranged at minority and community banks at Generation, ComEd, PECO, BGE, Pepco, DPL, and ACE with aggregate commitments of $38 million, $32 million, $33 million, $8 million, $8 million, $8 million, and $8 million, respectively. These facilities expire on October 8, 2021. These facilities are solely utilized to issue letters of credit. As of December 31, 2020, letters of credit issued under these facilities totaled $5 million, $5 million, and $2 million for Generation, ComEd, and BGE, respectively. (c) Includes $600 million aggregate bank commitment related to Exelon Corporate. Exelon Corporate had $6 million outstanding letters of credit at December 31, 2020. Exelon Corporate had $594 million in available capacity to support additional commercial paper at December 31, 2020. On March 19, 2020, Generation borrowed $1.5 billion on its revolving credit facility due to disruptions in the commercial paper markets as a result of COVID-19. The funds were used to refinance commercial paper. Generation repaid the $1.5 billion borrowed on the revolving credit facility on April 3, 2020. Short-Term Loan Agreements On March 23, 2017, Exelon Corporate entered into a 12-month term loan agreement for $500 million, which was renewed annually on March 22, 2018, March 20, 2019, and March 19, 2020, respectively. The loan agreement will expire on March 18, 2021. Pursuant to the loan agreement, as of December 31, 2020, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.65% and all indebtedness thereunder is unsecured. The loans beared interest at LIBOR plus 0.95% as of December 31, 2019 as part of the March 20, 2019 renewal. The loan agreement is reflected in Exelon's Consolidated Balance Sheets within Short-term borrowings. On March 19, 2020, Generation entered into a term loan agreement for $200 million. The loan agreement has an expiration of March 18, 2021. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.50% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Generation's Consolidated Balance Sheet within Short-term borrowings. On March 31, 2020, Generation entered into a term loan agreement for $300 million. The loan agreement has an expiration of March 30, 2021. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.75% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Generation's Consolidated Balance Sheet within Short-term borrowings. On January 25, 2021, ComEd entered into two 90-day term loan agreements of $125 million each with variable interest rates of LIBOR plus 0.50% and LIBOR plus 0.75%, respectively. Revolving Credit Agreements On April 24, 2020, Exelon Corporate entered into a credit agreement establishing a $550 million 364-day revolving credit facility at a variable interest rate of LIBOR plus 1.75%. This facility will be used by Exelon as an additional source of short-term liquidity as needed. Bilateral Credit Agreements The following table reflects the bilateral credit agreements at December 31, 2020: Registrant Date Initiated Latest Amendment Date Maturity Date (a) Amount Generation (b) October 26, 2012 October 23, 2020 October 22, 2021 $ 200 Generation (c) January 11, 2013 January 4, 2019 March 1, 2021 100 Generation (c) January 5, 2016 January 4, 2019 April 5, 2021 150 Generation (c) February 21, 2019 N/A March 31, 2021 100 Generation (c) October 25, 2019 N/A N/A 200 Generation (c) October 25, 2019 N/A N/A 100 Generation (c) November 20, 2019 N/A N/A 300 Generation (c) November 21, 2019 N/A N/A 150 Generation (c) November 21, 2019 N/A November 21, 2021 100 Generation (c) May 15, 2020 N/A N/A 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 facility relates to CENG, which is incorporated within Generation, and supports the issuance of letters of credit and funding for working capital and does not back Generation's commercial paper program. During the second and third quarters of 2020, CENG drew on its bilateral credit facility. As of December 31, 2020, there was no outstanding balance at this facility. (c) Bilateral credit agreements solely support the issuance of letters of credit and do not back Generation's commercial paper program. Borrowings under Exelon’s, Generation’s, ComEd’s, PECO’s, BGE's, Pepco's, DPL's, and ACE's revolving credit agreements bear interest at a rate based upon either the prime rate or a LIBOR-based rate, plus an adder based upon the particular Registrant’s credit rating. The adders for the prime based borrowings and LIBOR-based borrowings are presented in the following table: Exelon (a) Generation ComEd PECO BGE Pepco DPL ACE Prime based borrowings 0 - 27.5 27.5 — — — 7.5 — 7.5 LIBOR-based borrowings 90.0 - 127.5 127.5 100.0 90.0 90.0 107.5 100.0 107.5 __________ (a) Includes interest rate adders at Exelon Corporate of 27.5 and 127.5 for prime and LIBOR-based borrowings, respectively. If any registrant loses its investment grade rating, the maximum adders for prime rate borrowings and LIBOR-based rate borrowings would be 65 basis points and 165 basis points, respectively. The credit agreements also require the borrower to pay a facility fee based upon the aggregate commitments. The fee varies depending upon the respective credit ratings of the borrower. Variable Rate Demand Bonds DPL has outstanding obligations in respect of Variable Rate Demand Bonds (VRDB). VRDBs are subject to repayment on the demand of the holders and, for this reason, are accounted for as short-term debt in accordance with GAAP. However, these bonds may be converted to a fixed-rate, fixed-term option to establish a maturity which corresponds to the date of final maturity of the bonds. On this basis, PHI views VRDBs as a source of long-term financing. As of both December 31, 2020 and December 31, 2019, $79 million in variable rate demand bonds issued by DPL were outstanding and are included in the Long-term debt due within one year in Exelon's, PHI's, and DPL's Consolidated Balance Sheet. Long-Term Debt The following tables present the outstanding long-term debt at the Registrants as of December 31, 2020 and 2019: Exelon Maturity December 31, Rates 2020 2019 Long-term debt First mortgage bonds (a) 0.19 % - 7.90 % 2021 - 2050 $ 18,915 $ 17,486 Senior unsecured notes 2.45 % - 7.60 % 2021 - 2050 10,585 10,685 Unsecured notes 2.40 % - 6.35 % 2021 - 2050 3,700 3,300 Pollution control notes 2.50 % - 2.70 % 2020 — 412 Nuclear fuel procurement contracts 3.15 % 2020 — 3 Notes payable and other 2.10 % - 7.99 % 2021 - 2053 170 154 Junior subordinated notes 3.50 % 2022 1,150 1,150 Long-term software licensing agreement 3.95 % 2024 30 55 Unsecured tax-exempt bonds 0.17 % - 1.70 % 2022 - 2024 143 222 Medium-terms notes (unsecured) 7.72 % 2027 10 10 Transition bonds 5.55 % 2021 21 40 Loan agreement 2.00 % 2023 50 50 Nonrecourse debt: Fixed rates 2.29 % - 6.00 % 2031 - 2037 977 1,182 Variable rates 2.99 % - 3.18 % 2021 - 2027 765 811 Total long-term debt 36,516 35,560 Unamortized debt discount and premium, net (77) (72) Unamortized debt issuance costs (248) (214) Fair value adjustment 721 765 Long-term debt due within one year (1,819) (4,710) Long-term debt $ 35,093 $ 31,329 Long-term debt to financing trusts (b) Subordinated debentures to ComEd Financing III 6.35 % 2033 $ 206 $ 206 Subordinated debentures to PECO Trust III 5.25 % - 7.38 % 2028 81 81 Subordinated debentures to PECO Trust IV 5.75 % 2033 103 103 Total long-term debt to financing trusts $ 390 $ 390 __________ (a) Substantially all of ComEd’s assets other than expressly excepted property and substantially all of PECO’s, Pepco's, DPL's, and ACE's assets are subject to the liens of their respective mortgage indentures. (b) Amounts owed to these financing trusts are recorded as Long-term debt to financing trusts within Exelon’s Consolidated Balance Sheets. Generation Maturity December 31, Rates 2020 2019 Long-term debt Senior unsecured notes 3.25 % - 7.60 % 2022 - 2042 $ 4,219 $ 5,420 Pollution control notes 2.50 % - 2.70 % 2020 — 412 Nuclear fuel procurement contracts 3.15 % 2020 — 3 Notes payable and other 2.10 % - 4.85 % 2021 - 2028 111 115 Nonrecourse debt: Fixed rates 2.29 % - 6.00 % 2031 - 2037 977 1,182 Variable rates 2.99 % - 3.18 % 2021 - 2027 765 811 Total long-term debt 6,072 7,943 Unamortized debt discount and premium, net (5) (5) Unamortized debt issuance costs (46) (42) Fair value adjustment 66 78 Long-term debt due within one year (197) (3,182) Long-term debt $ 5,890 $ 4,792 ComEd Maturity December 31, Rates 2020 2019 Long-term debt First mortgage bonds (a) 2.20 % - 6.45 % 2021 - 2050 $ 9,079 $ 8,578 Other 7.49 % 2053 8 8 Total long-term debt 9,087 8,586 Unamortized debt discount and premium, net (28) (27) Unamortized debt issuance costs (76) (68) Long-term debt due within one year (350) (500) Long-term debt $ 8,633 $ 7,991 Long-term debt to financing trust (b) Subordinated debentures to ComEd Financing III 6.35 % 2033 $ 206 $ 206 Total long-term debt to financing trusts 206 206 Unamortized debt issuance costs (1) (1) Long-term debt to financing trusts $ 205 $ 205 __________ (a) Substantially all of ComEd’s assets, other than expressly excepted property, are subject to the lien of its mortgage indenture. (b) Amount owed to this financing trust is recorded as Long-term debt to financing trust within ComEd’s Consolidated Balance Sheets. PECO Maturity December 31, Rates 2020 2019 Long-term debt First mortgage bonds (a) 1.70 % - 5.95 % 2021 - 2050 $ 3,750 $ 3,400 Loan agreement 2.00 % 2023 50 50 Total long-term debt 3,800 3,450 Unamortized debt discount and premium, net (20) (21) Unamortized debt issuance costs (27) (24) Long-term debt due within one year (300) — Long-term debt $ 3,453 $ 3,405 Long-term debt to financing trusts (b) Subordinated debentures to PECO Trust III 5.25 % - 7.38 % 2028 $ 81 $ 81 Subordinated debentures to PECO Trust IV 5.75 % 2033 103 103 Long-term debt to financing trusts $ 184 $ 184 __________ (a) Substantially all of PECO’s assets are subject to the lien of its mortgage indenture. (b) Amounts owed to this financing trust are recorded as Long-term debt to financing trusts within PECO’s Consolidated Balance Sheets. BGE Maturity December 31, Rates 2020 2019 Long-term debt Unsecured notes 2.40 % - 6.35 % 2021 - 2050 $ 3,700 $ 3,300 Total long-term debt 3,700 3,300 Unamortized debt discount and premium, net (12) (9) Unamortized debt issuance costs (24) (21) Long-term debt due within one year (300) — Long-term debt $ 3,364 $ 3,270 PHI Maturity December 31, Rates 2020 2019 Long-term debt First mortgage bonds (a) 0.19 % - 7.90 % 2021 - 2050 $ 6,086 $ 5,508 Senior unsecured notes 7.45 % 2032 185 185 Unsecured tax-exempt bonds 0.17 % - 1.70 % 2022 - 2024 143 222 Medium-terms notes (unsecured) 7.72 % 2027 10 10 Transition bonds 5.55 % 2021 21 40 Finance leases 3.54 % 2022 - 2028 50 28 Other 7.28 % - 7.99 % 2021 - 2022 1 2 Total long-term debt 6,496 5,995 Unamortized debt discount and premium, net 4 4 Unamortized debt issuance costs (28) (19) Fair value adjustment 534 583 Long-term debt due within one year (347) (103) Long-term debt $ 6,659 $ 6,460 _________ (a) Substantially all of Pepco's, DPL's, and ACE's assets are subject to the liens of their respective mortgage indentures. Pepco Maturity December 31, Rates 2020 2019 Long-term debt First mortgage bonds (a) 2.53 % - 7.90 % 2022 - 2050 $ 3,075 $ 2,775 Unsecured tax-exempt bonds 1.70 % 2022 110 110 Finance leases 3.54 % 2025 - 2028 17 10 Other 7.28 % - 7.99 % 2021 - 2022 1 2 Total long-term debt 3,203 2,897 Unamortized debt discount and premium, net 2 2 Unamortized debt issuance costs (40) (35) Long-term debt due within one year (3) (2) Long-term debt $ 3,162 $ 2,862 __________ (a) Substantially all of Pepco's assets are subject to the lien of its mortgage indenture. DPL Maturity December 31, Rates 2020 2019 Long-term debt First mortgage bonds (a) 0.19 % - 4.27 % 2023 - 2049 $ 1,624 $ 1,446 Unsecured tax-exempt bonds 0.17 % - 0.20 % 2024 33 112 Medium-terms notes (unsecured) 7.72 % 2027 10 10 Finance leases 3.54 % 2025 - 2028 20 10 Total long-term debt 1,687 1,578 Unamortized debt discount and premium, net 1 1 Unamortized debt issuance costs (11) (12) Long-term debt due within one year (82) (80) Long-term debt $ 1,595 $ 1,487 __________ (a) Substantially all of DPL's assets are subject to the lien of its mortgage indenture. ACE Maturity December 31, Rates 2020 2019 Long-term debt First mortgage bonds (a) 2.25 % - 6.80 % 2021 - 2050 $ 1,387 $ 1,287 Transition bonds 5.55 % 2021 21 40 Finance leases 3.54 % 2022 - 2028 13 8 Total long-term debt 1,421 1,335 Unamortized debt discount and premium, net (1) (1) Unamortized debt issuance costs (7) (7) Long-term debt due within one year (261) (20) Long-term debt $ 1,152 $ 1,307 __________ (a) Substantially all of ACE's assets are subject to the lien of its mortgage indenture. Long-term debt maturities at the Registrants in the periods 2021 through 2025 and thereafter are as follows: Year Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE 2021 $ 1,819 $ 197 $ 350 $ 300 $ 300 $ 347 $ 3 $ 82 $ 261 2022 3,092 1,025 — 350 250 317 312 3 2 2023 859 1 — 50 300 508 3 503 2 2024 814 1 250 — — 558 403 3 152 2025 2,215 900 — 350 — 158 3 3 152 Thereafter 28,107 (a) 3,948 8,692 (b) 2,934 (c) 2,850 4,608 2,479 1,093 852 Total $ 36,906 $ 6,072 $ 9,292 $ 3,984 $ 3,700 $ 6,496 $ 3,203 $ 1,687 $ 1,421 __________ (a) Includes $390 million due to ComEd and PECO financing trusts. (b) Includes $206 million due to ComEd financing trust. (c) Includes $184 million due to PECO financing trusts. Debt Covenants As of December 31, 2020, the Registrants are in compliance with debt covenants. Nonrecourse Debt Exelon and Generation have issued nonrecourse debt financing, in which approximately $2.2 billion of generating assets have been pledged as collateral at December 31, 2020. Borrowings under these agreements are secured by the assets and equity of each respective project. The lenders do not have recourse against Exelon or Generation in the event of a default. If a specific project financing entity does not maintain compliance with its specific nonrecourse debt financing 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 its 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 will bear interest at an average blended interest rate of 2.82%. As of December 31, 2020 and December 31, 2019, approximately $460 million and $485 million were outstanding, respectively. In addition, Generation has issued letters of credit to support its equity investment in the project. As of December 31, 2020, Generation had $37 million in letters of credit outstanding related to the project. In December 2017, Generation’s interests in Antelope Valley were contributed to and are pledged as collateral for the EGR IV financing structures referenced below. Antelope Valley sells all of its output to PG&E through a PPA. On January 29, 2019, PG&E filed for protection under Chapter 11 of the U.S. Bankruptcy Code, which created an event of default for Antelope Valley’s nonrecourse debt that provided the lender with a right to accelerate amounts outstanding under the loan such that they would become immediately due and payable. As a result of the event of default and in the absence of a waiver from the lender foregoing their acceleration rights, the debt was reclassified as current in Exelon’s and Generation’s Consolidated Balance Sheets in the first quarter of 2019. Further, distributions from Antelope Valley to EGR IV were suspended. The United States Bankruptcy Court entered an order on June 20, 2020 confirming PG&E’s plan of reorganization. On July 1, 2020 the plan became effective, and PG&E emerged from bankruptcy. On July 21, 2020, Antelope Valley received a waiver from the DOE for the event of default and, as such, distributions from Antelope Valley to EGR IV were permitted and the debt was classified as noncurrent as of June 30, 2020. The debt continues to be presented as noncurrent as of December 31, 2020. See Note 12 — Asset Impairments for additional information. Continental Wind, LLC. In September 2013, Continental Wind, an indirect subsidiary of Exelon and Generation, 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 MW. The net proceeds were distributed to Generation for its 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, 2020 and December 31, 2019, approximately $415 million and $447 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, 2020, the Continental Wind letter of credit facility had $114 million in letters of credit outstanding related to the project. In 2017, Generation’s interests in Continental Wind were contributed to EGRP. Refer to Note 23 - Variable Interest Entities for additional information on EGRP. Renewable Power Generation. In March 2016, RPG, an indirect subsidiary of Exelon and Generation, issued $150 million aggregate principal amount of a nonrecourse senior secured notes. The net proceeds were distributed to Generation 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, 2020 and December 31, 2019, approximately $95 million and $106 million were outstanding, respectively. In 2017, Generation’s interests in RPG were contributed to EGRP. Refer to Note 23 - Variable Interest Entities for additional information on EGRP. SolGen, LLC. In September 2016, SolGen, an indirect subsidiary of Exelon and Generation, issued $150 million aggregate principal amount of a nonrecourse senior secured notes. The net proceeds were distributed to Generation for general business purposes. The loan is scheduled to mature on September 30, 2036. The term loan bears interest at a fixed rate of 3.93% payable semi-annually. As of December 31, 2020 and December 31, 2019, approximately $125 million and $131 million were outstanding, respectively. As a result of the sale agreement with an affiliate of Brookfield Renewable in the fourth quarter of 2020, the outstanding balance was reclassified to Liabilities held for sale in Exelon's and Generation's Consolidated Balance Sheets as of December 31, 2020. In 2017, Generation’s interests in SolGen were contributed to and were pledged as collateral for the EGR IV financing structure. In December 2020, as part of the EGR IV financing, SolGen was removed from the collateral terms structured within the agreement. See EGR IV discussed below for additional information and Note 2 — Mergers, Acquisitions, and Dispositions for additional information on the sale agreement. ExGen Renewables IV. In November 2017, EGR IV, an indirect subsidiary of Exelon and Generation, 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, EGR IV 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, EGR IV 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 2.75%, subject to a 1% LIBOR floor with interest payable quarterly. In addition to the financing, EGR IV 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 of 2020, and to settle the November 2017 interest rate swap. Generation’s interests in EGRP and Antelope Valley remained contributed to and are pledged as collateral for this financing. As of December 31, 2020, $750 million was outstanding. See Note 23 — Variable Interest Entities for additional information on EGRP and Note 16 — Derivative Financial Instruments for additional information on interest rate swaps.

Fair Value of Financial Assets

Fair Value of Financial Assets and Liabilities (All Registrants)	12 Months Ended
	Dec. 31, 2020
Fair Value Disclosures [Abstract]
Fair Value of Financial Assets and Liabilities (All Registrants)	Fair Value of Financial Assets and Liabilities (All Registrants) Exelon measures and classifies 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 the Registrants 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 Registrants’ short-term liabilities, long-term debt, SNF obligation, and trust preferred securities (long-term debt to financing trusts or junior subordinated debentures) as of December 31, 2020 and 2019. The Registrants have no financial liabilities classified as Level 1. The carrying amounts of the Registrants’ short-term liabilities as presented on their Consolidated Balance Sheets are representative of their fair value (Level 2) because of the short-term nature of these instruments. December 31, 2020 December 31, 2019 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 (a) Exelon $ 36,912 $ 40,688 $ 3,064 $ 43,752 $ 36,039 $ 37,453 $ 2,580 $ 40,033 Generation 6,087 5,648 1,208 6,856 7,974 7,304 1,366 8,670 ComEd 8,983 11,117 — 11,117 8,491 9,848 — 9,848 PECO 3,753 4,553 50 4,603 3,405 3,868 50 3,918 BGE 3,664 4,366 — 4,366 3,270 3,649 — 3,649 PHI 7,006 6,099 1,806 7,905 6,563 5,902 1,164 7,066 Pepco 3,165 3,336 748 4,084 2,864 3,198 388 3,586 DPL 1,677 1,484 455 1,939 1,567 1,408 311 1,719 ACE 1,413 1,018 602 1,620 1,327 1,026 464 1,490 Long-Term Debt to Financing Trusts (a) Exelon $ 390 $ — $ 467 $ 467 $ 390 $ — $ 428 $ 428 ComEd 205 — 246 246 205 — 227 227 PECO 184 — 221 221 184 — 201 201 SNF Obligation Exelon $ 1,208 $ 909 $ — $ 909 $ 1,199 $ 1,055 $ — $ 1,055 Generation 1,208 909 — 909 1,199 1,055 — 1,055 __________ (a) Includes unamortized debt issuance costs which are not fair valued. Refer to Note 17 — Debt and Credit Agreements for each Registrants’ unamortized debt issuance costs . Exelon uses the following methods and assumptions to estimate fair value of financial liabilities recorded at carrying cost: Type Level Registrants Valuation Long-Term Debt, including amounts due within one year Taxable Debt Securities 2 All 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. Exelon obtains credit spreads based on trades of existing Exelon 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 Exelon, Generation, DPL Debt rates are reset on a regular basis and the carrying value approximates fair value. Taxable Private Placement Debt Securities 3 Exelon, Pepco, DPL, ACE Rates are obtained similar to the process for taxable debt securities. Due to low trading volume and qualitative factors such as market conditions, low volume of investors, and investor demand, these debt securities are Level 3. Government Backed Fixed Rate Project Financing Debt 3 Exelon, Generation 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 Exelon, Generation, Pepco 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. Long-Term Debt to Financing Trusts Long Term Debt to Financing Trusts 3 Exelon, ComEd, PECO Fair value is based on publicly traded securities issued by the financing trusts. Due to low trading volume of these securities and qualitative factors, such as market conditions, investor demand, and circumstances related to each issue, this debt is classified as Level 3. SNF Obligation SNF Obligation 2 Exelon, Generation The carrying amount is derived from a contract with the DOE to provide for disposal of SNF from Generation’s nuclear generating stations. 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 Generation’s discount rate, which is calculated using the same methodology as described above for the taxable debt securities, and an estimated maturity date of 2035 and 2030 for the years ended December 31, 2020 and 2019, respectively. Recurring Fair Value Measurements The following tables present assets and liabilities measured and recorded at fair value in the Registrants' Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2020 and 2019: Exelon and Generation Exelon Generation As of December 31, 2020 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) $ 686 $ — $ — $ — $ 686 $ 124 $ — $ — $ — $ 124 NDT fund investments Cash equivalents (b) 210 95 — — 305 210 95 — — 305 Equities 3,886 2,077 — 1,562 7,525 3,886 2,077 — 1,562 7,525 Fixed income Corporate debt (c) — 1,485 285 — 1,770 — 1,485 285 — 1,770 U.S. Treasury and agencies 1,871 126 — — 1,997 1,871 126 — — 1,997 Foreign governments — 56 — — 56 — 56 — — 56 State and municipal debt — 101 — — 101 — 101 — — 101 Other — 41 — 961 1,002 — 41 — 961 1,002 Fixed income subtotal 1,871 1,809 285 961 4,926 1,871 1,809 285 961 4,926 Private credit — — 212 629 841 — — 212 629 841 Private equity — — — 504 504 — — — 504 504 Real estate — — — 679 679 — — — 679 679 NDT fund investments subtotal (d)(e) 5,967 3,981 497 4,335 14,780 5,967 3,981 497 4,335 14,780 Rabbi trust investments Cash equivalents 60 — — — 60 4 — — — 4 Mutual funds 91 — — — 91 29 — — — 29 Fixed income — 11 — — 11 — — — — — Life insurance contracts — 87 34 — 121 — 28 — — 28 Rabbi trust investments subtotal 151 98 34 — 283 33 28 — — 61 Investments in equities (f) 195 — — — 195 195 — — — 195 Commodity derivative assets Economic hedges 745 1,914 1,599 — 4,258 745 1,914 1,599 — 4,258 Proprietary trading — 17 27 — 44 — 17 27 — 44 Effect of netting and allocation of collateral (g)(h) (607) (1,597) (905) — (3,109) (607) (1,597) (905) — (3,109) Commodity derivative assets subtotal 138 334 721 — 1,193 138 334 721 — 1,193 DPP consideration — 639 — — 639 — 639 — — 639 Total assets 7,137 5,052 1,252 4,335 17,776 6,457 4,982 1,218 4,335 16,992 Liabilities Commodity derivative liabilities Economic hedges (682) (1,928) (1,655) — (4,265) (682) (1,928) (1,354) — (3,964) Proprietary trading — (21) (4) — (25) — (21) (4) — (25) Effect of netting and allocation of collateral (g)(h) 540 1,918 1,067 — 3,525 540 1,918 1,067 — 3,525 Commodity derivative liabilities subtotal (142) (31) (592) — (765) (142) (31) (291) — (464) Deferred compensation obligation — (145) — — (145) — (42) — — (42) Total liabilities (142) (176) (592) — (910) (142) (73) (291) — (506) Total net assets $ 6,995 $ 4,876 $ 660 $ 4,335 $ 16,866 $ 6,315 $ 4,909 $ 927 $ 4,335 $ 16,486 Exelon Generation As of December 31, 2019 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) $ 639 $ — $ — $ — $ 639 $ 214 $ — $ — $ — $ 214 NDT fund investments Cash equivalents (b) 365 87 — — 452 365 87 — — 452 Equities 3,353 1,801 — 1,388 6,542 3,353 1,801 — 1,388 6,542 Fixed income Corporate debt (c) — 1,421 257 — 1,678 — 1,421 257 — 1,678 U.S. Treasury and agencies 1,808 131 — — 1,939 1,808 131 — — 1,939 Foreign governments — 42 — — 42 — 42 — — 42 State and municipal debt — 90 — — 90 — 90 — — 90 Other — 33 — 953 986 — 33 — 953 986 Fixed income subtotal 1,808 1,717 257 953 4,735 1,808 1,717 257 953 4,735 Private credit — — 254 508 762 — — 254 508 762 Private equity — — — 402 402 — — — 402 402 Real estate — — — 607 607 — — — 607 607 NDT fund investments subtotal (d)(e) 5,526 3,605 511 3,858 13,500 5,526 3,605 511 3,858 13,500 Rabbi trust investments Cash equivalents 50 — — — 50 4 — — — 4 Mutual funds 81 — — — 81 25 — — — 25 Fixed income — 12 — — 12 — — — — — Life insurance contracts — 78 41 — 119 — 25 — — 25 Rabbi trust investments subtotal 131 90 41 — 262 29 25 — — 54 Commodity derivative assets Economic hedges 768 2,491 1,485 — 4,744 768 2,491 1,485 — 4,744 Proprietary trading — 37 60 — 97 — 37 60 — 97 Effect of netting and allocation of collateral (g)(h) (908) (2,162) (588) — (3,658) (908) (2,162) (588) — (3,658) Commodity derivative assets subtotal (140) 366 957 — 1,183 (140) 366 957 — 1,183 Total assets 6,156 4,061 1,509 3,858 15,584 5,629 3,996 1,468 3,858 14,951 Liabilities Commodity derivative liabilities Economic hedges (1,071) (2,855) (1,228) — (5,154) (1,071) (2,855) (927) — (4,853) Proprietary trading — (34) (15) — (49) — (34) (15) — (49) Effect of netting and allocation of collateral (g)(h) 1,071 2,714 802 — 4,587 1,071 2,714 802 — 4,587 Commodity derivative liabilities subtotal — (175) (441) — (616) — (175) (140) — (315) Deferred compensation obligation — (147) — — (147) — (41) — — (41) Total liabilities — (322) (441) — (763) — (216) (140) — (356) Total net assets $ 6,156 $ 3,739 $ 1,068 $ 3,858 $ 14,821 $ 5,629 $ 3,780 $ 1,328 $ 3,858 $ 14,595 __________ (a) Exelon excludes cash of $409 million and $373 million at December 31, 2020 and 2019, respectively, and restricted cash of $59 million and $110 million at December 31, 2020 and 2019, respectively, and includes long-term restricted cash of $53 million and $177 million at December 31, 2020 and 2019, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. Generation excludes cash of $171 million and $177 million at December 31, 2020 and 2019, respectively, and restricted cash of $20 million and $58 million at December 31, 2020 and 2019, respectively. (b) Includes $116 million and $90 million of cash received from outstanding repurchase agreements at December 31, 2020 and 2019, 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 $(62) million and $(48) million as of December 31, 2020 and 2019, respectively, held in an investment vehicle primarily to hedge the equity option component of its convertible debt. (d) Includes derivative assets of $2 million and $2 million, which have total notional amounts of $1,043 million and $724 million at December 31, 2020 and 2019, 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 Exelon and Generation's exposure to credit or market loss. (e) Excludes net liabilities of $181 million and $147 million at December 31, 2020 and 2019, respectively, which include certain derivative assets that have notional amounts of $104 million and $99 million at December 31, 2020 and 2019, 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) Reflects equity investments held by Generation which were previously designated as equity investments without readily determinable fair values but are now publicly traded and therefore have readily determinable fair values. Generation recorded the fair value of these investments in Other current assets on Exelon's and Generation's Consolidated Balance Sheets based on the quoted market prices of the stocks at December 31, 2020, which resulted in an unrealized gain of $186 million within Other, net in Exelon's and Generation's Consolidated Statement of Operations and Comprehensive Income for the year ended December 31, 2020. (g) Collateral posted/(received) from counterparties, net of collateral paid to counterparties, totaled $(67) million, $321 million, and $162 million allocated to Level 1, Level 2, and Level 3 mark-to-market derivatives, respectively, as of December 31, 2020. Collateral posted/(received) from counterparties, net of collateral paid to counterparties, totaled $163 million, $551 million, and $214 million allocated to Level 1, Level 2, and Level 3 mark-to-market derivatives, respectively, as of December 31, 2019. (h) Of the collateral posted/(received), $209 million and $511 million represents variation margin on the exchanges as of December 31, 2020 and 2019, respectively. As of December 31, 2020, Exelon and Generation have outstanding commitments to invest in private credit, private equity, and real estate investments of approximately $195 million, $254 million, and $369 million, respectively. These commitments will be funded by Generation’s existing NDT funds. Exelon and Generation held investments without readily determinable fair values with carrying amounts of $73 million and $55 million as of December 31, 2020, respectively. Exelon and Generation held investments without readily determinable fair values with carrying amounts of $69 million as of December 31, 2019. Changes in fair value, cumulative adjustments, and impairments were not material for the years ended December 31, 2020 and December 31, 2019. ComEd, PECO, and BGE ComEd PECO BGE As of December 31, 2020 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets Cash equivalents (a) $ 285 $ — $ — $ 285 $ 8 $ — $ — $ 8 $ 120 $ — $ — $ 120 Rabbi trust investments Mutual funds — — — — 9 — — 9 10 — — 10 Life insurance contracts — — — — — 13 — 13 — — — — Rabbi trust investments subtotal — — — — 9 13 — 22 10 — — 10 Total assets 285 — — 285 17 13 — 30 130 — — 130 Liabilities Mark-to-market derivative liabilities (b) — — (301) (301) — — — — — — — — Deferred compensation obligation — (8) — (8) — (9) — (9) — (5) — (5) Total liabilities — (8) (301) (309) — (9) — (9) — (5) — (5) Total net assets (liabilities) $ 285 $ (8) $ (301) $ (24) $ 17 $ 4 $ — $ 21 $ 130 $ (5) $ — $ 125 ComEd PECO BGE As of December 31, 2019 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets Cash equivalents (a) $ 280 $ — $ — $ 280 $ 15 $ — $ — $ 15 $ — $ — $ — $ — Rabbi trust investments Mutual funds — — — — 8 — — 8 8 — — 8 Life insurance contracts — — — — — 11 — 11 — — — — Rabbi trust investments subtotal — — — — 8 11 — 19 8 — — 8 Total assets 280 — — 280 23 11 — 34 8 — — 8 Liabilities Mark-to-market derivative liabilities (b) — — (301) (301) — — — — — — — — Deferred compensation obligation — (8) — (8) — (9) — (9) — (5) — (5) Total liabilities — (8) (301) (309) — (9) — (9) — (5) — (5) Total net assets (liabilities) $ 280 $ (8) $ (301) $ (29) $ 23 $ 2 $ — $ 25 $ 8 $ (5) $ — $ 3 __________ (a) ComEd excludes cash of $83 million and $90 million at December 31, 2020 and 2019, respectively, and restricted cash of $37 million and $33 million at December 31, 2020 and 2019, respectively, and includes long-term restricted cash of $43 million and $163 million at December 31, 2020 and 2019, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. PECO excludes cash of $18 million and $12 million at December 31, 2020 and 2019, respectively. BGE excludes cash of $24 million at both December 31, 2020 and 2019, respectively, and restricted cash of $1 million at both December 31, 2020 and 2019, respectively. (b) The Level 3 balance consists of the current and noncurrent liability of $33 million and $268 million, respectively, at December 31, 2020 and $32 million and $269 million, respectively, at December 31, 2019 related to floating-to-fixed energy swap contracts with unaffiliated suppliers. PHI, Pepco, DPL, and ACE As of December 31, 2020 As of December 31, 2019 PHI Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets Cash equivalents (a) $ 86 $ — $ — $ 86 $ 124 $ — $ — $ 124 Rabbi trust investments Cash equivalents 55 — — 55 44 — — 44 Mutual funds 14 — — 14 14 — — 14 Fixed income — 11 — 11 — 12 — 12 Life insurance contracts — 26 34 60 — 24 41 65 Rabbi trust investments subtotal 69 37 34 140 58 36 41 135 Total assets 155 37 34 226 182 36 41 259 Liabilities Deferred compensation obligation — (17) — (17) — (19) — (19) Total liabilities — (17) — (17) — (19) — (19) Total net assets $ 155 $ 20 $ 34 $ 209 $ 182 $ 17 $ 41 $ 240 Pepco DPL ACE As of December 31, 2020 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets Cash equivalents (a) $ 35 $ — $ — $ 35 $ — $ — $ — $ — $ 13 $ — $ — $ 13 Rabbi trust investments Cash equivalents 53 — — 53 — — — — — — — — Fixed income — 2 — 2 — — — — — — — — Life insurance contracts — 26 34 60 — — — — — — — — Rabbi trust investments subtotal 53 28 34 115 — — — — — — — — Total assets 88 28 34 150 — — — — 13 — — 13 Liabilities Deferred compensation obligation — (2) — (2) — — — — — — — — Total liabilities — (2) — (2) — — — — — — — — Total net assets $ 88 $ 26 $ 34 $ 148 $ — $ — $ — $ — $ 13 $ — $ — $ 13 Pepco DPL ACE As of December 31, 2019 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets Cash equivalents (a) $ 34 $ — $ — $ 34 $ — $ — $ — $ — $ 16 $ — $ — $ 16 Rabbi trust investments Cash equivalents 43 — — 43 — — — — — — — — Fixed income — 2 — 2 — — — — — — — — Life insurance contracts — 24 41 65 — — — — — — — — Rabbi trust investments subtotal 43 26 41 110 — — — — — — — — Total assets 77 26 41 144 — — — — 16 — — 16 Liabilities Deferred compensation obligation — (2) — (2) — — — — — — — — Total liabilities — (2) — (2) — — — — — — — — Total net assets $ 77 $ 24 $ 41 $ 142 $ — $ — $ — $ — $ 16 $ — $ — $ 16 __________ (a) PHI excludes cash of $74 million and $57 million at December 31, 2020 and 2019, respectively, and includes long-term restricted cash of $10 million and $14 million at December 31, 2020 and 2019, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. Pepco excludes cash of $30 million and $29 million at December 31, 2020 and 2019, respectively. DPL excludes cash of $15 million and $13 million at December 31, 2020 and 2019, respectively. ACE excludes cash of $17 million and $12 million at December 31, 2020 and 2019, respectively, and includes long-term restricted cash of $10 million and $14 million at December 31, 2020 and 2019, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. 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, 2020 and 2019: Exelon Generation ComEd PHI and Pepco For the year ended December 31, 2020 Total NDT Fund Investments Mark-to-Market Total Generation Mark-to-Market Life Insurance Contracts Eliminated in Consolidation Balance as of January 1, 2020 $ 1,068 $ 511 $ 817 $ 1,328 $ (301) $ 41 $ — Total realized / unrealized gains (losses) Included in net income (409) 2 (414) (a) (412) — 3 — Included in noncurrent payables to affiliates — 21 — 21 — — (21) Included in regulatory assets/liabilities 21 — — — — (b) — 21 Change in collateral (53) — (53) (53) — — — Purchases, sales, issuances and settlements Purchases 151 8 143 151 — — — Sales (27) — (27) (27) — — — Settlements (55) (45) — (45) — (10) — Transfers into Level 3 (12) — (12) (c) (12) — — — Transfers out of Level 3 (24) — (24) (c) (24) — — — Balance as of December 31, 2020 $ 660 $ 497 $ 430 $ 927 $ (301) $ 34 $ — The amount of total gains included in net income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of December 31, 2020 $ 11 $ 2 $ 6 $ 8 $ — $ 3 $ — Exelon Generation ComEd PHI and Pepco For the year ended December 31, 2019 Total NDT Fund Investments Mark-to-Market Total Generation Mark-to-Market Life Insurance Contracts Eliminated in Consolidation Balance as of January 1, 2019 $ 907 $ 543 $ 575 $ 1,118 $ (249) $ 38 $ — Total realized / unrealized gains (losses) Included in net income (23) 5 (31) (a) (26) — 3 — Included in noncurrent payables to affiliates — 34 — 34 — — (34) Included in regulatory assets/liabilities (18) — — — (52) (b) — 34 Change in collateral 138 — 138 138 — — — Purchases, sales, issuances and settlements Purchases 176 44 132 176 — — — Sales (23) (21) (2) (23) — — — Settlements (89) (94) 5 (89) — — — Transfers into Level 3 5 — 5 (c) 5 — — — Transfers out of Level 3 (5) — (5) (c) (5) — — — Balance as of December 31, 2019 $ 1,068 $ 511 $ 817 $ 1,328 $ (301) $ 41 $ — The amount of total gains included in net income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of December 31, 2019 $ 359 $ 5 $ 351 $ 356 $ — $ 3 $ — __________ (a) Includes a reduction for the reclassification of $420 million and $377 million of realized gains due to the settlement of derivative contracts for the years ended December 31, 2020 and 2019, respectively. (b) Includes $33 million of decreases in fair value and an increase for realized losses due to settlements of $33 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2020. Includes $78 million of decreases in fair value and an increase for realized losses due to settlements of $26 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2019. (c) Transfers into and out of Level 3 generally occur when the contract tenor becomes less and more observable, respectively, primarily due to changes in market liquidity or assumptions for certain commodity contracts. The following tables present the income statement classification of the total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2020 and 2019: Exelon Generation PHI and Pepco Operating Purchased Operating and Maintenance Other, net Operating Purchased Other, net Operating and Total (losses) gains included in net income for the year ended December 31, 2020 $ (404) $ (10) $ 3 $ 2 $ (404) $ (10) $ 2 $ 3 Change in unrealized (losses) gains relating to assets and liabilities held for the year ended December 31, 2020 (31) 37 3 2 (31) 37 2 3 Exelon Generation PHI and Pepco Operating Purchased Operating and Maintenance Other, net Operating Purchased Other, net Operating and Total gains (losses) included in net income for the year ended December 31, 2019 $ 219 $ (245) $ 3 $ 5 $ 219 $ (245) $ 5 $ 3 Change in unrealized gains (losses) relating to assets and liabilities held for the year ended December 31, 2019 546 (195) 3 5 546 (195) 5 3 Valuation Techniques Used to Determine Fair Value Cash Equivalents (All Registrants). 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 (Exelon and Generation). The trust fund investments have been established to satisfy Generation’s and CENG's 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. Generation’s and CENG's 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 Exelon and Generation 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 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. 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 considered to be preferable. Exelon and Generation have obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, Exelon and Generation 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 Exelon and Generation 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 Exelon's 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

