0001109357-21-000022 | 10-K | XBRL Viewer

$ 6

$ (155)

$ (69)

33,039

34,438

35,978

9,408

8,615

9,337

5,014

4,252

4,353

1,714

1,732

1,783

30,240

30,096

32,143

Gain on deconsolidation of business

2,823

4,374

3,891

(1,610)

(1,591)

(1,529)

(25)

1,145

1,227

(112)

(490)

(389)

(1,666)

2,333

3,985

2,225

Equity in losses of unconsolidated affiliates

373

774

118

(6)

(183)

(28)

Net income (loss) attributable to common shareholders

1,954

3,028

2,079

1,963

2,936

2,005

Net income (loss) attributable to noncontrolling interests

(9)

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)

Unrealized gain (loss) on investments in unconsolidated affiliates

Unrealized (loss) gain on foreign currency translation

(10)

Other comprehensive income (loss)

(206)

(198)

Comprehensive income attributable to noncontrolling interests

1,748

2,830

2,121

(9)

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

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

$ 1,211

$ 1,172

$ 1,268

17,603

18,924

20,437

(7)

4,613

4,131

4,803

555

587

661

2,123

1,535

1,797

482

519

556

17,358

17,628

19,510

256

1,323

975

(328)

(394)

(396)

(29)

(35)

(36)

937

1,023

(178)

580

594

(610)

836

1,917

365

Equity in losses of unconsolidated affiliates

249

516

(108)

(8)

(184)

(30)

Net income (loss) attributable to noncontrolling interests

579

1,217

443

(10)

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)

Unrealized gain (loss) on investments in unconsolidated affiliates

Unrealized (loss) gain on foreign currency translation

(10)

Other comprehensive income (loss)

Comprehensive income attributable to noncontrolling interests

581

1,224

446

(10)

Comprehensive income (loss) attributable to common shareholders

591

1,131

372

Commonwealth Edison Co [Member]

(47)

(133)

(29)

5,904

5,747

5,882

345

376

529

1,231

1,041

1,068

289

264

267

1,133

1,033

940

299

301

311

4,950

4,580

4,741

954

1,171

1,146

(369)

(346)

(334)

(13)

(339)

(320)

(314)

615

851

832

177

163

168

Other comprehensive income (loss), net of income taxes

438

688

664

438

688

664

PECO Energy Co [Member]

(21)

(7)

3,058

3,100

3,038

188

157

126

816

707

742

159

154

156

347

333

301

172

165

163

2,512

2,388

2,452

546

713

587

(136)

(124)

(115)

(11)

(12)

(14)

(129)

(120)

(121)

417

593

466

(30)

Other comprehensive income (loss), net of income taxes

447

528

460

Baltimore Gas and Electric Company [Member]

447

528

460

(26)

3,098

3,106

3,169

311

286

257

617

600

615

172

160

162

550

502

483

268

260

254

2,598

2,574

2,696

500

532

474

(133)

(121)

(106)

(110)

(93)

(87)

390

439

387

Other comprehensive income (loss), net of income taxes

349

360

313

349

360

313

(14)

(7)

4,663

4,806

4,798

366

352

355

940

939

978

159

143

152

782

754

740

450

455

4,045

4,084

4,156

629

722

643

(268)

(263)

(261)

(211)

(208)

(218)

418

514

425

Equity in losses of unconsolidated affiliates

(77)

Other comprehensive income (loss), net of income taxes

495

477

393

Comprehensive income (loss) attributable to common shareholders

495

477

393

Potomac Electric Power Company [Member]

(3)

(7)

2,149

2,260

2,232

278

264

206

248

273

275

205

209

226

377

374

385

367

378

379

1,799

1,899

1,919

359

361

313

(138)

(133)

(128)

(100)

(102)

(97)

259

216

(7)

Other comprehensive income (loss), net of income taxes

266

243

205

Delmarva Power & Light Company [Member]

266

243

205

(7)

(11)

1,271

1,306

1,332

120

208

171

182

153

152

162

191

184

182

1,120

1,089

1,143

151

217

190

(61)

(58)

(51)

(48)

100

169

142

(25)

Other comprehensive income (loss), net of income taxes

125

147

120

Atlantic City Electric Company [Member]

125

147

120

(12)

(4)

1,245

1,240

1,236

192

187

188

134

133

142

180

157

136

Sale and Leaseback Transaction, Gain (Loss), Net

1,123

1,089

1,087

124

151

149

(59)

(58)

(64)

(53)

(52)

(62)

(41)

Other comprehensive income (loss), net of income taxes

112

Generation commodities and services [Member]

112

Revenue from Contract with Customer, Including Assessed Tax

16,400

17,754

19,168

Generation commodities and services [Member] | Exelon Generation Co L L C [Member]

9,592

10,849

11,679

Revenue from Contract with Customer, Including Assessed Tax

16,392

17,752

19,169

Rate-regulated utility revenues [Member]

9,592

10,849

11,679

Revenue from Contract with Customer, Including Assessed Tax

16,633

16,839

16,879

Electricity, US Regulated [Member] | Commonwealth Edison Co [Member]

4,512

4,648

4,991

Revenue from Contract with Customer, Including Assessed Tax

5,914

5,850

5,884

Electricity, US Regulated [Member] | PECO Energy Co [Member]

1,653

1,565

1,626

Revenue from Contract with Customer, Including Assessed Tax

2,519

2,505

2,469

Electricity, US Regulated [Member] | Baltimore Gas and Electric Company [Member]