Commitments and Contingencies (

Commitments and Contingencies (All Registrants)	12 Months Ended
Commitments and Contingencies (All Registrants)	Dec. 31, 2020
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies (All Registrants)	Commitments and Contingencies (All Registrants) Commitments PHI Merger Commitments (Exelon, PHI, Pepco, DPL, and ACE). Approval of the PHI merger in Delaware, New Jersey, Maryland, and the District of Columbia was conditioned upon Exelon and PHI agreeing to certain commitments. The following amounts represent total commitment costs that have been recorded since the acquisition date and the total remaining obligations for Exelon, PHI, Pepco, DPL, and ACE as of December 31, 2020: Description Exelon PHI Pepco DPL ACE Total commitments $ 513 $ 320 $ 120 $ 89 $ 111 Remaining commitments (a) 82 67 55 7 5 __________ (a) Remaining commitments extend through 2026 and include rate credits, energy efficiency programs, and delivery system modernization. In addition, Exelon is committed to develop or to assist in the commercial development of approximately 37 MWs of new solar generation in Maryland, District of Columbia, and Delaware at an estimated cost of approximately $135 million , which will generate future earnings at Exelon and Generation. Investment costs, which are expected to be primarily capital in nature, are recognized as incurred and recorded in Exelon's and Generation's financial statements. As of December 31, 2020, 27 MWs of new generation were developed and Exelon and Generation have incurred costs of $119 million . Exelon has also committed to purchase 100 MWs of wind energy in PJM. DPL has committed to conducting three RFPs to procure up to a total of 120 MWs of wind RECs for the purpose of meeting Delaware's renewable portfolio standards. DPL has conducted two of the three wind REC RFPs. The first 40 MW wind REC tranche was conducted in 2017 and did not result in a purchase agreement. The second 40 MW wind REC tranche was conducted in 2018 and resulted in a proposed REC purchase agreement that was approved by the DPSC in March 2019. The third and final 40 MW wind REC tranche will be conducted in 2022. Commercial Commitments (All Registrants). The Registrants' commercial commitments as of December 31, 2020, representing commitments potentially triggered by future events, were as follows: Expiration within Exelon Total 2021 2022 2023 2024 2025 2026 and beyond Letters of credit $ 1,243 $ 1,179 $ 50 $ 14 $ — $ — $ — Surety bonds (a) 1,070 1,017 53 — — — — Financing trust guarantees 378 — — — — — 378 Guaranteed lease residual values (b) 28 2 3 3 6 5 9 Total commercial commitments $ 2,719 $ 2,198 $ 106 $ 17 $ 6 $ 5 $ 387 Generation Letters of credit $ 1,228 $ 1,164 $ 50 $ 14 $ — $ — $ — Surety bonds (a) 926 873 53 — — — — Total commercial commitments $ 2,154 $ 2,037 $ 103 $ 14 $ — $ — $ — ComEd Letters of credit $ 7 $ 7 $ — $ — $ — $ — $ — Surety bonds (a) 16 16 — — — — — Financing trust guarantees 200 — — — — — 200 Total commercial commitments $ 223 $ 23 $ — $ — $ — $ — $ 200 PECO Surety bonds (a) $ 2 $ 2 $ — $ — $ — $ — $ — Financing trust guarantees 178 — — — — — 178 Total commercial commitments $ 180 $ 2 $ — $ — $ — $ — $ 178 BGE Letters of credit $ 2 $ 2 $ — $ — $ — $ — $ — Surety bonds (a) 3 3 — — — — — Total commercial commitments $ 5 $ 5 $ — $ — $ — $ — $ — PHI Surety bonds (a) $ 22 $ 22 $ — $ — $ — $ — $ — Guaranteed lease residual values (b) 28 2 3 3 6 5 9 Total commercial commitments $ 50 $ 24 $ 3 $ 3 $ 6 $ 5 $ 9 Pepco Surety bonds (a) $ 14 $ 14 $ — $ — $ — $ — $ — Guaranteed lease residual values (b) 9 — 1 1 2 2 3 Total commercial commitments $ 23 $ 14 $ 1 $ 1 $ 2 $ 2 $ 3 DPL Surety bonds (a) $ 4 $ 4 $ — $ — $ — $ — $ — Guaranteed lease residual values (b) 12 1 1 1 3 2 4 Total commercial commitments $ 16 $ 5 $ 1 $ 1 $ 3 $ 2 $ 4 ACE Surety bonds (a) $ 4 $ 4 $ — $ — $ — $ — $ — Guaranteed lease residual values (b) 7 1 1 1 1 1 2 Total commercial commitments $ 11 $ 5 $ 1 $ 1 $ 1 $ 1 $ 2 __________ (a) Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds. (b) Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The lease term associated with these assets ranges from 1 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $71 million guaranteed by Exelon and PHI, of which $24 million , $30 million, and $17 million is guaranteed by Pepco, DPL, and ACE, respectively. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote. Nuclear Insurance (Exelon and Generation) Generation is subject to liability, property damage, and other risks associated with major incidents at any of its nuclear stations. Generation has mitigated its 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, 2020, the current liability limit per incident is $13.8 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, Generation maintains 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 $13.3 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. Generation’s share of this secondary layer would be approximately $2.9 billion , however any amounts payable under this secondary layer would be capped at $434 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 $13.8 billion limit for a single incident. As part of the execution of the NOSA on April 1, 2014, Generation executed an Indemnity Agreement pursuant to which Generation 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 CENG nuclear plants or their operations. Exelon guarantees Generation’s obligations under this indemnity. See Note 23 — Variable Interest Entities for additional information on Generation’s operations relating to CENG. Generation is required each year to report to the NRC the current levels and sources of property insurance that demonstrates Generation possesses sufficient financial resources to stabilize and decontaminate a reactor and reactor station site in the event of an accident. The property insurance maintained for each facility is currently provided through insurance policies purchased from NEIL, an industry mutual insurance company of which Generation is 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, but Generation cannot predict the level of future distributions or if they will continue at all. Generation's portion of the annual distribution declared by NEIL is estimated to be $75 million for 2020, and was $136 million and $58 million for 2019 and 2018, respectively. In addition, in March 2018, NEIL declared a supplemental distribution. Generation's portion of the supplemental distribution declared by NEIL was $31 million . The distributions were recorded as a reduction to Operating and maintenance expense within Exelon and Generation’s 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 Generation cannot predict the level of future assessments, if any. The current maximum aggregate annual retrospective premium obligation for Generation 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 Generation is required by the NRC to maintain, to provide for decommissioning the facility. In the event of an insured loss, Generation is unable to predict the timing of the availability of insurance proceeds to Generation 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 Generation 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 its insured losses, Generation is 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 Generation. Any such losses could have a material adverse effect on Exelon’s and Generation’s financial statements. Spent Nuclear Fuel Obligation (Exelon and Generation) 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, Generation is a party to contracts with the DOE (Standard Contracts) to provide for disposal of SNF from Generation’s nuclear generating stations. In accordance with the NWPA and the Standard Contracts, Generation historically had 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, Exelon and Generation will not accrue any further costs related to SNF disposal fees. This fee may be adjusted prospectively to ensure full cost recovery. Generation currently assumes the DOE will begin accepting SNF in 2035 and uses that date for purposes of estimating the nuclear decommissioning asset retirement obligations. The SNF acceptance date assumption is based on management’s estimates 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 by no later than January 31, 1998. The DOE, however, failed to meet that deadline and its performance is expected to be delayed significantly. In August 2004, Generation and the DOJ, in close consultation with the DOE, reached a settlement under which the government agreed to reimburse Generation, subject to certain damage limitations based on the extent of the government’s breach, for costs associated with storage of SNF at Gene ration’s nuclear stations pending the DOE’s fulfillment of its obligations. Generation’s settlement agreement does not include FitzPatrick and FitzPatrick does not currently have a settlement agreement in place. 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. Generation submits annual reimbursement requests to the DOE for costs associated with the storage of SNF. In all cases, reimbursement requests are made only after costs are incurred and only for costs resulting from DOE delays in accepti ng the SNF. U nder the settlement agreements, Generation received total cumulative cash reimbursements of $1,455 million through December 31, 2020 for costs incurred. After considering the amounts due to co-owners of certain nuclear stations and to the former owner of Oyster Creek, Generation received net cumulative cash reimbursements of $1,266 million . As of December 31, 2020 and 2019, 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, 2020 December 31, 2019 DOE receivable - current (a) $ 129 $ 249 DOE receivable - noncurrent (b) 70 30 Amounts owed to co-owners (c) (23) (37) __________ (a) Recorded in Accounts receivable, other. (b) Recorded in Deferred debits and other assets, other. (c) Recorde d in Accounts receivable, other. Represents amounts owed to the co-owners of Peach Bottom, Quad Cities, and Nine Mile Point Unit 2 generating facilitie s. The Standard Contracts with the DOE also required the payment to the DOE of a one-time fee applicable to nuclear generation through April 6, 1983. The below table outlines the SNF liability recorded at Exelon and Generation as of December 31, 2020 and 2019: December 31, 2020 December 31, 2019 Former ComEd units (a) $ 1,082 $ 1,075 Fitzpatrick (b) 126 124 Total SNF Obligation $ 1,208 $ 1,199 __________ (a) ComEd previously elected to defer payment of the one-time fee of $277 million for its units (which are now part of Generation), 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 Generation 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, Generation 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 Exelon's and Generation's 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, 2020 was 0.096% for the deferred amount transferred from ComEd and 0.101% for the deferred FitzPatrick amount. The following table summarizes sites for which Exelon and Generation 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 (All Registrants). The Registrants’ 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, the Registrants are generally liable for the costs of remediating environmental contamination of property now or formerly owned by them and of property contaminated by hazardous substances generated by them. The Registrants own or lease a number of real estate parcels, including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. In addition, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future. Unless otherwise disclosed, the Registrants cannot reasonably estimate whether they will incur significant liabilities for additional investigation and remediation costs at these or additional sites identified by the Registrants, environmental agencies, or others, or whether such costs will be recoverable from third parties, including customers. Additional costs could have a material, unfavorable impact on the Registrants' financial statements. MGP Sites (Exelon and the Utility Registrants). ComEd, PECO, BGE, and DPL have identified sites where former MGP or gas purification activities have or may have resulted in actual site contamination. For almost all of these sites, there are additional PRPs that may share responsibility for the ultimate remediation of each location. • ComEd has 21 sites that are currently under some degree of active study and/or remediation. ComEd expects the majority of the remediation at these sites to continue through at least 2026. • PECO ha s 8 sites that are currently under some degree of active study and/or remediation. PECO expects the majority of the remediation at these sites to continue through at least 2023. • BGE has 4 sites that currently require some level of remediation and/or ongoing activity. BGE expects the majority of the remediation at these sites to continue through at least 2023. • DPL has 1 site that is currently under study and the required cost at the site is not expected to be material. The historical nature of the MGP and gas purification sites and the fact that many of the sites have been buried and built over, impacts the ability to determine a precise estimate of the ultimate costs prior to initial sampling and determination of the exact scope and method of remedial activity. Management determines its best estimate of remediation costs using all available information at the time of each study, including probabilistic and deterministic modeling for ComEd and PECO, and the remediation standards currently required by the applicable state environmental agency. Prior to completion of any significant clean up, each site remediation plan is approved by the appropriate state environmental agency. ComEd, pursuant to an ICC order, and PECO, pursuant to settlements of natural gas distribution rate cases with the PAPUC, are currently recovering environmental remediation costs of former MGP facility sites through customer rates. While BGE and DPL do not have riders for MGP clean-up costs, they have historically received recovery of actual clean-up costs in distribution rates. As of December 31, 2020 and 2019, the Registrants had accrued the following undiscounted amounts for environmental liabilities in Other current liabilities and Other deferred credits and other liabilities within their respective Consolidated Balance Sheets: December 31, 2020 December 31, 2019 Total environmental Portion of total related to Total environmental Portion of total related to Exelon $ 483 $ 314 $ 478 $ 320 Generation 121 — 105 — ComEd 293 293 304 303 PECO 23 21 19 17 BGE 2 — 2 — PHI 44 — 48 — Pepco 42 — 46 — DPL 1 — 1 — ACE 1 — 1 — Cotter Corporation (Exelon and Generation). The EPA has advised Cotter Corporation (Cotter), a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill 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 in connection with the West Lake Landfill. In connection with Exelon’s 2001 corporate restructuring, this responsibility to indemnify Cotter was transferred to Generation. Including Cotter, there are three PRPs participating in the West Lake Landfill remediation proceeding. Investigation by Generation has identified a number of other parties who also may be PRPs and could be liable to contribute to the final remedy. Further investigation is ongoing. In September 2018, the EPA issued its Record of Decision (ROD) Amendment for the selection of a final remedy. The ROD Amendment modified the remedy previously selected by EPA in its 2008 ROD. While the 2008 ROD required only that the radiological materials and other wastes at the site be capped, the 2018 ROD Amendment requires partial excavation of the radiological materials in addition to the previously selected capping remedy. The ROD Amendment also allows for variation in depths of excavation depending on radiological concentrations. The EPA and the PRPs have entered into a Consent Agreement to perform the Remedial Design, which is expected to be completed by early 2022. In March 2019 the PRPs received Special Notice Letters from the EPA to perform the Remedial Action work. On October 8, 2019, Cotter (Generation’s indemnitee) provided a non-binding good faith offer to conduct, or finance, a portion of the remedy, subject to certain conditions. The total estimated cost of the remedy, taking into account the current EPA technical requirements and the total costs expected to be incurred collectively by the PRPs in fully executing the remedy, is approximately $280 million, including cost escalation on an undiscounted basis, which would be allocated among the final group of PRPs. Generation has determined that a loss associated with the EPA’s partial excavation and enhanced landfill cover remedy is probable and has recorded a liability, included in the table 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 Generation’s 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 Exelon's and Generation's future financial statements. One of the other PRPs has indicated it will be making a contribution claim against Cotter for costs that it has incurred to prevent the subsurface fire from spreading to those areas of the West Lake Landfill where radiological materials are believed to have been disposed. At this time, Exelon and Generation do not have sufficient information to assess this claim and therefore are unable to estimate a range of loss, if any. As such, no liability has been recorded for the potential contribution claim. It is reasonably possible, however, that resolution of this matter could have a material, unfavorable impact on Exelon’s and Generation's financial statements. In January 2018, the PRPs were advised by the EPA that it will begin an additional investigation and evaluation of groundwater conditions at the West Lake Landfill. In September 2018, the PRPs agreed to an Administrative Settlement Agreement and Order on Consent for the performance by the PRPs of the groundwater Remedial Investigation (RI)/Feasibility Study (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. Generation estimates the undiscounted cost for the groundwater RI/FS to be approximately $30 million . Generation determined a loss associated with the RI/FS is probable and has recorded a liability, included in the table above, that reflects management’s best estimate of Cotter’s allocable share of the cost among the PRPs. At this time Generation cannot predict the likelihood that, or the extent to which 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 Exelon’s and Generation’s future financial statements. 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. The Latty Avenue site is included in ComEd’s (now Generation's) indemnification responsibilities discussed above as part of the sale of Cotter. The radioactive residues had been generated initially in connection with the processing of uranium ores as part of the U.S. Government’s Manhattan Project. Cotter purchased the residues in 1969 for initial processing at the Latty Avenue facility for the subsequent extraction of uranium and metals. In 1976, the NRC found that the Latty Avenue site had radiation levels exceeding NRC criteria for decontamination of land areas. Latty Avenue was investigated and remediated by the United States Army Corps of Engineers pursuant to funding under FUSRAP. Pursuant to a series of annual agreements since 2011, the DOJ and the PRPs have tolled the statute of limitations until August 31, 2021 so that settlement discussions can proceed. On August 3, 2020, the DOJ advised Cotter and the other PRPs that it is seeking approximately $90 million from all the PRPs and has directed that the PRPs must submit a good faith joint proposed settlement offer . Generation has determined that a loss associated with this matter is probable under its indemnification agreement with Cotter and has recorded an estimated liability, which is included in the table above. Benning Road Site (Exelon, Generation, PHI, and Pepco) . In September 2010, PHI received a letter from EPA identifying the Benning Road site as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. A portion of the site was formerly the location of a Pepco Energy Services electric generating facility, which was deactivated in June 2012. The remaining portion of the site consists of a Pepco transmission and distribution service center that remains in operation. In December 2011, the U.S. District Court for the District of Columbia approved a Consent Decree entered into by Pepco and Pepco Energy Services with the DOEE, which requires Pepco and Pepco Energy Services to conduct a RI/FS for the Benning Road site and an approximately 10 to 15-acre portion of the adjacent Anacostia River. Since 2013, Pepco and Pepco Energy Services (now Generation, pursuant to Exelon's 2016 acquisition of PHI) have been performing RI work and have submitted multiple draft RI reports to the DOEE. In September 2019, Pepco and Generation issued a draft “final” RI report which DOEE approved on February 3, 2020. Pepco and Generation are developing a FS to evaluate possible remedial alternatives for submission to DOEE. The Court has established a schedule for completion of the FS, and approval by the DOEE, by September 16, 2021. After completion and approval of the FS, DOEE will prepare a Proposed Plan for public comment and then issue a ROD identifying any further response actions determined to be necessary. PHI, Pepco, and Generation have determined that a loss associated with this matter is probable and have accrued an estimated liability, which is included in the table above. Anacostia River Tidal Reach (Exelon, PHI, and Pepco) . Contemporaneous with the Benning Road site RI/FS being performed by Pepco and Generation, DOEE and the National Park Service have been conducting a separate RI/FS focused on the entire tidal reach of the Anacostia River extending from just north of the Maryland-District of Columbia boundary line to the confluence of the Anacostia and Potomac Rivers. The river-wide RI incorporated the results of the river sampling performed by Pepco and Pepco Energy Services as part of the Benning RI/FS, as well as similar sampling efforts conducted by owners of other sites adjacent to this segment of the river and supplemental river sampling conducted by DOEE’s contractor. In April 2018, DOEE released a draft RI report for public review and comment. Pepco submitted written comments on the draft RI and participated in a public hearing. Pepco has determined that it is probable that costs for remediation will be incurred and recorded a liability in the third quarter 2019 for management’s best estimate of its share of those costs. On September 30, 2020, DOEE released its Interim ROD. The Interim ROD reflects an adaptive management approach which will require several identified “hot spots” in the river to be addressed first while continuing to conduct studies and to monitor the river to evaluate improvements and determine potential future remediation plans. The adaptive management process chosen by DOEE is less intrusive, provides more long-term environmental certainty, is less costly, and allows for site specific remediation plans already underway, including the plan for the Benning Road site to proceed to conclusion. Pepco has concluded that incremental exposure remains reasonably possible, but management cannot reasonably estimate a range of loss beyond the amounts recorded, which are included in the table above. In addition to the activities associated with the remedial process outlined above, CERCLA separately requires federal and state (here including Washington, D.C.) Natural Resource Trustees (federal or state agencies designated by the President or the relevant state, respectively, or Indian tribes) to conduct an assessment of any damages to natural resources within their jurisdiction as a result of the contamination that is being remediated. The Trustees can seek compensation from responsible parties for such damages, including restoration costs. During the second quarter of 2018, Pepco became aware that the Trustees are in the beginning stages of a Natural Resources Damages (NRD) assessment, a process that often takes many years beyond the remedial decision to complete. Pepco has concluded that a loss associated with the eventual NRD assessment is reasonably possible. Due to the very early stage of the assessment process, Pepco cannot reasonably estimate the range of loss. Litigation and Regulatory Matters Asbestos Personal Injury Claims (Exelon and Generation). Generation maintains a reserve for claims associated with asbestos-related personal injury actions in certain facilities that are currently owned by Generation or were previously owned by ComEd and PECO. 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, 2020 and 2019, Exelon and Generation recorded estimated liabilities of approximately $89 million and $83 million, respectively, in total for asbestos-related bodily injury claims. As of December 31, 2020, approximately $25 million of this amount related to 261 open claims presented to Generation, while the remaining $64 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, Generation monitors actual experience against the number of forecasted claims to be received and expected claim payments and evaluates whether adjustments to the estimated liabilities are necessary. It is reasonably possible that additional exposure to estimated future asbestos-related bodily injury claims in excess of the amount accrued could have a material, unfavorable impact on Exelon’s and Generation’s financial statements. However, management cannot reasonably estimate a range of loss beyond the amounts recorded. Fund Transfer Restrictions (All Registrants). Under applicable law, Exelon may borrow or receive an extension of credit from its subsidiaries. Under the terms of Exelon’s intercompany money pool agreement, Exelon can lend to, but not borrow from the money pool. Under

Shareholders' Equity (Exelon an

Shareholders' Equity (Exelon and Utility Registrants)	12 Months Ended
Shareholders' Equity (Exelon and Utility Registrants)	Dec. 31, 2020
Equity [Abstract]
Shareholders' Equity (Exelon and Utility Registrants) [Text Block]	Shareholders' Equity (Exelon and Utility Registrants)ComEd Common Stock Warrants The following table presents warrants outstanding to purchase ComEd common stock and shares of common stock reserved for the conversion of warrants. The warrants entitle the holders to convert such warrants into common stock of ComEd at a conversion rate of one share of common stock for three warrants. December 31, 2020 2019 Warrants outstanding 60,143 60,228 Common Stock reserved for conversion 20,048 20,076 Share Repurchases There currently is no Exelon Board of Director authority to repurchase shares. Any previous shares repurchased are held as treasury shares, at cost, unless cancelled or reissued at the discretion of Exelon’s management. Preferred and Preference Securities The following table presents Exelon, ComEd, PECO, BGE, Pepco, and ACE's shares of preferred securities authorized, none of which were outstanding as of December 31, 2020 and 2019. There are no shares of preferred securities authorized for DPL. Preferred Securities Authorized Exelon 100,000,000 ComEd 850,000 PECO 15,000,000 BGE 1,000,000 Pepco 6,000,000 ACE (a) 2,799,979 __________ (a) Includes 799,979 shares of cumulative preferred stock and 2,000,000 of no-par preferred stock as of December 31, 2020 and 2019. The following table presents ComEd's, BGE's, and ACE's preference securities authorized, none of which were outstanding as of December 31, 2020 and 2019. There are no shares of preference securities authorized for Exelon, PECO, Pepco, and DPL. Preference Securities Authorized ComEd 6,810,451 BGE (a) 6,500,000 ACE 3,000,000 __________

Stock-Based Compensation Plans

Stock-Based Compensation Plans Stock-Based Compensation Plans (All Registrants)	12 Months Ended
	Dec. 31, 2020
Common Stock [Abstract]
Stock-Based Compensation Plans	Stock-Based Compensation Plans (All Registrants) Stock-Based Compensation Plans Exelon grants stock-based awards through its LTIP, which primarily includes performance share awards, restricted stock units, and stock options. At December 31, 2020, there were approximately 34 million shares authorized for issuance under the LTIP. For the years ended December 31, 2020, 2019, and 2018, exercised and distributed stock-based awards were primarily issued from authorized but unissued common stock shares. The Registrants grant cash awards. The following table does not include expense related to these plans as they are not considered stock-based compensation plans under the applicable authoritative guidance. The following table presents the stock-based compensation expense included in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. The Utility Registrants' stock-based compensation expense for the years ended December 31, 2020, 2019, and 2018 was not material. Year Ended December 31, Exelon 2020 2019 2018 Total stock-based compensation expense included in operating and maintenance expense $ 64 $ 77 $ 208 Income tax benefit (16) (20) (54) Total after-tax stock-based compensation expense $ 48 $ 57 $ 154 Generation Total stock-based compensation expense included in operating and maintenance expense $ 27 $ 37 $ 77 Income tax benefit (7) (10) (20) Total after-tax stock-based compensation expense $ 20 $ 27 $ 57 Exelon receives a tax deduction based on the intrinsic value of the award on the exercise date for stock options and the distribution date for performance share awards and restricted stock units. For each award, throughout the requisite service period, Exelon recognizes the tax benefit related to compensation costs. The following table presents information regarding Exelon’s realized tax benefit when distributed: Year Ended December 31, 2020 2019 2018 Performance share awards $ 21 $ 41 $ 16 Restricted stock units 15 24 28 Performance Share Awards Performance share awards are granted under the LTIP. The performance share awards are settled 50% in common stock and 50% in cash at the end of the three-year performance period, except for awards granted to vice presidents and higher officers that are settled 100% in cash if certain ownership requirements are satisfied. The common stock portion of the performance share awards is considered an equity award and is valued based on Exelon's 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 Exelon’s current stock price. As the value of the common stock and cash portions of the awards are based on Exelon’s stock price during the performance period, coupled with changes in the total shareholder return modifier and expected payout of the award, the compensation costs are subject to volatility until payout is established. For nonretirement-eligible employees, stock-based compensation costs 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. Exelon processes forfeitures as they occur for employees who do not complete the requisite service period. The following table summarizes Exelon’s nonvested performance share awards activity: Shares Weighted Average Nonvested at December 31, 2019 (a) 1,709,755 $ 39.21 Granted 1,122,378 46.61 Change in performance (751,309) 42.51 Vested (747,551) 35.70 Forfeited (67,964) 45.59 Undistributed vested awards (b) (334,917) 50.76 Nonvested at December 31, 2020 (a) 930,392 $ 43.67 __________ (a) Excludes 1,414,661 and 2,017,870 of performance share awards issued to retirement-eligible employees as of December 31, 2020 and 2019, respectively, as they are fully vested. (b) Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2020. The following table summarizes the weighted average grant date fair value and the total fair value of performance share awards vested. Year Ended December 31, 2020 (a) 2019 2018 Weighted average grant date fair value (per share) $ 46.61 $ 47.37 $ 38.15 Total fair value of performance shares vested 39 158 61 Total fair value of performance shares settled in cash 63 131 49 __________ (a) As of December 31, 2020, $13 million of total unrecognized compensation costs related to nonvested performance shares are expected to be recognized over the remaining weighted-average period of 1.8 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 of services is measured based on the grant date fair value of the restricted stock unit issued. The value of the restricted stock units is expensed over the requisite service period using the straight-line method. The requisite service period for restricted stock units is generally three The following table summarizes Exelon’s nonvested restricted stock unit activity: Shares Weighted Average Nonvested at December 31, 2019 (a) 1,498,713 $ 40.35 Granted 847,382 46.33 Vested (725,151) 38.38 Forfeited (52,046) 45.20 Undistributed vested awards (b) (454,768) 45.91 Nonvested at December 31, 2020 (a) 1,114,130 $ 43.67 __________ (a) Excludes 748,165 and 863,196 of restricted stock units issued to retirement-eligible employees as of December 31, 2020 and 2019, respectively, as they are fully vested. (b) Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2020. The following table summarizes the weighted average grant date fair value and the total fair value of restricted stock units vested. Year Ended December 31, 2020 (a) 2019 2018 Weighted average grant date fair value (per share) $ 46.33 $ 45.65 $ 38.60 Total fair value of restricted stock units vested 54 92 106 __________ (a) As of December 31, 2020, $23 million of total unrecognized compensation costs related to nonvested restricted stock units are expected to be recognized over the remaining weighted-average period of 2.3 years. Stock Options Non-qualified stock options to purchase shares of Exelon’s common stock were granted through 2012 under the LTIP. The exercise price of the stock options is equal to the fair market value of the underlying stock on the date of option grant. Stock options will expire no later than ten years from the date of grant. At December 31, 2020 all stock options were vested and there were no unrecognized compensation costs. The following table presents information with respect to stock option activity: Shares Weighted Weighted Aggregate Balance of shares outstanding at December 31, 2019 1,889,045 $ 40.43 1.56 $ 10 Options exercised (475,827) 38.30 5 Options expired (147,808) 46.07 Balance of shares outstanding at December 31, 2020 1,265,410 $ 40.57 0.91 $ 3 Exercisable at December 31, 2020 (a) 1,265,410 $ 40.57 0.91 $ 3 __________ (a) Includes stock options issued to retirement eligible employees. The following table summarizes additional information regarding stock options exercised: Year Ended December 31, 2020 2019 2018 Intrinsic value (a) $ 5 $ 9 $ 12 Cash received for exercise price 18 59 56 __________ (a) The difference between the market value on the date of exercise and the option exercise price.

Changes in Accumulated Other Co

Changes in Accumulated Other Comprehensive Income (Exelon)	12 Months Ended
Changes in Accumulated Other Comprehensive Income (Exelon)	Dec. 31, 2020
Equity [Abstract]
Changes in Accumulated Other Comprehensive Income (Exelon)	Changes in Accumulated Other Comprehensive Income (Exelon) The following tables present changes in Exelon's AOCI, net of tax, by component: Gains and Unrealized Pension and (a) Foreign AOCI of Investments (b) Total Balance at December 31, 2017 $ (14) $ 10 $ (2,998) $ (23) $ (1) $ (3,026) OCI before reclassifications 11 — (143) (10) 1 (141) Amounts reclassified from AOCI 1 — 181 — — 182 Net current-period OCI 12 — 38 (10) 1 41 Impact of adoption of Recognition and Measurement of Financial Assets and Financial Liabilities standard (c) — (10) — — — (10) Balance at December 31, 2018 $ (2) $ — $ (2,960) $ (33) $ — $ (2,995) OCI before reclassifications — — (289) 6 (2) (285) Amounts reclassified from AOCI — — 84 — 2 86 Net current-period OCI — — (205) 6 — (199) Balance at December 31, 2019 $ (2) $ — $ (3,165) $ (27) $ — $ (3,194) OCI before reclassifications (3) — (357) 4 — (356) Amounts reclassified from AOCI — — 150 — — 150 Net current-period OCI (3) — (207) 4 — (206) Balance at December 31, 2020 $ (5) $ — $ (3,372) $ (23) $ — $ (3,400) __________ (a) This AOCI component is included in the computation of net periodic pension and OPEB cost. See Note 15 — Retirement Benefits for additional information. See Exelon's Statements of Operations and Comprehensive Income for individual components of AOCI. (b) All amounts are net of noncontrolling interests. (c) Exelon adopted the new standard Recognition and Measurement of Financial Assets and Financial Liabilities. The standard was adopted as of January 1, 2018, which resulted in an increase to Retained earnings and Accumulated other comprehensive loss of $10 million for Exelon. The amounts reclassified related to Rabbi Trusts. The following table presents income tax benefit (expense) allocated to each component of Exelon's other comprehensive income (loss): For the Year Ended December 31, 2020 2019 2018 Pension and non-pension postretirement benefit plans: Prior service benefit reclassified to periodic benefit cost $ 16 $ 23 $ 24 Actuarial loss reclassified to periodic benefit cost (66) (52) (86) Pension and non-pension postretirement benefit plans valuation adjustment 122 100 50

Variable Interest Entities (Exe

Variable Interest Entities (Exelon, Generation, PHI, and ACE)	12 Months Ended
	Dec. 31, 2020
Variable Interest Entity [Abstract]
Variable Interest Entity Disclosure	Variable Interest Entities (Exelon, Generation, PHI, and ACE) At December 31, 2020 and 2019, Exelon, Generation, PHI, and ACE collectively consolidated several VIEs or VIE groups for which the applicable Registrant was the primary beneficiary (see Consolidated VIEs below) and had significant interests in several other VIEs for which the applicable Registrant does not have the power to direct the entities’ activities and, accordingly, was 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 of Exelon, Generation, PHI, and ACE as of December 31, 2020 and 2019. 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 the general credit of Exelon, Generation, PHI, and ACE. December 31, 2020 December 31, 2019 Exelon Generation PHI (a) ACE Exelon Generation PHI (a) ACE Cash and cash equivalents $ 98 $ 98 $ — $ — $ 163 $ 163 $ — $ — Restricted cash and cash equivalents 47 44 3 3 88 85 3 3 Accounts receivable Customer 148 148 — — 151 151 — — Other 36 36 — — 39 39 — — Unamortized energy contract assets 22 22 — — 23 23 — — Inventories, net Materials and supplies 244 244 — — 227 227 — — Assets held for sale (b) 101 101 — — — — — — Other current assets 674 669 5 — 32 31 1 — Total current assets 1,370 1,362 8 3 723 719 4 3 Property, plant and equipment, net 5,803 5,803 — — 6,022 6,022 — — Nuclear decommissioning trust funds 3,007 3,007 — — 2,741 2,741 — — Unamortized energy contract assets 249 249 — — 250 250 — — Other noncurrent assets 52 42 10 10 89 73 16 14 Total noncurrent assets 9,111 9,101 10 10 9,102 9,086 16 14 Total assets (c) $ 10,481 $ 10,463 $ 18 $ 13 $ 9,825 $ 9,805 $ 20 $ 17 Long-term debt due within one year $ 94 $ 68 $ 26 $ 21 $ 544 $ 523 $ 21 $ 20 Accounts payable 81 81 — — 106 106 — — Accrued expenses 70 70 — — 70 70 — — Unamortized energy contract liabilities 4 4 — — 8 8 — — Liabilities held for sale (b) 16 16 — — — — — — Other current liabilities 5 5 — — 3 3 — — Total current liabilities 270 244 26 21 731 710 21 20 Long-term debt 889 889 — — 527 504 23 21 Asset retirement obligations 2,318 2,318 — — 2,128 2,128 — — Unamortized energy contract liabilities — — — — 1 1 — — Other noncurrent liabilities 129 129 — — 89 89 — — Total noncurrent liabilities 3,336 3,336 — — 2,745 2,722 23 21 Total liabilities (d) $ 3,606 $ 3,580 $ 26 $ 21 $ 3,476 $ 3,432 $ 44 $ 41 __________ (a) Includes certain purchase accounting adjustments from the PHI merger not pushed down to ACE. (b) Generation entered into an agreement for the sale of a significant portion of Generation's solar business. As a result of this transaction, in the fourth quarter of 2020, Exelon and Generation reclassified the consolidated VIEs' solar assets and liabilities as held for sale. Refer to Note 2 — Mergers, Acquisitions, and Dispositions for additional information on the sale of the solar business. (c) Exelon's and Generation's balances include unrestricted assets for current unamortized energy contract assets of $22 million and $23 million, Property, plant, and equipment of $1 million and $20 million, non-current unamortized energy contract assets of $249 million and $250 million, and Assets held for sale of $9 million and $0 million as of December 31, 2020 and 2019, respectively. (d) Exelon's and Generation's balances include liabilities with recourse of $8 million and $3 million as of December 31, 2020 and 2019, respectively. As of December 31, 2020 and 2019, Exelon's and Generation's consolidated VIEs consist of: Consolidated VIE or VIE groups: Reason entity is a VIE: Reason Generation is primary beneficiary: CENG - A joint venture between Generation and EDF. Generation has a 50.01% equity ownership in CENG. See additional discussion below. Disproportionate relationship between equity interest and operational control as a result of the NOSA described further below. Generation conducts the operational activities. EGRP - A collection of wind and solar project entities. Generation has a 51% equity ownership in EGRP. 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. Generation conducts the operational activities. Bluestem Wind Energy Holdings, LLC - A Tax Equity structure which is consolidated by EGRP. Generation is a minority interest holder. Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner. Generation conducts the operational activities. Antelope Valley - A solar generating facility, which is 100% owned by Generation. Antelope Valley sells all of its output to PG&E through a PPA. The PPA contract absorbs variability through a performance guarantee. Generation conducts all activities. Equity investment in distributed energy company - Generation has a 31% equity ownership. This distributed energy company has an interest in an unconsolidated VIE. (See Unconsolidated VIEs disclosure below). Generation fully impaired this investment in the third quarter of 2019. Refer to Note 12 — Asset Impairments for additional information. Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner. Generation conducts the operational activities. NER - A bankruptcy remote, special purpose entity which is 100% owned by Generation, which purchases certain of Generation’s 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. Generation conducts all activities. CENG - On April 1, 2014, Generation, CENG, and subsidiaries of CENG executed the NOSA pursuant to which Generation conducts all activities associated with the operations of the CENG fleet and provides corporate and administrative services to CENG and the CENG fleet for the remaining life of the CENG nuclear plants as if they were a part of the Generation nuclear fleet, subject to the CENG member rights of EDF. EDF has the option to sell its 49.99% equity interest in CENG to Generation. On November 20, 2019, Generation received notice of EDF's intention to exercise the put option to sell its interest in CENG to Generation and the put automatically exercised on January 19, 2020. Refer to Note 2 — Mergers, Acquisitions, and Dispositions for additional information. Exelon and Generation, where indicated, provide the following support to CENG: • Generation executed an Indemnity Agreement pursuant to which Generation agreed to indemnify EDF against third-party claims that may arise from any future nuclear incident (as defined in the Price-Anderson Act) in connection with the CENG nuclear plants or their operations. Exelon guarantees Generation’s obligations under this Indemnity Agreement. See Note 19 — Commitments and Contingencies for more details, • Generation and EDF share in the $688 million of contingent payment obligations for the payment of contingent retrospective premium adjustments for the nuclear liability insurance, and • Exelon has executed an agreement to provide up to $245 million to support the operations of CENG as well as a $165 million guarantee of CENG’s cash pooling agreement with its subsidiaries. EGRP - EGRP is a collection of wind and solar project entities and some of these project entities are VIEs that are consolidated by EGRP. Generation owns a number of limited liability companies that build, own, and operate solar and wind power facilities some of which are owned by EGRP. While Generation or EGRP owns 100% of the solar entities and 100% of the majority of the wind entities, it has been determined that certain of the solar and wind entities are VIEs because the entities require additional subordinated financial support in the form of a parental guarantee of debt, loans from the customers in order to obtain the necessary funds for construction of the solar facilities, or the customers absorb price variability from the entities through the fixed price power and/or REC purchase agreements. Generation is the primary beneficiary of these solar and wind entities that qualify as VIEs because Generation controls the design, construction, and operation of the facilities. There is limited recourse to Generation related to certain solar and wind entities. In 2017, Generation’s interests in EGRP were contributed to and are pledged for the EGR IV non-recourse debt project financing structure. Refer to Note 17 — Debt and Credit Agreements for additional information. As of December 31, 2020 and 2019, Exelon's, PHI's and ACE's consolidated VIE consists of: Consolidated VIEs: Reason entity is a VIE: Reason ACE is the primary beneficiary: ACE Funding - A special purpose entity formed by ACE for the purpose of securitizing authorized portions of ACE’s recoverable stranded costs through the issuance and sale of Transition Bonds. Proceeds from the sale of each series of Transition Bonds by ATF were transferred to ACE in exchange for the transfer by ACE to ATF of the right to collect a non-bypassable Transition Bond Charge from ACE customers pursuant to bondable stranded costs rate orders issued by the NJBPU in an amount sufficient to fund the principal and interest payments on Transition Bonds and related taxes, expenses, and fees. ACE’s equity investment is a variable interest as, by design, it absorbs any initial variability of ATF. The bondholders also have a variable interest for the investment made to purchase the Transition Bonds. ACE controls the servicing activities. Unconsolidated VIEs Exelon’s and Generation’s 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 Exelon’s and Generation’s Consolidated Balance Sheets in Investments. For the energy purchase and sale contracts (commercial agreements), the carrying amount of assets and liabilities in Exelon’s and Generation’s Consolidated Balance Sheets that relate to their involvement with the VIEs are predominately related to working capital accounts and generally represent the amounts owed by, or owed to, Exelon and Generation for the deliveries associated with the current billing cycles under the commercial agreements. As of December 31, 2020 and 2019, Exelon and Generation had significant unconsolidated variable interests in several VIEs for which Exelon or Generation, as applicable, was not the primary beneficiary. These interests include certain equity method investments and certain commercial agreements. The following table presents summary information about Exelon's and Generation’s significant unconsolidated VIE entities: December 31, 2020 December 31, 2019 Commercial Agreement VIEs Equity Investment VIEs Total Commercial Equity Total Total assets (a) $ 777 $ 401 $ 1,178 $ 636 $ 443 $ 1,079 Total liabilities (a) 61 223 284 33 227 260 Exelon's ownership interest in VIE (a) — 157 157 — 191 191 Other ownership interests in VIE (a) 716 21 737 604 25 629 __________ (a) These items represent amounts on the unconsolidated VIE balance sheets, not in Exelon’s or Generation’s Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs. Exelon and Generation do not have any exposure to loss as they do not have a carrying amount in the equity investment VIEs as o f December 31, 2020 and 2019. As of December 31, 2020 and 2019, Exelon's and Generation's unconsolidated VIEs consist of: Unconsolidated VIE groups: Reason entity is a VIE: Reason Generation is not the primary beneficiary: Equity investments in distributed energy companies - 1) Generation has a 90% equity ownership in a distributed energy company. 2) Generation, via a consolidated VIE, has a 90% equity ownership in another distributed energy company (See Consolidated VIEs disclosure above). Generation fully impaired this investment in the third quarter of 2019. Refer to Note 12 — Asset Impairments for additional information. Similar structures to a limited partnership and the limited partners do not have kick out rights with respect to the general partner. Generation does not conduct the operational activities. Energy Purchase and Sale agreements - Generation has several energy purchase and sale agreements with generating facilities. PPA contracts that absorb variability through fixed pricing. Generation does not conduct the operational activities.

Supplemental Financial Informat

Supplemental Financial Information (All Registrants)	12 Months Ended
Supplemental Financial Information (All Registrants)	Dec. 31, 2020
Supplemental Financial Information [Abstract]
Supplemental Financial Information (All Registrants)	Supplemental Financial Information (All Registrants) Supplemental Statement of Operations Information The following tables provide additional information about material items recorded in the Registrants' Consolidated Statements of Operations and Comprehensive Income. Taxes other than income taxes Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE For the year ended December 31, 2020 Utility (a) $ 859 $ 99 $ 238 $ 135 $ 87 $ 299 $ 275 $ 21 $ 3 Property 602 265 30 16 164 126 84 39 3 Payroll 235 113 27 16 17 25 7 5 3 For the year ended December 31, 2019 Utility (a) $ 881 $ 112 $ 242 $ 132 $ 90 $ 304 $ 286 $ 18 $ — Property 595 274 29 17 153 122 85 34 2 Payroll 232 115 27 15 17 24 7 4 2 For the year ended December 31, 2018 Utility (a) $ 919 $ 114 $ 243 $ 131 $ 94 $ 337 $ 316 $ 21 $ — Property 557 273 30 15 143 94 58 32 3 Payroll 247 130 27 16 17 24 5 3 2 __________ (a) Generation’s utility tax represents gross receipts tax related to its retail operations, and the Utility Registrants’ utility taxes represents municipal and state utility taxes and gross receipts taxes related to their operating revenues. The offsetting collection of utility taxes from customers is recorded in revenues in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. Other, Net Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE For the year ended December 31, 2020 Decommissioning-related activities: Net realized income on NDT funds (a) Regulatory Agreement Units $ 185 $ 185 $ — $ — $ — $ — $ — $ — $ — Non-regulatory Agreement Units 160 160 — — — — — — — Net unrealized gains on NDT funds Regulatory Agreement Units 724 724 — — — — — — — Non-regulatory Agreement Units 391 391 — — — — — — — Regulatory offset to NDT fund-related activities (b) (729) (729) — — — — — — — Decommissioning-related activities 731 731 — — — — — — — AFUDC—Equity 104 — 29 17 22 36 28 4 4 Non-service net periodic benefit cost 53 — — — — — — — — Unrealized gains from equity investments (c) 186 186 — — — — — — — For the year ended December 31, 2019 Decommissioning-related activities: Net realized income on NDT funds (a) Regulatory Agreement Units $ 297 $ 297 $ — $ — $ — $ — $ — $ — $ — Non-regulatory Agreement Units 363 363 — — — — — — — Net unrealized gains on NDT funds Regulatory Agreement Units 795 795 — — — — — — — Non-regulatory Agreement Units 411 411 — — — — — — — Regulatory offset to NDT fund-related activities (b) (876) (876) — — — — — — — Decommissioning-related activities 990 990 — — — — — — — AFUDC—Equity 85 — 17 13 21 34 25 4 5 Non-service net periodic benefit cost 13 — — — — — — — — For the year ended December 31, 2018 Decommissioning-related activities: Net realized income on NDT funds (a) Regulatory Agreement Units $ 506 $ 506 $ — $ — $ — $ — $ — $ — $ — Non-regulatory Agreement Units 302 302 — — — — — — — Net unrealized losses on NDT funds Regulatory Agreement Units (715) (715) — — — — — — — Non-regulatory Agreement Units (483) (483) — — — — — — — Regulatory offset to NDT fund-related activities (b) 171 171 — — — — — — — Decommissioning-related activities (219) (219) — — — — — — — AFUDC—Equity 69 — 19 7 18 25 22 2 1 Non-service net periodic benefit cost (47) — — — — — — — — __________ (a) Realized income includes interest, dividends, and realized gains and losses on sales of NDT fund investments. (b) Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units, including the elimination of income taxes related to all NDT fund activity for those units. See Note 10 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning. (c) Unrealized gains resulting from equity investments without readily determinable fair values that became publicly traded entities in the fourth quarter of 2020 and were fair valued based on quoted market prices of the stocks as of December 31, 2020. Supplemental Cash Flow Information The following tables provide additional information about material items recorded in the Registrants' Consolidated Statements of Cash Flows. Depreciation, amortization, and accretion Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE For the year ended December 31, 2020 Property, plant, and equipment (a) $ 4,364 $ 2,070 $ 922 $ 319 $ 397 $ 586 $ 257 $ 155 $ 140 Amortization of regulatory assets (a) 588 — 211 28 153 196 120 36 40 Amortization of intangible assets, net (a) 62 53 — — — — — — — Amortization of energy contract assets and liabilities (b) 30 30 — — — — — — — Nuclear fuel (c) 983 983 — — — — — — — ARO accretion (d) 500 500 — — — — — — — Total depreciation, amortization, and accretion $ 6,527 $ 3,636 $ 1,133 $ 347 $ 550 $ 782 $ 377 $ 191 $ 180 For the year ended December 31, 2019 Property, plant, and equipment (a) $ 3,665 $ 1,485 $ 886 $ 303 $ 359 $ 547 $ 239 $ 146 $ 123 Amortization of regulatory assets (a) 528 — 147 30 143 207 135 38 34 Amortization of intangible assets, net (a) 59 50 — — — — — — — Amortization of energy contract assets and liabilities (b) 21 21 — — — — — — — Nuclear fuel (c) 1,016 1,016 — — — — — — — ARO accretion (d) 491 491 — — — — — — — Total depreciation, amortization, and accretion $ 5,780 $ 3,063 $ 1,033 $ 333 $ 502 $ 754 $ 374 $ 184 $ 157 For the year ended December 31, 2018 Property, plant, and equipment (a) $ 3,740 $ 1,748 $ 820 $ 274 $ 335 $ 480 $ 218 $ 131 $ 94 Amortization of regulatory assets (a) 555 — 120 27 148 260 167 51 42 Amortization of intangible assets, net (a) 58 49 — — — — — — — Amortization of energy contract assets and liabilities (b) 14 14 — — — — — — — Nuclear fuel (c) 1,115 1,115 — — — — — — — ARO accretion (d) 489 489 — — — — — — — Total depreciation, amortization, and accretion $ 5,971 $ 3,415 $ 940 $ 301 $ 483 $ 740 $ 385 $ 182 $ 136 __________ (a) Included in Depreciation and amortization in the Registrants' Consolidated Statements of Operations and Comprehensive Income. (b) Included in Operating revenues or Purchased power and fuel expense in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. (c) Included in Purchased power and fuel expense in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. (d) Included in Operating and maintenance expense in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. Cash paid (refunded) during the year: Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE For the year ended December 31, 2020 Interest (net of amount capitalized) $ 1,521 $ 331 $ 371 $ 144 $ 125 $ 257 $ 129 $ 61 $ 57 Income taxes (net of refunds) 10 70 (61) (37) (57) 46 40 12 (3) For the year ended December 31, 2019 Interest (net of amount capitalized) $ 1,470 $ 373 $ 343 $ 129 $ 106 $ 255 $ 130 $ 59 $ 55 Income taxes (net of refunds) 265 (44) (42) 82 17 29 7 19 (5) For the year ended December 31, 2018 Interest (net of amount capitalized) $ 1,421 $ 369 $ 332 $ 125 $ 94 $ 250 $ 123 $ 56 $ 61 Income taxes (net of refunds) 95 746 (153) (2) 14 (32) 41 (6) (12) Other non-cash operating activities: Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE For the year ended December 31, 2020 Pension and non-pension postretirement benefit costs $ 411 $ 115 $ 114 $ 5 $ 62 $ 70 $ 15 $ 7 $ 14 Allowance for credit losses 150 17 32 42 15 43 24 16 2 Other decommissioning-related activity (a) (659) (659) — — — — — — — Energy-related options (b) 104 104 — — — — — — — True-up adjustments to decoupling mechanisms and formula rates (c) (6) — 47 (16) (16) (21) (40) 7 12 Severance costs 105 90 1 1 — — — — — Provision for excess and obsolete inventory 131 128 2 1 — — — — — Long-term incentive plan 56 — — — — — — — — Amortization of operating ROU asset 222 155 2 1 31 28 7 8 3 Asset impairments — — 15 — — 13 — 7 6 AFUDC - Equity (104) — (29) (17) (22) (36) (28) (4) (4) For the year ended December 31, 2019 Pension and non-pension postretirement benefit costs $ 438 $ 135 $ 96 $ 12 $ 61 $ 95 $ 25 $ 15 $ 16 Allowance for credit losses 120 31 33 31 8 17 7 4 5 Other decommissioning-related activity (a) (506) (506) — — — — — — — Energy-related options (b) 22 22 — — — — — — — True-up adjustments to decoupling mechanisms and formula rates (d) 124 — 128 — — (4) (4) — — Long-term incentive plan 10 — — — — — — — — Amortization of operating ROU asset 244 172 3 — 30 33 8 8 4 Change in environmental liabilities 23 — — — — 23 23 — — AFUDC - Equity (85) — (17) (13) (21) (34) (25) (4) (5) For the year ended December 31, 2018 Pension and non-pension postretirement benefit costs $ 583 $ 204 $ 177 $ 18 $ 59 $ 67 $ 15 $ 6 $ 12 Allowance for credit losses 159 48 40 33 10 28 11 6 11 Other decommissioning-related activity (a) (2) (2) — — — — — — — Energy-related options (b) 10 10 — — — — — — — True-up adjustments to decoupling mechanisms and formula rates (d) 49 — 28 — — 21 21 — — Asset retirement costs 20 — — — — 20 22 (1) (1) Long-term incentive plan 140 — — — — — — — — AFUDC - Equity (69) — (19) (7) (18) (25) (22) (2) (1) __________ (a) Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units, including the elimination of operating revenues, ARO updates and accretion, ARC amortization, investment income, and income taxes related to all NDT fund activity for these units. See Note 10 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning. (b) Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations. (c) For ComEd, reflects the true-up adjustments in regulatory assets and liabilities associated with its distribution, energy efficiency, distributed generation, and transmission formula rates. For BGE, Pepco, and DPL, reflects the change in regulatory assets and liabilities associated with their decoupling mechanisms and transmission formula rates. For PECO and ACE, reflects the change in regulatory assets and liabilities associated with their transmission formula rates. See Note 3 — Regulatory Matters for additional information. (d) For ComEd, reflects the true-up adjustments in regulatory assets and liabilities associated with its distribution and energy efficiency formula rates. For Pepco and DPL, reflects the change in regulatory assets and liabilities associated with their decoupling mechanisms. See Note 3 — Regulatory Matters for additional information. The following tables provide a reconciliation of cash, restricted cash, and cash equivalents reported within the Registrants' Consolidated Balance Sheets that sum to the total of the same amounts in their Consolidated Statements of Cash Flows. Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE December 31, 2020 Cash and cash equivalents $ 663 $ 226 $ 83 $ 19 $ 144 $ 111 $ 30 $ 15 $ 17 Restricted cash and cash equivalents 438 89 279 7 1 39 35 — 3 Restricted cash included in other long-term assets 53 — 43 — — 10 — — 10 Cash, restricted cash, and cash equivalents - Held for Sale 12 12 — — — — — — — Total cash, restricted cash, and cash equivalents $ 1,166 $ 327 $ 405 $ 26 $ 145 $ 160 $ 65 $ 15 $ 30 December 31, 2019 Cash and cash equivalents $ 587 $ 303 $ 90 $ 21 $ 24 $ 131 $ 30 $ 13 $ 12 Restricted cash and cash equivalents 358 146 150 6 1 36 33 — 2 Restricted cash included in other long-term assets 177 — 163 — — 14 — — 14 Total cash, restricted cash, and cash equivalents $ 1,122 $ 449 $ 403 $ 27 $ 25 $ 181 $ 63 $ 13 $ 28 December 31, 2018 Cash and cash equivalents $ 1,349 $ 750 $ 135 $ 130 $ 7 $ 124 $ 16 $ 23 $ 7 Restricted cash and cash equivalents 247 153 29 5 6 43 37 1 4 Restricted cash included in other long-term assets 185 — 166 — — 19 — — 19 Total cash, restricted cash, and cash equivalents $ 1,781 $ 903 $ 330 $ 135 $ 13 $ 186 $ 53 $ 24 $ 30 December 31, 2017 Cash and cash equivalents $ 898 $ 416 $ 76 $ 271 $ 17 $ 30 $ 5 $ 2 $ 2 Restricted cash and cash equivalents 207 138 5 4 1 42 35 — 6 Restricted cash included in other long-term assets 85 — 63 — — 23 — — 23 Total cash, restricted cash, and cash equivalents $ 1,190 $ 554 $ 144 $ 275 $ 18 $ 95 $ 40 $ 2 $ 31 Supplemental Balance Sheet Information The following tables provide additional information about material items recorded in the Registrants' Consolidated Balance Sheets. Investments Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE December 31, 2020 Equity method investments: Other equity method investments $ 81 $ 65 $ 6 $ 8 $ — $ — $ — $ — $ — Other investments: Employee benefit trusts and investments (a) 283 61 — 22 10 140 115 — — Equity investments without readily determinable fair values 73 55 — — — — — — — Other available for sale debt security investments 3 3 — — — — — — — Total investments $ 440 $ 184 $ 6 $ 30 $ 10 $ 140 $ 115 $ — $ — December 31, 2019 Equity method investments: Other equity method investments $ 92 $ 71 $ 6 $ 8 $ — $ — $ — $ — $ — Other investments: Employee benefit trusts and investments (a) 262 54 — 19 7 135 110 — — Equity investments without readily determinable fair values 69 69 — — — — — — — Other available for sale debt security investments 41 41 — — — — — — — Total investments $ 464 $ 235 $ 6 $ 27 $ 7 $ 135 $ 110 $ — $ — __________ (a) The Registrants’ debt and equity security investments are recorded at fair market value. Accrued expenses Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE December 31, 2020 Compensation-related accruals (a) $ 1,069 $ 426 $ 170 $ 73 $ 84 $ 109 $ 36 $ 18 $ 17 Taxes accrued 527 229 94 16 73 117 90 18 12 Interest accrued 331 44 109 37 46 51 26 7 12 December 31, 2019 Compensation-related accruals (a) $ 1,052 $ 422 $ 171 $ 58 $ 78 $ 101 $ 28 $ 19 $ 15 Taxes accrued 414 222 83 3 26 117 90 14 8 Interest accrued 337 65 110 37 46 49 23 8 12 __________ (a) Primarily includes accrued payroll, bonuses and other incentives, vacation, and benefits.

Related Party Transactions (All

Related Party Transactions (All Registrants)	12 Months Ended
Related Party Transactions (All Registrants)	Dec. 31, 2020
Related Party Transactions [Abstract]
Related-Party Transactions (All Registrants)	Related Party Transactions (All Registrants) Operating revenues from affiliates Generation The following table presents Generation’s Operating revenues from affiliates, which are primarily recorded as Purchased power from affiliates and an immaterial amount recorded as Operating and maintenance expense from affiliates at the Utility Registrants: For the Years Ended 2020 2019 2018 Operating revenues from affiliates: ComEd (a)(b) $ 330 $ 369 $ 523 PECO (c) 190 158 128 BGE (d) 315 289 260 PHI 367 353 355 Pepco (e) 279 264 206 DPL (f) 75 70 120 ACE (g) 13 19 29 Other 9 3 2 Total operating revenues from affiliates (Generation) $ 1,211 $ 1,172 $ 1,268 __________ (a) Generation has an ICC-approved RFP contract with ComEd to provide a portion of ComEd’s electricity supply requirements. Generation also sells RECs and ZECs to ComEd. (b) For 2020, ComEd’s Purchased power from Generation of $345 million is recorded as Operating revenues from ComEd of $330 million and Purchased power and fuel from ComEd of $15 million at Generation. For 2019, ComEd’s Purchased power from Generation of $376 million is recorded as Operating revenues from ComEd of $369 million and Purchased power and fuel from ComEd of $7 million at Generation. (c) Generation provides electric supply to PECO under contracts executed through PECO’s competitive procurement process. In addition, Generation has a ten-year agreement with PECO to sell solar AECs. (d) Generation provides a portion of BGE’s energy requirements under its MDPSC-approved market-based SOS and gas commodity programs. (e) Generation provides electric supply to Pepco under contracts executed through Pepco's competitive procurement process approved by the MDPSC and DCPSC. (f) Generation provides a portion of DPL's energy requirements under its MDPSC and DPSC approved market based SOS commodity programs. (g) Generation provides electric supply to ACE under contracts executed through ACE's competitive procurement process. PHI PHI’s Operating revenues from affiliates are primarily with BSC for services that PHISCO provides to BSC. Operating and maintenance expense from affiliates The Registrants receive a variety of corporate support services from BSC. Pepco, DPL, and ACE also receive corporate support services from PHISCO. See Note 1 - Significant Accounting Policies for additional information regarding BSC and PHISCO. The following table presents the service company costs allocated to the Registrants: Operating and maintenance from affiliates Capitalized costs For the years ended December 31, For the years ended December 31, 2020 2019 2018 2020 2019 2018 Exelon BSC $ 585 $ 516 $ 448 PHISCO 61 72 79 Generation BSC $ 552 $ 570 $ 652 54 66 67 ComEd BSC 283 263 265 186 148 135 PECO BSC 150 149 146 76 88 64 BGE BSC 170 157 157 132 126 79 PHI BSC 152 139 147 149 88 102 PHISCO — — — 61 72 79 Pepco BSC 85 85 89 55 38 40 PHISCO 120 124 137 27 33 32 DPL BSC 54 52 51 51 25 28 PHISCO 97 100 111 18 20 25 ACE BSC 45 42 42 40 19 20 PHISCO 87 90 98 16 19 21 Current Receivables from/Payables to affiliates The following tables present current receivables from affiliates and current payables to affiliates: December 31, 2020 Receivables from affiliates: Payables to affiliates: Generation ComEd PECO BGE Pepco DPL ACE BSC PHISCO Other Total Generation $ 13 $ — $ — $ — $ — $ — $ 72 $ — $ 22 $ 107 ComEd $ 78 (a) — — — — — 59 — 9 146 PECO 17 1 — — — — 28 — 4 50 BGE 11 — — — — — 47 — 3 61 PHI — — — — — — — 4 — 11 15 Pepco 13 2 — 1 — — 25 14 — 55 DPL 3 1 — — — — 21 10 1 36 ACE 6 — — — — — 15 9 1 31 Other 25 5 2 2 2 1 6 — — 43 Total $ 153 $ 22 $ 2 $ 3 $ 2 $ 1 $ 6 $ 271 $ 33 $ 51 $ 544 December 31, 2019 Receivables from affiliates: Payables to affiliates: Generation ComEd PECO BGE ACE BSC PHISCO Other Total Generation $ 27 $ — $ — $ — $ 67 $ — $ 23 $ 117 ComEd $ 78 (a) — — — 54 — 8 140 PECO 27 — — — 25 — 3 55 BGE 28 — — — 34 — 4 66 PHI — — — — — 4 — 10 14 Pepco 34 — — — — 16 15 1 66 DPL 7 — — — 3 10 11 1 32 ACE 7 — — — 7 10 1 25 Other 9 1 1 1 1 — — 13 Total $ 190 $ 28 $ 1 $ 1 $ 4 $ 217 $ 36 $ 51 $ 528 __________ (a) At December 31, 2020 and 2019, Generation also had a contract liability with ComEd for $50 million and $37 million, respectively, that was included in Other liabilities on Generation’s Consolidated Balance Sheets. At December 31, 2020 and 2019, ComEd had a Current Payable to Generation of $28 million and $41 million, respectively, on its Consolidated Balance Sheets, which consisted of Generation’s Current Receivable from ComEd, partially offset by Generation’s contract liability with ComEd. Borrowings from Exelon/PHI intercompany money pool To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing both Exelon and PHI operate an intercompany money pool. Generation, ComEd, PECO, and PHI Corporate participate in the Exelon money pool. Pepco, DPL, and ACE participate in the PHI intercompany money pool. Noncurrent Receivables from/Payables to affiliates Generation has long-term 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. The following table presents noncurrent receivables from affiliates at ComEd and PECO which are recorded as noncurrent payables to affiliates at Generation: December 31, 2020 2019 ComEd $ 2,541 $ 2,622 PECO 475 480 Long-term debt to financing trusts The following table presents Long-term debt to financing trusts: As of December 31, 2020 2019 Exelon ComEd PECO Exelon ComEd PECO ComEd Financing III $ 206 $ 205 $ — $ 206 $ 205 $ — PECO Trust III 81 — 81 81 — 81 PECO Trust IV 103 — 103 103 — 103 Total $ 390 $ 205 $ 184 $ 390 $ 205 $ 184 Long-term debt to affiliates

Subsequent Events (Exelon and G

Subsequent Events (Exelon and Generation)	12 Months Ended
Subsequent Events (Exelon and Generation)	Dec. 31, 2020
Subsequent Events [Abstract]
Subsequent Events (Exelon and Generation)	Subsequent Events (Exelon and Generation) Planned Separation On February 21, 2021, Exelon’s Board of Directors approved a plan to separate the Utility Registrants and Generation, creating two publicly traded companies. Under the separation plan, Exelon shareholders will retain their current shares of Exelon stock and receive a pro-rata distribution of shares of the new company’s stock in a transaction that is expected to be tax-free to Exelon and its shareholders for U.S. federal income tax purposes. The actual number of shares to be distributed to Exelon shareholders will be determined prior to closing. Exelon is targeting to complete the separation in the first quarter of 2022, subject to final approval by Exelon’s Board of Directors, a Form 10 registration statement being declared effective by the SEC, regulatory approvals, and satisfaction of other conditions. The transaction is subject to approval by the FERC, NRC, and NYPSC, and receipt of a private letter ruling from the IRS and tax opinion from Exelon’s tax advisors. There can be no assurance that any separation transaction will ultimately occur or, if one does occur, of its terms or timing. Impacts of February 2021 Weather Events and Texas-based Generating Assets Outages Beginning on February 15, 2021, Generation’s Texas-based generating assets within the ERCOT market, specifically Colorado Bend II, Wolf Hollow II, and Handley, experienced periodic outages as a result of historically severe cold weather conditions. In addition, those weather conditions drove increased demand for service, limited the availability of natural gas to fuel power plants, dramatically increased wholesale power prices, and also increased gas prices in certain regions. In response to the high demand and significantly reduced total generation on the system, ERCOT implemented load reductions to maintain the reliability of the grid and required the use of an administrative price cap of $9,000 per megawatt hour during load shedding events. Exelon and Generation estimate the impact to their Net income for the first quarter of 2021 arising from these market and weather conditions to be approximately $560 million to $710 million. The estimated impact includes favorable results in certain regions within Generation’s wholesale gas business. The ultimate impact to Exelon’s and Generation’s consolidated financial statements may be affected by a number of factors, including final settlement data, the impacts of customer and counterparty credit losses, any state sponsored solutions to address the financial challenges caused by the event, and litigation and contract disputes which may result. Generation used a combination of commercial paper and letters of credit to manage collateral needs and has posted approximately $1.4 billion of collateral with ERCOT as of February 22, 2021. Generation continues to believe it has sufficient cash on hand and available capacity on its revolver, which was $2.4 billion as of February 22, 2021, to meet its liquidity requirements.

Schedule I - Condensed Financia

Schedule I - Condensed Financial Information of Parent (Exelon Corporate)	12 Months Ended
	Dec. 31, 2020
Condensed Financial Information Disclosure [Abstract]
Schedule I - Condensed Financial Information of Parent (Exelon Corporate)	Exelon Corporation and Subsidiary Companies Schedule I – Condensed Financial Information of Parent (Exelon Corporate) Condensed Statements of Operations and Other Comprehensive Income For the Years Ended (In millions) 2020 2019 2018 Operating expenses Operating and maintenance $ (2) $ 33 $ (5) Operating and maintenance from affiliates 10 9 9 Other 2 1 4 Total operating expenses 10 43 8 Operating loss (10) (43) (8) Other income and (deductions) Interest expense, net (378) (321) (312) Equity in earnings of investments 2,313 3,254 2,183 Interest income from affiliates, net 30 39 42 Other, net 15 14 3 Total other income 1,980 2,986 1,916 Income before income taxes 1,970 2,943 1,908 Income taxes 7 7 (97) Net income $ 1,963 $ 2,936 $ 2,005 Other comprehensive income (loss) Pension and non-pension postretirement benefit plans: Prior service benefit reclassified to periodic costs $ (40) $ (64) $ (66) Actuarial loss reclassified to periodic cost 190 148 247 Pension and non-pension postretirement benefit plan valuation adjustment (357) (289) (143) Unrealized (loss) gain on cash flow hedges (1) 1 12 Unrealized gain on equity investments — — 1 Unrealized (loss) on foreign currency translation — — (10) Other comprehensive income (loss) (208) (204) 41 Comprehensive income $ 1,755 $ 2,732 $ 2,046 Exelon Corporation and Subsidiary Companies Schedule I – Condensed Financial Information of Parent (Exelon Corporate) Condensed Statements of Cash Flows For the Years Ended (In millions) 2020 2019 2018 Net cash flows provided by operating activities $ 3,018 $ 1,948 $ 2,576 Cash flows from investing activities Changes in Exelon intercompany money pool (477) 95 1 Notes receivable from affiliates 550 — — Investment in affiliates (1,969) (1,071) (1,231) Net cash flows used in investing activities (1,896) (976) (1,230) Cash flows from financing activities Changes in short-term borrowings (136) 136 — Issuance of long-term debt 2,000 — — Retirement of long-term debt (1,450) — — Dividends paid on common stock (1,492) (1,408) (1,332) Proceeds from employee stock plans 45 112 105 Other financing activities (27) — (4) Net cash flows used in financing activities (1,060) (1,160) (1,231) Increase (Decrease) in cash, restricted cash, and cash equivalents 62 (188) 115 Cash, restricted cash, and cash equivalents at beginning of period 1 189 74 Cash, restricted cash, and cash equivalents at end of period $ 63 $ 1 $ 189 Exelon Corporation and Subsidiary Companies Schedule I – Condensed Financial Information of Parent (Exelon Corporate) Condensed Balance Sheets December 31, (In millions) 2020 2019 ASSETS Current assets Cash and cash equivalents $ 63 $ 1 Accounts receivable, net Other accounts receivable 354 168 Accounts receivable from affiliates 11 41 Mark-to-market derivative assets — 3 Notes receivable from affiliates 598 679 Regulatory assets 315 253 Other 4 4 Total current assets 1,345 1,149 Property, plant, and equipment, net 46 47 Deferred debits and other assets Regulatory assets 3,816 3,772 Investments in affiliates 43,149 42,245 Deferred income taxes 1,625 1,524 Notes receivable from affiliates 324 329 Other 312 308 Total deferred debits and other assets 49,226 48,178 Total assets $ 50,617 $ 49,374 Exelon Corporation and Subsidiary Companies Schedule I – Condensed Financial Information of Parent (Exelon Corporate) Condensed Balance Sheets December 31, (In millions) 2020 2019 LIABILITIES AND SHAREHOLDERS’ EQUITY Current liabilities Short-term borrowings $ 500 $ 636 Long-term debt due within one year 300 1,458 Accounts payable 1 1 Accrued expenses 76 131 Payables to affiliates 457 363 Regulatory liabilities 4 13 Pension obligations 92 77 Other 4 10 Total current liabilities 1,434 2,689 Long-term debt 7,418 5,717 Deferred credits and other liabilities Regulatory liabilities 32 31 Pension obligations 8,351 7,960 Non-pension postretirement benefit obligations 387 403 Deferred income taxes 348 263 Other 62 87 Total deferred credits and other liabilities 9,180 8,744 Total liabilities 18,032 17,150 Commitments and contingencies Shareholders’ equity Common stock (No par value, 2,000 shares authorized, 976 shares and 973 shares outstanding at December 31, 2020 and 2019, respectively) 19,373 19,274 Treasury stock, at cost (2 shares at December 31, 2020 and 2019) (123) (123) Retained earnings 16,735 16,267 Accumulated other comprehensive loss, net (3,400) (3,194) Total shareholders’ equity 32,585 32,224 Total liabilities and shareholders’ equity $ 50,617 $ 49,374 Short-Term Borrowings Exelon Corporate meets its short-term liquidity requirements primarily through the issuance of commercial paper. Exelon Corporate had no outstanding commercial paper borrowings and $136 million at December 31, 2020 and 2019, respectively. Short-Term Loan Agreements On March 23, 2017, Exelon Corporate entered into a 12-month term loan agreement for $500 million, which was renewed annually on March 22, 2018, March 20, 2019, and March 19, 2020, respectively. The loan agreement will expire on March 18, 2021. Pursuant to the loan agreement, as of December 31, 2020, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.65% and all indebtedness thereunder is unsecured. The loans beared interest at LIBOR plus 0.95% as of December 31, 2019 as part of the March 20, 2019 renewal. The loan agreement is reflected in Exelon’s Consolidated Balance Sheet within Short-Term borrowings. Revolving Credit Agreements On May 26, 2018, Exelon Corporate's syndicated revolving credit facility of $600 million had its maturity date extended to May 26, 2023. As of December 31, 2020, Exelon Corporation had available capacity under those commitments of $594 million. See Note 17—Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information regarding Exelon Corporation’s credit agreement. On April 24, 2020, Exelon Corporate entered into a credit agreement establishing a $550 million 364-day revolving credit facility at a variable interest rate of LIBOR plus 1.75%. This facility will be used by Exelon as an additional source of short-term liquidity as needed. Long-Term Debt The following tables present the outstanding long-term debt for Exelon Corporate as of December 31, 2020 and December 31, 2019: Maturity December 31, Rates 2020 2019 Long-term debt Junior subordinated notes 3.50 % 2022 $ 1,150 $ 1,150 Senior unsecured notes (a) 2.45 % - 7.60 % 2021 - 2050 6,439 5,889 Total long-term debt 7,589 7,039 Unamortized debt discount and premium, net (10) (7) Unamortized debt issuance costs (47) (39) Fair value adjustment 186 182 Long-term debt due within one year (300) (1,458) Long-term debt $ 7,418 $ 5,717 __________ (a) Senior unsecured notes include mirror debt that is held on both Generation and Exelon Corporation's balance sheets. The debt maturities for Exelon Corporate for the periods 2021, 2022, 2023, 2024, 2025, and thereafter are as follows: 2021 $ 300 2022 1,150 2023 — 2024 — 2025 807 Thereafter 5,332 Total long-term debt $ 7,589 The financial statements of Exelon Corporate include related party transactions as presented in the tables below: For the Years Ended (In millions) 2020 2019 2018 Operating and maintenance from affiliates: BSC (a) $ 10 $ 9 $ 11 Other — — (2) Total operating and maintenance from affiliates: $ 10 $ 9 $ 9 Interest income from affiliates, net: Generation $ 29 $ 36 $ 36 BSC 1 3 4 EEDC (b) — — 2 Total interest income from affiliates, net: $ 30 $ 39 $ 42 Equity in earnings (losses) of investments: EEDC (b) $ 1,729 $ 2,054 $ 1,830 Generation 589 1,125 369 UII — 97 — PCI — 1 (17) Exelon Enterprises — (16) — Exelon INQB8R (6) (8) — Exelon Transmission Company — (2) 1 Other 1 3 — Total equity in earnings of investments: $ 2,313 $ 3,254 $ 2,183 Cash contributions received from affiliates $ 3,372 $ 2,514 $ 2,302 December 31, (in millions) 2020 2019 Accounts receivable from affiliates (current): BSC (a) $ — $ 11 Generation 3 13 ComEd — 2 PECO 1 2 BGE — 1 PHISCO 6 7 Exelon Enterprises 1 — Exelon VTI, LLC — 5 Total accounts receivable from affiliates (current): $ 11 $ 41 Notes receivable from affiliates (current): BSC (a) $ 252 $ 109 Generation (c) 285 558 PECO 40 — PHI 21 12 Total notes receivable from affiliates (current): $ 598 $ 679 Investments in affiliates: BSC (a) $ 196 $ 197 EEDC (b) 30,103 28,147 Generation 12,400 13,484 PCI 62 62 UII 365 365 Voluntary Employee Beneficiary Association trust — (4) Exelon Enterprises 3 6 Exelon INQB8R, LLC 23 (8) Other (3) (4) Total investments in affiliates: $ 43,149 $ 42,245 Notes receivable from affiliates (non-current): Generation (c) $ 324 $ 329 Accounts payable to affiliates (current): UII $ 360 $ 360 BSC 91 — EEDC (b) 4 — Generation (c) 2 — Exelon Enterprises — 3 Total accounts payable to affiliates (current): $ 457 $ 363 __________ (a) Exelon Corporate receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology, and supply management services. All services are provided at cost, including applicable overhead. (b) EEDC consists of ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE. (c) In connection with the debt obligations assumed by Exelon as part of the Constellation merger, Exelon and subsidiaries of Generation (former Constellation subsidiaries) assumed intercompany loan agreements that mirror the terms and amounts of the third-party debt obligations of Exelon, resulting in intercompany notes payable included in Long-Term Debt to affiliates in Generation’s Consolidated Balance Sheets and intercompany notes receivable at Exelon Corporate, which are eliminated in consolidation in Exelon’s Consolidated Balance Sheets.

Schedule II - Valuation and Qua

Schedule II - Valuation and Qualifying Accounts	12 Months Ended
Schedule II - Valuation and Qualifying Accounts	Dec. 31, 2020
SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract]
Valuation and Qualifying Accounts	Exelon Corporation and Subsidiary Companies Schedule II – Valuation and Qualifying Accounts Column A Column B Column C Column D Column E Additions and adjustments Description Balance at Charged to Charged Deductions Balance at (In millions) For the year ended December 31, 2020 Allowance for credit losses (a) $ 294 $ 240 (b) $ (18) (c) $ 79 (d) $ 437 Deferred tax valuation allowance 26 — 1 — 27 Reserve for obsolete materials 155 128 (e) (1) 6 276 For the year ended December 31, 2019 Allowance for credit losses (a) $ 319 $ 119 (b) $ 26 $ 170 (d) $ 294 Deferred tax valuation allowance 35 — (9) — 26 Reserve for obsolete materials 156 6 — 7 155 For the year ended December 31, 2018 Allowance for credit losses (a) $ 322 $ 159 (b) $ 35 $ 197 (d) $ 319 Deferred tax valuation allowance 37 — 5 7 35 Reserve for obsolete materials 174 25 (31) (f) 12 156 __________ (a) Excludes the non-current allowance for credit losses related to PECO’s installment plan receivables of $5 million, $9 million, and $13 million for the years ended December 31, 2020, 2019, and 2018, respectively. (b) The amount charged to costs and expenses includes the amount that was reclassified to regulatory assets/liabilities under different mechanisms applicable to the different jurisdictions the Utility Registrants operate in. (c) Includes a decrease related to the sale of customer accounts receivable at Generation in the second quarter of 2020. See Note 6—Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information. (d) Primarily reflects write-offs, net of recoveries of individual accounts receivable. (e) 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. (f) Primarily reflects the reclassification of assets as held for sale at Generation. Exelon Generation Company, LLC and Subsidiary Companies (2) Generation (i) Financial Statements (Item 8): Report of Independent Registered Public Accounting Firm dated February 24, 2021 of PricewaterhouseCoopers LLP Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2020, 2019, and 2018 Consolidated Statements of Cash Flows for the Years Ended December 31, 2020, 2019, and 2018 Consolidated Balance Sheets at December 31, 2020 and 2019 Consolidated Statements of Changes in Equity for the Years Ended December 31, 2020, 2019, and 2018 Notes to Consolidated Financial Statements (ii) Financial Statement Schedule: Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2020, 2019, and 2018 Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto Exelon Generation Company, LLC and Subsidiary Companies Schedule II – Valuation and Qualifying Accounts Column A Column B Column C Column D Column E Additions and adjustments Description Balance at Charged to Charged Deductions Balance at (In millions) For the year ended December 31, 2020 Allowance for credit losses $ 81 $ 12 $ (56) (a) $ 5 (b) $ 32 Deferred tax valuation allowance 24 — (1) — 23 Reserve for obsolete materials 143 123 (c) (1) — 265 For the year ended December 31, 2019 Allowance for credit losses $ 104 $ 27 $ (11) $ 39 (b) $ 81 Deferred tax valuation allowance 26 — (2) — 24 Reserve for obsolete materials 145 — — 2 143 For the year ended December 31, 2018 Allowance for credit losses $ 114 $ 44 $ 4 $ 58 (b) $ 104 Deferred tax valuation allowance 23 — 3 — 26 Reserve for obsolete materials 166 20 (32) (d) 9 145 __________ (a) Reflects the sale of customer accounts receivable at Generation in the second quarter of 2020. See Note 6—Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information. (b) Write-offs, net of recoveries of individual accounts receivable. (c) 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. (d) Primarily reflects the reclassification of assets as held for sale. Commonwealth Edison Company and Subsidiary Companies (3) ComEd (i) Financial Statements (Item 8): Report of Independent Registered Public Accounting Firm dated February 24, 2021 of PricewaterhouseCoopers LLP Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2020, 2019, and 2018 Consolidated Statements of Cash Flows for the Years Ended December 31, 2020, 2019, and 2018 Consolidated Balance Sheets at December 31, 2020 and 2019 Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2020, 2019, and 2018 Notes to Consolidated Financial Statements (ii) Financial Statement Schedule: Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2020, 2019, and 2018 Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto Commonwealth Edison Company and Subsidiary Companies Schedule II – Valuation and Qualifying Accounts Column A Column B Column C Column D Column E Additions and adjustments Description Balance at Charged to Charged Deductions Balance at (In millions) For the year ended December 31, 2020 Allowance for credit losses $ 79 $ 54 (a) $ 13 $ 28 (b) $ 118 Reserve for obsolete materials 7 3 — 4 6 For the year ended December 31, 2019 Allowance for credit losses $ 81 $ 35 (a) $ 20 $ 57 (b) $ 79 Reserve for obsolete materials 6 6 — 5 7 For the year ended December 31, 2018 Allowance for credit losses $ 73 $ 44 (a) $ 23 $ 59 (b) $ 81 Reserve for obsolete materials 5 3 1 3 6 __________ (a) ComEd is allowed to recover from or refund to customers the difference between its annual credit loss expense and the amounts collected in rates annually through a rider mechanism. The amount charged to costs and expenses includes the amount that was reclassified to regulatory assets/liabilities under such mechanism. See Note 3 – Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. (b) Write-offs, net of recoveries of individual accounts receivable. PECO Energy Company and Subsidiary Companies (4) PECO (i) Financial Statements (Item 8): Report of Independent Registered Public Accounting Firm dated February 24, 2021 of PricewaterhouseCoopers LLP Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2020, 2019, and 2018 Consolidated Statements of Cash Flows for the Years Ended December 31, 2020, 2019, and 2018 Consolidated Balance Sheets at December 31, 2020 and 2019 Consolidated Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2020, 2019, and 2018 Notes to Consolidated Financial Statements (ii) Financial Statement Schedule: Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2020, 2019, and 2018 Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto PECO Energy Company and Subsidiary Companies Schedule II – Valuation and Qualifying Accounts Column A Column B Column C Column D Column E Additions and adjustments Description Balance at Charged to Charged Deductions Balance at (In millions) For the year ended December 31, 2020 Allowance for credit losses (a) $ 62 $ 76 (b) $ 6 $ 20 (c) $ 124 Deferred tax valuation allowance — — 1 — $ 1 Reserve for obsolete materials 2 1 — 1 2 For the year ended December 31, 2019 Allowance for credit losses (a) $ 61 $ 31 $ 3 $ 33 (c) $ 62 Reserve for obsolete materials 2 — — — 2 For the year ended December 31, 2018 Allowance for credit losses (a) $ 56 $ 33 $ 3 $ 31 (c) $ 61 Reserve for obsolete materials 2 — — — 2 __________ (a) Excludes the non-current allowance for credit losses related to PECO’s installment plan receivables of $5 million, $9 million, and $13 million for the years ended December 31, 2020, 2019, and 2018, respectively. (b) The amount charged to costs and expenses includes the amount that was reclassified to the COVID-19 regulatory asset. See Note 3 – Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. (c) Write-offs, net of recoveries of individual accounts receivable. Baltimore Gas and Electric Company (5) BGE (i) Financial Statements (Item 8): Report of Independent Registered Public Accounting Firm dated February 24, 2021 of PricewaterhouseCoopers LLP Statements of Operations and Comprehensive Income for the Years Ended December 31, 2020, 2019 and 2018 Statements of Cash Flows for the Years Ended December 31, 2020, 2019 and 2018 Balance Sheets at December 31, 2020 and 2019 Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2020, 2019 and 2018 Notes to Financial Statements (ii) Financial Statement Schedule: Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2020, 2019, and 2018 Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto Baltimore Gas and Electric Company Schedule II – Valuation and Qualifying Accounts Column A Column B Column C Column D Column E Additions and adjustments Description Balance at Charged to Charged Deductions Balance at (In millions) For the year ended December 31, 2020 Allowance for credit losses $ 17 $ 31 (a) $ 6 $ 10 (b) $ 44 Deferred tax valuation allowance 1 — (1) — — Reserve for obsolete materials 1 — — — 1 For the year ended December 31, 2019 Allowance for credit losses $ 20 $ 8 (a) $ 7 $ 18 (b) $ 17 Deferred tax valuation allowance 1 — — — 1 Reserve for obsolete materials 1 — — — 1 For the year ended December 31, 2018 Allowance for credit losses $ 24 $ 10 (a) $ (2) $ 12 (b) $ 20 Deferred tax valuation allowance 1 — — — 1 Reserve for obsolete materials — 1 — — 1 __________ (a) The amount charged to costs and expenses includes the amount that was reclassified to regulatory assets/liabilities under different mechanisms as approved by the MDPSC. (b) Write-offs, net of recoveries of individual accounts receivable. Pepco Holdings LLC and Subsidiary Companies (6) PHI (i) Financial Statements (Item 8): Report of Independent Registered Public Accounting Firm dated February 24, 2021 of PricewaterhouseCoopers LLP Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2020, 2019, and 2018 Consolidated Statements of Cash Flows for the Years Ended December 31, 2020, 2019, and 2018 Consolidated Balance Sheets at December 31, 2020 and 2019 Consolidated Statements of Changes in Equity for the Years Ended December 31, 2020, 2019, and 2018 Notes to Consolidated Financial Statements (ii) Financial Statement Schedule: Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2020, 2019, and 2018 Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto Pepco Holdings LLC and Subsidiary Companies Schedule II – Valuation and Qualifying Accounts Column A Column B Column C Column D Column E Additions and adjustments Description Balance at Charged to Charged Deductions Balance at (In millions) For the year ended December 31, 2020 Allowance for credit losses $ 53 $ 69 (a) $ 13 $ 16 (b) $ 119 Reserve for obsolete materials 3 — — 1 2 For the year ended December 31, 2019 Allowance for credit losses $ 53 $ 17 (a) $ 7 $ 24 (c) $ 53 Deferred tax valuation allowance 8 — (8) — — Reserve for obsolete materials 2 1 — — 3 For the year ended December 31, 2018 Allowance for credit losses $ 55 $ 28 (a) $ 7 $ 37 (c) $ 53 Deferred tax valuation allowance 13 — 2 7 8 Reserve for obsolete materials 2 — — — 2 __________ (a) The amount charged to costs and expenses includes the amount that was reclassified to regulatory assets/liabilities under different mechanisms applicable to the different jurisdictions Pepco, DPL, and ACE operate in. (b) Write-offs, net of recoveries of individual accounts receivable. (c) Write-offs of individual accounts receivable. Potomac Electric Power Company (7) Pepco (i) Financial Statements (Item 8): Report of Independent Registered Public Accounting Firm dated February 24, 2021 of PricewaterhouseCoopers LLP Statements of Operations and Comprehensive Income for the Years Ended December 31, 2020, 2019 and 2018 Statements of Cash Flows for the Years Ended December 31, 2020, 2019 and 2018 Balance Sheets at December 31, 2020 and 2019 Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2020, 2019 and 2018 Notes to Financial Statements (ii) Financial Statement Schedule: Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2020, 2019, and 2018 Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto Potomac Electric Power Company Schedule II – Valuation and Qualifying Accounts Column A Column B Column C Column D Column E Additions and adjustments Description Balance at Charged to Charged Deductions Balance at (In millions) For the year ended December 31, 2020 Allowance for credit losses $ 20 $ 25 (a) $ 5 $ 5 (b) $ 45 Reserve for obsolete materials 1 — — — 1 For the year ended December 31, 2019 Allowance for credit losses $ 21 $ 7 (a) $ 2 $ 10 (c) $ 20 Reserve for obsolete materials 1 — — — 1 For the year ended December 31, 2018 Allowance for credit losses $ 21 $ 11 (a) $ 3 $ 14 (c) $ 21 Reserve for obsolete materials 1 — — — 1 __________ (a) The amount charged to costs and expenses includes the amount that was reclassified to regulatory assets/liabilities under different mechanisms as approved by the DCPSC and MDPSC. (b) Write-offs, net of recoveries of individual accounts receivable. (c) Write-off of individual accounts receivable. Delmarva Power & Light Company (8) DPL (i) Financial Statements (Item 8): Report of Independent Registered Public Accounting Firm dated February 24, 2021 of PricewaterhouseCoopers LLP Statements of Operations and Comprehensive Income for the Years Ended December 31, 2020, 2019 and 2018 Statements of Cash Flows for the Years Ended December 31, 2020, 2019 and 2018 Balance Sheets at December 31, 2020 and 2019 Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2020, 2019 and 2018 Notes to Financial Statements (ii) Financial Statement Schedule: Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2020, 2019, and 2018 Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto Delmarva Power & Light Company Schedule II – Valuation and Qualifying Accounts Column A Column B Column C Column D Column E Additions and adjustments Description Balance at Charged to Charged Deductions Balance at (In millions) For the year ended December 31, 2020 Allowance for credit losses $ 15 $ 16 (a) $ 4 $ 4 (b) $ 31 For the year ended December 31, 2019 Allowance for credit losses $ 13 $ 4 (a) $ 3 $ 5 (c) $ 15 For the year ended December 31, 2018 Allowance for credit losses $ 16 $ 6 (a) $ 2 $ 11 (c) $ 13 __________ (a) The amount charged to costs and expenses includes the amount that was reclassified to regulatory assets/liabilities under different mechanisms as approved by the DPSC and MDPSC. (b) Write-offs, net of recoveries of individual accounts receivable. (c) Write-off of individual accounts receivable. Atlantic City Electric Company and Subsidiary Company (9) ACE (i) Financial Statements (Item 8): Report of Independent Registered Public Accounting Firm dated February 24, 2021 of PricewaterhouseCoopers LLP Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2020, 2019, and 2018 Consolidated Statements of Cash Flows for the Years Ended December 31, 2020, 2019, and 2018 Consolidated Balance Sheets at December 31, 2020 and 2019 Consolidated Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2020, 2019, and 2018 Notes to Consolidated Financial Statements (ii) Financial Statement Schedule: Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2020, 2019, and 2018 Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto Atlantic City Electric Company and Subsidiary Company Schedule II – Valuation and Qualifying Accounts Column A Column B Column C Column D Column E Additions and adjustments Description Balance at Charged to Charged Deductions Balance at (In millions) For the year ended December 31, 2020 Allowance for credit losses $ 18 $ 28 (a) $ 4 $ 7 (b) $ 43 Reserve for obsolete materials 1 — — 1 — For the year ended December 31, 2019 Allowance for credit losses $ 19 $ 5 (a) $ 2 $ 8 (c) $ 18 Reserve for obsolete materials 1 — — — 1 For the year ended December 31, 2018 Allowance for credit losses $ 18 $ 11 (a) $ 2 $ 12 (c) $ 19 Reserve for obsolete materials 1 — — — 1 __________ (a) ACE is allowed to recover from or refund to customers the difference between its annual credit loss expense and the amounts collected in rates annually through the Societal Benefits Charge. The amount charged to costs and expenses includes the amount that was reclassified to regulatory assets/liabilities under such mechanism. See Note 3 – Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. (b) Write-offs, net of recoveries of individual accounts receivable. (c) Write-off of individual accounts receivable.

Significant Accounting Polici_2

Significant Accounting Policies (Policies)	12 Months Ended
Significant Accounting Policies (Policies)	Dec. 31, 2020
Accounting Policies [Abstract]
Business Description and Basis of Presentation (All Registrants)	Description of Business (All Registrants) Exelon is a utility services holding company engaged in the generation, delivery and marketing of energy through Generation and the energy distribution and transmission businesses through ComEd, PECO, BGE, Pepco, DPL, and ACE. Name of Registrant Business Service Territories Exelon Generation Generation, physical delivery and marketing of power across multiple geographical regions through its customer-facing business, Constellation, which sells electricity to both wholesale and retail customers. Generation also sells natural gas, renewable energy, and other energy-related products and services. Five reportable segments: Mid-Atlantic, Midwest, New York, ERCOT, and Other Power Regions Commonwealth Edison Company Purchase and regulated retail sale of electricity Northern Illinois, including the City of Chicago Transmission and distribution of electricity to retail customers PECO Energy Company Purchase and regulated retail sale of electricity and natural gas Southeastern Pennsylvania, including the City of Philadelphia (electricity) Transmission and distribution of electricity and distribution of natural gas to retail customers Pennsylvania counties surrounding the City of Philadelphia (natural gas) Baltimore Gas and Electric Company Purchase and regulated retail sale of electricity and natural gas Central Maryland, including the City of Baltimore (electricity and natural gas) Transmission and distribution of electricity and distribution of natural gas to retail customers Pepco Holdings LLC Utility services holding company engaged, through its reportable segments Pepco, DPL, and ACE Service Territories of Pepco, DPL, and ACE Potomac Electric Purchase and regulated retail sale of electricity District of Columbia, and major portions of Montgomery and Prince George’s Counties, Maryland. Transmission and distribution of electricity to retail customers Delmarva Power & Light Company Purchase and regulated retail sale of electricity and natural gas Portions of Delaware and Maryland (electricity) Transmission and distribution of electricity and distribution of natural gas to retail customers Portions of New Castle County, Delaware (natural gas) Atlantic City Electric Company Purchase and regulated retail sale of electricity Portions of Southern New Jersey Transmission and distribution of electricity to retail customers Basis of Presentation (All Registrants) This is a combined annual report of all Registrants. The Notes to the Consolidated Financial Statements apply to the Registrants as indicated parenthetically next to each corresponding disclosure. When appropriate, the Registrants are named specifically for their related activities and disclosures. Each of the Registrant’s Consolidated Financial Statements includes the accounts of its subsidiaries. All intercompany transactions have been eliminated. Through its business services subsidiary, BSC, Exelon provides its subsidiaries with a variety of support services at cost, including legal, human resources, financial, information technology, and supply management services. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services at cost, including legal, accounting, engineering, customer operations, distribution and transmission planning, asset management, system operations, and power procurement, to PHI operating companies. The costs of BSC and PHISCO are directly charged or allocated to the applicable subsidiaries. The results of Exelon’s corporate operations are presented as “Other” within the consolidated financial statements and include intercompany eliminations unless otherwise disclosed. Exelon owns 100% of Generation, PECO, BGE, and PHI and more than 99% of ComEd. PHI owns 100% of Pepco, DPL, and ACE. Generation owns 100% of its significant consolidated subsidiaries, either directly or indirectly, except for certain consolidated VIEs, including CENG and EGRP, of which Generation holds a 50.01% and 51% interest, respectively. The remaining interests in these consolidated VIEs are included in noncontrolling interests on Exelon’s and Generation’s Consolidated Balance Sheets. See Note 23 — Variable Interest Entities for additional information of Exelon’s and Generation’s consolidated VIEs. The Registrants consolidate the accounts of entities in which a Registrant has a controlling financial interest, after the elimination of intercompany transactions. Where the Registrants 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. The Registrants apply proportionate consolidation when they have an undivided interest in an asset and are proportionately liable for their share of each liability associated with the asset. The Registrants proportionately consolidate their undivided ownership interests in jointly owned electric plants and transmission facilities. Under proportionate consolidation, the Registrants separately record their proportionate share of the assets, liabilities, revenues, and expenses related to the undivided interest in the asset. The Registrants apply equity method accounting when they have significant influence over an investee through an ownership in common stock, which generally approximates a 20% to 50% voting interest. The Registrants apply equity method accounting to certain investments and joint ventures. Under equity method accounting, the Registrants report their interest in the entity as an investment and the Registrants’ percentage share of the earnings from the entity as single line items in their financial statements. The Registrants use accounting for investments in equity securities with or without readily determinable fair values if they lack significant influence, which generally results when they hold less than 20% of the common stock of an entity. Under accounting for investments in equity securities with readily determinable fair values, the Registrants report their investment values 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 Registrants report their investments 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. 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.
Use Of Estimates (All Registrants)	Use of Estimates (All Registrants) The preparation of financial statements of each of the Registrants 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, inventory reserves, allowance for credit losses, goodwill and asset impairment assessments, derivative instruments, unamortized
Accounting for the Effects of Regulation (Exelon and the Utility Registrants)	Accounting for the Effects of Regulation (Exelon and the Utility Registrants) For their regulated electric and gas operations, Exelon and the Utility Registrants reflect the effects of cost-based rate regulation in their financial statements, which is required for entities with regulated operations that meet the following criteria: 1) rates are established or approved by a third-party regulator; (2) rates are designed to recover the entities’ cost of providing services or products; and (3) there is a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. Exelon and the Utility Registrants account for their regulated operations in accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction, principally the ICC, PAPUC, MDPSC, DCPSC, DPSC, and NJBPU, under state public utility laws and the FERC under various Federal laws. Regulatory assets and liabilities are amortized and the related expense or revenue is recognized in the Consolidated Statements of Operations consistent with the recovery or refund included in customer rates. Exelon's regulatory assets and liabilities as of the balance sheet date are probable of being recovered or settled in future rates. If a separable portion of the Registrants' business was no longer able to meet the criteria discussed above, the affected entities would be required to eliminate from their consolidated financial statements the effects of regulation for that portion, which could have a material impact on their financial statements. See Note 3 — Regulatory Matters for additional information. With the exception of income tax-related regulatory assets and liabilities, Exelon and the Utility Registrants classify regulatory assets and liabilities with a recovery or settlement period greater than one year as both current and non-current in their Consolidated Balance Sheets, with the current portion representing the amount expected to be recovered from or refunded to customers over the next twelve-month period as of the balance sheet date. Income tax-related regulatory assets and liabilities are classified entirely as non-current in Exelon's and the Utility Registrants’ Consolidated Balance Sheets to align with the classification of the related deferred income tax balances. Exelon and the Utility Registrants treat the impacts of a final rate order received after the balance sheet date but prior to the issuance of the financial statements as a non-recognized subsequent event, as the receipt of a final rate order is a separate and distinct event that has future impacts on the parties affected by the order.
Revenues (All Registrants)	Revenues (All Registrants) Operating Revenues. The Registrants’ operating revenues generally consist of revenues from contracts with customers involving the sale and delivery of energy commodities and related products and services, utility revenues from ARP, and realized and unrealized revenues recognized under mark-to-market energy commodity derivative contracts. The Registrants recognize revenue from contracts with customers to depict the transfer of goods or services to customers in an amount that the entities expect to be entitled to in exchange for those goods or services. Generation’s primary sources of revenue include competitive sales of power, natural gas, and other energy-related products and services. The Utility Registrants’ primary sources of revenue include regulated electric and natural gas tariff sales, distribution, and transmission services. At the end of each month, the Registrants accrue an estimate for the unbilled amount of energy delivered or services provided to customers. ComEd records ARP revenue for its best estimate of the electric distribution, energy efficiency, and transmission revenue impacts resulting from future changes in rates that ComEd believes are probable of approval by the ICC and FERC in accordance with its formula rate mechanisms. BGE, Pepco, and DPL record ARP revenue for their best estimate of the electric and natural gas distribution revenue impacts resulting from future changes in rates that they believe are probable of approval by the MDPSC and/or DCPSC in accordance with their revenue decoupling mechanisms. PECO, BGE, Pepco, DPL, and ACE record ARP revenue for their best estimate of the transmission revenue impacts resulting from future changes in rates that they believe are probable of approval by FERC in accordance with their formula rate mechanisms. See Note 3 — Regulatory Matters for additional information. 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. To the extent a Utility Registrant receives full cost recovery for energy procurement and related costs from retail customers, it records the fair value of its energy swap contracts with unaffiliated suppliers as well as
Taxes Directly Imposed on Revenue-Producing Transactions	Taxes Directly Imposed on Revenue-Producing Transactions. The Registrants 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 gas. Some of these taxes are imposed on the customer, but paid by the Registrants, while others are imposed on the Registrants. Where these taxes are imposed on the customer, such as sales taxes, they are reported on a net basis with no impact to the Consolidated Statements of Operations and Comprehensive Income. However, where these taxes are imposed on the Registrants, such as gross receipts taxes or other surcharges or fees, they are reported on a gross basis. Accordingly, revenues are recognized for the taxes collected from customers along with an offsetting expense. Se e Note 24 — Supplemental Financial Information for Generation’s and the Utility Registrants' utility taxes that are presented on a gross basis.
Leases (All Registrants)	Leases (All Registrants) The Registrants adopted new accounting guidance issued by the FASB related to leases as of January 1, 2019. The Registrants recognize a ROU asset and lease liability for operating and finance 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. Finance lease ROU assets are included in Plant, property, and equipment, net and finance lease liabilities are included in Long-term debt due within one year and Long-term debt 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 each Registrant’s 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. The Registrants 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 and 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 on the Registrants’ Statements of Operations and Comprehensive Income. Expense for finance leases is primarily recorded to Operating and maintenance on the Utility Registrants’ 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 and are based on the electricity produced by those generating assets. Operating lease income and variable lease payments are recorded to Operating revenues on the Registrants’ Statements of Operations and Comprehensive Income. The Registrants’ operating and finance leases consist primarily of contracted generation, real estate including office buildings, and vehicles and equipment. The Registrants 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 of the economic benefits. For new agreements entered after January 1, 2019, the Registrants 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. The Registrants account for land right arrangements that provide for exclusive use as leases while shared use land arrangements are generally not leases. The Registrants do not account for secondary use pole attachments as leases.
Income Taxes (All Registrants)	Income Taxes (All Registrants) Deferred Federal and state income taxes are recorded on significant temporary differences between the book and tax basis of assets and liabilities and for tax benefits carried forward. Investment tax credits have been deferred in the Registrants’ Consolidated Balance Sheets and are recognized in book income over the life of the related property. The Registrants 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. The Registrants 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 their Consolidated Statements of Operations and Comprehensive Income.
Cash and Cash Equivalents (All Registrants)	Cash and Cash Equivalents (All Registrants) The Registrants consider investments purchased with an original maturity of three months or less to be cash equivalents. Restricted Cash and Cash Equivalents (All Registrants) Restricted cash and cash equivalents represent funds that are restricted to satisfy designated current liabilities. As of December 31, 2020 and 2019, the Registrants' restricted cash and cash equivalents primarily represented the following items: Registrant Description Exelon Payment of medical, dental, vision, and long-term disability benefits, in addition to the items listed for Generation and the Utility Registrants. Generation Project-specific nonrecourse financing structures for debt service and financing of operations of the underlying entities. ComEd Collateral held from suppliers associated with energy and REC procurement contracts, any over-recovered RPS costs and alternative compliance payments received from RES pursuant to FEJA, and costs for the remediation of an MGP site. PECO Proceeds from the sales of assets that were subject to PECO’s mortgage indenture. BGE Proceeds from the loan program for the completion of certain energy efficiency measures and collateral held from energy suppliers. PHI Payment of merger commitments, collateral held from its energy suppliers associated with procurement contracts, and repayment of Transition Bonds. Pepco Payment of merger commitments and collateral held from energy suppliers. DPL Collateral held from energy suppliers. ACE Repayment of Transition Bonds and collateral held from energy suppliers.
Allowance for Uncollectible Accounts (All Registrants)	Allowance for Credit Losses on Accounts Receivables (All Registrants) The allowance for credit losses reflects the Registrants’ best estimates 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 Generation’s 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 Generation wholesale customers is developed using a credit monitoring process, similar to that used for retail customers. When a wholesale customer’s risk characteristics are no longer aligned with the pooled population, Generation uses specific identification to develop an allowance for credit losses. Adjustments to the allowance for credit losses are recorded in Operating and maintenance expense on Generation’s Consolidated Statements of Operations and Comprehensive Income. The allowance for credit losses for the Utility Registrants’ customers is developed by applying loss rates for each Utility Registrant, based on historical loss experience, current conditions, and forward-looking risk factors, to the outstanding receivable balance by customer risk segment. Utility Registrants' customer accounts are written off consistent with approved regulatory requirements. Adjustments to the allowance for credit losses are primarily recorded to Operating and maintenance expense on the Utility Registrants' Consolidated Statements of Operations and Comprehensive Income or Regulatory assets and liabilities on the Utility Registrants' Consolidated Balance Sheets. See Note 3 - Regulatory Matters for additional information regarding the regulatory recovery of credit losses on customer accounts receivable.
Variable Interest Entities (Exelon, Generation, PHI, and ACE)	Variable Interest Entities (Exelon, Generation, PHI, and ACE) Exelon accounts for its investments in and arrangements with VIEs based on the following specific requirements: • requires an entity to qualitatively assess whether it should consolidate a VIE based on whether the entity has a controlling financial interest, • requires an ongoing reconsideration of this assessment instead of only upon certain triggering events, and • requires the entity that consolidates a VIE (the primary beneficiary) to disclose (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.
Inventories (All Registrants)	Inventories (All Registrants) Inventory is recorded at the lower of weighted average cost or net realizable value. Provisions are recorded for excess and obsolete inventory. Fossil fuel, materials and supplies, and emissions allowances are generally included in inventory when purchased. Fossil fuel and emissions allowances are expensed to purchased power and fuel expense when used or sold. Materials and supplies generally includes transmission, distribution, and generating plant materials and are expensed to operating and maintenance or capitalized to property, plant, and equipment, as appropriate, when installed or used.
Marketable Securities (All Registrants)	Debt and Equity Security Investments (Exelon and Generation) Debt Security Investments. Debt securities are reported at fair value and classified as available-for-sale securities. Unrealized gains and losses, net of tax, are reported in OCI. Equity Security Investments without Readily Determinable Fair Values. Exelon has certain equity securities without readily determinable fair values. Exelon has elected to use the practicability exception 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 earnings. Equity Security Investments with Readily Determinable Fair Values. Exelon has certain equity securities with readily determinable fair values. For equity securities held in NDT funds, realized and unrealized gains and losses, net of tax, on Generation’s NDT funds associated with the Regulatory Agreement Units are included in regulatory liabilities at Exelon, ComEd, and PECO, in Noncurrent payables to affiliates at Generation and in
Property Plant And Equipment (All Registrants)	Property, Plant, and Equipment (All Registrants) Property, plant, and equipment is recorded at original cost. Original cost includes construction-related direct labor and material costs. The Utility Registrants also include indirect construction costs including labor and related costs of departments associated with supporting construction activities. When appropriate, original cost also includes capitalized interest for Generation, Exelon Corporate, and PHI and AFUDC for regulated property at the Utility Registrants. The cost of repairs and maintenance, including planned major maintenance activities and minor replacements of property, is charged to Operating and maintenance expense as incurred. Third parties reimburse the Utility Registrants for all or a portion of expenditures for certain capital projects. Such contributions in aid of construction costs (CIAC) are recorded as a reduction to Property, plant, and equipment, net. DOE SGIG and other funds reimbursed to the Utility Registrants have been accounted for as CIAC. For Generation, 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. For the Utility Registrants, upon retirement, the cost of property, net of salvage, is charged to accumulated depreciation consistent with the composite and group methods of depreciation. Depreciation expense at ComEd, BGE, Pepco, DPL, and ACE includes the estimated cost of dismantling and removing plant from service upon retirement. Actual incurred removal costs are applied against a related regulatory liability or recorded to a regulatory asset if in excess of previously collected removal costs. PECO’s removal costs are capitalized to accumulated depreciation when incurred and recorded to depreciation expense over the life of the new asset constructed consistent with PECO’s regulatory recovery method. 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 within Property, plant, and equipment. Similar costs incurred for cloud-based solutions treated as service arrangements are capitalized within Other Current Assets and Deferred Debits and Other Assets. 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 or pursuant to prescribed regulatory requirements. Capitalized Interest and AFUDC. During construction, Exelon and Generation capitalize the costs of debt funds used to finance non-regulated construction projects. Capitalization of debt funds is recorded as a charge to construction work in progress and as a non-cash credit to interest expense. AFUDC is the cost, during the period of construction, of debt and equity funds used to finance construction projects for regulated operations. AFUDC is recorded to construction work in progress and as a non-cash credit to an allowance that is included in interest expense for debt-related funds and other income and deductions for equity-related funds. The rates used for capitalizing AFUDC are computed under a method prescribed by regulatory authorities.
Nuclear Fuel (Exelon and Generation)	Nuclear Fuel (Exelon and Generation)The cost of nuclear fuel is capitalized within Property, plant, and equipment and charged to fuel expense using the unit-of-production method. Any potential future SNF disposal fees will be expensed through 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.
Nuclear Outage Costs (Exelon and Generation)	Nuclear Outage Costs (Exelon and Generation) Costs associated with nuclear outages, including 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.
Depreciation, Depletion, and Amortization (All Registrants)	Depreciation and Amortization (All Registrants) Except for the amortization of nuclear fuel, depreciation 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. ComEd, BGE, Pepco, DPL, and ACE's depreciation expense includes the estimated cost of dismantling and removing plant from service upon retirement, which is consistent with each utility's regulatory recovery method. PECO's removal costs are capitalized to accumulated depreciation when incurred, and recorded to depreciation expense over the life of the new asset constructed consistent with PECO's regulatory recovery method. The estimated service lives for the Registrants 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. See Note 8 — Property, Plant, and Equipment for additional information regarding depreciation. Amortization of regulatory assets and liabilities are recorded over the recovery or refund period specified in the related legislation or regulatory order or agreement. When the recovery or refund period is less than one year, amortization is recorded to the line item in which the deferred cost or income would have originally been recorded in the Utility Registrants’ Consolidated Statements of Operations and Comprehensive Income. Amortization of ComEd’s electric distribution and energy efficiency formula rate regulatory assets and the Utility Registrants' transmission formula rate regulatory assets is recorded to Operating revenues. Amortization of income tax related regulatory assets and liabilities is generally recorded to Income tax expense. With the exception of the regulatory assets and liabilities discussed above, when the recovery period is more than one year, the amortization is generally recorded to Depreciation and amortization in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
Asset Retirement Obligations (All Registrants)	Asset Retirement Obligations (All Registrants)Generation estimates and recognizes a liability for its legal obligation to perform asset retirement activities even though the timing and/or methods of settlement may be conditional on future events. Generation generally updates its nuclear decommissioning ARO annually, unless circumstances warrant more frequent updates, based on its annual evaluation of cost escalation factors and probabilities assigned to the multiple outcome scenarios within its probability-weighted discounted cash flow models. Generation’s multiple outcome scenarios are generally based on decommissioning cost studies which are updated, on a rotational basis, for each of Generation’s 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 to regulatory liabilities for Regulatory Agreement Units or, in the case of the Utility Registrants' accretion, through an increase to regulatory assets.
Guarantees (All Registrants)	Guarantees (All Registrants)If necessary, the Registrants recognize a liability at the time of issuance of a guarantee for the fair market value of the obligations they have undertaken by issuing the guarantee. The liability is reduced or eliminated as the Registrants are released from risk under the guarantee. Depending on the nature of the guarantee, the release from risk of the Registrant may be recognized only upon the expiration or settlement of the guarantee or by a systematic and rational amortization method over the term of the guarantee.
Asset Impairments (All Registrants)	Asset Impairments Long-Lived Assets (All Registrants). The Registrants regularly monitor and evaluate the carrying value of long-lived assets and 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, specific regulatory disallowance, or plans to dispose of a long-lived asset significantly before the end of its useful life. The Registrants determine if long-lived assets and asset groups are impaired by comparing the undiscounted expected future cash flows to the carrying value. When the undiscounted cash flow analysis indicates a long-lived asset or asset group is not 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. See Note 12 — Asset Impairments for additional information. Goodwill (Exelon, ComEd, and PHI). Goodwill represents the excess of the purchase price paid over the estimated fair value of the net assets acquired and liabilities assumed in the acquisition of a business. Goodwill is not amortized, but is assessed for impairment at least annually or on an interim basis if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. See Note 13 — Intangible Assets for additional information. Equity Method Investments (Exelon and Generation). Exelon and Generation 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 Generation holds an investment recognizes an impairment loss, Exelon and Generation would record their proportionate share of that impairment loss and evaluate the investment for an other-than-temporary decline in value. Debt Security Investments (Exelon and Generation). Declines in the fair value of debt security investments below the cost basis are reviewed to determine if such declines are other-than-temporary. If the decline is determined to be other-than-temporary, the amount of the impairment loss is included in earnings. Equity Security Investments (Exelon and Generation). Equity investments with readily determinable fair values are measured and recorded at fair value with any changes in fair value recorded through earnings. 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 on the basis of the qualitative assessment, an impairment loss will be recognized in earnings to the amount by which the security’s carrying amount exceeds its fair value.
Derivatives Financial Instruments (All Registrants)	Derivative Financial Instruments (All Registrants) All derivatives are recognized on the balance sheet at their fair value unless they qualify for certain exceptions, including the 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 revenue, Purchased power and fuel, Interest expense, or Other, net in the Consolidated Statements of Operations and Comprehensive Income based on the activity the transaction is economically hedging. While the majority of the derivatives serve as economic hedges, there are also derivatives entered into for proprietary trading purposes, subject to Exelon’s Risk Management Policy, and changes in the fair value of those derivatives are recorded in revenue in the Consolidated Statements of Operations and Comprehensive Income. At the Utility Registrants, changes in fair value may be recorded as a regulatory asset or liability if there is an ability to recover or return the associated costs. 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. On July 1, 2018, Exelon and Generation de-designated its fair value and cash flow
Retirement Benefits (All Registrants)	Retirement Benefits (All Registrants) Exelon sponsors defined benefit pension plans and OPEB plans for essentially all current employees.
New Accounting Pronouncements, Policy [Policy Text Block]	New Accounting Standards (All Registrants) New Accounting Standards Adopted in 2020: In 2020, the Registrants adopted the following new authoritative accounting guidance issued by the FASB. Impairment of Financial Instruments (Issued June 2016). Provides for a new Current Expected Credit Loss (CECL) impairment model for specified financial instruments including loans, trade receivables, debt securities classified as held-to-maturity investments, and net investments in leases recognized by a lessor. Under the new guidance, on initial recognition and at each reporting period, an entity is required to recognize an allowance that reflects its current estimate of credit losses expected to be incurred over the life of the financial instrument based on historical experience, current conditions, and reasonable and supportable forecasts. The standard was effective January 1, 2020 and requires a modified retrospective transition approach through a cumulative-effect adjustment to retained earnings as of the beginning of the period of adoption. This standard is primarily applicable to Generation's and the Utility Registrants' trade accounts receivables balances. The guidance did not have a significant impact on the Registrants' consolidated financial statements. Goodwill Impairment (Issued January 2017). Simplifies the accounting for goodwill impairment by removing Step 2 of the current impairment assessment model, which requires calculation of a hypothetical purchase price allocation. Under the revised guidance, goodwill impairment will be measured as the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill (currently Step 1 of the two-step impairment assessment). Entities will continue to have the option to perform a qualitative assessment to determine if a quantitative impairment assessment is necessary. The standard was effective January 1, 2020 and must be applied on a prospective basis. Exelon, ComEd, and PHI adopted the new guidance in 2020. The new guidance did not impact Exelon's, ComEd's, and PHI's 2020 annual goodwill impairment assessments as they performed a qualitative assessment.

Regulatory Matters (Tables)

Regulatory Matters (Tables)	12 Months Ended
Regulatory Matters (Tables)	Dec. 31, 2020
Public Utilities, General Disclosures [Line Items]
Public Utilities Distribution Rate Cases [Table Text Block]	The following tables show the completed and pending distribution base rate case proceedings in 2020. Completed Distribution Base Rate Case Proceedings Registrant/Jurisdiction Filing Date Service Requested Revenue Requirement (Decrease) Increase Approved Revenue Requirement (Decrease) Increase Approved ROE Approval Date Rate Effective Date ComEd - Illinois (a) April 8, 2019 Electric $ (6) $ (17) 8.91 % December 4, 2019 January 1, 2020 ComEd - Illinois (a) April 16, 2020 Electric (11) (14) 8.38 % December 9, 2020 January 1, 2021 BGE - Maryland (b) May 15, 2020 (amended September 11, 2020) Electric 137 81 9.50 % December 16, 2020 January 1, 2021 Natural Gas 91 21 9.65 % DPL - Maryland December 5, 2019 (amended April 23, 2020) Electric 17 12 9.60 % July 14, 2020 July 16, 2020 DPL - Delaware February 21, 2020 (amended October 9, 2020) Natural Gas 7 2 9.60 % January 6, 2021 September 21, 2020 __________ (a) Pursuant to EIMA and FEJA, ComEd’s electric distribution rates are established through a performance-based formula, which sunsets at the end of 2022. The electric distribution formula rate includes decoupling provisions and, as a result, ComEd's electric distribution formula rate revenues are not impacted by abnormal weather, usage per customer, or number of customers. ComEd is required to file an annual update to its electric distribution formula rate on or before May 1 st , with resulting rates effective in January of the following year. ComEd’s annual electric distribution formula rate update is based on prior year actual costs and current year projected capital additions (initial year revenue requirement). The update also reconciles any differences between the revenue requirement in effect for the prior year and actual costs incurred from the year (annual reconciliation). ComEd’s 2020 approved revenue requirement above reflects an increase of $51 million for the initial year revenue requirement for 2020 and a decrease of $68 million related to the annual reconciliation for 2018. The revenue requirement for 2020 and the revenue requirement for 2018 provides for a weighted average debt and equity return on distribution rate base of 6.51% inclusive of an allowed ROE of 8.91%, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points . ComEd’s 2021 approved revenue requirement above reflects an increase of $50 million for the initial year revenue requirement for 2021 and a decrease of $64 million related to the annual reconciliation for 2019. The revenue requirement for 2021 and the revenue requirement for 2019 provide for a weighted average debt and equity return on distribution rate base of 6.28% inclusive of an allowed ROE of 8.38%, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. See table below for ComEd's regulatory assets associated with its electric distribution formula rate. (b) Reflects a three-year cumulative multi-year plan for 2021 through 2023. The MDPSC awarded BGE electric revenue requirement increases of $59 million, $39 million, and $42 million in 2021, 2022, and 2023, respectively, and natural gas revenue requirement increases of $53 million, $11 million, and $10 million in 2021, 2022, and 2023, respectively. However, the MDPSC utilized certain tax benefits to fully offset the increases in 2021 so that customer rates will remain unchanged from 2020 to 2021. The MDPSC has deferred a decision on whether to use certain tax benefits to offset the revenue requirement increases in 2022 and 2023 and BGE cannot predict the outcome. Pending Distribution Base Rate Case Proceedings Registrant/Jurisdiction Filing Date Service Requested Revenue Requirement Increase Requested ROE Expected Approval Timing PECO - Pennsylvania September 30, 2020 Natural Gas $ 69 10.95 % Second quarter of 2021 Pepco - District of Columbia (a) May 30, 2019 (amended June 1, 2020) Electric 136 9.7 % Second quarter of 2021 Pepco - Maryland (b) October 26, 2020 Electric 110 10.2 % Second quarter of 2021 DPL - Delaware (c) March 6, 2020 (amended February 2, 2021) Electric 23 10.3 % Third quarter of 2021 ACE - New Jersey (d) December 9, 2020 Electric 67 10.3 % Fourth quarter of 2021 _________ (a) Pepco filed the multi-year plan enhanced proposal as an alternative to address the impacts of COVID-19. Reflects a three-year cumulative multi-year plan for 2020 through 2022 and requested revenue requirement increases of $73 million in 2022 and $63 million in 2023, to recover capital investments made during 2018 through 2020 and planned capital investments through the end of 2022. (b) Reflects a three-year cumulative multi-year plan for April 1, 2021 through March 31, 2024 and total requested revenue requirement increases of $56 million effective April 1, 2023 and $54 million effective April 1, 2024 to recover capital investments made in 2019 and 2020 and planned capital investments through March 31, 2024. (c) The rates went into effect on October 6, 2020, subject to refund. (d) Requested increases are before New Jersey sales and use tax. ACE intends to put rates into effect on September 8, 2021, subject to refund.
Public Utilities Transmission Rate Filings [Table Text Block]	For 2020, the following total increases/(decreases) were included in the Utility Registrants' electric transmission formula rate updates: Registrant (a) Initial Revenue Requirement Increase/(Decrease) Annual Reconciliation Decrease Total Revenue Requirement Increase/(Decrease) (b) Allowed Return on Rate Base (c) Allowed ROE (d) ComEd $ 18 $ (4) $ 14 8.17 % 11.50 % PECO 5 (28) (23) 7.47 % 10.35 % BGE 16 (3) 4 7.26 % 10.50 % Pepco 2 (46) (44) 7.81 % 10.50 % DPL (4) (40) (44) 7.20 % 10.50 % ACE 5 (25) (20) 7.40 % 10.50 % __________ (a) All rates are effective June 30, 2020 - May 31, 2021, subject to review by interested parties pursuant to review protocols of each Utility Registrant's tariff. (b) The decrease in PECO's transmission revenue requirement relates to refunds from December 1, 2017, in accordance with the settlement agreement dated July 22, 2019. The increase in BGE's transmission revenue requirement includes a $9 million reduction related to a FERC approved dedicated facilities charge to recover the costs of providing transmission service to specifically designated load by BGE. ComEd, BGE, Pepco, DPL, and ACE’s transmission revenue requirement include a decrease related to the April 24, 2020 settlement agreement related to excess deferred income taxes. Refer to Transmission-Related Income Tax Regulatory assets below for additional information. (c) Represents the weighted average debt and equity return on transmission rate bases. (d) As part of the FERC-approved settlement of ComEd’s 2007 and PECO's 2017 transmission rate cases, the rate of return on common equity is 11.50% and 10.35%, respectively inclusive of a 50-basis-point incentive adder for being a member of a RTO, and the common equity component of the ratio used to calculate the weighted average debt and equity return for the transmission formula rate is currently capped at 55% and 55.75%, respectively. As part of the FERC-approved settlement of the ROE complaint against BGE, Pepco, DPL, and ACE, the rate of return on common equity is 10.50%, inclusive of a 50-basis-point incentive adder for being a member of a RTO.
Public Utilities Energy Efficiency Revenue [Table Text Block]	During 2020, the ICC approved the following total increases in ComEd's requested energy efficiency revenue requirement: Filing Date Requested Revenue Requirement Increase Approved Revenue Requirement Increase Approved ROE Approval Date Rate Effective Date May 21, 2020 $ 48 $ 48 (a) 8.38 % December 2, 2020 January 1, 2021 _________ (a) ComEd’s 2021 approved revenue requirement above reflects an increase of $45 million for the initial year revenue r equirement for 2021 and an increase of $3 million related to the annual reconciliation for 2019. The revenue requirement for 2021 provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 6.28% inclusive of an allowed ROE of 8.38%, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. The revenue requirement for 2019 provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 6.56% inclusive of an allowed ROE of 8.96%, which includes an upward performance adjustment that can either increase or decrease the ROE. See table below for ComEd's regulatory assets associated with its energy efficiency formula rate.
Schedule of Regulatory Assets	The following tables provide information about the regulatory assets and liabilities of Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE as of December 31, 2020 and December 31, 2019: December 31, 2020 Exelon ComEd PECO BGE PHI Pepco DPL ACE Regulatory assets Pension and OPEB $ 3,010 $ — $ — $ — $ — $ — $ — $ — Pension and OPEB - merger related 1,014 — — — — — — — Deferred income taxes 715 — 705 — 10 10 — — AMI programs - deployment costs 174 — — 109 65 35 30 — AMI programs - legacy meters 219 90 — 37 92 68 24 — Electric distribution formula rate annual reconciliations (14) (14) — — — — — — Electric distribution formula rate significant one-time events 117 117 — — — — — — Energy efficiency costs 982 982 — — — — — — Fair value of long-term debt 598 — — — 478 — — — Fair value of PHI's unamortized energy contracts 328 — — — 328 — — — Asset retirement obligations 135 92 21 18 4 3 — 1 MGP remediation costs 285 271 10 4 — — — — Renewable energy 301 301 — — — — — — Electric energy and natural gas costs 95 — — 23 72 37 5 30 Transmission formula rate annual reconciliations 5 — — 2 3 — 2 1 Energy efficiency and demand response programs 572 — — 289 283 203 80 — Under-recovered revenue decoupling 113 — — 20 93 93 — — Stranded costs 25 — — — 25 — — 25 Removal costs 701 — — 107 594 151 105 339 DC PLUG charge 100 — — — 100 100 — — Deferred storm costs 50 — — — 50 5 4 41 COVID-19 81 22 38 10 11 7 4 — Under-recovered credit loss expense 107 89 — — 18 — — 18 Other 274 78 27 30 147 72 26 15 Total regulatory assets 9,987 2,028 801 649 2,373 784 280 470 Less: current portion 1,228 279 25 168 440 214 58 75 Total noncurrent regulatory assets $ 8,759 $ 1,749 $ 776 $ 481 $ 1,933 $ 570 $ 222 $ 395
Schedule of Regulatory Liabilities	December 31, 2020 Exelon ComEd PECO BGE PHI Pepco DPL ACE Regulatory liabilities Deferred income taxes $ 4,502 $ 2,205 $ — $ 1,001 $ 1,296 $ 621 $ 404 $ 271 Nuclear decommissioning 3,016 2,541 475 — — — — — Removal costs 1,649 1,482 — 47 120 20 100 — Electric energy and natural gas costs 175 34 97 6 38 24 10 4 Transmission formula rate annual reconciliations 52 2 12 — 38 23 9 6 Renewable portfolio standards costs 427 427 — — — — — — Stranded costs 24 — — — 24 — — 24 Other 221 1 40 85 59 2 17 13 Total regulatory liabilities 10,066 6,692 624 1,139 1,575 690 540 318 Less: current portion 581 289 121 30 137 46 47 44 Total noncurrent regulatory liabilities $ 9,485 $ 6,403 $ 503 $ 1,109 $ 1,438 $ 644 $ 493 $ 274
Public Utilities General Disclosures [Table Text Block]	The following table presents authorized amounts capitalized for ratemaking purposes related to earnings on shareholders’ investment that are not recognized for financial reporting purposes in Exelon's and the Utility Registrant's Consolidated Balance Sheets. These amounts will be recognized as revenues in the related Consolidated Statements of Operations and Comprehensive Income in the periods they are billable to our customers. Exelon ComEd (a) PECO BGE (b) PHI Pepco (c) DPL (c) ACE December 31, 2020 $ 51 $ (1) $ — $ 45 $ 7 $ 4 $ 3 $ — December 31, 2019 $ 63 $ 3 $ — $ 53 $ 7 $ 4 $ 3 $ — __________ (a) Reflects ComEd's unrecognized equity returns/(losses) earned/(incurred) for ratemaking purposes on its electric distribution formula rate regulatory assets. (b) BGE's authorized amounts capitalized for ratemaking purposes primarily relate to earnings on shareholders' investment on its AMI programs.
Regulatory assets 2019 [Member]
Public Utilities, General Disclosures [Line Items]
Schedule of Regulatory Assets	December 31, 2019 Exelon ComEd PECO BGE PHI Pepco DPL ACE Regulatory assets Pension and OPEB $ 2,784 $ — $ — $ — $ — $ — $ — $ — Pension and OPEB - merger related 1,138 — — — — — — — Deferred income taxes 528 — 518 — 10 10 — — AMI programs - deployment costs 207 — — 129 78 43 35 — AMI programs - legacy meters 276 113 12 45 106 79 27 — Electric distribution formula rate annual reconciliations 34 34 — — — — — — Electric distribution formula rate significant one-time events 66 66 — — — — — — Energy efficiency costs 746 746 — — — — — — Fair value of long-term debt 650 — — — 523 — — — Fair value of PHI's unamortized energy contracts 443 — — — 443 — — — Asset retirement obligations 127 85 23 16 3 2 — 1 MGP remediation costs 302 287 11 4 — — — — Renewable energy 301 301 — — — — — — Electric energy and natural gas costs 110 — 6 36 68 43 5 20 Transmission formula rate annual reconciliations 11 — — 1 10 1 2 7 Energy efficiency and demand response programs 572 — — 303 269 196 73 — Merger integration costs 32 — — 2 30 15 8 7 Under-recovered revenue decoupling 37 — — 8 29 29 — — Stranded costs 37 — — — 37 — — 37 Removal costs 641 — — 67 574 152 100 324 DC PLUG charge 126 — — — 126 126 — — Other 337 129 25 26 167 76 24 29 Total regulatory assets 9,505 1,761 595 637 2,473 772 274 425 Less: current portion 1,170 281 41 183 412 188 52 57 Total noncurrent regulatory assets $ 8,335 $ 1,480 $ 554 $ 454 $ 2,061 $ 584 $ 222 $ 368
Regulatory liabilities 2019 [Member]
Public Utilities, General Disclosures [Line Items]
Schedule of Regulatory Liabilities	December 31, 2019 Exelon ComEd PECO BGE PHI Pepco DPL ACE Regulatory liabilities Deferred income taxes $ 4,944 $ 2,297 $ — $ 1,089 $ 1,558 $ 725 $ 477 $ 356 Nuclear decommissioning 3,102 2,622 480 — — — — — Removal costs 1,621 1,435 — 58 128 20 108 — Electric energy and natural gas costs 109 45 56 — 8 — 8 — Transmission formula rate annual reconciliations 34 6 28 — — — — — Other 582 337 37 81 83 9 18 26 Total regulatory liabilities 10,392 6,742 601 1,228 1,777 754 611 382 Less: current portion 406 200 91 33 70 8 37 25 Total noncurrent regulatory liabilities $ 9,986 $ 6,542 $ 510 $ 1,195 $ 1,707 $ 746 $ 574 $ 357

Revenue from Contracts with C_2

Revenue from Contracts with Customers Revenue from Contracts with Customers (Tables)	12 Months Ended
	Dec. 31, 2020
Contract Asset/Liabilities [Line Items]
Contract with Customer, Prior Year Contract Revenues Recognized in Current Year [Table Text Block]	The following table reflects revenues recognized in the years ended December 31, 2020, 2019 and 2018, which were included in contract liabilities at December 31, 2019, 2018, and 2017, respectively: 2020 2019 2018 Exelon $ 27 $ 18 $ 11 Generation 64 32 11
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Table Text Block]	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, 2020. 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 Generation's power and gas sales contracts as they contain variable volumes and/or variable pricing. This disclosure also excludes the Utility Registrants' gas and electric tariff sales contracts and transmission revenue contracts as they generally have an original expected duration of one year or less and, therefore, do not contain any future, unsatisfied performance obligations to be included in this disclosure. 2021 2022 2023 2024 2025 and thereafter Total Exelon $ 262 $ 93 $ 54 $ 40 $ 330 $ 779 Generation 352 124 55 34 243 808 PHI 9 8 8 6 87 118 Pepco 7 6 6 5 70 94 DPL 1 1 1 — 9 12 ACE 1 1 1 1 8 12
Contract Assets [Member]
Contract Asset/Liabilities [Line Items]
Contract with Customer, Contract Asset, Contract Liability, and Receivable [Table Text Block]	The following table provides a rollforward of the contract assets reflected in Exelon's and Generation's Consolidated Balance Sheets. The Utility Registrants do not have any contract assets. Exelon Generation Balance as of December 31, 2018 $ 187 $ 187 Amounts reclassified to receivables (143) (143) Revenues recognized 130 130 Balance at December 31, 2019 174 174 Amounts reclassified to receivables (86) (86) Revenues recognized 68 68 Contract assets reclassified as held for sale (a) (12) (12) Balance at December 31, 2020 $ 144 $ 144 __________ (a) Represents contract assets related to Generation's solar business, which were classified as held for sale as a result of the sale agreement. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information.
Contract Liabilities [Member]
Contract Asset/Liabilities [Line Items]
Contract with Customer, Contract Asset, Contract Liability, and Receivable [Table Text Block]	The following table provides a rollforward of the contract liabilities reflected in Exelon's, Generation's, PHI's, Pepco's, DPL's, and ACE'S Consolidated Balance Sheets. As of December 31, 2020, 2019, and 2018, ComEd's, PECO's, and BGE's contract liabilities were immaterial. Exelon Generation PHI Pepco DPL ACE Balance as of December 31, 2017 $ 35 $ 35 $ — $ — $ — $ — Consideration received or due 179 465 — — — — Revenues recognized (187) (458) — — — — Balance as of December 31, 2018 27 42 — — — — Consideration received or due 94 287 — — — — Revenues recognized (88) (258) — — — — Balance at December 31, 2019 33 71 — — — — Consideration received or due 219 282 122 98 12 12 Revenues recognized (98) (266) (4) (4) — — Contracts liabilities reclassified as held for sale (a) (3) (3) — — — — Balance at December 31, 2020 $ 151 $ 84 $ 118 $ 94 $ 12 $ 12 __________ (a) Represents contract liabilities related to Generation's solar business, which were classified as held for sale as a result of the sale agreement. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information.

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
Segment Information (Tables)	Dec. 31, 2020
Segment Reporting [Abstract]
Analysis and reconciliation of reportable segment information	An analysis and reconciliation of the Registrants’ reportable segment information to the respective information in the consolidated financial statements for the years ended December 31, 2020, 2019, and 2018 is as follows: Generation ComEd PECO BGE PHI Other (a) Intersegment Exelon Operating revenues (b) : 2020 Competitive businesses electric revenues $ 15,060 $ — $ — $ — $ — $ — $ (1,196) $ 13,864 Competitive businesses natural gas revenues 2,003 — — — — — (3) 2,000 Competitive businesses other revenues 540 — — — — — (4) 536 Rate-regulated electric revenues — 5,904 2,543 2,336 4,485 — (61) 15,207 Rate-regulated natural gas revenues — — 515 762 162 — (7) 1,432 Shared service and other revenues — — — — 16 2,035 (2,051) — Total operating revenues $ 17,603 $ 5,904 $ 3,058 $ 3,098 $ 4,663 $ 2,035 $ (3,322) $ 33,039 2019 Competitive businesses electric revenues $ 16,285 $ — $ — $ — $ — $ — $ (1,165) $ 15,120 Competitive businesses natural gas revenues 2,148 — — — — — (1) 2,147 Competitive businesses other revenues 491 — — — — — (4) 487 Rate-regulated electric revenues — 5,747 2,490 2,379 4,626 — (47) 15,195 Rate-regulated natural gas revenues — — 610 727 167 — (15) 1,489 Shared service and other revenues — — — — 13 1,921 (1,934) — Total operating revenues $ 18,924 $ 5,747 $ 3,100 $ 3,106 $ 4,806 $ 1,921 $ (3,166) $ 34,438 Generation ComEd PECO BGE PHI Other (a) Intersegment Exelon 2018 Competitive businesses electric revenues $ 17,411 $ — $ — $ — $ — $ — $ (1,256) $ 16,155 Competitive businesses natural gas revenues 2,718 — — — — — (8) 2,710 Competitive businesses other revenues 308 — — — — — (5) 303 Rate-regulated electric revenues — 5,882 2,470 2,428 4,602 — (45) 15,337 Rate-regulated natural gas revenues — — 568 741 181 — (20) 1,470 Shared service and other revenues — — — — 15 1,948 (1,960) 3 Total operating revenues $ 20,437 $ 5,882 $ 3,038 $ 3,169 $ 4,798 $ 1,948 $ (3,294) $ 35,978 Intersegment revenues (c) : 2020 $ 1,211 $ 37 $ 9 $ 20 $ 17 $ 2,024 $ (3,314) $ 4 2019 1,172 30 6 26 14 1,913 (3,159) 2 2018 1,269 27 8 29 15 1,942 (3,289) 1 Depreciation and amortization: 2020 $ 2,123 $ 1,133 $ 347 $ 550 $ 782 $ 79 $ — $ 5,014 2019 1,535 1,033 333 502 754 95 — 4,252 2018 1,797 940 301 483 740 92 — 4,353 Operating expenses: 2020 $ 17,358 $ 4,950 $ 2,512 $ 2,598 $ 4,045 $ 2,047 $ (3,270) $ 30,240 2019 17,628 4,580 2,388 2,574 4,084 1,996 (3,154) 30,096 2018 19,510 4,741 2,452 2,696 4,156 1,929 (3,341) 32,143 Interest expense, net: 2020 $ 357 $ 382 $ 147 $ 133 $ 268 $ 351 $ (3) $ 1,635 2019 429 359 136 121 263 308 — 1,616 2018 432 347 129 106 261 279 — 1,554 Income (loss) before income taxes: 2020 $ 836 $ 615 $ 417 $ 390 $ 418 $ (343) $ — $ 2,333 2019 1,917 851 593 439 514 (327) (2) 3,985 2018 365 832 466 387 425 (249) (1) 2,225 Income taxes: 2020 $ 249 $ 177 $ (30) $ 41 $ (77) $ 13 $ — $ 373 2019 516 163 65 79 38 (87) — 774 2018 (108) 168 6 74 33 (55) — 118 Net income (loss): 2020 $ 579 $ 438 $ 447 $ 349 $ 495 $ (354) $ — $ 1,954 2019 1,217 688 528 360 477 (240) (2) 3,028 Generation ComEd PECO BGE PHI Other (a) Intersegment Exelon 2018 443 664 460 313 393 (193) (1) 2,079 Capital expenditures: 2020 $ 1,747 $ 2,217 $ 1,147 $ 1,247 $ 1,604 $ 86 $ — $ 8,048 2019 1,845 1,915 939 1,145 1,355 49 — 7,248 2018 2,242 2,126 849 959 1,375 43 — 7,594 Total assets: 2020 $ 48,094 $ 34,466 $ 12,531 $ 11,650 $ 23,736 $ 9,005 $ (10,165) $ 129,317 2019 48,995 32,765 11,469 10,634 22,719 8,484 (10,089) 124,977 __________ (a) Other primarily includes Exelon’s corporate operations, shared service entities, and other financing and investment activities. (b) Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 24 — Supplemental Financial Information for additional information on total utility taxes. (c) Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with Generation’s sale of certain products and services by and between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income. See Note 25 - Related Party Transactions for additional information on intersegment revenues. PHI: Pepco DPL ACE Other (a) Intersegment PHI Operating revenues (b) : 2020 Rate-regulated electric revenues $ 2,149 $ 1,109 $ 1,245 $ — $ (18) $ 4,485 Rate-regulated natural gas revenues — 162 — — — 162 Shared service and other revenues — — — 372 (356) 16 Total operating revenues $ 2,149 $ 1,271 $ 1,245 $ 372 $ (374) $ 4,663 2019 Rate-regulated electric revenues $ 2,260 $ 1,139 $ 1,240 $ — $ (13) $ 4,626 Rate-regulated natural gas revenues — 167 — — — 167 Shared service and other revenues — — — 396 (383) 13 Total operating revenues $ 2,260 $ 1,306 $ 1,240 $ 396 $ (396) $ 4,806 2018 Rate-regulated electric revenues $ 2,232 $ 1,151 $ 1,236 $ — $ (17) $ 4,602 Rate-regulated natural gas revenues — 181 — — — 181 Shared service and other revenues — — — 435 (420) 15 Total operating revenues $ 2,232 $ 1,332 $ 1,236 $ 435 $ (437) $ 4,798 Intersegment revenues (c) : 2020 $ 7 $ 9 $ 4 $ 372 $ (375) $ 17 2019 5 7 3 396 (397) 14 2018 6 8 3 435 (437) 15 Depreciation and amortization: 2020 $ 377 $ 191 $ 180 $ 34 $ — $ 782 2019 374 184 157 39 — 754 2018 385 182 136 37 — 740 Operating expenses: 2020 $ 1,799 $ 1,120 $ 1,123 $ 378 $ (375) $ 4,045 2019 1,899 1,089 1,089 403 (396) 4,084 2018 1,919 1,143 1,087 442 (435) 4,156 Interest expense, net: 2020 $ 138 $ 61 $ 59 $ 10 $ — $ 268 2019 133 61 58 10 1 263 2018 128 58 64 11 — 261 Income (loss) before income taxes: 2020 $ 259 $ 100 $ 71 $ (12) $ — $ 418 2019 (d) 259 169 99 (13) — 514 2018 (d) 216 142 87 (20) — 425 Income taxes: 2020 $ (7) $ (25) $ (41) $ (4) $ — $ (77) 2019 16 22 — — — 38 2018 11 22 12 (12) — 33 Pepco DPL ACE Other (a) Intersegment PHI Net income (loss): 2020 $ 266 $ 125 $ 112 $ (8) $ — $ 495 2019 243 147 99 (12) — 477 2018 205 120 75 (7) — 393 Capital expenditures: 2020 $ 773 $ 424 $ 401 $ 6 $ — $ 1,604 2019 626 348 375 6 — 1,355 2018 656 364 335 20 — 1,375 Total assets: 2020 $ 9,264 $ 5,140 $ 4,286 $ 5,079 $ (33) $ 23,736 2019 (d) 8,661 4,830 3,933 5,335 (40) 22,719 __________ (a) Other primarily includes PHI’s corporate operations, shared service entities, and other financing and investment activities. (b) Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 24 — Supplemental Financial Information for additional information on total utility taxes. (c) Includes intersegment revenues with ComEd, BGE, and PECO, which are eliminated at Exelon. (d) The Income (loss) before income taxes in Other and Intersegment Eliminations have been adjusted by an offsetting $489 million and $408 million in 2019 and 2018, respectively, and Total assets amounts in Other and Intersegment Eliminations have been adjusted by an offsetting $5.7 billion in 2019 for consistency with the Exelon consolidating disclosure above.
Analysis and reconciliation of reportable segment revenues for Generation	The following tables disaggregate the Registrants' 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. For Generation, the disaggregation of revenues reflects Generation's two primary products of power sales and natural gas sales, with further disaggregation of power sales provided by geographic region. For the Utility Registrants, the disaggregation of revenues reflects the two primary utility services of rate-regulated electric sales and rate-regulated natural gas sales (where applicable), with further disaggregation of these tariff sales provided by major customer groups. Exelon's disaggregated revenues are consistent with Generation and the Utility Registrants, but exclude any intercompany revenues. Competitive Business Revenues (Generation): 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 Generation Consolidated Operating Revenues $ 15,905 $ 1,698 $ 17,603 $ — $ 17,603 2019 Revenues from external customers (a) Contracts with customers Other (b) Total Intersegment Revenues Total Revenues Mid-Atlantic $ 5,053 $ 17 $ 5,070 $ 4 $ 5,074 Midwest 4,095 232 4,327 (34) 4,293 New York 1,571 25 1,596 — 1,596 ERCOT 768 229 997 16 1,013 Other Power Regions 3,687 608 4,295 (49) 4,246 Total Competitive Businesses Electric Revenues $ 15,174 $ 1,111 $ 16,285 $ (63) $ 16,222 Competitive Businesses Natural Gas Revenues 1,446 702 2,148 62 2,210 Competitive Businesses Other Revenues (c) 440 51 491 1 492 Total Generation Consolidated Operating Revenues $ 17,060 $ 1,864 $ 18,924 $ — $ 18,924 2018 Revenues from external customers (a) Contracts with customers Other (b) Total Intersegment Revenues Total Revenues Mid-Atlantic $ 5,241 $ 233 $ 5,474 $ 13 $ 5,487 Midwest 4,527 190 4,717 (11) 4,706 New York 1,723 (36) 1,687 — 1,687 ERCOT 572 560 1,132 1 1,133 Other Power Regions 3,530 871 4,401 (66) 4,335 Total Competitive Businesses Electric Revenues $ 15,593 $ 1,818 $ 17,411 $ (63) $ 17,348 Competitive Businesses Natural Gas Revenues 1,524 1,194 2,718 62 2,780 Competitive Businesses Other Revenues (c) 510 (202) 308 1 309 Total Generation Consolidated Operating Revenues $ 17,627 $ 2,810 $ 20,437 $ — $ 20,437 __________ (a) Includes all wholesale and retail electric sales to third parties and affiliated sales to the Utility Registrants. (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 gains of $110 million and losses of $4 million and $262 million for the years ended December 31, 2020, 2019, and 2018, respectively, and the elimination of intersegment revenues. Revenues net of purchased power and fuel expense (Generation): 2020 2019 2018 RNF from external (a) Intersegment Total RNF from external (a) Intersegment Total RNF from external (a) Intersegment Total Mid-Atlantic $ 2,174 $ 30 $ 2,204 $ 2,637 $ 18 $ 2,655 $ 3,022 $ 51 $ 3,073 Midwest 2,902 — 2,902 2,994 (32) 2,962 3,112 23 3,135 New York 983 14 997 1,081 13 1,094 1,112 10 1,122 ERCOT 407 19 426 338 (30) 308 501 (243) 258 Other Power Regions 759 (94) 665 694 (74) 620 883 (154) 729 Total RNF for Reportable Segments $ 7,225 $ (31) $ 7,194 $ 7,744 $ (105) $ 7,639 $ 8,630 $ (313) $ 8,317 Other (b) 793 31 824 324 105 429 114 313 427 Total Generation RNF $ 8,018 $ — $ 8,018 $ 8,068 $ — $ 8,068 $ 8,744 $ — $ 8,744 __________ (a) Includes purchases and sales from/to third parties and affiliated sales to the Utility Registrants. (b) Other represents activities not allocated to a region. See text above for a description of included activities. Primarily includes: • unrealized mark-to-market gain s of $295 million and losses of $215 million and $319 million for the years ended December 31, 2020, 2019, and 2018, respectively; • accelerated nuclear fuel amortization associated with the announced early plant retirements as discussed in Note 7 - Early Plant Retirements of $60 million , $13 million, and $57 million in for the years ended December 31, 2020, 2019, and 2018, respectively; and • the elimination of intersegment RNF.
Schedule of Revenue by Major Customers by Reporting Segments	Electric and Gas Revenue by Customer Class (Utility Registrants): 2020 Revenues from contracts with customers ComEd PECO BGE PHI Pepco DPL ACE Rate-regulated electric revenues Residential $ 3,090 $ 1,656 $ 1,345 $ 2,332 $ 988 $ 652 $ 692 Small commercial & industrial 1,399 386 241 472 132 171 169 Large commercial & industrial 515 228 406 1,001 736 89 176 Public authorities & electric railroads 45 29 27 60 34 13 13 Other (a) 884 225 309 613 218 190 207 Total rate-regulated electric revenues (b) $ 5,933 $ 2,524 $ 2,328 $ 4,478 $ 2,108 $ 1,115 $ 1,257 Rate-regulated natural gas revenues Residential $ — $ 361 $ 504 $ 96 $ — $ 96 $ — Small commercial & industrial — 126 79 42 — 42 — Large commercial & industrial — — 135 4 — 4 — Transportation — 24 — 14 — 14 — Other (c) — 4 29 6 — 6 — Total rate-regulated natural gas revenues (d) $ — $ 515 $ 747 $ 162 $ — $ 162 $ — Total rate-regulated revenues from contracts with customers $ 5,933 $ 3,039 $ 3,075 $ 4,640 $ 2,108 $ 1,277 $ 1,257 Other revenues Revenues from alternative revenue programs $ (47) $ 16 $ 16 $ 21 $ 40 $ (7) $ (12) Other rate-regulated electric revenues (e) 18 3 5 2 1 1 — Other rate-regulated natural gas revenues (e) — — 2 — — — — Total other revenues $ (29) $ 19 $ 23 $ 23 $ 41 $ (6) $ (12) Total rate-regulated revenues for reportable segments $ 5,904 $ 3,058 $ 3,098 $ 4,663 $ 2,149 $ 1,271 $ 1,245 2019 Revenues from contracts with customers ComEd PECO BGE PHI Pepco DPL ACE Rate-regulated electric revenues Residential $ 2,916 $ 1,596 $ 1,326 $ 2,316 $ 1,012 $ 645 $ 659 Small commercial & industrial 1,463 404 254 505 149 186 170 Large commercial & industrial 540 219 436 1,112 833 99 180 Public authorities & electric railroads 47 29 27 61 34 14 13 Other (a) 888 249 321 650 227 204 218 Total rate-regulated electric revenues (b) $ 5,854 $ 2,497 $ 2,364 $ 4,644 $ 2,255 $ 1,148 $ 1,240 Rate-regulated natural gas revenues Residential $ — $ 409 $ 474 $ 96 $ — $ 96 $ — Small commercial & industrial — 169 77 44 — 45 — Large commercial & industrial — 1 132 5 — 5 — Transportation — 25 — 14 — 14 — Other (c) — 6 31 7 — 7 — Total rate-regulated natural gas revenues (d) $ — $ 610 $ 714 $ 166 $ — $ 167 $ — Total rate-regulated revenues from contracts with customers $ 5,854 $ 3,107 $ 3,078 $ 4,810 $ 2,255 $ 1,315 $ 1,240 Other revenues Revenues from alternative revenue programs $ (133) $ (21) $ 12 $ (14) $ (3) $ (11) $ — Other rate-regulated electric revenues (e) 26 13 12 10 8 2 — Other rate-regulated natural gas revenues (e) — 1 4 — — — — Total other revenues $ (107) $ (7) $ 28 $ (4) $ 5 $ (9) $ — Total rate-regulated revenues for reportable segments $ 5,747 $ 3,100 $ 3,106 $ 4,806 $ 2,260 $ 1,306 $ 1,240 2018 Revenues from contracts with customers ComEd PECO BGE PHI Pepco DPL ACE Rate-regulated electric revenues Residential $ 2,942 $ 1,566 $ 1,382 $ 2,351 $ 1,021 $ 669 $ 661 Small commercial & industrial 1,487 404 257 488 140 186 162 Large commercial & industrial 538 223 429 1,124 846 100 178 Public authorities & electric railroads 47 28 28 58 32 14 12 Other (a) 867 243 327 593 193 175 227 Total rate-regulated electric revenues (b) $ 5,881 $ 2,464 $ 2,423 $ 4,614 $ 2,232 $ 1,144 $ 1,240 Rate-regulated natural gas revenues Residential $ — $ 395 $ 491 $ 99 $ — $ 99 $ — Small commercial & industrial — 143 77 44 — 44 — Large commercial & industrial — 1 124 8 — 8 — Transportation — 23 — 16 — 16 — Other (c) — 6 63 13 — 13 — Total rate-regulated natural gas revenues (d) $ — $ 568 $ 755 $ 180 $ — $ 180 $ — Total rate-regulated revenues from contracts with customers $ 5,881 $ 3,032 $ 3,178 $ 4,794 $ 2,232 $ 1,324 $ 1,240 Other revenues Revenues from alternative revenue programs $ (29) $ (7) $ (26) $ (7) $ (7) $ 4 $ (4) Other rate-regulated electric revenues (e) 30 12 13 10 7 3 — Other rate-regulated natural gas revenues (e) — 1 4 1 — 1 — Total other revenues $ 1 $ 6 $ (9) $ 4 $ — $ 8 $ (4) Total rate-regulated revenues for reportable segments $ 5,882 $ 3,038 $ 3,169 $ 4,798 $ 2,232 $ 1,332 $ 1,236 __________ (a) Includes revenues from transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue. (b) Includes operating revenues from affiliates in 2020, 2019, and 2018 respectively of: • $37 million, $30 million, and $27 million at ComEd • $8 million, $5 million, and $7 million at PECO • $10 million, $8 million, and $8 million at BGE • $17 million, $14 million, and $15 million at PHI • $7 million, $5 million, and $6 million at Pepco • $9 million, $7 million, and $8 million at DPL • $4 million, $3 million, and $3 million at ACE (c) Includes revenues from off-system natural gas sales. (d) Includes operating revenues from affiliates in 2020, 2019, and 2018 respectively of: • $1 million, $1 million, and $1 million at PECO • $10 million, $18 million, and $21 million at BGE (e) Includes late payment charge revenues.

Accounts Receivable (Tables)

Accounts Receivable (Tables)	12 Months Ended
Accounts Receivable (Tables)	Dec. 31, 2020
Receivables [Abstract]
Allowance for Credit Losses Rollforward	The following table presents the rollforward of Allowance for Credit Losses on Customer Accounts Receivable for the year ended December 31, 2020. Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE Balance as of December 31, 2019 $ 243 $ 80 $ 59 $ 55 $ 12 $ 37 $ 13 $ 11 $ 13 Plus: Current Period Provision for Expected Credit Losses (a) 248 13 62 79 30 64 24 15 25 Less: Write-offs, net of recoveries (b) 69 5 24 18 7 15 5 4 6 Less: Sale of customer accounts receivable (c) 56 56 — — — — — — — Balance as of December 31, 2020 $ 366 $ 32 $ 97 $ 116 $ 35 $ 86 $ 32 $ 22 $ 32 _________ (a) For the Utility Registrants, the increase is primarily as a result of increased aging of receivables, the temporary suspension of customer disconnections for non-payment, temporary cessation of new late payment fees, and reconnection of service to customers previously disconnected due to COVID-19. (b) Recoveries were not material to the Registrants. (c) See below for additional information on the sale of customer accounts receivable at Generation in the second quarter of 2020. The following table presents the rollforward of Allowance for Credit Losses on Other Accounts Receivable for the year ended December 31, 2020. Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE Balance as of December 31, 2019 $ 48 $ — $ 20 $ 7 $ 5 $ 16 $ 7 $ 4 $ 5 Plus: Current Period Provision for Expected Credit Losses 33 — 5 3 7 18 6 5 7 Less: Write-offs, net of recoveries (a) 10 — 4 2 3 1 — — 1 Balance as of December 31, 2020 $ 71 $ — $ 21 $ 8 $ 9 $ 33 $ 13 $ 9 $ 11 _________ (a) Recoveries were not material to the Registrants.
Unbilled Customer Revenue	The following table provides additional information about unbilled customer revenues recorded in the Registrants' Consolidated Balance Sheets as of December 31, 2020 and 2019. Unbilled customer revenues (a) Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE December 31, 2020 $ 998 $ 258 $ 218 $ 147 $ 197 $ 178 $ 87 $ 62 $ 29 December 31, 2019 1,535 807 218 146 170 194 100 61 33 _________ (a) Unbilled customer revenues are classified in Customer accounts receivables, net in the Registrants' Consolidated Balance Sheets.
Purchases and Sales of Accounts Receivable	The following table summarizes the impact of the sale of certain receivables: As of December 31, 2020 Derecognized receivables transferred at fair value (a) $ 1,139 Cash proceeds received 500 DPP 639 _________ (a) Includes additional customer accounts receivable sold into the Facility of $6,608 million since the start of the financing agreement. For the year ended December 31, 2020 Loss on sale of receivables (a) $ 30 _________ (a) Reflected in Operating and maintenance expense on Exelon and Generation's Consolidated Statement of Operations and Comprehensive Income. For the year ended December 31, 2020 Proceeds from new transfers $ 2,816 Cash collections received on DPP 3,771 Cash collections reinvested in the Facility 6,587 Generation is required, under supplier tariffs in ISO-NE, MISO, NYISO, and PJM, to sell customer and other receivables to utility companies, which include the Utility Registrants. The Utility Registrants are required, under separate legislation and regulations in Illinois, Pennsylvania, Maryland, District of Columbia, and New Jersey, to purchase certain receivables from alternative retail electric and, as applicable, natural gas suppliers that participate in the utilities' consolidated billing. The following tables present the total receivables purchased and sold for the year ended December 31, 2020. Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE Total Receivables Purchased $ 3,529 $ — $ 1,094 $ 1,020 $ 652 $ 1,015 $ 622 $ 207 $ 186 Total Receivables Sold 572 824 — — — — — — — Related Party Transactions: Receivables purchased from Generation — — 34 67 79 72 51 13 8 Receivables sold to the Utility Registrants — 252 — — — — — — —

Early Plant Retirements (Tables

Early Plant Retirements (Tables)	12 Months Ended
Early Plant Retirements (Tables)	Dec. 31, 2020
Implications of Potential Early Plant Retirements [Abstract]
Restructuring and Related Costs [Table Text Block]	As a result of the decision to early retire Byron and Dresden, Exelon and Generation recognized certain one-time charges for the year ended December 31, 2020 related to materials and supplies inventory reserve adjustments, employee-related costs, including severance benefit costs further discussed below, and construction work-in-progress impairments, among other items. In addition, as a result of the decisions to early retire Byron and Dresden, there are ongoing annual financial impacts stemming from shortening the expected economic useful lives of these nuclear plants primarily related to accelerated depreciation of plant assets (including any ARC), accelerated amortization of nuclear fuel, and changes in ARO accretion expense associated with the changes in decommissioning timing and cost assumptions to reflect an earlier retirement date. See Note 10 — Asset Retirement Obligations for additional information on changes to the nuclear decommissioning ARO balance and Note 12 — Asset Impairments for impairment assessment considerations given to the Midwest asset group as a result of the early retirement decision. The total impact on Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income is summarized in the table below. Income statement expense (pre-tax) 2020 (a) 2019 (b) 2018 (c) Depreciation and amortization Accelerated depreciation (d) $ 895 $ 216 $ 539 Accelerated nuclear fuel amortization 60 13 57 Operating and maintenance One-time charges 255 — 32 Other charges (e) 34 (53) — Contractual offset (f) (364) — — Total $ 880 $ 176 $ 628 _________ (a) Reflects expense for Byron and Dresden. (b) Reflects expense for TMI. (c) Reflects expense for TMI and Oyster Creek. (d) Includes the accelerated depreciation of plant assets including any ARC. (e) For Dresden, reflects the net impacts associated with the remeasurement of the ARO. For TMI, primarily reflects the net impacts associated with the remeasurement of the ARO. See Note 10 - Asset Retirement Obligations for additional information. (f) Reflects contractual offset for ARO accretion, ARC depreciation, and net impacts associated with the remeasurement of the ARO. For Byron and Dresden, based on the regulatory agreement with the ICC, decommissioning-related activities in 2020 have been offset within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. The offset in 2020 resulted in an equal adjustment to the noncurrent payables to ComEd at Generation and an adjustment to the regulatory liabilities at ComEd. See Note 10 - Asset Retirement Obligations for additional information.
Implications of Potential Early Plant Retirement on Balance Sheet [Table Text Block]	The following table provides the balance sheet amounts as of December 31, 2020 for Exelon's and Generation's significant assets and liabilities associated with the Braidwood and LaSalle nuclear plants. Current depreciation provisions are based on the estimated useful lives of these nuclear generating stations, which reflect the first renewal of the operating licenses. Braidwood LaSalle Total Asset Balances Materials and supplies inventory, net $ 84 $ 106 $ 190 Nuclear fuel inventory, net 120 285 405 Completed plant, net 1,397 1,590 2,987 Construction work in progress 31 30 61 Liability Balances Asset retirement obligation (570) (954) (1,524) NRC License First Renewal Term 2046 (Unit 1) 2042 (Unit 1) 2047 (Unit 2) 2043 (Unit 2)

Property, Plant and Equipment_2

Property, Plant and Equipment (Tables)	12 Months Ended
Property, Plant and Equipment (Tables)	Dec. 31, 2020
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	The following tables present a summary of property, plant, and equipment by asset category as of December 31, 2020 and 2019: Asset Category Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE December 31, 2020 Electric—transmission and distribution $ 60,946 $ — $ 29,371 $ 9,462 $ 8,797 $ 15,137 $ 10,264 $ 4,730 $ 4,568 Electric—generation 29,725 29,724 — — — — — — — Gas—transportation and distribution 6,733 — — 3,098 3,315 591 — 751 — Common—electric and gas 2,170 — — 956 1,138 178 — 180 — Nuclear fuel (a) 5,399 5,399 — — — — — — — Construction work in progress 3,576 450 799 474 627 1,174 824 163 182 Other property, plant, and equipment (b) 762 11 59 34 29 108 65 23 28 Total property, plant, and equipment 109,311 35,584 30,229 14,024 13,906 17,188 11,153 5,847 4,778 Less: accumulated depreciation (c) 26,727 13,370 5,672 3,843 4,034 1,811 3,697 1,533 1,303 Property, plant, and equipment, net $ 82,584 $ 22,214 $ 24,557 $ 10,181 $ 9,872 $ 15,377 $ 7,456 $ 4,314 $ 3,475 December 31, 2019 Electric—transmission and distribution $ 56,809 $ — $ 27,566 $ 8,957 $ 8,326 $ 13,809 $ 9,734 $ 4,464 $ 4,207 Electric—generation 29,839 29,839 — — — — — — — Gas—transportation and distribution 6,147 — — 2,899 2,999 525 — 690 — Common—electric and gas 1,907 — — 877 991 146 — 160 — Nuclear fuel (a) 5,656 5,656 — — — — — — — Construction work in progress 3,055 702 662 250 483 921 628 125 166 Other property, plant and equipment (b) 799 13 47 27 25 108 64 21 27 Total property, plant and equipment 104,212 36,210 28,275 13,010 12,824 15,509 10,426 5,460 4,400 Less: accumulated depreciation (c) 23,979 12,017 5,168 3,718 3,834 1,213 3,517 1,425 1,210 Property, plant, and equipment, net $ 80,233 $ 24,193 $ 23,107 $ 9,292 $ 8,990 $ 14,296 $ 6,909 $ 4,035 $ 3,190 __________ (a) Includes nuclear fuel that is in the fabrication and installation phase of $939 million and $1,025 million at December 31, 2020 and 2019, respectively. (b) Primarily composed of land and non-utility property. (c) Includes accumulated amortization of nuclear fuel in the reactor core at Generation of $2,774 million and $2,867 million as of December 31, 2020 and 2019, respectively. The following table presents the average service life for each asset category in number of years: Average Service Life (years) Asset Category Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE Electric - transmission and distribution 5-80 N/A 5-80 5-70 5-80 5-75 5-75 5-70 5-65 Electric - generation 1-58 1-58 N/A N/A N/A N/A N/A N/A N/A Gas - transportation and distribution 5-80 N/A N/A 5-70 5-80 5-75 N/A 5-75 N/A Common - electric and gas 4-75 N/A N/A 5-55 4-50 5-75 N/A 5-75 N/A Nuclear fuel 1-8 1-8 N/A N/A N/A N/A N/A N/A N/A Other property, plant, and equipment 1-50 1-10 33-50 50 20-50 3-50 25-50 8-50 13-15
Property Plant And Equipment Average Service Life Percentage By Asset Category Table	The following table presents the annual depreciation rates for each asset category. Nuclear fuel amortization is charged to fuel expense using the unit-of-production method and not included in the below table. Annual Depreciation Rates Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE December 31, 2020 Electric—transmission and distribution 2.79 % N/A 2.95 % 2.31 % 2.69 % 2.81 % 2.53 % 2.85 % 3.08 % Electric—generation 6.11 % 6.11 % N/A N/A N/A N/A N/A N/A N/A Gas—transportation and distribution 2.14 % N/A N/A 1.85 % 2.56 % 1.50 % N/A 1.50 % N/A Common—electric and gas 7.01 % N/A N/A 6.39 % 7.45 % 7.36 % N/A 6.72 % N/A December 31, 2019 Electric—transmission and distribution 2.80 % N/A 2.99 % 2.36 % 2.60 % 2.77 % 2.47 % 2.86 % 2.94 % Electric—generation 4.35 % 4.35 % N/A N/A N/A N/A N/A N/A N/A Gas—transportation and distribution 2.04 % N/A N/A 1.89 % 2.30 % 1.55 % N/A 1.55 % N/A Common—electric and gas 7.37 % N/A N/A 6.06 % 8.30 % 8.25 % N/A 6.24 % N/A December 31, 2018 Electric—transmission and distribution 2.73 % N/A 2.95 % 2.35 % 2.61 % 2.61 % 2.40 % 2.77 % 2.45 % Electric—generation 5.37 % 5.37 % N/A N/A N/A N/A N/A N/A N/A Gas—transportation and distribution 2.07 % N/A N/A 1.90 % 2.36 % 1.59 % N/A 1.59 % N/A Common—electric and gas 6.98 % N/A N/A 5.44 % 8.50 % 6.30 % N/A 3.70 % N/A
Schedule Of Capitalized Interest And AFUDC	The following table summarizes capitalized interest and credits to AFUDC by year: Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE December 31, 2020 Capitalized interest $ 22 $ 22 $ — $ — $ — $ — $ — $ — $ — AFUDC debt and equity 150 — 42 23 30 55 42 6 7 December 31, 2019 Capitalized interest $ 24 $ 24 $ — $ — $ — $ — $ — $ — $ — AFUDC debt and equity 132 — 32 17 29 54 39 6 9 December 31, 2018 Capitalized interest $ 31 $ 31 $ — $ — $ — $ — $ — $ — $ — AFUDC debt and equity 109 — 30 12 24 44 34 4 4

Jointly Owned Electric Utilit_2

Jointly Owned Electric Utility Plant (Tables)	12 Months Ended
Jointly Owned Electric Utility Plant (Tables)	Dec. 31, 2020
Public Utilities, Property, Plant and Equipment [Abstract]
Schedule of Jointly Owned Utility Plants	Exelon's, Generation's, PECO's, DPL's, and ACE's material undivided ownership interests in jointly owned electric plants and transmission facilities at December 31, 2020 and 2019 were as follows: Nuclear Generation Transmission Quad Cities Peach Salem Nine Mile Point Unit 2 NJ/DE (a) Operator Generation Generation PSEG Generation PSEG/DPL Ownership interest 75.00 % 50.00 % 42.59 % 82.00 % various Exelon’s share at December 31, 2020: Plant in service $ 1,188 $ 1,506 $ 717 $ 990 $ 103 Accumulated depreciation 670 601 265 187 54 Construction work in progress 13 13 39 25 — Exelon’s share at December 31, 2019: Plant in service $ 1,161 $ 1,466 $ 663 $ 951 $ 102 Accumulated depreciation 627 571 249 156 53 Construction work in progress 13 21 53 27 — __________ (a) PECO, DPL, and ACE own a 42.55%, 1%, and 13.9% share, respectively in 151.3 miles of 500kV lines located in New Jersey and of the Salem generating plant substation. PECO, DPL, and ACE also own a 42.55%, 7.45%, and 7.45% share, respectively, in 2.5 miles of 500kV line located over the Delaware River. ACE also has a 21.78% share in a 500kV New Freedom Switching substation.

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
Asset Retirement Obligations (Tables)	Dec. 31, 2020
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation Rollforward	The following table provides a rollforward of the nuclear decommissioning ARO reflected in Exelon’s and Generation’s Consolidated Balance Sheets, from January 1, 2019 to December 31, 2020: Nuclear decommissioning ARO at January 1, 2019 $ 10,005 Net increase due to changes in, and timing of, estimated future cash flows 864 Sale of Oyster Creek (755) Accretion expense 479 Costs incurred related to decommissioning plants (89) Nuclear decommissioning ARO at December 31, 2019 (a) 10,504 Net increase due to changes in, and timing of, estimated future cash flows 1,022 Accretion Expense 489 Costs incurred related to decommissioning plants (93) Nuclear decommissioning ARO at December 31, 2020 (a) $ 11,922 __________ (a) Includes $80 million and $112 million as the current portion of the ARO at December 31, 2020 and 2019, respectively, which is included in Other current liabilities in Exelon’s and Generation’s Consolidated Balance Sheets. The following table provides a rollforward of the non-nuclear AROs reflected in the Registrants’ Consolidated Balance Sheets from January 1, 2019 to December 31, 2020: Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE Non-nuclear AROs at January 1, 2019 $ 471 $ 238 $ 121 $ 28 $ 25 $ 52 $ 37 $ 11 $ 4 Net increase (decrease) due to changes in, and timing of, estimated future cash flows 17 7 8 — (2) 4 3 1 — Development projects 2 2 — — — — — — — Accretion expense (a) 16 12 1 1 1 1 1 — — Asset divestitures (42) (42) — — — — — — — Payments (4) (1) (1) (1) (1) — — — — Non-nuclear AROs at December 31, 2019 460 216 129 28 23 57 41 12 4 Net increase (decrease) due to changes in, and timing of, estimated future cash flows 7 2 — 2 1 1 (3) 2 2 Development projects 1 1 — — — — — — — Accretion expense (a) 16 11 1 1 1 1 1 — — Asset divestitures (4) (4) — — — — — — — Payments (9) (4) (1) (2) (2) — — — — AROs reclassified to liabilities held for sale (b) (10) (10) — — — — — — — Non-nuclear AROs at December 31, 2020 $ 461 $ 212 $ 129 $ 29 $ 23 $ 59 $ 39 $ 14 $ 6 __________ (a) For ComEd, PECO, BGE, PHI, Pepco, and DPL, the majority of the accretion is recorded as an increase to a regulatory asset due to the associated regulatory treatment. (b) Represents AROs related to Generation's solar business, which were classified as held for sale as a result of the sale agreement. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information.

Leases (Tables)

Leases (Tables)	12 Months Ended
Leases (Tables)	Dec. 31, 2020
Leases [Abstract]
Components of Lease Cost [Table Text Block]	The components of operating lease costs were as follows: Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE For the year ended December 31, 2020 Operating lease costs $ 292 $ 194 $ 3 $ 1 $ 33 $ 46 $ 11 $ 13 $ 6 Variable lease costs 241 234 1 — 1 2 1 1 — Short-term lease costs 2 2 — — — — — — — Total lease costs (a) $ 535 $ 430 $ 4 $ 1 $ 34 $ 48 $ 12 $ 14 $ 6 For the year ended December 31, 2019 Operating lease costs $ 320 $ 222 $ 3 $ 1 $ 33 $ 48 $ 12 $ 14 $ 7 Variable lease costs 300 282 2 — 2 6 2 2 1 Short-term lease costs 19 19 — — — — — — — Total lease costs (a) $ 639 $ 523 $ 5 $ 1 $ 35 $ 54 $ 14 $ 16 $ 8 __________ (a) Excludes $48 million, $44 million, $4 million, and $4 million of sublease income recorded at Exelon, Generation, PHI, and DPL, respectively, for the year ended December 31, 2020 and $51 million, $44 million, $7 million, and $7 million of sublease income recorded at Exelon, Generation, PHI, and DPL, respectively, for the year ended December 31, 2019. PHI, Pepco, DPL, and ACE recorded finance lease costs of $9 million, $3 million, $4 million, and $2 million, respectively, for the year ended December 31, 2020. The weighted average remaining lease terms, in years, for operating and finance leases were as follows: Operating Leases Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE As of December 31, 2020 10.1 10.5 3.8 4.2 8.3 8.2 9.1 9.1 4.0 As of December 31, 2019 10.1 10.6 4.6 4.4 5.4 9.0 9.8 9.7 4.7 Finance Leases PHI Pepco DPL ACE As of December 31, 2020 6.5 6.3 6.5 6.5 The weighted average discount rates for operating and finance leases were as follows: Operating Leases Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE As of December 31, 2020 4.7 % 4.9 % 3.0 % 2.9 % 3.8 % 4.2 % 4.0 % 4.0 % 3.5 % As of December 31, 2019 4.6 % 4.8 % 3.0 % 3.2 % 3.6 % 4.2 % 4.0 % 4.0 % 3.6 % Finance Leases PHI Pepco DPL ACE As of December 31, 2020 2.5 % 2.6 % 2.4 % 2.4 % ROU assets obtained in exchange for operating and finance lease obligations were as follows: Operating Leases Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE For the year ended December 31, 2020 $ 1 $ 3 $ — $ 1 $ — $ (1) $ — $ (1) $ — For the year ended December 31, 2019 52 14 6 — 2 (3) (1) (2) (1) Finance Leases PHI Pepco DPL ACE For the year ended December 31, 2020 $ 29 $ 8 $ 14 $ 7
Schedule of Rent Expense [Table Text Block]	The following table presents the Registrants' rental expense under the prior lease accounting guidance for the year ended December 31, 2018: Exelon Generation (a) ComEd PECO BGE PHI Pepco DPL ACE Rent expense $ 670 $ 558 $ 7 $ 10 $ 35 $ 48 $ 10 $ 13 $ 8 __________
Supplemental Balance Sheet Information Related to Lessee Right-of-Use Assets and Lease Liabilities [Table Text Block]	The following tables provide additional information regarding the presentation of operating and finance lease ROU assets and lease liabilities within the Registrants’ Consolidated Balance Sheets: Operating Leases Exelon (a) Generation (a) ComEd PECO BGE PHI Pepco DPL ACE As of December 31, 2020 Operating lease ROU assets Other deferred debits and other assets $ 1,064 $ 726 $ 7 $ 1 $ 46 $ 241 $ 49 $ 54 $ 15 Operating lease liabilities Other current liabilities 213 132 3 — 45 31 6 9 4 Other deferred credits and other liabilities 1,089 775 5 1 19 224 46 56 11 Total operating lease liabilities $ 1,302 $ 907 $ 8 $ 1 $ 64 $ 255 $ 52 $ 65 $ 15 As of December 31, 2019 Operating lease ROU assets Other deferred debits and other assets $ 1,305 $ 895 $ 9 $ 2 $ 77 $ 273 $ 56 $ 63 $ 18 Operating lease liabilities Other current liabilities 225 157 3 — 32 31 6 9 4 Other deferred credits and other liabilities 1,307 925 8 1 50 254 51 65 14 Total operating lease liabilities $ 1,532 $ 1,082 $ 11 $ 1 $ 82 $ 285 $ 57 $ 74 $ 18 __________ (a) Exelon's and Generation's operating ROU assets and lease liabilities include $387 million and $528 million, respectively, related to contracted generation as of December 31, 2020, and $515 million and $664 million, respectively, as of December 31, 2019. Finance Leases PHI Pepco DPL ACE As of December 31, 2020 Finance lease ROU assets Plant, property and equipment, net $ 50 $ 17 $ 20 $ 13 Finance lease liabilities Long-term debt due within one year 7 2 3 2 Long-term debt 43 15 17 11 Total finance lease liabilities $ 50 $ 17 $ 20 $ 13
Lessee, Operating Lease, Liability, Maturity [Table Text Block]	Future minimum lease payments for operating and finance leases as of December 31, 2020 were as follows: Operating Leases Year Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE 2021 $ 239 $ 145 $ 3 $ 1 $ 46 $ 40 $ 8 $ 11 $ 5 2022 177 113 2 — 16 39 8 10 4 2023 146 100 1 — 1 38 7 9 3 2024 141 98 1 — — 36 6 8 2 2025 140 99 1 — — 33 6 7 2 Remaining years 834 640 — — 18 120 28 35 — Total 1,677 1,195 8 1 81 306 63 80 16 Interest 375 288 — — 17 51 11 15 1 Total operating lease liabilities $ 1,302 $ 907 $ 8 $ 1 $ 64 $ 255 $ 52 $ 65 $ 15
Finance Lease, Liability, Fiscal Year Maturity	Finance Leases Year PHI Pepco DPL ACE 2021 $ 8 $ 3 $ 3 $ 2 2022 8 3 3 2 2023 8 3 3 2 2024 8 3 3 2 2025 8 3 3 2 Remaining years 13 3 6 4 Total 53 18 21 14 Interest 3 1 1 1 Total finance lease liabilities $ 50 $ 17 $ 20 $ 13
Schedule of Supplemental Cash Flow Information Related to Leases [Table Text Block]	Cash paid for amounts included in the measurement of operating and finance lease liabilities were as follows: Operating cash flows from operating leases Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE For the year ended December 31, 2020 $ 271 $ 204 $ 3 $ 1 $ 20 $ 39 $ 8 $ 9 $ 4 For the year ended December 31, 2019 287 206 3 — 33 37 9 6 5 Financing cash flows from finance leases PHI Pepco DPL ACE For the year ended December 31, 2020 $ 6 $ 2 $ 3 $ 1
Components of Operating Lease Income [Table Text Block]	The components of lease income were as follows: Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE For the year ended December 31, 2020 Operating lease income $ 52 $ 47 $ — $ — $ — $ 3 $ — $ 3 $ — Variable lease income 283 282 — — — 1 — 1 — For the year ended December 31, 2019 Operating lease income $ 54 $ 47 $ — $ — $ — $ 5 $ — $ 4 $ — Variable lease income 261 258 — — — 3 — 3 —
Lessor, Operating Lease, Payment to be Received, Fiscal Year Maturity [Table Text Block]	Future minimum lease payments to be recovered under operating leases as of December 31, 2020 were as follows: Year Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE 2021 $ 51 $ 45 $ — $ — $ — $ 4 $ 1 $ 3 $ — 2022 50 45 — — — 4 — 3 — 2023 49 45 — — — 4 — 4 — 2024 49 45 — — — 3 — 3 — 2025 48 45 — — — 4 — 4 — Remaining years 217 182 1 4 1 31 — 31 — Total $ 464 $ 407 $ 1 $ 4 $ 1 $ 50 $ 1 $ 48 $ —

Intangible Assets (Tables)

Intangible Assets (Tables)	12 Months Ended
Intangible Assets (Tables)	Dec. 31, 2020
Finite-Lived Intangible Assets [Line Items]
Schedule Of Goodwill	The following table presents the gross amount, accumulated impairment loss, and carrying amount of goodwill at Exelon, ComEd, and PHI as of December 31, 2020 and 2019. There were no additions or impairments during the years ended December 31, 2020 and 2019. Gross Amount Accumulated Impairment Loss Carrying Amount Exelon $ 8,660 $ 1,983 $ 6,677 ComEd (a) 4,608 1,983 2,625 PHI (b) 4,005 — 4,005 __________ (a) Reflects goodwill recorded in 2000 from the PECO/Unicom merger (predecessor parent company of ComEd). (b) Reflects goodwill recorded in 2016 from the PHI merger.
Schedule of Finite-Lived Intangible Assets	Exelon’s, Generation’s, ComEd’s, and PHI's other intangible assets and liabilities, included in Unamortized energy contract assets and liabilities and Other deferred debits and other assets in their Consolidated Balance Sheets, consisted of the following as of December 31, 2020 and 2019. The intangible assets and liabilities shown below are 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, 2020 December 31, 2019 Gross Accumulated Amortization Net Gross Accumulated Amortization Net Generation Unamortized Energy Contracts $ 1,963 $ (1,642) $ 321 $ 1,967 $ (1,612) $ 355 Customer Relationships 326 (215) 111 343 (190) 153 Trade Name 222 (197) 25 243 (193) 50 ComEd Chicago Settlement Agreements 162 (162) — 162 (155) 7 PHI Unamortized Energy Contracts (1,515) 1,188 (327) (1,515) 1,073 (442) Exelon Corporate Software License 95 (53) 42 95 (44) 51 Exelon $ 1,253 $ (1,081) $ 172 $ 1,295 $ (1,121) $ 174
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, 2020, 2019, and 2018: For the Years Ended December 31, Exelon (a)(b) Generation (a) ComEd PHI (b) 2020 $ (17) $ 81 $ 7 $ (115) 2019 (28) 74 7 (119) 2018 (109) 63 7 (188) __________ (a) At Exelon and Generation, amortization of unamortized energy contracts totaling $30 million, $21 million, and $14 million for the years ended December 31, 2020, 2019, and 2018, respectively, was recorded in Operating revenues or Purchased power and fuel expense in their Consolidated Statements of Operations and Comprehensive Income. (b) At Exelon and PHI, amortization of the unamortized energy contract fair value adjustment amounts and the corresponding offsetting regulatory asset and liability amounts are amortized through Purchased power and fuel expense in their Consolidated Statements of Operations and Comprehensive Income.
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, 2020: For the Years Ending December 31, Exelon Generation PHI 2021 $ (1) $ 81 $ (92) 2022 (22) 57 (89) 2023 (20) 51 (81) 2024 20 48 (38) 2025 40 41 (5)
Schedule of Alternative or Renewable Energy Credits [Table Text Block]	The following table presents the current and noncurrent RECs as of December 31, 2020 and 2019: As of December 31, 2020 As of December 31, 2019 Exelon Generation Exelon Generation Current REC's $ 632 $ 621 $ 345 $ 336 Noncurrent REC's — — 86 86

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
Income Taxes (Tables)	Dec. 31, 2020
Schedule of Components of Income Tax Expense (Benefit)	Income tax expense (benefit) from continuing operations is comprised of the following components: For the Year Ended December 31, 2020 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE Included in operations: Federal Current $ 26 $ 130 $ (24) $ (7) $ 4 $ 25 $ 40 $ (13) $ (4) Deferred 156 150 112 1 10 (129) (62) (20) (43) Investment tax credit amortization (28) (25) (2) — — (1) — — — State Current 42 40 (27) — — (5) — — — Deferred 177 (46) 118 (24) 27 33 15 8 6 Total $ 373 $ 249 $ 177 $ (30) $ 41 $ (77) $ (7) $ (25) $ (41) For the Year Ended December 31, 2019 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE Included in operations: Federal Current $ 85 $ 147 $ 59 $ 45 $ (51) $ 43 $ 16 $ 29 $ (3) Deferred 489 346 15 20 95 (34) (6) (21) (6) Investment tax credit amortization (72) (69) (2) — — (1) — — — State Current 5 10 (5) — — 3 — — — Deferred 267 82 96 — 35 27 6 14 9 Total $ 774 $ 516 $ 163 $ 65 $ 79 $ 38 $ 16 $ 22 $ — For the Year Ended December 31, 2018 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE Included in operations: Federal Current $ 226 $ 337 $ (63) $ 11 $ (5) $ (4) $ 28 $ (3) $ (14) Deferred (99) (347) 145 10 47 23 (22) 13 18 Investment tax credit amortization (24) (21) (2) — — (1) — — — State Current (1) 6 (29) 1 — 7 — — — Deferred 16 (83) 117 (16) 32 8 5 12 8 Total $ 118 $ (108) $ 168 $ 6 $ 74 $ 33 $ 11 $ 22 $ 12
Effective Income Tax Rate Reconciliation	The effective income tax rate from continuing operations varies from the U.S. federal statutory rate principally due to the following: For the Year Ended December 31, 2020 (a) Exelon Generation ComEd (b) PECO (c) BGE (d) PHI (d) Pepco (d) DPL (d) ACE (d) U.S. federal statutory rate 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % Increase (decrease) due to: State income taxes, net of Federal income tax benefit 7.8 0.5 11.6 (4.5) 5.5 5.1 4.5 6.6 7.0 Qualified NDT fund income 8.4 23.5 — — — — — — — Deferred Prosecution Agreement payments 1.8 — 6.8 — — — — — — Amortization of investment tax credit, including deferred taxes on basis difference (1.1) (2.6) (0.3) — (0.1) (0.2) (0.1) (0.3) (0.5) Plant basis differences (4.0) — (0.6) (18.7) (1.5) (1.6) (1.7) (0.4) (3.0) Production tax credits and other credits (2.2) (5.4) (0.3) — (0.4) (0.3) (0.3) (0.3) (0.5) Noncontrolling interests 1.1 3.2 — — — — — — — Excess deferred tax amortization (13.6) — (11.2) (4.6) (13.9) (42.0) (25.4) (51.7) (82.1) Tax settlements (3.7) (10.3) — — — — — — — Other 0.5 (0.1) 1.8 (0.4) (0.1) (0.4) (0.7) 0.1 0.4 Effective income tax rate 16.0 % 29.8 % 28.8 % (7.2) % 10.5 % (18.4) % (2.7) % (25.0) % (57.7) % For the Year Ended December 31, 2019 (a) Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE U.S. federal statutory rate 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % Increase (decrease) due to: State income taxes, net of Federal income tax benefit 5.4 3.8 8.5 — 6.4 4.7 2.0 6.8 7.0 Qualified NDT fund income 5.9 12.3 — — — — — — — Amortization of investment tax credit, including deferred taxes on basis difference (1.5) (3.0) (0.2) — (0.1) (0.2) (0.1) (0.2) (0.3) Plant basis differences (1.4) — — (7.2) (1.2) (1.2) (1.8) (0.4) (0.7) Production tax credits and other credits (3.1) (4.8) (1.2) — (1.3) (0.2) (0.1) — (0.1) Noncontrolling interests (0.6) (1.2) — — — — — — — Excess deferred tax amortization (5.5) — (9.7) (2.8) (6.8) (17.5) (15.1) (14.2) (27.0) Other (0.8) (1.2) 0.8 — — 0.8 0.3 — 0.1 Effective income tax rate 19.4 % 26.9 % 19.2 % 11.0 % 18.0 % 7.4 % 6.2 % 13.0 % — % For the Year Ended December 31, 2018 (a) Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE U.S. federal statutory rate 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % Increase (decrease) due to: State income taxes, net of Federal income tax benefit 0.5 (16.6) 8.3 (2.6) 6.6 2.9 2.0 6.7 7.4 Qualified NDT fund income (1.9) (11.8) — — — — — — — Amortization of investment tax credit, including deferred taxes on basis difference (1.2) (6.5) (0.2) (0.1) (0.1) (0.2) (0.1) (0.3) (0.4) Plant basis differences (3.5) — (0.2) (14.1) (1.3) (1.6) (2.8) (0.3) (0.5) Production tax credits and other credits (2.2) (13.5) — — — — — — — Noncontrolling interests (1.0) (6.1) — — — — — — — Excess deferred tax amortization (8.3) — (9.1) (3.2) (8.0) (14.8) (15.3) (12.0) (14.9) Tax Cuts and Jobs Act of 2017 0.9 2.7 (0.1) — — 0.1 — — — Other 1.0 1.3 0.5 0.3 0.9 0.4 0.3 0.4 1.2 Effective income tax rate 5.3 % (29.5) % 20.2 % 1.3 % 19.1 % 7.8 % 5.1 % 15.5 % 13.8 % __________ (a) Positive percentages represent income tax expense. Negative percentages represent income tax benefit. (b) At ComEd, the higher effective tax rate is primarily related to the nondeductible Deferred Prosecution Agreement payments. See Note 19 — Commitments and Contingencies for additional information. (c) At PECO, the negative effective tax rate is primarily related to an increase in plant basis differences attributable to tax repair deductions related to an increase in storms and qualifying projects. (d) At BGE, the lower effective tax rate, and at PHI, Pepco, DPL, and ACE, the negative effective tax rate is primarily attributable to accelerated amortization of transmission related income tax regulatory liabilities as a result of regulatory settlements. See Note 3 — Regulatory Matters for additional information.
Tax Effects of Temporary Differences	The tax effects of temporary differences and carryforwards, which give rise to significant portions of the deferred tax assets (liabilities), as of December 31, 2020 and 2019 are presented below: As of December 31, 2020 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE Plant basis differences $ (13,868) $ (2,592) $ (4,432) $ (2,131) $ (1,711) $ (2,822) $ (1,259) $ (806) $ (725) Accrual based contracts 40 (37) — — — 77 — — — Derivatives and other financial instruments 41 (41) 84 — — 2 — — — Deferred pension and postretirement obligation 1,559 (236) (288) (30) (33) (80) (74) (40) (7) Nuclear decommissioning activities (742) (742) — — — — — — — Deferred debt refinancing costs 169 16 (6) — (2) 131 (3) (1) (1) Regulatory assets and liabilities (1,107) — 87 (231) 142 (41) 38 67 46 Tax loss carryforward 286 55 — 47 57 90 4 49 38 Tax credit carryforward 841 838 — — — — — — — Investment in partnerships (835) (813) — — — — — — — Other, net 1,070 347 223 104 29 220 107 18 27 Deferred income tax liabilities (net) $ (12,546) $ (3,205) $ (4,332) $ (2,241) $ (1,518) $ (2,423) $ (1,187) $ (713) $ (622) Unamortized investment tax credits (a) (464) (445) (9) (1) (3) (6) (2) (2) (3) Total deferred income tax liabilities (net) and unamortized investment tax credits $ (13,010) $ (3,650) $ (4,341) $ (2,242) $ (1,521) $ (2,429) $ (1,189) $ (715) $ (625) __________ (a) Does not include unamortized investment tax credits reclassified to liabilities held for sale. As of December 31, 2019 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE Plant basis differences $ (13,413) $ (2,814) $ (4,197) $ (1,978) $ (1,578) $ (2,681) $ (1,204) $ (753) $ (687) Accrual based contracts 61 (43) — — — 104 — — — Derivatives and other financial instruments 165 88 84 — — 2 — — — Deferred pension and postretirement obligation 1,504 (220) (270) (28) (28) (89) (75) (42) (10) Nuclear decommissioning activities (503) (503) — — — — — — — Deferred debt refinancing costs 183 20 (7) — (3) 142 (3) (2) (1) Regulatory assets and liabilities (884) — 183 (169) 157 (10) 55 88 77 Tax loss carryforward 240 55 — 25 49 93 13 44 31 Tax credit carryforward 892 897 — — — — — — — Investment in partnerships (830) (808) — — — — — — — Other, net 926 236 196 70 10 181 85 12 16 Deferred income tax liabilities (net) $ (11,659) $ (3,092) $ (4,011) $ (2,080) $ (1,393) $ (2,258) $ (1,129) $ (653) $ (574) Unamortized investment tax credits (668) (648) (10) (1) (3) (7) (2) (2) (3) Total deferred income tax liabilities (net) and $ (12,327) $ (3,740) $ (4,021) $ (2,081) $ (1,396) $ (2,265) $ (1,131) $ (655) $ (577)
Summary of Loss Carryforwards	The following table provides Exelon’s, Generation’s, PECO’s, BGE’s, PHI’s, Pepco’s, DPL’s, and ACE’s carryforwards, which are presented on a post-apportioned basis, and any corresponding valuation allowances as of December 31, 2020. ComEd does not have net operating losses or credit carryforwards for the year ended December 31, 2020. Exelon Generation PECO BGE PHI Pepco DPL ACE Federal Federal general business credits carryforwards and other carryforwards $ 858 $ 852 $ — $ — $ — $ — $ — $ — State State net operating losses and other carryforwards 5,202 1,118 616 902 1,436 63 728 531 Deferred taxes on state tax attributes (net) 324 76 49 59 98 4 49 38 Valuation allowance on state tax attributes 27 23 1 — — — — — Year in which net operating loss or credit carryforwards will begin to expire (a) 2034 2034 2032 2033 2029 2029 2032 2031 __________ (a) Generation's state net operating loss carryforwards will begin expiring in 2029. PECO's Pennsylvania charitable contribution carryforwards and BGE's Maryland charitable deduction and capital loss carryforwards will begin expiring in 2021. ACE's New Jersey tax credit carryforward has an indefinite carryforward period. These amounts are not material.
Reconciliation of Unrecognized Tax Benefits Excluding Amounts Pertaining to Examined Tax Returns Roll Forward	The following table presents changes in unrecognized tax benefits, by Registrant. Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE Balance at January 1, 2018 $ 743 $ 468 $ 2 $ — $ 120 $ 125 $ 59 $ 21 $ 14 Change to positions that only affect timing 15 15 — — — — — — — Increases based on tax positions prior to 2018 30 21 — — — 8 7 1 — Decreases based on tax positions prior to 2018 (a) (251) (36) — — (120) (88) (66) (22) — Decrease from settlements with taxing authorities (53) (53) — — — — — — — Decreases from expiration of statute of limitations (7) (7) — — — — — — — Balance at December 31, 2018 477 408 2 — — 45 — — 14 Change to positions that only affect timing 26 12 3 1 4 3 2 1 — Increases based on tax positions related to 2019 2 1 — — — — — — — Increases based on tax positions prior to 2019 34 19 3 2 3 — — — — Decreases based on tax positions prior to 2019 (3) (3) — — — — — — — Decrease from settlements with taxing authorities (29) 4 (2) — — — — — — Balance at December 31, 2019 507 441 6 3 7 48 2 1 14 Change to positions that only affect timing 6 — 2 3 3 3 1 — 1 Increases based on tax positions related to 2020 3 1 — — — — — — — Increases based on tax positions prior to 2020 26 23 1 — — 1 — — — Decreases based on tax positions prior to 2020 (b) (348) (346) — — — — — — — Decrease from settlements with taxing authorities (b) (69) (69) — — — — — — — Balance at December 31, 2020 $ 125 $ 50 $ 9 $ 6 $ 10 $ 52 $ 3 $ 1 $ 15 __________ (a) Exelon, Generation, BGE, PHI, Pepco, and DPL decreased their unrecognized state tax benefits primarily due to the receipt of favorable guidance with respect to the deductibility of certain depreciable fixed assets. The recognition of the tax benefits related to BGE, PHI, Pepco, and DPL was offset by corresponding regulatory liabilities and that portion had no immediate impact to their effective tax rate. (b) Exelon's and Generation's 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 to Exelon's and Generation’s net income of $76 million and $73 million, respectively, in the first quarter of 2020, reflecting a decrease to Exelon's and Generation's income tax expense of $67 million.
Summary of Positions for which Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Table Text Block]	The following table presents Exelon's, Generation's, and PHI's unrecognized tax benefits that, if recognized, would decrease the effe ctive tax rate. ComEd's, PECO's, BGE's, Pepco's, DPL's, and ACE's amounts are not material. Exelon Generation PHI (a) December 31, 2020 $ 73 $ 39 $ 33 December 31, 2019 462 429 32 December 31, 2018 463 408 31 __________ (a) PHI has $ 21 million of unrecognized state tax benefits that, if recognized, $ 14 million would be in the form of a net operating loss carryforward, which is expected to require a full valuation allowance based on present circumstances.
Long-Term Marginal State Income Tax Rate [Table Text Block]	Quarterly, Exelon reviews and updates its marginal state income tax rates for changes in state apportionment. The Registrants remeasure their existing deferred income tax balances to reflect the changes in marginal rates, which results in either an increase or a decrease to their net deferred income tax liability balances. Utility Registrants record corresponding regulatory liabilities or assets to the extent such amounts are probable of settlement or recovery through customer rates and an adjustment to income tax expense for all other amounts. The impacts to the Utility Registrants for the years ended December 31, 2020, 2019, and 2018 were not material. December 31, 2020 Exelon Generation Increase (decrease) to Deferred Income Tax Liability and Income Tax Expense, Net of Federal Taxes $ 66 $ (26) December 31, 2019 Increase to Deferred Income Tax Liability and Income Tax Expense, Net of Federal Taxes $ 23 $ 9 December 31, 2018 Decrease to Deferred Income Tax Liability and Income Tax Expense, Net of Federal Taxes $ (50) $ (53)
Allocation of Federal Tax Benefit Under Tax Sharing Agreement [Table Text Block] [Table Text Block]	The following table presents the allocation of tax benefits from Exelon under the Tax Sharing Agreement. Generation ComEd PECO BGE PHI Pepco DPL ACE December 31, 2020 (a) $ 64 $ 14 $ 17 $ — $ 17 $ 8 $ 6 $ 1 December 31, 2019 (b) 41 — 14 3 7 6 1 — December 31, 2018 (c) 155 1 48 26 2 — — — __________ (a) BGE did not record an allocation of federal tax benefits from Exelon under the Tax Sharing Agreement as a result of a tax net operating loss. (b) ACE did not record an allocation of federal tax benefits from Exelon under the Tax Sharing Agreement as a result of a tax net operating loss. (c) Pepco, DPL, and ACE did not record an allocation of federal tax benefits from Exelon under the Tax Sharing Agreement as a result of a tax net operating loss.
Total amounts of interest and penalties recognized	The following table represents the net interest and penalties receivable (payable) related to tax positions reflected in Exelon's Consolidated Balance Sheets. Generation's and the Utility Registrants' amounts are not material. Net interest and penalties receivable as of Exelon December 31, 2020 $ 314 December 31, 2019 318

Retirement Benefits (Tables)

Retirement Benefits (Tables)	12 Months Ended
Retirement Benefits (Tables)	Dec. 31, 2020
Retirement Benefits [Abstract]
Defined Benefit Plan Change In Benefit Obligation RollForward	The following tables provide a rollforward of the changes in the benefit obligations and plan assets of Exelon for the most recent two years for all plans combined: Pension Benefits OPEB 2020 2019 2020 2019 Change in benefit obligation: Net benefit obligation at beginning of year $ 22,868 $ 20,692 $ 4,658 $ 4,369 Service cost 387 357 90 93 Interest cost 757 883 154 188 Plan participants’ contributions — — 49 44 Actuarial loss (a) 2,217 2,322 49 250 Plan amendments — 68 (111) — Curtailments — (3) — — Settlements (45) (35) (5) (4) Contractual termination benefits — 1 — — Gross benefits paid (1,290) (1,417) (280) (282) Net benefit obligation at end of year $ 24,894 $ 22,868 $ 4,604 $ 4,658 Pension Benefits OPEB 2020 2019 2020 2019 Change in plan assets: Fair value of net plan assets at beginning of year $ 18,590 $ 16,678 $ 2,541 $ 2,408 Actual return on plan assets 2,547 3,008 190 324 Employer contributions 542 356 59 51 Plan participants’ contributions — — 49 44 Gross benefits paid (1,290) (1,417) (280) (282) Settlements (45) (35) (5) (4) Fair value of net plan assets at end of year $ 20,344 $ 18,590 $ 2,554 $ 2,541 __________ (a) The pension and OPEB actuarial losses in 2020 and 2019 primarily reflect a decrease in the discount rate. OPEB losses in 2020 were offset by gains related to plan changes.
Schedule of Amounts Recognized in Balance Sheet	Exelon presents its benefit obligations and plan assets net on its balance sheet within the following line items: Pension Benefits OPEB 2020 2019 2020 2019 Other current liabilities $ 47 $ 31 $ 42 $ 41 Pension obligations 4,503 4,247 — — Non-pension postretirement benefit obligations — — 2,008 2,076 Unfunded status (net benefit obligation less plan assets) $ 4,550 $ 4,278 $ 2,050 $ 2,117
Defined Benefit Plan, Plan with Accumulated Benefit Obligation in Excess of Plan Assets	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 benefit obligations (PBO) and accumulated postretirement benefit obligation (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 Exelon 2020 2019 ABO $ 23,514 $ 21,727 Fair value of net plan assets 20,344 18,590
Calculation of Net Periodic Benefit Costs [Table Text Block]	The following table presents the components of Exelon’s net periodic benefit costs, prior to capitalization, for the years ended December 31, 2020, 2019, and 2018. Pension Benefits OPEB 2020 2019 2018 2020 2019 2018 Components of net periodic benefit cost: Service cost $ 387 $ 357 $ 405 $ 90 $ 93 $ 112 Interest cost 757 883 802 154 188 175 Expected return on assets (1,270) (1,225) (1,252) (163) (153) (173) Amortization of: Prior service cost (credit) 4 — 2 (124) (179) (186) Actuarial loss 512 414 629 49 45 66 Curtailment benefits — — — (1) — — Settlement and other charges 14 17 3 1 1 1 Contractual termination benefits — 1 — — — — Net periodic benefit cost $ 404 $ 447 $ 589 $ 6 $ (5) $ (5)
Schedule Of Pension And Other Postretirement Benefit Costs [Table Text Block]	The amounts below represent the Registrants' allocated pension and OPEB costs. For Exelon, the service cost component is included in Operating and maintenance expense and Property, plant, and equipment, net while the non-service cost components are included in Other, net and Regulatory assets. For Generation and the Utility Registrants, the service cost and non-service cost components are included in Operating and maintenance expense and Property, plant, and equipment, net in their consolidated financial statements. For the Years Ended December 31, Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE 2020 $ 411 $ 115 $ 114 $ 5 $ 64 $ 70 $ 15 $ 7 $ 14 2019 442 135 96 12 61 95 25 15 16 2018 583 204 177 18 60 67 15 6 12
Changes In Plan Assets And Benefit Obligations Recognized In OCI And Regulatory Assets	The following tables provide the components of AOCI and regulatory assets (liabilities) for Exelon for the years ended December 31, 2020, 2019, and 2018 for all plans combined. Pension Benefits OPEB 2020 2019 2018 2020 2019 2018 Changes in plan assets and benefit obligations recognized in AOCI and regulatory assets (liabilities): Current year actuarial loss (gain) $ 941 $ 538 $ 635 $ 22 $ 80 $ (232) Amortization of actuarial loss (512) (414) (629) (49) (45) (66) Current year prior service cost (credit) — 68 (4) (111) — — Amortization of prior service (cost) credit (4) — (2) 124 179 186 Curtailments — (3) — 1 — — Settlements (14) (17) (3) (1) (1) — Total recognized in AOCI and regulatory assets (liabilities) $ 411 $ 172 $ (3) $ (14) $ 213 $ (112) Total recognized in AOCI $ 271 $ 169 $ 3 $ 6 $ 107 $ (55) Total recognized in regulatory assets (liabilities) $ 140 $ 3 $ (6) $ (20) $ 106 $ (57)
Schedule of Amounts in Accumulated Other Comprehensive Income (Loss) to be Recognized over Next Fiscal Year [Table Text Block]	The following table provides the components of gross accumulated other comprehensive loss and regulatory assets (liabilities) for Exelon that have not been recognized as components of periodic benefit cost at December 31, 2020 and 2019, respectively, for all plans combined: Pension Benefits OPEB 2020 2019 2020 2019 Prior service cost (credit) $ 35 $ 39 $ (145) $ (158) Actuarial loss 8,077 7,662 538 565 Total $ 8,112 $ 7,701 $ 393 $ 407 Total included in AOCI $ 4,339 $ 4,068 $ 183 $ 177 Total included in regulatory assets (liabilities) $ 3,773 $ 3,633 $ 210 $ 230
Defined Benefit Plan Weighted Average Assumptions Used In Calculating Benefit Obligation [Table Text Block]	For Exelon, the following assumptions were used to determine the benefit obligations for the plans at December 31, 2020 and 2019. 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 2020 2019 2020 2019 Discount rate 2.58 % (a) 3.34 % (a) 2.51 % (a) 3.31 % (a) Investment crediting rate 3.72 % (b) 3.82 % (b) N/A N/A Rate of compensation increase 3.75 % (c) 3.75 % (c) Mortality table Pri-2012 table with MP- 2020 improvement scale (adjusted) Pri-2012 table with MP- 2019 improvement scale (adjusted) Pri-2012 table with MP- 2020 improvement scale (adjusted) Pri-2012 table with MP- 2019 improvement scale (adjusted) Health care cost trend on covered charges N/A N/A Initial and ultimate rate of 5.00% 5.00% with ultimate trend of 5.00% in 2017 __________ (a) The discount rates above represent the blended rates used to determine the majority of Exelon’s pension and OPEB obligations. Certain benefit plans used individual rates, which range from 2.11% - 2.73% and 2.45% - 2.63% for pension and OPEB plans, respectively, as of December 31, 2020 and 3.02% - 3.44% and 3.27% - 3.40% for pension and OPEB plans, respectively, as of December 31, 2019. (b) The investment crediting rate above represents a weighted average rate. (c) 3.25% through 2019 and 3.75% thereafter.
Defined Benefit Plan Weighted Average Assumptions Used In Calculating Net Periodic Benefit Cost [Table Text Block]	The following assumptions were used to determine the net periodic benefit cost for Exelon for the years ended December 31, 2020, 2019 and 2018: Pension Benefits OPEB 2020 2019 2018 2020 2019 2018 Discount rate 3.34 % (a) 4.31 % (a) 3.62 % (a) 3.31 % (a) 4.30 % (a) 3.61 % (a) Investment crediting rate 3.82 % (b) 4.46 % (b) 4.00 % (b) N/A N/A N/A Expected return on plan assets 7.00 % (c) 7.00 % (c) 7.00 % (c) 6.69 % (c) 6.67 % (c) 6.60 % (c) Rate of compensation increase (d) (d) (d) (d) (d) (d) Mortality table Pri-2012 table with MP- 2019 improvement scale (adjusted) RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted) RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted) Pri-2012 table with MP- 2019 improvement scale (adjusted) RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted) RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted) Health care cost trend on covered charges N/A N/A N/A Initial and ultimate rate of 5.00% 5.00% with ultimate trend of 5.00% in 2017 5.00% with ultimate trend of 5.00% in 2017 __________ (a) The discount rates above represent the blended rates used to establish the majority of Exelon’s pension and OPEB costs. Certain benefit plans used individual rates, which range from 3.02%-3.44% and 3.27%-3.40% for pension and OPEB plans, respectively, for the year ended December 31, 2020; 4.13%-4.36% and 4.27%-4.38% for pension and OPEB plans; respectively, for the year ended December 31, 2019; and 3.49%-3.65% and 3.57%-3.68% for pension and OPEB plans, respectively, for the year ended December 31, 2018. (b) The investment crediting rate above represents a weighted average rate. (c) Not applicable to pension and OPEB plans that do not have plan assets. (d) 3.25% through 2019 and 3.75% thereafter.
Pension And Other Postretirement Benefit Contributions [Table Text Block]	The following tables provide contributions to the pension and OPEB plans: Pension Benefits OPEB 2020 2019 2018 2020 2019 2018 Exelon $ 542 $ 356 $ 337 $ 59 $ 51 $ 46 Generation 236 160 128 19 15 11 ComEd 143 72 38 5 5 4 PECO 18 27 28 — 1 — BGE 56 34 40 22 14 14 PHI 30 10 62 9 15 12 Pepco 2 2 6 9 12 11 DPL — 1 — — — — ACE 2 — 6 — 1 — The following table provides all Registrants' planned contributions to the qualified pension plans, planned benefit payments to non-qualified pension plans, and planned contributions to OPEB plans in 2021: Qualified Pension Plans Non-Qualified Pension Plans OPEB Exelon $ 505 $ 51 $ 75 Generation 196 27 24 ComEd 170 2 23 PECO 14 1 — BGE 57 1 16 PHI 29 9 7 Pepco 1 2 6 DPL — 1 — ACE 3 — —
Schedule of Expected Benefit Payments [Table Text Block]	Estimated future benefit payments to participants in all of the pension plans and postretirement benefit plans at December 31, 2020 were: Pension OPEB 2021 $ 1,279 $ 257 2022 1,280 259 2023 1,315 261 2024 1,325 262 2025 1,338 265 2026 through 2030 6,759 1,320 Total estimated future benefit payments through 2030 $ 13,296 $ 2,624
Defined Benefit Plan Weighted Average Asset Allocations And Target Allocations [Table Text Block]	Exelon’s pension and OPEB plan target asset allocations at December 31, 2020 and 2019 were as follows: December 31, 2020 December 31, 2019 Asset Category Pension Benefits OPEB Pension Benefits OPEB Equity securities 34 % 45 % 33 % 46 % Fixed income securities 43 % 39 % 44 % 32 % Alternative investments (a) 23 % 16 % 23 % 22 % Total 100 % 100 % 100 % 100 % __________ (a) Alternative investments include private equity, hedge funds, real estate, and private credit.
Defined Benefit Plan Fair Value Of Plan Assets [Text Block]	The following tables present pension and OPEB plan assets measured and recorded at fair value in Exelon's Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy at December 31, 2020 and 2019: December 31, 2020 December 31, 2019 Level 1 Level 2 Level 3 Not subject to leveling Total Level 1 Level 2 Level 3 Not subject to leveling Total Pension plan assets (a) Cash equivalents $ 408 $ 121 $ — $ — $ 529 $ 258 $ 107 $ — $ — $ 365 Equities (b) 4,255 — 2 2,552 6,809 3,616 1 5 2,589 6,211 Fixed income: U.S. Treasury and agencies 1,137 367 — — 1,504 1,294 280 — — 1,574 State and municipal debt — 85 — — 85 — 56 — — 56 Corporate debt (c) — 4,873 573 — 5,446 — 4,390 245 — 4,635 Other (b) — 239 21 537 797 — 305 — 851 1,156 Fixed income subtotal 1,137 5,564 594 537 7,832 1,294 5,031 245 851 7,421 Private equity — — — 1,632 1,632 — — — 1,391 1,391 Hedge funds — — — 1,314 1,314 — — — 1,126 1,126 Real estate — — — 1,080 1,080 — — — 1,030 1,030 Private credit — — 234 1,046 1,280 — — 237 929 1,166 Pension plan assets subtotal 5,800 5,685 830 8,161 20,476 5,168 5,139 487 7,916 18,710 OPEB plan assets (a) Cash equivalents 50 52 — — 102 39 49 — — 88 Equities 618 2 — 569 1,189 473 5 — 719 1,197 Fixed income: U.S. Treasury and agencies 16 66 — — 82 17 64 — — 81 State and municipal debt — 89 — — 89 — 107 — — 107 Corporate debt (c) — 89 — — 89 — 71 — — 71 Other 285 3 — 179 467 258 5 — 201 464 Fixed income subtotal 301 247 — 179 727 275 247 — 201 723 Hedge funds — — — 308 308 — — — 293 293 Real estate — — — 111 111 — — — 109 109 Private credit — — — 117 117 — — — 131 131 OPEB plan assets subtotal 969 301 — 1,284 2,554 787 301 — 1,453 2,541 Total pension and OPEB plan assets (d) $ 6,769 $ 5,986 $ 830 $ 9,445 $ 23,030 $ 5,955 $ 5,440 $ 487 $ 9,369 $ 21,251 __________ (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 $2 million for the years ended December 31, 2020 and 2019, which have total notional amounts of $6,879 million and $6,668 million at December 31, 2020 and 2019, respectively. 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) Includes investments in equities sold short held in investment vehicles primarily to hedge the equity option component of its convertible debt. Pension equities sold short totaled $(96) million and $(75) million as of December 31, 2020 and 2019, respectively. OPEB equities sold short totaled $(42) million and $(35) million as of December 31, 2020 and 2019, respectively. (d) Excludes net liabilities of $132 million and $120 million at December 31, 2020 and 2019, respectively, which include certain derivative assets that have notional amounts of $239 million and $632 million at December 31, 2020 and 2019, respectively. 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.
Schedule of Changes in Fair Value of Plan Assets [Table Text Block]	The following table presents the reconciliation of Level 3 assets and liabilities for Exelon measured at fair value for pension and OPEB plans for the years ended December 31, 2020 and 2019: Fixed Income Equities Private Total Pension Assets Balance as of January 1, 2020 $ 245 $ 5 $ 237 $ 487 Actual return on plan assets: Relating to assets still held at the 19 (3) 15 31 Purchases, sales and settlements: Purchases 34 — 24 58 Settlements (a) (3) — (42) (45) Transfers into Level 3 (b) 299 — — 299 Balance as of December 31, 2020 $ 594 $ 2 $ 234 $ 830 Fixed Income Equities Private Total Pension Assets Balance as of January 1, 2019 $ 216 $ 2 $ 268 $ 486 Actual return on plan assets: Relating to assets still held at the reporting date 28 3 28 59 Relating to assets sold during the period (7) — — (7) Purchases, sales and settlements: Purchases 26 — 41 67 Sales (4) — — (4) Settlements (a) (2) — (100) (102) Transfers out of Level 3 (12) — — (12) Balance as of December 31, 2019 $ 245 $ 5 $ 237 $ 487 __________ (a) Represents cash settlements only. (b) In 2020, a contract was terminated for a certain fixed income commingled fund resulting in the ownership of certain fixed income securities which led to a transfer into Level 3 from not subject to leveling of $299 million.
Schedule Of Defined Contributions [Table Text Block]	The Registrants participate in various 401(k) defined contribution savings plans that are sponsored by Exelon. The plans are qualified under applicable sections of the IRC and allow employees to contribute a portion of their pre-tax and/or after-tax income in accordance with specified guidelines. All Registrants match a percentage of the employee contributions up to certain limits. The following table presents matching contributions to the savings plan for the years ended December 31, 2020, 2019, and 2018: For the Years Ended December 31, Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE 2020 $ 158 $ 63 $ 36 $ 12 $ 13 14 $ 4 $ 3 $ 3 2019 161 73 35 11 12 13 3 3 2 2018 179 86 37 9 12 13 3 2 2

Derivative Financial Instrume_2

Derivative Financial Instruments (Tables)	12 Months Ended
Derivative Financial Instruments (Tables)	Dec. 31, 2020
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Summary of the derivative fair value	The following table provides a summary of the derivative fair value balances recorded by Exelon, Generation, and ComEd as of December 31, 2020 and 2019: Exelon Generation ComEd December 31, 2020 Total Economic Proprietary Collateral (a)(b) Netting (a) Subtotal Economic Mark-to-market derivative assets (current assets) $ 639 $ 2,757 $ 40 $ 103 $ (2,261) $ 639 $ — Mark-to-market derivative assets (noncurrent assets) 554 1,501 4 64 (1,015) 554 — Total mark-to-market derivative assets 1,193 4,258 44 167 (3,276) 1,193 — Mark-to-market derivative liabilities (current liabilities) (293) (2,629) (23) 131 2,261 (260) (33) Mark-to-market derivative liabilities (noncurrent liabilities) (472) (1,335) (2) 118 1,015 (204) (268) Total mark-to-market derivative liabilities (765) (3,964) (25) 249 3,276 (464) (301) Total mark-to-market derivative net assets (liabilities) $ 428 $ 294 $ 19 $ 416 $ — $ 729 $ (301) December 31, 2019 Mark-to-market derivative assets (current assets) $ 675 $ 3,506 $ 72 $ 287 $ (3,190) $ 675 $ — Mark-to-market derivative assets (noncurrent assets) 508 1,238 25 122 (877) 508 — Total mark-to-market derivative assets 1,183 4,744 97 409 (4,067) 1,183 — Mark-to-market derivative liabilities (current liabilities) (236) (3,713) (38) 357 3,190 (204) (32) Mark-to-market derivative liabilities (noncurrent liabilities) (380) (1,140) (11) 163 877 (111) (269) Total mark-to-market derivative liabilities (616) (4,853) (49) 520 4,067 (315) (301) Total mark-to-market derivative net assets (liabilities) $ 567 $ (109) $ 48 $ 929 $ — $ 868 $ (301) _________ (a) Exelon and Generation net all available amounts allowed under the derivative authoritative guidance in the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation 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 and not reflected in the table above. (b) Of the collateral posted, $209 million and $511 million represents variation margin on the exchanges at December 31, 2020 and 2019, respectively.
Economic Hedges (Commodity Price Risk)	For the years ended December 31, 2020, 2019, and 2018, Exelon and Generation 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. Gain (Loss) Income Statement Location 2020 2019 2018 Operating revenues $ 112 $ — $ (270) Purchased power and fuel 168 (204) (47) Total Exelon and Generation $ 280 $ (204) $ (317)
Disclosure of Credit Derivatives [Table Text Block]	The following tables provide information on Generation’s 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, 2020. 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 figures 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, 2020 Total Credit Collateral (a) Net Number of Net Exposure of Investment grade $ 577 $ 27 $ 550 — $ — Non-investment grade 32 — 32 No external ratings Internally rated — investment grade 165 1 164 Internally rated — non-investment grade 80 28 52 Total $ 854 $ 56 $ 798 — $ — Net Credit Exposure by Type of Counterparty As of December 31, 2020 Financial institutions $ 15 Investor-owned utilities, marketers, power producers 607 Energy cooperatives and municipalities 138 Other 38 Total $ 798 __________ (a) As of December 31, 2020, credit collateral held from counterparties where Generation had credit exposure included $31 million of cash and $25 million of letters of credit. The credit collateral does not include non-liquid collateral.
Fair Value of Derivatives with Credit- Risk Related Contingent Features [Table Text Block] [Table Text Block]	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 2020 2019 Gross fair value of derivative contracts containing this feature (a) $ (834) $ (956) Offsetting fair value of in-the-money contracts under master netting arrangements (b) 537 649 Net fair value of derivative contracts containing this feature (c) $ (297) $ (307) __________ (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 Generation could potentially be required to post collateral. (c) Amount represents the net fair value of out-of-the-money derivative contracts containing credit-risk related contingent features after considering the mitigating effects of offsetting positions under master netting arrangements and reflects the actual net liability upon which any potential contingent collateral obligations would be based.
Cash Collateral and Letters of Credit on Derivative Contracts [Table Text Block]	As of December 31, 2020 and 2019, Exelon and Generation 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, 2020 2019 Cash collateral posted $ 511 $ 982 Letters of credit posted 226 264 Cash collateral held 110 103 Letters of credit held 40 112 Additional collateral required in the event of a credit downgrade below investment grade 1,432 1,509

Debt and Credit Agreements (Tab

Debt and Credit Agreements (Tables)	12 Months Ended
Debt and Credit Agreements (Tables)	Dec. 31, 2020
Short-term Debt [Line Items]
Schedule of commercial paper, credit facilities, and borrowing rates	Borrowings under Exelon’s, Generation’s, ComEd’s, PECO’s, BGE's, Pepco's, DPL's, and ACE's revolving credit agreements bear interest at a rate based upon either the prime rate or a LIBOR-based rate, plus an adder based upon the particular Registrant’s credit rating. The adders for the prime based borrowings and LIBOR-based borrowings are presented in the following table: Exelon (a) Generation ComEd PECO BGE Pepco DPL ACE Prime based borrowings 0 - 27.5 27.5 — — — 7.5 — 7.5 LIBOR-based borrowings 90.0 - 127.5 127.5 100.0 90.0 90.0 107.5 100.0 107.5 __________ (a) Includes interest rate adders at Exelon Corporate of 27.5 and 127.5 for prime and LIBOR-based borrowings, respectively.
Schedule of bilateral credit agreements	Bilateral Credit Agreements The following table reflects the bilateral credit agreements at December 31, 2020: Registrant Date Initiated Latest Amendment Date Maturity Date (a) Amount Generation (b) October 26, 2012 October 23, 2020 October 22, 2021 $ 200 Generation (c) January 11, 2013 January 4, 2019 March 1, 2021 100 Generation (c) January 5, 2016 January 4, 2019 April 5, 2021 150 Generation (c) February 21, 2019 N/A March 31, 2021 100 Generation (c) October 25, 2019 N/A N/A 200 Generation (c) October 25, 2019 N/A N/A 100 Generation (c) November 20, 2019 N/A N/A 300 Generation (c) November 21, 2019 N/A N/A 150 Generation (c) November 21, 2019 N/A November 21, 2021 100 Generation (c) May 15, 2020 N/A N/A 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 facility relates to CENG, which is incorporated within Generation, and supports the issuance of letters of credit and funding for working capital and does not back Generation's commercial paper program. During the second and third quarters of 2020, CENG drew on its bilateral credit facility. As of December 31, 2020, there was no outstanding balance at this facility. (c) Bilateral credit agreements solely support the issuance of letters of credit and do not back Generation's commercial paper program.
Schedule of long-term debt instruments	Long-Term Debt The following tables present the outstanding long-term debt at the Registrants as of December 31, 2020 and 2019: Exelon Maturity December 31, Rates 2020 2019 Long-term debt First mortgage bonds (a) 0.19 % - 7.90 % 2021 - 2050 $ 18,915 $ 17,486 Senior unsecured notes 2.45 % - 7.60 % 2021 - 2050 10,585 10,685 Unsecured notes 2.40 % - 6.35 % 2021 - 2050 3,700 3,300 Pollution control notes 2.50 % - 2.70 % 2020 — 412 Nuclear fuel procurement contracts 3.15 % 2020 — 3 Notes payable and other 2.10 % - 7.99 % 2021 - 2053 170 154 Junior subordinated notes 3.50 % 2022 1,150 1,150 Long-term software licensing agreement 3.95 % 2024 30 55 Unsecured tax-exempt bonds 0.17 % - 1.70 % 2022 - 2024 143 222 Medium-terms notes (unsecured) 7.72 % 2027 10 10 Transition bonds 5.55 % 2021 21 40 Loan agreement 2.00 % 2023 50 50 Nonrecourse debt: Fixed rates 2.29 % - 6.00 % 2031 - 2037 977 1,182 Variable rates 2.99 % - 3.18 % 2021 - 2027 765 811 Total long-term debt 36,516 35,560 Unamortized debt discount and premium, net (77) (72) Unamortized debt issuance costs (248) (214) Fair value adjustment 721 765 Long-term debt due within one year (1,819) (4,710) Long-term debt $ 35,093 $ 31,329 Long-term debt to financing trusts (b) Subordinated debentures to ComEd Financing III 6.35 % 2033 $ 206 $ 206 Subordinated debentures to PECO Trust III 5.25 % - 7.38 % 2028 81 81 Subordinated debentures to PECO Trust IV 5.75 % 2033 103 103 Total long-term debt to financing trusts $ 390 $ 390 __________ (a) Substantially all of ComEd’s assets other than expressly excepted property and substantially all of PECO’s, Pepco's, DPL's, and ACE's assets are subject to the liens of their respective mortgage indentures. (b) Amounts owed to these financing trusts are recorded as Long-term debt to financing trusts within Exelon’s Consolidated Balance Sheets. Generation Maturity December 31, Rates 2020 2019 Long-term debt Senior unsecured notes 3.25 % - 7.60 % 2022 - 2042 $ 4,219 $ 5,420 Pollution control notes 2.50 % - 2.70 % 2020 — 412 Nuclear fuel procurement contracts 3.15 % 2020 — 3 Notes payable and other 2.10 % - 4.85 % 2021 - 2028 111 115 Nonrecourse debt: Fixed rates 2.29 % - 6.00 % 2031 - 2037 977 1,182 Variable rates 2.99 % - 3.18 % 2021 - 2027 765 811 Total long-term debt 6,072 7,943 Unamortized debt discount and premium, net (5) (5) Unamortized debt issuance costs (46) (42) Fair value adjustment 66 78 Long-term debt due within one year (197) (3,182) Long-term debt $ 5,890 $ 4,792 ComEd Maturity December 31, Rates 2020 2019 Long-term debt First mortgage bonds (a) 2.20 % - 6.45 % 2021 - 2050 $ 9,079 $ 8,578 Other 7.49 % 2053 8 8 Total long-term debt 9,087 8,586 Unamortized debt discount and premium, net (28) (27) Unamortized debt issuance costs (76) (68) Long-term debt due within one year (350) (500) Long-term debt $ 8,633 $ 7,991 Long-term debt to financing trust (b) Subordinated debentures to ComEd Financing III 6.35 % 2033 $ 206 $ 206 Total long-term debt to financing trusts 206 206 Unamortized debt issuance costs (1) (1) Long-term debt to financing trusts $ 205 $ 205 __________ (a) Substantially all of ComEd’s assets, other than expressly excepted property, are subject to the lien of its mortgage indenture. (b) Amount owed to this financing trust is recorded as Long-term debt to financing trust within ComEd’s Consolidated Balance Sheets. PECO Maturity December 31, Rates 2020 2019 Long-term debt First mortgage bonds (a) 1.70 % - 5.95 % 2021 - 2050 $ 3,750 $ 3,400 Loan agreement 2.00 % 2023 50 50 Total long-term debt 3,800 3,450 Unamortized debt discount and premium, net (20) (21) Unamortized debt issuance costs (27) (24) Long-term debt due within one year (300) — Long-term debt $ 3,453 $ 3,405 Long-term debt to financing trusts (b) Subordinated debentures to PECO Trust III 5.25 % - 7.38 % 2028 $ 81 $ 81 Subordinated debentures to PECO Trust IV 5.75 % 2033 103 103 Long-term debt to financing trusts $ 184 $ 184 __________ (a) Substantially all of PECO’s assets are subject to the lien of its mortgage indenture. (b) Amounts owed to this financing trust are recorded as Long-term debt to financing trusts within PECO’s Consolidated Balance Sheets. BGE Maturity December 31, Rates 2020 2019 Long-term debt Unsecured notes 2.40 % - 6.35 % 2021 - 2050 $ 3,700 $ 3,300 Total long-term debt 3,700 3,300 Unamortized debt discount and premium, net (12) (9) Unamortized debt issuance costs (24) (21) Long-term debt due within one year (300) — Long-term debt $ 3,364 $ 3,270 PHI Maturity December 31, Rates 2020 2019 Long-term debt First mortgage bonds (a) 0.19 % - 7.90 % 2021 - 2050 $ 6,086 $ 5,508 Senior unsecured notes 7.45 % 2032 185 185 Unsecured tax-exempt bonds 0.17 % - 1.70 % 2022 - 2024 143 222 Medium-terms notes (unsecured) 7.72 % 2027 10 10 Transition bonds 5.55 % 2021 21 40 Finance leases 3.54 % 2022 - 2028 50 28 Other 7.28 % - 7.99 % 2021 - 2022 1 2 Total long-term debt 6,496 5,995 Unamortized debt discount and premium, net 4 4 Unamortized debt issuance costs (28) (19) Fair value adjustment 534 583 Long-term debt due within one year (347) (103) Long-term debt $ 6,659 $ 6,460 _________ (a) Substantially all of Pepco's, DPL's, and ACE's assets are subject to the liens of their respective mortgage indentures. Pepco Maturity December 31, Rates 2020 2019 Long-term debt First mortgage bonds (a) 2.53 % - 7.90 % 2022 - 2050 $ 3,075 $ 2,775 Unsecured tax-exempt bonds 1.70 % 2022 110 110 Finance leases 3.54 % 2025 - 2028 17 10 Other 7.28 % - 7.99 % 2021 - 2022 1 2 Total long-term debt 3,203 2,897 Unamortized debt discount and premium, net 2 2 Unamortized debt issuance costs (40) (35) Long-term debt due within one year (3) (2) Long-term debt $ 3,162 $ 2,862 __________ (a) Substantially all of Pepco's assets are subject to the lien of its mortgage indenture. DPL Maturity December 31, Rates 2020 2019 Long-term debt First mortgage bonds (a) 0.19 % - 4.27 % 2023 - 2049 $ 1,624 $ 1,446 Unsecured tax-exempt bonds 0.17 % - 0.20 % 2024 33 112 Medium-terms notes (unsecured) 7.72 % 2027 10 10 Finance leases 3.54 % 2025 - 2028 20 10 Total long-term debt 1,687 1,578 Unamortized debt discount and premium, net 1 1 Unamortized debt issuance costs (11) (12) Long-term debt due within one year (82) (80) Long-term debt $ 1,595 $ 1,487 __________ (a) Substantially all of DPL's assets are subject to the lien of its mortgage indenture. ACE Maturity December 31, Rates 2020 2019 Long-term debt First mortgage bonds (a) 2.25 % - 6.80 % 2021 - 2050 $ 1,387 $ 1,287 Transition bonds 5.55 % 2021 21 40 Finance leases 3.54 % 2022 - 2028 13 8 Total long-term debt 1,421 1,335 Unamortized debt discount and premium, net (1) (1) Unamortized debt issuance costs (7) (7) Long-term debt due within one year (261) (20) Long-term debt $ 1,152 $ 1,307 __________ (a) Substantially all of ACE's assets are subject to the lien of its mortgage indenture.
Schedule of maturities of long-term debt	Long-term debt maturities at the Registrants in the periods 2021 through 2025 and thereafter are as follows: Year Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE 2021 $ 1,819 $ 197 $ 350 $ 300 $ 300 $ 347 $ 3 $ 82 $ 261 2022 3,092 1,025 — 350 250 317 312 3 2 2023 859 1 — 50 300 508 3 503 2 2024 814 1 250 — — 558 403 3 152 2025 2,215 900 — 350 — 158 3 3 152 Thereafter 28,107 (a) 3,948 8,692 (b) 2,934 (c) 2,850 4,608 2,479 1,093 852 Total $ 36,906 $ 6,072 $ 9,292 $ 3,984 $ 3,700 $ 6,496 $ 3,203 $ 1,687 $ 1,421 __________ (a) Includes $390 million due to ComEd and PECO financing trusts. (b) Includes $206 million due to ComEd financing trust. (c) Includes $184 million due to PECO financing trusts.
Commercial Paper
Short-term Debt [Line Items]
Schedule of commercial paper, credit facilities, and borrowing rates	The following table reflects the Registrants' commercial paper programs supported by the revolving credit agreements and bilateral credit agreements at December 31, 2020 and 2019: Maximum Outstanding Average Interest Rate on Commercial Paper Issuer 2020 (a)(b)(c) 2019 (a)(b)(c) 2020 2019 2020 2019 Exelon (d) $ 9,000 $ 9,000 $ 1,031 $ 870 0.25 % 2.25 % Generation 5,300 5,300 340 320 0.27 % 1.84 % ComEd 1,000 1,000 323 130 0.23 % 2.38 % PECO 600 600 — — — % 2.39 % BGE 600 600 — 76 — % 2.46 % PHI (e) 900 900 368 208 0.24 % N/A Pepco 300 300 35 82 0.22 % 2.56 % DPL 300 300 146 56 0.24 % 2.02 % ACE 300 300 187 70 0.25 % 2.43 % __________ (a) Excludes $1,500 million and $1,400 million in bilateral credit facilities at December 31, 2020 and 2019, respectively, and $144 million and $159 million in credit facilities for project finance at December 31, 2020 and 2019, respectively. These credit facilities do not back Generation's commercial paper program. (b) At December 31, 2020, excludes $135 million of credit facility agreements arranged at minority and community banks at Generation, ComEd, PECO, BGE, Pepco, DPL, and ACE with aggregate commitments of $38 million, $32 million, $33 million, $8 million, $8 million, $8 million, and $8 million, respectively. These facilities expire on October 8, 2021. These facilities are solely utilized to issue letters of credit. At December 31, 2019, excludes $142 million of credit facility agreements arranged at minority and community banks at Generation, ComEd, PECO, BGE, Pepco, DPL, and ACE with aggregate commitments of $44 million, $33 million, $33 million, $8 million, $8 million, $8 million, and $8 million, respectively. (c) Pepco, DPL, and ACE's revolving credit facility has the ability to flex to $500 million, $500 million, and $350 million, respectively. The borrowing capacity may be increased or decreased during the term of the facility, except that (i) the sum of the borrowing capacity must equal the total amount of the facility, and (ii) the aggregate amount of credit used at any given time by each of Pepco, DPL, or ACE may not exceed $900 million or the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the borrowing reallocations may not exceed eight per year during the term of the facility. (d) Includes revolving credit agreement at Exelon Corporate with a maximum program size of $600 million at both December 31, 2020 and 2019, respectively. Exelon Corporate had no outstanding commercial paper as of December 31, 2020 and $136 million at 2019 with an average interest rate on commercial paper borrowings of 1.92%. (e) Represents the consolidated amounts of Pepco, DPL, and ACE.
Revolving Credit Facility
Short-term Debt [Line Items]
Schedule of commercial paper, credit facilities, and borrowing rates	At December 31, 2020, the Registrants had the following aggregate bank commitments, credit facility borrowings, and available capacity under their respective credit facilities: Available Capacity at December 31, 2020 Borrower (a) Facility Type Aggregate Bank (b) Facility Draws Outstanding Actual To Support Additional Commercial (c) Exelon (c) Syndicated Revolver / Bilaterals / Project Finance $ 10,644 $ — $ 1,230 $ 9,414 $ 7,698 Generation Syndicated Revolver 5,300 — 262 5,038 4,698 Generation Bilaterals 1,500 — 840 660 — Generation Project Finance 144 — 119 25 — ComEd Syndicated Revolver 1,000 — 2 998 675 PECO Syndicated Revolver 600 — — 600 600 BGE Syndicated Revolver 600 — — 600 600 PHI Syndicated Revolver 900 — 1 899 531 Pepco Syndicated Revolver 300 — 1 299 264 DPL Syndicated Revolver 300 — — 300 154 ACE Syndicated Revolver 300 — — 300 113 __________ (a) On May 26, 2018, each of the Registrants' respective syndicated revolving credit facilities had their maturity dates extended to May 26, 2023. (b) Excludes $135 million of credit facility agreements arranged at minority and community banks at Generation, ComEd, PECO, BGE, Pepco, DPL, and ACE with aggregate commitments of $38 million, $32 million, $33 million, $8 million, $8 million, $8 million, and $8 million, respectively. These facilities expire on October 8, 2021. These facilities are solely utilized to issue letters of credit. As of December 31, 2020, letters of credit issued under these facilities totaled $5 million, $5 million, and $2 million for Generation, ComEd, and BGE, respectively. (c) Includes $600 million aggregate bank commitment related to Exelon Corporate. Exelon Corporate had $6 million outstanding letters of credit at December 31, 2020. Exelon Corporate had $594 million in available capacity to support additional commercial paper at December 31, 2020.

Fair Value of Financial Asset_2

Fair Value of Financial Assets and Liabilities (Tables)	12 Months Ended
Fair Value of Financial Assets and Liabilities (Tables)	Dec. 31, 2020
Fair Value Disclosures [Abstract]
Fair Value of Financial Liabilities Recorded at Amortized Cost	The following tables present the carrying amounts and fair values of the Registrants’ short-term liabilities, long-term debt, SNF obligation, and trust preferred securities (long-term debt to financing trusts or junior subordinated debentures) as of December 31, 2020 and 2019. The Registrants have no financial liabilities classified as Level 1. The carrying amounts of the Registrants’ short-term liabilities as presented on their Consolidated Balance Sheets are representative of their fair value (Level 2) because of the short-term nature of these instruments. December 31, 2020 December 31, 2019 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 (a) Exelon $ 36,912 $ 40,688 $ 3,064 $ 43,752 $ 36,039 $ 37,453 $ 2,580 $ 40,033 Generation 6,087 5,648 1,208 6,856 7,974 7,304 1,366 8,670 ComEd 8,983 11,117 — 11,117 8,491 9,848 — 9,848 PECO 3,753 4,553 50 4,603 3,405 3,868 50 3,918 BGE 3,664 4,366 — 4,366 3,270 3,649 — 3,649 PHI 7,006 6,099 1,806 7,905 6,563 5,902 1,164 7,066 Pepco 3,165 3,336 748 4,084 2,864 3,198 388 3,586 DPL 1,677 1,484 455 1,939 1,567 1,408 311 1,719 ACE 1,413 1,018 602 1,620 1,327 1,026 464 1,490 Long-Term Debt to Financing Trusts (a) Exelon $ 390 $ — $ 467 $ 467 $ 390 $ — $ 428 $ 428 ComEd 205 — 246 246 205 — 227 227 PECO 184 — 221 221 184 — 201 201 SNF Obligation Exelon $ 1,208 $ 909 $ — $ 909 $ 1,199 $ 1,055 $ — $ 1,055 Generation 1,208 909 — 909 1,199 1,055 — 1,055 __________ (a) Includes unamortized debt issuance costs which are not fair valued. Refer to Note 17 — Debt and Credit Agreements for each Registrants’ unamortized debt issuance costs .
Assets and Liabilities Measured and Recorded at Fair Value on Recurring Basis	The following tables present assets and liabilities measured and recorded at fair value in the Registrants' Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2020 and 2019: Exelon and Generation Exelon Generation As of December 31, 2020 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) $ 686 $ — $ — $ — $ 686 $ 124 $ — $ — $ — $ 124 NDT fund investments Cash equivalents (b) 210 95 — — 305 210 95 — — 305 Equities 3,886 2,077 — 1,562 7,525 3,886 2,077 — 1,562 7,525 Fixed income Corporate debt (c) — 1,485 285 — 1,770 — 1,485 285 — 1,770 U.S. Treasury and agencies 1,871 126 — — 1,997 1,871 126 — — 1,997 Foreign governments — 56 — — 56 — 56 — — 56 State and municipal debt — 101 — — 101 — 101 — — 101 Other — 41 — 961 1,002 — 41 — 961 1,002 Fixed income subtotal 1,871 1,809 285 961 4,926 1,871 1,809 285 961 4,926 Private credit — — 212 629 841 — — 212 629 841 Private equity — — — 504 504 — — — 504 504 Real estate — — — 679 679 — — — 679 679 NDT fund investments subtotal (d)(e) 5,967 3,981 497 4,335 14,780 5,967 3,981 497 4,335 14,780 Rabbi trust investments Cash equivalents 60 — — — 60 4 — — — 4 Mutual funds 91 — — — 91 29 — — — 29 Fixed income — 11 — — 11 — — — — — Life insurance contracts — 87 34 — 121 — 28 — — 28 Rabbi trust investments subtotal 151 98 34 — 283 33 28 — — 61 Investments in equities (f) 195 — — — 195 195 — — — 195 Commodity derivative assets Economic hedges 745 1,914 1,599 — 4,258 745 1,914 1,599 — 4,258 Proprietary trading — 17 27 — 44 — 17 27 — 44 Effect of netting and allocation of collateral (g)(h) (607) (1,597) (905) — (3,109) (607) (1,597) (905) — (3,109) Commodity derivative assets subtotal 138 334 721 — 1,193 138 334 721 — 1,193 DPP consideration — 639 — — 639 — 639 — — 639 Total assets 7,137 5,052 1,252 4,335 17,776 6,457 4,982 1,218 4,335 16,992 Liabilities Commodity derivative liabilities Economic hedges (682) (1,928) (1,655) — (4,265) (682) (1,928) (1,354) — (3,964) Proprietary trading — (21) (4) — (25) — (21) (4) — (25) Effect of netting and allocation of collateral (g)(h) 540 1,918 1,067 — 3,525 540 1,918 1,067 — 3,525 Commodity derivative liabilities subtotal (142) (31) (592) — (765) (142) (31) (291) — (464) Deferred compensation obligation — (145) — — (145) — (42) — — (42) Total liabilities (142) (176) (592) — (910) (142) (73) (291) — (506) Total net assets $ 6,995 $ 4,876 $ 660 $ 4,335 $ 16,866 $ 6,315 $ 4,909 $ 927 $ 4,335 $ 16,486 Exelon Generation As of December 31, 2019 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) $ 639 $ — $ — $ — $ 639 $ 214 $ — $ — $ — $ 214 NDT fund investments Cash equivalents (b) 365 87 — — 452 365 87 — — 452 Equities 3,353 1,801 — 1,388 6,542 3,353 1,801 — 1,388 6,542 Fixed income Corporate debt (c) — 1,421 257 — 1,678 — 1,421 257 — 1,678 U.S. Treasury and agencies 1,808 131 — — 1,939 1,808 131 — — 1,939 Foreign governments — 42 — — 42 — 42 — — 42 State and municipal debt — 90 — — 90 — 90 — — 90 Other — 33 — 953 986 — 33 — 953 986 Fixed income subtotal 1,808 1,717 257 953 4,735 1,808 1,717 257 953 4,735 Private credit — — 254 508 762 — — 254 508 762 Private equity — — — 402 402 — — — 402 402 Real estate — — — 607 607 — — — 607 607 NDT fund investments subtotal (d)(e) 5,526 3,605 511 3,858 13,500 5,526 3,605 511 3,858 13,500 Rabbi trust investments Cash equivalents 50 — — — 50 4 — — — 4 Mutual funds 81 — — — 81 25 — — — 25 Fixed income — 12 — — 12 — — — — — Life insurance contracts — 78 41 — 119 — 25 — — 25 Rabbi trust investments subtotal 131 90 41 — 262 29 25 — — 54 Commodity derivative assets Economic hedges 768 2,491 1,485 — 4,744 768 2,491 1,485 — 4,744 Proprietary trading — 37 60 — 97 — 37 60 — 97 Effect of netting and allocation of collateral (g)(h) (908) (2,162) (588) — (3,658) (908) (2,162) (588) — (3,658) Commodity derivative assets subtotal (140) 366 957 — 1,183 (140) 366 957 — 1,183 Total assets 6,156 4,061 1,509 3,858 15,584 5,629 3,996 1,468 3,858 14,951 Liabilities Commodity derivative liabilities Economic hedges (1,071) (2,855) (1,228) — (5,154) (1,071) (2,855) (927) — (4,853) Proprietary trading — (34) (15) — (49) — (34) (15) — (49) Effect of netting and allocation of collateral (g)(h) 1,071 2,714 802 — 4,587 1,071 2,714 802 — 4,587 Commodity derivative liabilities subtotal — (175) (441) — (616) — (175) (140) — (315) Deferred compensation obligation — (147) — — (147) — (41) — — (41) Total liabilities — (322) (441) — (763) — (216) (140) — (356) Total net assets $ 6,156 $ 3,739 $ 1,068 $ 3,858 $ 14,821 $ 5,629 $ 3,780 $ 1,328 $ 3,858 $ 14,595 __________ (a) Exelon excludes cash of $409 million and $373 million at December 31, 2020 and 2019, respectively, and restricted cash of $59 million and $110 million at December 31, 2020 and 2019, respectively, and includes long-term restricted cash of $53 million and $177 million at December 31, 2020 and 2019, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. Generation excludes cash of $171 million and $177 million at December 31, 2020 and 2019, respectively, and restricted cash of $20 million and $58 million at December 31, 2020 and 2019, respectively. (b) Includes $116 million and $90 million of cash received from outstanding repurchase agreements at December 31, 2020 and 2019, 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 $(62) million and $(48) million as of December 31, 2020 and 2019, respectively, held in an investment vehicle primarily to hedge the equity option component of its convertible debt. (d) Includes derivative assets of $2 million and $2 million, which have total notional amounts of $1,043 million and $724 million at December 31, 2020 and 2019, 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 Exelon and Generation's exposure to credit or market loss. (e) Excludes net liabilities of $181 million and $147 million at December 31, 2020 and 2019, respectively, which include certain derivative assets that have notional amounts of $104 million and $99 million at December 31, 2020 and 2019, 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) Reflects equity investments held by Generation which were previously designated as equity investments without readily determinable fair values but are now publicly traded and therefore have readily determinable fair values. Generation recorded the fair value of these investments in Other current assets on Exelon's and Generation's Consolidated Balance Sheets based on the quoted market prices of the stocks at December 31, 2020, which resulted in an unrealized gain of $186 million within Other, net in Exelon's and Generation's Consolidated Statement of Operations and Comprehensive Income for the year ended December 31, 2020. (g) Collateral posted/(received) from counterparties, net of collateral paid to counterparties, totaled $(67) million, $321 million, and $162 million allocated to Level 1, Level 2, and Level 3 mark-to-market derivatives, respectively, as of December 31, 2020. Collateral posted/(received) from counterparties, net of collateral paid to counterparties, totaled $163 million, $551 million, and $214 million allocated to Level 1, Level 2, and Level 3 mark-to-market derivatives, respectively, as of December 31, 2019. (h) Of the collateral posted/(received), $209 million and $511 million represents variation margin on the exchanges as of December 31, 2020 and 2019, respectively. As of December 31, 2020, Exelon and Generation have outstanding commitments to invest in private credit, private equity, and real estate investments of approximately $195 million, $254 million, and $369 million, respectively. These commitments will be funded by Generation’s existing NDT funds. Exelon and Generation held investments without readily determinable fair values with carrying amounts of $73 million and $55 million as of December 31, 2020, respectively. Exelon and Generation held investments without readily determinable fair values with carrying amounts of $69 million as of December 31, 2019. Changes in fair value, cumulative adjustments, and impairments were not material for the years ended December 31, 2020 and December 31, 2019. ComEd, PECO, and BGE ComEd PECO BGE As of December 31, 2020 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets Cash equivalents (a) $ 285 $ — $ — $ 285 $ 8 $ — $ — $ 8 $ 120 $ — $ — $ 120 Rabbi trust investments Mutual funds — — — — 9 — — 9 10 — — 10 Life insurance contracts — — — — — 13 — 13 — — — — Rabbi trust investments subtotal — — — — 9 13 — 22 10 — — 10 Total assets 285 — — 285 17 13 — 30 130 — — 130 Liabilities Mark-to-market derivative liabilities (b) — — (301) (301) — — — — — — — — Deferred compensation obligation — (8) — (8) — (9) — (9) — (5) — (5) Total liabilities — (8) (301) (309) — (9) — (9) — (5) — (5) Total net assets (liabilities) $ 285 $ (8) $ (301) $ (24) $ 17 $ 4 $ — $ 21 $ 130 $ (5) $ — $ 125 ComEd PECO BGE As of December 31, 2019 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets Cash equivalents (a) $ 280 $ — $ — $ 280 $ 15 $ — $ — $ 15 $ — $ — $ — $ — Rabbi trust investments Mutual funds — — — — 8 — — 8 8 — — 8 Life insurance contracts — — — — — 11 — 11 — — — — Rabbi trust investments subtotal — — — — 8 11 — 19 8 — — 8 Total assets 280 — — 280 23 11 — 34 8 — — 8 Liabilities Mark-to-market derivative liabilities (b) — — (301) (301) — — — — — — — — Deferred compensation obligation — (8) — (8) — (9) — (9) — (5) — (5) Total liabilities — (8) (301) (309) — (9) — (9) — (5) — (5) Total net assets (liabilities) $ 280 $ (8) $ (301) $ (29) $ 23 $ 2 $ — $ 25 $ 8 $ (5) $ — $ 3 __________ (a) ComEd excludes cash of $83 million and $90 million at December 31, 2020 and 2019, respectively, and restricted cash of $37 million and $33 million at December 31, 2020 and 2019, respectively, and includes long-term restricted cash of $43 million and $163 million at December 31, 2020 and 2019, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. PECO excludes cash of $18 million and $12 million at December 31, 2020 and 2019, respectively. BGE excludes cash of $24 million at both December 31, 2020 and 2019, respectively, and restricted cash of $1 million at both December 31, 2020 and 2019, respectively. (b) The Level 3 balance consists of the current and noncurrent liability of $33 million and $268 million, respectively, at December 31, 2020 and $32 million and $269 million, respectively, at December 31, 2019 related to floating-to-fixed energy swap contracts with unaffiliated suppliers. PHI, Pepco, DPL, and ACE As of December 31, 2020 As of December 31, 2019 PHI Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets Cash equivalents (a) $ 86 $ — $ — $ 86 $ 124 $ — $ — $ 124 Rabbi trust investments Cash equivalents 55 — — 55 44 — — 44 Mutual funds 14 — — 14 14 — — 14 Fixed income — 11 — 11 — 12 — 12 Life insurance contracts — 26 34 60 — 24 41 65 Rabbi trust investments subtotal 69 37 34 140 58 36 41 135 Total assets 155 37 34 226 182 36 41 259 Liabilities Deferred compensation obligation — (17) — (17) — (19) — (19) Total liabilities — (17) — (17) — (19) — (19) Total net assets $ 155 $ 20 $ 34 $ 209 $ 182 $ 17 $ 41 $ 240 Pepco DPL ACE As of December 31, 2020 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets Cash equivalents (a) $ 35 $ — $ — $ 35 $ — $ — $ — $ — $ 13 $ — $ — $ 13 Rabbi trust investments Cash equivalents 53 — — 53 — — — — — — — — Fixed income — 2 — 2 — — — — — — — — Life insurance contracts — 26 34 60 — — — — — — — — Rabbi trust investments subtotal 53 28 34 115 — — — — — — — — Total assets 88 28 34 150 — — — — 13 — — 13 Liabilities Deferred compensation obligation — (2) — (2) — — — — — — — — Total liabilities — (2) — (2) — — — — — — — — Total net assets $ 88 $ 26 $ 34 $ 148 $ — $ — $ — $ — $ 13 $ — $ — $ 13 Pepco DPL ACE As of December 31, 2019 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets Cash equivalents (a) $ 34 $ — $ — $ 34 $ — $ — $ — $ — $ 16 $ — $ — $ 16 Rabbi trust investments Cash equivalents 43 — — 43 — — — — — — — — Fixed income — 2 — 2 — — — — — — — — Life insurance contracts — 24 41 65 — — — — — — — — Rabbi trust investments subtotal 43 26 41 110 — — — — — — — — Total assets 77 26 41 144 — — — — 16 — — 16 Liabilities Deferred compensation obligation — (2) — (2) — — — — — — — — Total liabilities — (2) — (2) — — — — — — — — Total net assets $ 77 $ 24 $ 41 $ 142 $ — $ — $ — $ — $ 16 $ — $ — $ 16 __________ (a) PHI excludes cash of $74 million and $57 million at December 31, 2020 and 2019, respectively, and includes long-term restricted cash of $10 million and $14 million at December 31, 2020 and 2019, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. Pepco excludes cash of $30 million and $29 million at December 31, 2020 and 2019, respectively. DPL excludes cash of $15 million and $13 million at December 31, 2020 and 2019, respectively. ACE excludes cash of $17 million and $12 million at December 31, 2020 and 2019, respectively, and includes long-term restricted cash of $10 million and $14 million at December 31, 2020 and 2019, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets.
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, 2020 and 2019: Exelon Generation ComEd PHI and Pepco For the year ended December 31, 2020 Total NDT Fund Investments Mark-to-Market Total Generation Mark-to-Market Life Insurance Contracts Eliminated in Consolidation Balance as of January 1, 2020 $ 1,068 $ 511 $ 817 $ 1,328 $ (301) $ 41 $ — Total realized / unrealized gains (losses) Included in net income (409) 2 (414) (a) (412) — 3 — Included in noncurrent payables to affiliates — 21 — 21 — — (21) Included in regulatory assets/liabilities 21 — — — — (b) — 21 Change in collateral (53) — (53) (53) — — — Purchases, sales, issuances and settlements Purchases 151 8 143 151 — — — Sales (27) — (27) (27) — — — Settlements (55) (45) — (45) — (10) — Transfers into Level 3 (12) — (12) (c) (12) — — — Transfers out of Level 3 (24) — (24) (c) (24) — — — Balance as of December 31, 2020 $ 660 $ 497 $ 430 $ 927 $ (301) $ 34 $ — The amount of total gains included in net income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of December 31, 2020 $ 11 $ 2 $ 6 $ 8 $ — $ 3 $ — Exelon Generation ComEd PHI and Pepco For the year ended December 31, 2019 Total NDT Fund Investments Mark-to-Market Total Generation Mark-to-Market Life Insurance Contracts Eliminated in Consolidation Balance as of January 1, 2019 $ 907 $ 543 $ 575 $ 1,118 $ (249) $ 38 $ — Total realized / unrealized gains (losses) Included in net income (23) 5 (31) (a) (26) — 3 — Included in noncurrent payables to affiliates — 34 — 34 — — (34) Included in regulatory assets/liabilities (18) — — — (52) (b) — 34 Change in collateral 138 — 138 138 — — — Purchases, sales, issuances and settlements Purchases 176 44 132 176 — — — Sales (23) (21) (2) (23) — — — Settlements (89) (94) 5 (89) — — — Transfers into Level 3 5 — 5 (c) 5 — — — Transfers out of Level 3 (5) — (5) (c) (5) — — — Balance as of December 31, 2019 $ 1,068 $ 511 $ 817 $ 1,328 $ (301) $ 41 $ — The amount of total gains included in net income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of December 31, 2019 $ 359 $ 5 $ 351 $ 356 $ — $ 3 $ — __________ (a) Includes a reduction for the reclassification of $420 million and $377 million of realized gains due to the settlement of derivative contracts for the years ended December 31, 2020 and 2019, respectively. (b) Includes $33 million of decreases in fair value and an increase for realized losses due to settlements of $33 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2020. Includes $78 million of decreases in fair value and an increase for realized losses due to settlements of $26 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2019. (c) Transfers into and out of Level 3 generally occur when the contract tenor becomes less and more observable, respectively, primarily due to changes in market liquidity or assumptions for certain commodity contracts.
Total Realized and Unrealized Gains (Losses) Included in Income for Level 3 Assets and Liabilities Measured at Fair Value on a Recurring Basis	The following tables present the income statement classification of the total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2020 and 2019: Exelon Generation PHI and Pepco Operating Purchased Operating and Maintenance Other, net Operating Purchased Other, net Operating and Total (losses) gains included in net income for the year ended December 31, 2020 $ (404) $ (10) $ 3 $ 2 $ (404) $ (10) $ 2 $ 3 Change in unrealized (losses) gains relating to assets and liabilities held for the year ended December 31, 2020 (31) 37 3 2 (31) 37 2 3 Exelon Generation PHI and Pepco Operating Purchased Operating and Maintenance Other, net Operating Purchased Other, net Operating and Total gains (losses) included in net income for the year ended December 31, 2019 $ 219 $ (245) $ 3 $ 5 $ 219 $ (245) $ 5 $ 3 Change in unrealized gains (losses) relating to assets and liabilities held for the year ended December 31, 2019 546 (195) 3 5 546 (195) 5 3
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 at December 31, 2020 Fair Value at December 31, 2019 Valuation Unobservable 2020 Range & Arithmetic Average 2019 Range & Arithmetic Average Mark-to-market derivatives—Economic hedges (Exelon and Generation) (a)(b) $ 245 $ 558 Discounted Cash Flow Forward power $2.25 - $163 $30 $9 - $180 $29 Forward gas $1.57 - $7.88 $2.59 $0.83 - $10.72 $2.55 Option Volatility 11% - 237% 32% 8% - 236% 70% Mark-to-market derivatives—Proprietary trading (Exelon and Generation) (a)(b) $ 23 $ 45 Discounted Cash Flow Forward power $10 - $106 $27 $25 - $180 $33 Mark-to-market derivatives (Exelon and ComEd) $ (301) $ (301) Discounted Cash Flow Forward heat rate (c) 8x - 9x 8.85x 9x - 10x 9.68x Marketability 3% - 8% 4.93% 3% - 7% 4.95% Renewable 91% - 123% 99% 91% - 123% 99% __________ (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 on level three positions of $162 million and $214 million as of December 31, 2020 and December 31, 2019, respectively. (c) Quoted forward natural gas rates are utilized to project the forward power curve for the delivery of energy at specified future dates. The natural gas curve is extrapolated beyond its observable period to the end of the contract’s delivery.

Commitments and Contingencies_2

Commitments and Contingencies (Tables)	12 Months Ended
Commitments and Contingencies (Tables)	Dec. 31, 2020
Environmental Loss Contingency Tables [Abstract]
PHI Merger Commitments [Table Text Block]	The following amounts represent total commitment costs that have been recorded since the acquisition date and the total remaining obligations for Exelon, PHI, Pepco, DPL, and ACE as of December 31, 2020: Description Exelon PHI Pepco DPL ACE Total commitments $ 513 $ 320 $ 120 $ 89 $ 111 Remaining commitments (a) 82 67 55 7 5 __________ (a) Remaining commitments extend through 2026 and include rate credits, energy efficiency programs, and delivery system modernization.
Other Commitments [Table Text Block]	The Registrants' commercial commitments as of December 31, 2020, representing commitments potentially triggered by future events, were as follows: Expiration within Exelon Total 2021 2022 2023 2024 2025 2026 and beyond Letters of credit $ 1,243 $ 1,179 $ 50 $ 14 $ — $ — $ — Surety bonds (a) 1,070 1,017 53 — — — — Financing trust guarantees 378 — — — — — 378 Guaranteed lease residual values (b) 28 2 3 3 6 5 9 Total commercial commitments $ 2,719 $ 2,198 $ 106 $ 17 $ 6 $ 5 $ 387 Generation Letters of credit $ 1,228 $ 1,164 $ 50 $ 14 $ — $ — $ — Surety bonds (a) 926 873 53 — — — — Total commercial commitments $ 2,154 $ 2,037 $ 103 $ 14 $ — $ — $ — ComEd Letters of credit $ 7 $ 7 $ — $ — $ — $ — $ — Surety bonds (a) 16 16 — — — — — Financing trust guarantees 200 — — — — — 200 Total commercial commitments $ 223 $ 23 $ — $ — $ — $ — $ 200 PECO Surety bonds (a) $ 2 $ 2 $ — $ — $ — $ — $ — Financing trust guarantees 178 — — — — — 178 Total commercial commitments $ 180 $ 2 $ — $ — $ — $ — $ 178 BGE Letters of credit $ 2 $ 2 $ — $ — $ — $ — $ — Surety bonds (a) 3 3 — — — — — Total commercial commitments $ 5 $ 5 $ — $ — $ — $ — $ — PHI Surety bonds (a) $ 22 $ 22 $ — $ — $ — $ — $ — Guaranteed lease residual values (b) 28 2 3 3 6 5 9 Total commercial commitments $ 50 $ 24 $ 3 $ 3 $ 6 $ 5 $ 9 Pepco Surety bonds (a) $ 14 $ 14 $ — $ — $ — $ — $ — Guaranteed lease residual values (b) 9 — 1 1 2 2 3 Total commercial commitments $ 23 $ 14 $ 1 $ 1 $ 2 $ 2 $ 3 DPL Surety bonds (a) $ 4 $ 4 $ — $ — $ — $ — $ — Guaranteed lease residual values (b) 12 1 1 1 3 2 4 Total commercial commitments $ 16 $ 5 $ 1 $ 1 $ 3 $ 2 $ 4 ACE Surety bonds (a) $ 4 $ 4 $ — $ — $ — $ — $ — Guaranteed lease residual values (b) 7 1 1 1 1 1 2 Total commercial commitments $ 11 $ 5 $ 1 $ 1 $ 1 $ 1 $ 2 __________ (a) Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds. (b) Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The lease term associated with these assets ranges from 1 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $71 million guaranteed by Exelon and PHI, of which $24 million , $30 million, and $17 million is guaranteed by Pepco, DPL, and ACE, respectively. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.
Schedule of Government Settlement Agreements [Table Text Block]	As of December 31, 2020 and 2019, 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, 2020 December 31, 2019 DOE receivable - current (a) $ 129 $ 249 DOE receivable - noncurrent (b) 70 30 Amounts owed to co-owners (c) (23) (37) __________ (a) Recorded in Accounts receivable, other. (b) Recorded in Deferred debits and other assets, other. (c) Recorde d in Accounts receivable, other. Represents amounts owed to the co-owners of Peach Bottom, Quad Cities, and Nine Mile Point Unit 2 generating facilitie
Spent Nuclear Fuel Obligation [Table Text Block]	The below table outlines the SNF liability recorded at Exelon and Generation as of December 31, 2020 and 2019: December 31, 2020 December 31, 2019 Former ComEd units (a) $ 1,082 $ 1,075 Fitzpatrick (b) 126 124 Total SNF Obligation $ 1,208 $ 1,199 __________ (a) ComEd previously elected to defer payment of the one-time fee of $277 million for its units (which are now part of Generation), 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 Generation 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, Generation 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 .
Accrued environmental liabilities	As of December 31, 2020 and 2019, the Registrants had accrued the following undiscounted amounts for environmental liabilities in Other current liabilities and Other deferred credits and other liabilities within their respective Consolidated Balance Sheets: December 31, 2020 December 31, 2019 Total environmental Portion of total related to Total environmental Portion of total related to Exelon $ 483 $ 314 $ 478 $ 320 Generation 121 — 105 — ComEd 293 293 304 303 PECO 23 21 19 17 BGE 2 — 2 — PHI 44 — 48 — Pepco 42 — 46 — DPL 1 — 1 — ACE 1 — 1 —

Severance (Tables)

Severance (Tables)	12 Months Ended
Severance (Tables)	Dec. 31, 2020
Restructuring and Related Activities [Abstract]
Severance	As a result of the decision to early retire Byron and Dresden, Exelon and Generation recognized certain one-time charges for the year ended December 31, 2020 related to materials and supplies inventory reserve adjustments, employee-related costs, including severance benefit costs further discussed below, and construction work-in-progress impairments, among other items. In addition, as a result of the decisions to early retire Byron and Dresden, there are ongoing annual financial impacts stemming from shortening the expected economic useful lives of these nuclear plants primarily related to accelerated depreciation of plant assets (including any ARC), accelerated amortization of nuclear fuel, and changes in ARO accretion expense associated with the changes in decommissioning timing and cost assumptions to reflect an earlier retirement date. See Note 10 — Asset Retirement Obligations for additional information on changes to the nuclear decommissioning ARO balance and Note 12 — Asset Impairments for impairment assessment considerations given to the Midwest asset group as a result of the early retirement decision. The total impact on Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income is summarized in the table below. Income statement expense (pre-tax) 2020 (a) 2019 (b) 2018 (c) Depreciation and amortization Accelerated depreciation (d) $ 895 $ 216 $ 539 Accelerated nuclear fuel amortization 60 13 57 Operating and maintenance One-time charges 255 — 32 Other charges (e) 34 (53) — Contractual offset (f) (364) — — Total $ 880 $ 176 $ 628 _________ (a) Reflects expense for Byron and Dresden. (b) Reflects expense for TMI. (c) Reflects expense for TMI and Oyster Creek. (d) Includes the accelerated depreciation of plant assets including any ARC. (e) For Dresden, reflects the net impacts associated with the remeasurement of the ARO. For TMI, primarily reflects the net impacts associated with the remeasurement of the ARO. See Note 10 - Asset Retirement Obligations for additional information. (f) Reflects contractual offset for ARO accretion, ARC depreciation, and net impacts associated with the remeasurement of the ARO. For Byron and Dresden, based on the regulatory agreement with the ICC, decommissioning-related activities in 2020 have been offset within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. The offset in 2020 resulted in an equal adjustment to the noncurrent payables to ComEd at Generation and an adjustment to the regulatory liabilities at ComEd. See Note 10 - Asset Retirement Obligations for additional information.

Shareholders' Equity (Tables)

Shareholders' Equity (Tables)	12 Months Ended
Shareholders' Equity (Tables)	Dec. 31, 2020
Shareholder [Abstract]
Common Stock Warrants [Table Text Block]	The following table presents warrants outstanding to purchase ComEd common stock and shares of common stock reserved for the conversion of warrants. The warrants entitle the holders to convert such warrants into common stock of ComEd at a conversion rate of one share of common stock for three warrants. December 31, 2020 2019 Warrants outstanding 60,143 60,228 Common Stock reserved for conversion 20,048 20,076
Preferred Stock [Table Text Block]	The following table presents Exelon, ComEd, PECO, BGE, Pepco, and ACE's shares of preferred securities authorized, none of which were outstanding as of December 31, 2020 and 2019. There are no shares of preferred securities authorized for DPL. Preferred Securities Authorized Exelon 100,000,000 ComEd 850,000 PECO 15,000,000 BGE 1,000,000 Pepco 6,000,000 ACE (a) 2,799,979 __________
Preference Securities [Table Text Block]	The following table presents ComEd's, BGE's, and ACE's preference securities authorized, none of which were outstanding as of December 31, 2020 and 2019. There are no shares of preference securities authorized for Exelon, PECO, Pepco, and DPL. Preference Securities Authorized ComEd 6,810,451 BGE (a) 6,500,000 ACE 3,000,000 __________

Stock-Based Compensation Plan_2

Stock-Based Compensation Plans Stock-Based Compensation Plans (Tables)	12 Months Ended
	Dec. 31, 2020
Common Stock [Abstract]
Share-based Payment Arrangement, Cost by Plan [Table Text Block]	The following table presents the stock-based compensation expense included in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. The Utility Registrants' stock-based compensation expense for the years ended December 31, 2020, 2019, and 2018 was not material. Year Ended December 31, Exelon 2020 2019 2018 Total stock-based compensation expense included in operating and maintenance expense $ 64 $ 77 $ 208 Income tax benefit (16) (20) (54) Total after-tax stock-based compensation expense $ 48 $ 57 $ 154 Generation Total stock-based compensation expense included in operating and maintenance expense $ 27 $ 37 $ 77 Income tax benefit (7) (10) (20) Total after-tax stock-based compensation expense $ 20 $ 27 $ 57
Stock Based Compensation Tax Benefit	The following table presents information regarding Exelon’s realized tax benefit when distributed: Year Ended December 31, 2020 2019 2018 Performance share awards $ 21 $ 41 $ 16 Restricted stock units 15 24 28
Schedule of Nonvested Performance-based Units Activity	The following table summarizes Exelon’s nonvested performance share awards activity: Shares Weighted Average Nonvested at December 31, 2019 (a) 1,709,755 $ 39.21 Granted 1,122,378 46.61 Change in performance (751,309) 42.51 Vested (747,551) 35.70 Forfeited (67,964) 45.59 Undistributed vested awards (b) (334,917) 50.76 Nonvested at December 31, 2020 (a) 930,392 $ 43.67 __________ (a) Excludes 1,414,661 and 2,017,870 of performance share awards issued to retirement-eligible employees as of December 31, 2020 and 2019, respectively, as they are fully vested. (b) Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2020. The following table summarizes the weighted average grant date fair value and the total fair value of performance share awards vested. Year Ended December 31, 2020 (a) 2019 2018 Weighted average grant date fair value (per share) $ 46.61 $ 47.37 $ 38.15 Total fair value of performance shares vested 39 158 61 Total fair value of performance shares settled in cash 63 131 49 __________ (a) As of December 31, 2020, $13 million of total unrecognized compensation costs related to nonvested performance shares are expected to be recognized over the remaining weighted-average period of 1.8 years.
Schedule of Nonvested Restricted Stock Units Activity	The following table summarizes Exelon’s nonvested restricted stock unit activity: Shares Weighted Average Nonvested at December 31, 2019 (a) 1,498,713 $ 40.35 Granted 847,382 46.33 Vested (725,151) 38.38 Forfeited (52,046) 45.20 Undistributed vested awards (b) (454,768) 45.91 Nonvested at December 31, 2020 (a) 1,114,130 $ 43.67 __________ (a) Excludes 748,165 and 863,196 of restricted stock units issued to retirement-eligible employees as of December 31, 2020 and 2019, respectively, as they are fully vested. (b) Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2020. The following table summarizes the weighted average grant date fair value and the total fair value of restricted stock units vested. Year Ended December 31, 2020 (a) 2019 2018 Weighted average grant date fair value (per share) $ 46.33 $ 45.65 $ 38.60 Total fair value of restricted stock units vested 54 92 106 __________ (a) As of December 31, 2020, $23 million of total unrecognized compensation costs related to nonvested restricted stock units are expected to be recognized over the remaining weighted-average period of 2.3 years.
Schedule of Share-based Compensation, Stock Options, Activity	The following table presents information with respect to stock option activity: Shares Weighted Weighted Aggregate Balance of shares outstanding at December 31, 2019 1,889,045 $ 40.43 1.56 $ 10 Options exercised (475,827) 38.30 5 Options expired (147,808) 46.07 Balance of shares outstanding at December 31, 2020 1,265,410 $ 40.57 0.91 $ 3 Exercisable at December 31, 2020 (a) 1,265,410 $ 40.57 0.91 $ 3 __________ (a) Includes stock options issued to retirement eligible employees.
Stock Options Exercised	The following table summarizes additional information regarding stock options exercised: Year Ended December 31, 2020 2019 2018 Intrinsic value (a) $ 5 $ 9 $ 12 Cash received for exercise price 18 59 56 __________ (a) The difference between the market value on the date of exercise and the option exercise price.

Changes in Accumulated Other _2

Changes in Accumulated Other Comprehensive Income (Tables)	12 Months Ended
Changes in Accumulated Other Comprehensive Income (Tables)	Dec. 31, 2020
Equity [Abstract]
Schedule Of Changes In Accumulated Other Comprehensive Income (Loss)	The following tables present changes in Exelon's AOCI, net of tax, by component: Gains and Unrealized Pension and (a) Foreign AOCI of Investments (b) Total Balance at December 31, 2017 $ (14) $ 10 $ (2,998) $ (23) $ (1) $ (3,026) OCI before reclassifications 11 — (143) (10) 1 (141) Amounts reclassified from AOCI 1 — 181 — — 182 Net current-period OCI 12 — 38 (10) 1 41 Impact of adoption of Recognition and Measurement of Financial Assets and Financial Liabilities standard (c) — (10) — — — (10) Balance at December 31, 2018 $ (2) $ — $ (2,960) $ (33) $ — $ (2,995) OCI before reclassifications — — (289) 6 (2) (285) Amounts reclassified from AOCI — — 84 — 2 86 Net current-period OCI — — (205) 6 — (199) Balance at December 31, 2019 $ (2) $ — $ (3,165) $ (27) $ — $ (3,194) OCI before reclassifications (3) — (357) 4 — (356) Amounts reclassified from AOCI — — 150 — — 150 Net current-period OCI (3) — (207) 4 — (206) Balance at December 31, 2020 $ (5) $ — $ (3,372) $ (23) $ — $ (3,400) __________ (a) This AOCI component is included in the computation of net periodic pension and OPEB cost. See Note 15 — Retirement Benefits for additional information. See Exelon's Statements of Operations and Comprehensive Income for individual components of AOCI. (b) All amounts are net of noncontrolling interests. (c) Exelon adopted the new standard Recognition and Measurement of Financial Assets and Financial Liabilities. The standard was adopted as of January 1, 2018, which resulted in an increase to Retained earnings and Accumulated other comprehensive loss of $10 million for Exelon. The amounts reclassified related to Rabbi Trusts.
Schedule of Income Taxes Allocated to Other Comprehensive Income (Loss) Components	The following table presents income tax benefit (expense) allocated to each component of Exelon's other comprehensive income (loss): For the Year Ended December 31, 2020 2019 2018 Pension and non-pension postretirement benefit plans: Prior service benefit reclassified to periodic benefit cost $ 16 $ 23 $ 24 Actuarial loss reclassified to periodic benefit cost (66) (52) (86) Pension and non-pension postretirement benefit plans valuation adjustment 122 100 50

Variable Interest Entities (Tab

Variable Interest Entities (Tables)	12 Months Ended
Variable Interest Entities (Tables)	Dec. 31, 2020
Variable Interest Entity [Abstract]
Consolidated VIEs- Assets and Liabilities	The table below shows the carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in the consolidated financial statements of Exelon, Generation, PHI, and ACE as of December 31, 2020 and 2019. 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 the general credit of Exelon, Generation, PHI, and ACE. December 31, 2020 December 31, 2019 Exelon Generation PHI (a) ACE Exelon Generation PHI (a) ACE Cash and cash equivalents $ 98 $ 98 $ — $ — $ 163 $ 163 $ — $ — Restricted cash and cash equivalents 47 44 3 3 88 85 3 3 Accounts receivable Customer 148 148 — — 151 151 — — Other 36 36 — — 39 39 — — Unamortized energy contract assets 22 22 — — 23 23 — — Inventories, net Materials and supplies 244 244 — — 227 227 — — Assets held for sale (b) 101 101 — — — — — — Other current assets 674 669 5 — 32 31 1 — Total current assets 1,370 1,362 8 3 723 719 4 3 Property, plant and equipment, net 5,803 5,803 — — 6,022 6,022 — — Nuclear decommissioning trust funds 3,007 3,007 — — 2,741 2,741 — — Unamortized energy contract assets 249 249 — — 250 250 — — Other noncurrent assets 52 42 10 10 89 73 16 14 Total noncurrent assets 9,111 9,101 10 10 9,102 9,086 16 14 Total assets (c) $ 10,481 $ 10,463 $ 18 $ 13 $ 9,825 $ 9,805 $ 20 $ 17 Long-term debt due within one year $ 94 $ 68 $ 26 $ 21 $ 544 $ 523 $ 21 $ 20 Accounts payable 81 81 — — 106 106 — — Accrued expenses 70 70 — — 70 70 — — Unamortized energy contract liabilities 4 4 — — 8 8 — — Liabilities held for sale (b) 16 16 — — — — — — Other current liabilities 5 5 — — 3 3 — — Total current liabilities 270 244 26 21 731 710 21 20 Long-term debt 889 889 — — 527 504 23 21 Asset retirement obligations 2,318 2,318 — — 2,128 2,128 — — Unamortized energy contract liabilities — — — — 1 1 — — Other noncurrent liabilities 129 129 — — 89 89 — — Total noncurrent liabilities 3,336 3,336 — — 2,745 2,722 23 21 Total liabilities (d) $ 3,606 $ 3,580 $ 26 $ 21 $ 3,476 $ 3,432 $ 44 $ 41 __________ (a) Includes certain purchase accounting adjustments from the PHI merger not pushed down to ACE. (b) Generation entered into an agreement for the sale of a significant portion of Generation's solar business. As a result of this transaction, in the fourth quarter of 2020, Exelon and Generation reclassified the consolidated VIEs' solar assets and liabilities as held for sale. Refer to Note 2 — Mergers, Acquisitions, and Dispositions for additional information on the sale of the solar business. (c) Exelon's and Generation's balances include unrestricted assets for current unamortized energy contract assets of $22 million and $23 million, Property, plant, and equipment of $1 million and $20 million, non-current unamortized energy contract assets of $249 million and $250 million, and Assets held for sale of $9 million and $0 million as of December 31, 2020 and 2019, respectively. (d) Exelon's and Generation's balances include liabilities with recourse of $8 million and $3 million as of December 31, 2020 and 2019, respectively.
Schedule of Variable Interest Entities	The following table presents summary information about Exelon's and Generation’s significant unconsolidated VIE entities: December 31, 2020 December 31, 2019 Commercial Agreement VIEs Equity Investment VIEs Total Commercial Equity Total Total assets (a) $ 777 $ 401 $ 1,178 $ 636 $ 443 $ 1,079 Total liabilities (a) 61 223 284 33 227 260 Exelon's ownership interest in VIE (a) — 157 157 — 191 191 Other ownership interests in VIE (a) 716 21 737 604 25 629 __________ (a) These items represent amounts on the unconsolidated VIE balance sheets, not in Exelon’s or Generation’s Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs. Exelon and Generation do not have any exposure to loss as they do not have a carrying amount in the equity investment VIEs as o f December 31, 2020 and 2019.

Supplemental Financial Inform_2

Supplemental Financial Information (Tables)	12 Months Ended
Supplemental Financial Information (Tables)	Dec. 31, 2020
Supplemental Financial Information [Abstract]
Schedule Of Taxes Excluding Income And Excise Taxes [Table Text Block]	The following tables provide additional information about material items recorded in the Registrants' Consolidated Statements of Operations and Comprehensive Income. Taxes other than income taxes Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE For the year ended December 31, 2020 Utility (a) $ 859 $ 99 $ 238 $ 135 $ 87 $ 299 $ 275 $ 21 $ 3 Property 602 265 30 16 164 126 84 39 3 Payroll 235 113 27 16 17 25 7 5 3 For the year ended December 31, 2019 Utility (a) $ 881 $ 112 $ 242 $ 132 $ 90 $ 304 $ 286 $ 18 $ — Property 595 274 29 17 153 122 85 34 2 Payroll 232 115 27 15 17 24 7 4 2 For the year ended December 31, 2018 Utility (a) $ 919 $ 114 $ 243 $ 131 $ 94 $ 337 $ 316 $ 21 $ — Property 557 273 30 15 143 94 58 32 3 Payroll 247 130 27 16 17 24 5 3 2 __________ (a) Generation’s utility tax represents gross receipts tax related to its retail operations, and the Utility Registrants’ utility taxes represents municipal and state utility taxes and gross receipts taxes related to their operating revenues. The offsetting collection of utility taxes from customers is recorded in revenues in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
Schedule of Other Nonoperating Income, by Component [Table Text Block]	Other, Net Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE For the year ended December 31, 2020 Decommissioning-related activities: Net realized income on NDT funds (a) Regulatory Agreement Units $ 185 $ 185 $ — $ — $ — $ — $ — $ — $ — Non-regulatory Agreement Units 160 160 — — — — — — — Net unrealized gains on NDT funds Regulatory Agreement Units 724 724 — — — — — — — Non-regulatory Agreement Units 391 391 — — — — — — — Regulatory offset to NDT fund-related activities (b) (729) (729) — — — — — — — Decommissioning-related activities 731 731 — — — — — — — AFUDC—Equity 104 — 29 17 22 36 28 4 4 Non-service net periodic benefit cost 53 — — — — — — — — Unrealized gains from equity investments (c) 186 186 — — — — — — — For the year ended December 31, 2019 Decommissioning-related activities: Net realized income on NDT funds (a) Regulatory Agreement Units $ 297 $ 297 $ — $ — $ — $ — $ — $ — $ — Non-regulatory Agreement Units 363 363 — — — — — — — Net unrealized gains on NDT funds Regulatory Agreement Units 795 795 — — — — — — — Non-regulatory Agreement Units 411 411 — — — — — — — Regulatory offset to NDT fund-related activities (b) (876) (876) — — — — — — — Decommissioning-related activities 990 990 — — — — — — — AFUDC—Equity 85 — 17 13 21 34 25 4 5 Non-service net periodic benefit cost 13 — — — — — — — — For the year ended December 31, 2018 Decommissioning-related activities: Net realized income on NDT funds (a) Regulatory Agreement Units $ 506 $ 506 $ — $ — $ — $ — $ — $ — $ — Non-regulatory Agreement Units 302 302 — — — — — — — Net unrealized losses on NDT funds Regulatory Agreement Units (715) (715) — — — — — — — Non-regulatory Agreement Units (483) (483) — — — — — — — Regulatory offset to NDT fund-related activities (b) 171 171 — — — — — — — Decommissioning-related activities (219) (219) — — — — — — — AFUDC—Equity 69 — 19 7 18 25 22 2 1 Non-service net periodic benefit cost (47) — — — — — — — — __________ (a) Realized income includes interest, dividends, and realized gains and losses on sales of NDT fund investments. (b) Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units, including the elimination of income taxes related to all NDT fund activity for those units. See Note 10 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning. (c) Unrealized gains resulting from equity investments without readily determinable fair values that became publicly traded entities in the fourth quarter of 2020 and were fair valued based on quoted market prices of the stocks as of December 31, 2020.
Cash Flow Supplemental Disclosures	The following tables provide additional information about material items recorded in the Registrants' Consolidated Statements of Cash Flows. Depreciation, amortization, and accretion Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE For the year ended December 31, 2020 Property, plant, and equipment (a) $ 4,364 $ 2,070 $ 922 $ 319 $ 397 $ 586 $ 257 $ 155 $ 140 Amortization of regulatory assets (a) 588 — 211 28 153 196 120 36 40 Amortization of intangible assets, net (a) 62 53 — — — — — — — Amortization of energy contract assets and liabilities (b) 30 30 — — — — — — — Nuclear fuel (c) 983 983 — — — — — — — ARO accretion (d) 500 500 — — — — — — — Total depreciation, amortization, and accretion $ 6,527 $ 3,636 $ 1,133 $ 347 $ 550 $ 782 $ 377 $ 191 $ 180 For the year ended December 31, 2019 Property, plant, and equipment (a) $ 3,665 $ 1,485 $ 886 $ 303 $ 359 $ 547 $ 239 $ 146 $ 123 Amortization of regulatory assets (a) 528 — 147 30 143 207 135 38 34 Amortization of intangible assets, net (a) 59 50 — — — — — — — Amortization of energy contract assets and liabilities (b) 21 21 — — — — — — — Nuclear fuel (c) 1,016 1,016 — — — — — — — ARO accretion (d) 491 491 — — — — — — — Total depreciation, amortization, and accretion $ 5,780 $ 3,063 $ 1,033 $ 333 $ 502 $ 754 $ 374 $ 184 $ 157 For the year ended December 31, 2018 Property, plant, and equipment (a) $ 3,740 $ 1,748 $ 820 $ 274 $ 335 $ 480 $ 218 $ 131 $ 94 Amortization of regulatory assets (a) 555 — 120 27 148 260 167 51 42 Amortization of intangible assets, net (a) 58 49 — — — — — — — Amortization of energy contract assets and liabilities (b) 14 14 — — — — — — — Nuclear fuel (c) 1,115 1,115 — — — — — — — ARO accretion (d) 489 489 — — — — — — — Total depreciation, amortization, and accretion $ 5,971 $ 3,415 $ 940 $ 301 $ 483 $ 740 $ 385 $ 182 $ 136 __________ (a) Included in Depreciation and amortization in the Registrants' Consolidated Statements of Operations and Comprehensive Income. (b) Included in Operating revenues or Purchased power and fuel expense in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. (c) Included in Purchased power and fuel expense in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. (d) Included in Operating and maintenance expense in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. Cash paid (refunded) during the year: Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE For the year ended December 31, 2020 Interest (net of amount capitalized) $ 1,521 $ 331 $ 371 $ 144 $ 125 $ 257 $ 129 $ 61 $ 57 Income taxes (net of refunds) 10 70 (61) (37) (57) 46 40 12 (3) For the year ended December 31, 2019 Interest (net of amount capitalized) $ 1,470 $ 373 $ 343 $ 129 $ 106 $ 255 $ 130 $ 59 $ 55 Income taxes (net of refunds) 265 (44) (42) 82 17 29 7 19 (5) For the year ended December 31, 2018 Interest (net of amount capitalized) $ 1,421 $ 369 $ 332 $ 125 $ 94 $ 250 $ 123 $ 56 $ 61 Income taxes (net of refunds) 95 746 (153) (2) 14 (32) 41 (6) (12) Other non-cash operating activities: Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE For the year ended December 31, 2020 Pension and non-pension postretirement benefit costs $ 411 $ 115 $ 114 $ 5 $ 62 $ 70 $ 15 $ 7 $ 14 Allowance for credit losses 150 17 32 42 15 43 24 16 2 Other decommissioning-related activity (a) (659) (659) — — — — — — — Energy-related options (b) 104 104 — — — — — — — True-up adjustments to decoupling mechanisms and formula rates (c) (6) — 47 (16) (16) (21) (40) 7 12 Severance costs 105 90 1 1 — — — — — Provision for excess and obsolete inventory 131 128 2 1 — — — — — Long-term incentive plan 56 — — — — — — — — Amortization of operating ROU asset 222 155 2 1 31 28 7 8 3 Asset impairments — — 15 — — 13 — 7 6 AFUDC - Equity (104) — (29) (17) (22) (36) (28) (4) (4) For the year ended December 31, 2019 Pension and non-pension postretirement benefit costs $ 438 $ 135 $ 96 $ 12 $ 61 $ 95 $ 25 $ 15 $ 16 Allowance for credit losses 120 31 33 31 8 17 7 4 5 Other decommissioning-related activity (a) (506) (506) — — — — — — — Energy-related options (b) 22 22 — — — — — — — True-up adjustments to decoupling mechanisms and formula rates (d) 124 — 128 — — (4) (4) — — Long-term incentive plan 10 — — — — — — — — Amortization of operating ROU asset 244 172 3 — 30 33 8 8 4 Change in environmental liabilities 23 — — — — 23 23 — — AFUDC - Equity (85) — (17) (13) (21) (34) (25) (4) (5) For the year ended December 31, 2018 Pension and non-pension postretirement benefit costs $ 583 $ 204 $ 177 $ 18 $ 59 $ 67 $ 15 $ 6 $ 12 Allowance for credit losses 159 48 40 33 10 28 11 6 11 Other decommissioning-related activity (a) (2) (2) — — — — — — — Energy-related options (b) 10 10 — — — — — — — True-up adjustments to decoupling mechanisms and formula rates (d) 49 — 28 — — 21 21 — — Asset retirement costs 20 — — — — 20 22 (1) (1) Long-term incentive plan 140 — — — — — — — — AFUDC - Equity (69) — (19) (7) (18) (25) (22) (2) (1) __________ (a) Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units, including the elimination of operating revenues, ARO updates and accretion, ARC amortization, investment income, and income taxes related to all NDT fund activity for these units. See Note 10 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning. (b) Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations. (c) For ComEd, reflects the true-up adjustments in regulatory assets and liabilities associated with its distribution, energy efficiency, distributed generation, and transmission formula rates. For BGE, Pepco, and DPL, reflects the change in regulatory assets and liabilities associated with their decoupling mechanisms and transmission formula rates. For PECO and ACE, reflects the change in regulatory assets and liabilities associated with their transmission formula rates. See Note 3 — Regulatory Matters for additional information. (d) For ComEd, reflects the true-up adjustments in regulatory assets and liabilities associated with its distribution and energy efficiency formula rates. For Pepco and DPL, reflects the change in regulatory assets and liabilities associated with their decoupling mechanisms. See Note 3 — Regulatory Matters for additional information. The following tables provide a reconciliation of cash, restricted cash, and cash equivalents reported within the Registrants' Consolidated Balance Sheets that sum to the total of the same amounts in their Consolidated Statements of Cash Flows. Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE December 31, 2020 Cash and cash equivalents $ 663 $ 226 $ 83 $ 19 $ 144 $ 111 $ 30 $ 15 $ 17 Restricted cash and cash equivalents 438 89 279 7 1 39 35 — 3 Restricted cash included in other long-term assets 53 — 43 — — 10 — — 10 Cash, restricted cash, and cash equivalents - Held for Sale 12 12 — — — — — — — Total cash, restricted cash, and cash equivalents $ 1,166 $ 327 $ 405 $ 26 $ 145 $ 160 $ 65 $ 15 $ 30 December 31, 2019 Cash and cash equivalents $ 587 $ 303 $ 90 $ 21 $ 24 $ 131 $ 30 $ 13 $ 12 Restricted cash and cash equivalents 358 146 150 6 1 36 33 — 2 Restricted cash included in other long-term assets 177 — 163 — — 14 — — 14 Total cash, restricted cash, and cash equivalents $ 1,122 $ 449 $ 403 $ 27 $ 25 $ 181 $ 63 $ 13 $ 28 December 31, 2018 Cash and cash equivalents $ 1,349 $ 750 $ 135 $ 130 $ 7 $ 124 $ 16 $ 23 $ 7 Restricted cash and cash equivalents 247 153 29 5 6 43 37 1 4 Restricted cash included in other long-term assets 185 — 166 — — 19 — — 19 Total cash, restricted cash, and cash equivalents $ 1,781 $ 903 $ 330 $ 135 $ 13 $ 186 $ 53 $ 24 $ 30 December 31, 2017 Cash and cash equivalents $ 898 $ 416 $ 76 $ 271 $ 17 $ 30 $ 5 $ 2 $ 2 Restricted cash and cash equivalents 207 138 5 4 1 42 35 — 6 Restricted cash included in other long-term assets 85 — 63 — — 23 — — 23 Total cash, restricted cash, and cash equivalents $ 1,190 $ 554 $ 144 $ 275 $ 18 $ 95 $ 40 $ 2 $ 31
Supplemental Balance Sheet Disclosures [Text Block]	The following tables provide additional information about material items recorded in the Registrants' Consolidated Balance Sheets. Investments Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE December 31, 2020 Equity method investments: Other equity method investments $ 81 $ 65 $ 6 $ 8 $ — $ — $ — $ — $ — Other investments: Employee benefit trusts and investments (a) 283 61 — 22 10 140 115 — — Equity investments without readily determinable fair values 73 55 — — — — — — — Other available for sale debt security investments 3 3 — — — — — — — Total investments $ 440 $ 184 $ 6 $ 30 $ 10 $ 140 $ 115 $ — $ — December 31, 2019 Equity method investments: Other equity method investments $ 92 $ 71 $ 6 $ 8 $ — $ — $ — $ — $ — Other investments: Employee benefit trusts and investments (a) 262 54 — 19 7 135 110 — — Equity investments without readily determinable fair values 69 69 — — — — — — — Other available for sale debt security investments 41 41 — — — — — — — Total investments $ 464 $ 235 $ 6 $ 27 $ 7 $ 135 $ 110 $ — $ — __________ (a) The Registrants’ debt and equity security investments are recorded at fair market value. Accrued expenses Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE December 31, 2020 Compensation-related accruals (a) $ 1,069 $ 426 $ 170 $ 73 $ 84 $ 109 $ 36 $ 18 $ 17 Taxes accrued 527 229 94 16 73 117 90 18 12 Interest accrued 331 44 109 37 46 51 26 7 12 December 31, 2019 Compensation-related accruals (a) $ 1,052 $ 422 $ 171 $ 58 $ 78 $ 101 $ 28 $ 19 $ 15 Taxes accrued 414 222 83 3 26 117 90 14 8 Interest accrued 337 65 110 37 46 49 23 8 12 __________ (a) Primarily includes accrued payroll, bonuses and other incentives, vacation, and benefits.

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
Related Party Transactions (Tables)	Dec. 31, 2020
Related Party Transactions [Abstract]
Schedule of Related Party Transactions [Table Text Block]	The following table presents Generation’s Operating revenues from affiliates, which are primarily recorded as Purchased power from affiliates and an immaterial amount recorded as Operating and maintenance expense from affiliates at the Utility Registrants: For the Years Ended 2020 2019 2018 Operating revenues from affiliates: ComEd (a)(b) $ 330 $ 369 $ 523 PECO (c) 190 158 128 BGE (d) 315 289 260 PHI 367 353 355 Pepco (e) 279 264 206 DPL (f) 75 70 120 ACE (g) 13 19 29 Other 9 3 2 Total operating revenues from affiliates (Generation) $ 1,211 $ 1,172 $ 1,268 __________ (a) Generation has an ICC-approved RFP contract with ComEd to provide a portion of ComEd’s electricity supply requirements. Generation also sells RECs and ZECs to ComEd. (b) For 2020, ComEd’s Purchased power from Generation of $345 million is recorded as Operating revenues from ComEd of $330 million and Purchased power and fuel from ComEd of $15 million at Generation. For 2019, ComEd’s Purchased power from Generation of $376 million is recorded as Operating revenues from ComEd of $369 million and Purchased power and fuel from ComEd of $7 million at Generation. (c) Generation provides electric supply to PECO under contracts executed through PECO’s competitive procurement process. In addition, Generation has a ten-year agreement with PECO to sell solar AECs. (d) Generation provides a portion of BGE’s energy requirements under its MDPSC-approved market-based SOS and gas commodity programs. (e) Generation provides electric supply to Pepco under contracts executed through Pepco's competitive procurement process approved by the MDPSC and DCPSC. (f) Generation provides a portion of DPL's energy requirements under its MDPSC and DPSC approved market based SOS commodity programs. (g) Generation provides electric supply to ACE under contracts executed through ACE's competitive procurement process.
Related Party Transactions - BSC and PHISCO Service Companies [Table Text Block]	The following table presents the service company costs allocated to the Registrants: Operating and maintenance from affiliates Capitalized costs For the years ended December 31, For the years ended December 31, 2020 2019 2018 2020 2019 2018 Exelon BSC $ 585 $ 516 $ 448 PHISCO 61 72 79 Generation BSC $ 552 $ 570 $ 652 54 66 67 ComEd BSC 283 263 265 186 148 135 PECO BSC 150 149 146 76 88 64 BGE BSC 170 157 157 132 126 79 PHI BSC 152 139 147 149 88 102 PHISCO — — — 61 72 79 Pepco BSC 85 85 89 55 38 40 PHISCO 120 124 137 27 33 32 DPL BSC 54 52 51 51 25 28 PHISCO 97 100 111 18 20 25 ACE BSC 45 42 42 40 19 20 PHISCO 87 90 98 16 19 21
Related Party Transactions - Current Receivables From/Payables To Affiliates [Table Text Block]	The following tables present current receivables from affiliates and current payables to affiliates: December 31, 2020 Receivables from affiliates: Payables to affiliates: Generation ComEd PECO BGE Pepco DPL ACE BSC PHISCO Other Total Generation $ 13 $ — $ — $ — $ — $ — $ 72 $ — $ 22 $ 107 ComEd $ 78 (a) — — — — — 59 — 9 146 PECO 17 1 — — — — 28 — 4 50 BGE 11 — — — — — 47 — 3 61 PHI — — — — — — — 4 — 11 15 Pepco 13 2 — 1 — — 25 14 — 55 DPL 3 1 — — — — 21 10 1 36 ACE 6 — — — — — 15 9 1 31 Other 25 5 2 2 2 1 6 — — 43 Total $ 153 $ 22 $ 2 $ 3 $ 2 $ 1 $ 6 $ 271 $ 33 $ 51 $ 544 December 31, 2019 Receivables from affiliates: Payables to affiliates: Generation ComEd PECO BGE ACE BSC PHISCO Other Total Generation $ 27 $ — $ — $ — $ 67 $ — $ 23 $ 117 ComEd $ 78 (a) — — — 54 — 8 140 PECO 27 — — — 25 — 3 55 BGE 28 — — — 34 — 4 66 PHI — — — — — 4 — 10 14 Pepco 34 — — — — 16 15 1 66 DPL 7 — — — 3 10 11 1 32 ACE 7 — — — 7 10 1 25 Other 9 1 1 1 1 — — 13 Total $ 190 $ 28 $ 1 $ 1 $ 4 $ 217 $ 36 $ 51 $ 528 __________ (a) At December 31, 2020 and 2019, Generation also had a contract liability with ComEd for $50 million and $37 million, respectively, that was included in Other liabilities on Generation’s Consolidated Balance Sheets. At December 31, 2020 and 2019, ComEd had a Current Payable to Generation of $28 million and $41 million, respectively, on its Consolidated Balance Sheets, which consisted of Generation’s Current Receivable from ComEd, partially offset by Generation’s contract liability with ComEd.
Related Party Transactions - Noncurrent Receivables from/Payables to affiliates [Table Text Block]	The following table presents noncurrent receivables from affiliates at ComEd and PECO which are recorded as noncurrent payables to affiliates at Generation: December 31, 2020 2019 ComEd $ 2,541 $ 2,622 PECO 475 480
Related Party Transactions - Long Term Debt to Financing Trusts [Table Text Block]	The following table presents Long-term debt to financing trusts: As of December 31, 2020 2019 Exelon ComEd PECO Exelon ComEd PECO ComEd Financing III $ 206 $ 205 $ — $ 206 $ 205 $ — PECO Trust III 81 — 81 81 — 81 PECO Trust IV 103 — 103 103 — 103 Total $ 390 $ 205 $ 184 $ 390 $ 205 $ 184

Significant Accounting Polici_3

Significant Accounting Policies - Narrative (Details)	12 Months Ended
Significant Accounting Policies - Narrative (Details)	Dec. 31, 2020
Significant Accounting Policies Additional Narrative Information [Line Items]
Percentage ownership of consolidated subsidiaries	100.00%
Minimum expectation of tax position to be realized	50.00%
Commonwealth Edison Company [Member]
Significant Accounting Policies Additional Narrative Information [Line Items]
Percentage ownership of consolidated subsidiaries	99.00%
CENG [Member]
Significant Accounting Policies Additional Narrative Information [Line Items]
Equity Method Investment, Ownership Percentage	50.01%
ExGen Renewables [Member]
Significant Accounting Policies Additional Narrative Information [Line Items]
Equity Method Investment, Ownership Percentage	51.00%
Minimum [Member]
Significant Accounting Policies Additional Narrative Information [Line Items]
Equity Method Investment, Ownership Percentage	20.00%
Maximum [Member]
Significant Accounting Policies Additional Narrative Information [Line Items]
Equity Method Investment, Ownership Percentage	50.00%

Mergers, Acquisitions, and Disp

Mergers, Acquisitions, and Dispositions - Narrative (Details) $ in Millions	Feb. 28, 2018USD ($)	Apr. 01, 2014USD ($)	Dec. 31, 2020USD ($)MW	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Dec. 08, 2020USD ($)
Business Dispositions
Asset Retirement Obligation, Revision of Estimate					$ 20
Minimum [Member]
Business Acquisitions
Equity Method Investment, Ownership Percentage			20.00%
Maximum [Member]
Business Acquisitions
Equity Method Investment, Ownership Percentage			50.00%
Operating Expense [Member]
Business Dispositions
Asset Retirement Obligation, Revision of Estimate			$ 60	$ (150)
Solar Business [Member]
Business Dispositions
Capacity Of Facility Of Company Owned Solar Distribution Generation Facilities \| MW			360
Disposal Group, Including Discontinued Operation, Consideration						$ 810
Solar Business [Member] \| Minimum [Member]
Business Dispositions
Deconsolidation, Gain (Loss), Amount			$ 75
Solar Business [Member] \| Maximum [Member]
Business Dispositions
Deconsolidation, Gain (Loss), Amount			$ 125
Oyster Creek [Member] \| Operating Expense [Member]
Business Dispositions
Asset Retirement Obligation, Revision of Estimate				9	84
Electrical Contracting Business [Member]
Business Dispositions
Proceeds from Divestiture of Businesses	$ 87
CENG [Member]
Business Acquisitions
Equity Method Investment, Ownership Percentage			50.01%
Payments of Capital Distribution		$ 400
Due from Affiliates		400	$ 619
CENG Preferred Distribution Return			8.50%
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners			49.99%
Exelon Generation Co L L C [Member]
Business Dispositions
Asset Retirement Obligation, Revision of Estimate					0
Exelon Generation Co L L C [Member] \| Operating Expense [Member]
Business Dispositions
Asset Retirement Obligation, Revision of Estimate			$ 60	(150)
Exelon Generation Co L L C [Member] \| Solar Business [Member]
Business Dispositions
Capacity Of Facility Of Company Owned Solar Distribution Generation Facilities \| MW			360
Disposal Group, Including Discontinued Operation, Consideration						$ 810
Exelon Generation Co L L C [Member] \| Solar Business [Member] \| Minimum [Member]
Business Dispositions
Deconsolidation, Gain (Loss), Amount			$ 75
Exelon Generation Co L L C [Member] \| Solar Business [Member] \| Maximum [Member]
Business Dispositions
Deconsolidation, Gain (Loss), Amount			$ 125
Exelon Generation Co L L C [Member] \| Oyster Creek [Member] \| Operating Expense [Member]
Business Dispositions
Asset Retirement Obligation, Revision of Estimate				$ 9	$ 84
Exelon Generation Co L L C [Member] \| Electrical Contracting Business [Member]
Business Dispositions
Proceeds from Divestiture of Businesses	$ 87
Exelon Generation Co L L C [Member] \| CENG [Member]
Business Acquisitions
Equity Method Investment, Ownership Percentage			50.01%	50.01%
Payments of Capital Distribution		400
Due from Affiliates		$ 400	$ 619
CENG Preferred Distribution Return			8.50%
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners			49.99%
Nine Mile Point [Member] \| CENG [Member]
Business Acquisitions
Equity Method Investment, Ownership Percentage			82.00%
Nine Mile Point [Member] \| Exelon Generation Co L L C [Member] \| CENG [Member]
Business Acquisitions
Equity Method Investment, Ownership Percentage			82.00%

Regulatory Matters- Narrative (

Regulatory Matters- Narrative (Details) - USD ($)

7 Months Ended

12 Months Ended

36 Months Ended

48 Months Ended

60 Months Ended

72 Months Ended

Dec. 31, 2017

Dec. 31, 2020

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2024

Jun. 30, 2023

Dec. 31, 2022

Dec. 31, 2023

Jul. 10, 2023

Aug. 26, 2020

Jul. 21, 2017

Commonwealth Edison Co [Member]