645

610

734

Revenue from Contract with Customer, Including Assessed Tax

2,323

2,368

2,428

Electricity, US Regulated [Member] | Pepco Holdings LLC [Member]

509

585

671

Revenue from Contract with Customer, Including Assessed Tax

4,463

4,639

4,609

Electricity, US Regulated [Member] | Potomac Electric Power Company [Member]

1,279

1,371

1,387

Revenue from Contract with Customer, Including Assessed Tax

2,102

2,258

2,233

Electricity, US Regulated [Member] | Delmarva Power & Light Company [Member]

324

401

448

Revenue from Contract with Customer, Including Assessed Tax

1,107

1,143

1,139

Electricity, US Regulated [Member] | Atlantic City Electric Company [Member]

359

381

352

Revenue from Contract with Customer, Including Assessed Tax

1,253

1,237

Natural Gas, US Regulated [Member] | PECO Energy Co [Member]

596

589

587

Revenue from Contract with Customer, Including Assessed Tax

514

610

568

Natural Gas, US Regulated [Member] | Baltimore Gas and Electric Company [Member]

185

262

230

Revenue from Contract with Customer, Including Assessed Tax

739

700

738

Natural Gas, US Regulated [Member] | Pepco Holdings LLC [Member]

171

181

254

Revenue from Contract with Customer, Including Assessed Tax

162

167

181

Natural Gas, US Regulated [Member] | Delmarva Power & Light Company [Member]

Revenue from Contract with Customer, Including Assessed Tax

162

167

181

$ 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 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 - USD ($)
$ in Millions

Dec. 31, 2020

Dec. 31, 2019

$ 663

$ 587

438

358

3,597

4,835

(366)

(243)

3,231

4,592

1,469

1,631

(71)

(48)

1,398

1,583

644

679

297

312

1,425

1,456

Renewable energy credits, current

1,228

1,170

633

348

958

1,609

905

12,562

12,037

82,584

80,233

26,727

23,979

8,759

8,335

14,464

13,190

440

464

Mark-to-market derivative assets, noncurrent

6,677

555

508

294

336

2,982

3,197

34,171

32,707

^[1]

129,317

124,977

2,031

1,370

1,819

4,710

3,562

3,560

2,078

1,981

Mark-to-market derivative liabilities, current

581

406

295

247

Renewable energy credit obligation

100

132

661

443

375

1,264

1,331

12,771

14,185

Long-term debt to financing trusts

35,093

31,329

390

Deferred income taxes and unamortized investment tax credits

13,035

12,351

12,300

10,846

4,503

4,247

Spent nuclear fuel obligation

2,011

2,076

1,208

1,199

Mark-to-market derivative liabilities, noncurrent

9,485

9,986

473

393

Unamortized energy contract liabilities, noncurrent

238

338

2,942

3,064

46,195

44,500

^[1]

94,449

90,404

19,373

19,274

Treasury stock, at cost

(123)

16,735

16,267

(3,400)

(3,194)

32,585

32,224

Noncontrolling interests

2,283

2,349

Total equity

34,868

34,573

$ 129,317

$ 124,977

2,000,000,000

Variable Interest Entity, Primary Beneficiary [Member]

976,000,000

973,000,000

Treasury Stock, Shares

2,000,000

$ 98

$ 163

148

151

244

227

101

674

1,370

723

5,803

6,022

3,007

2,741

249

250

10,481

9,825

544

106

270

731

889

527

Unamortized energy contract liabilities, noncurrent

2,318

2,128

129

Variable Interest Entity, Primary Beneficiary [Member] | Nonrecourse [Member]

3,606

3,476

Variable Interest Entity, Primary Beneficiary [Member] | Asset Pledged as Collateral [Member]

3,598

3,473

10,200

9,532

226

303

146

1,330

2,973

(32)

(80)

1,298

2,893

352

619

352

619

644

675

153

190

233

236

Renewable energy credits, current

978

1,026

621

336

958

1,357

605

6,947

7,076

22,214

24,193

13,370

12,017

14,464

13,190

184

235

Mark-to-market derivative assets, noncurrent

555

508

1,558

1,438

293

336

1,826

1,960

18,933

17,726

^[2]

48,094

48,995

840

320

Long-term debt to affiliates due within one year

197

2,624

558

1,253

1,692

788

786

Borrowings from Exelon/PHI intercompany money pool

107

117

285

Mark-to-market derivative liabilities, current

262

215

Renewable energy credit obligation

661

443

375

444

517

5,219

7,289

Long-term debt to affiliates

5,566

4,464

324

328

Deferred income taxes and unamortized investment tax credits

3,656

3,752

12,054

10,603

Spent nuclear fuel obligation

858

878

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

1,308

1,415

22,309

21,084

^[2]

33,418

33,165

2,805

3,950

(30)

(32)

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

Exelon Generation Co L L C [Member] | Variable Interest Entity, Primary Beneficiary [Member]

48,094

48,995

163

148

151

244

227

101

669

1,362

719

5,803

6,022

3,007

2,741

249

250

10,463

9,805

523

106

244

710

889

504

Unamortized energy contract liabilities, noncurrent

2,318

2,128

129

Exelon Generation Co L L C [Member] | Variable Interest Entity, Primary Beneficiary [Member] | Nonrecourse [Member]

3,580

3,432

Exelon Generation Co L L C [Member] | Variable Interest Entity, Primary Beneficiary [Member] | Asset Pledged as Collateral [Member]

3,572

3,429

Commonwealth Edison Co [Member]

10,182

9,512

279

150

656

604

(97)

(59)

559

545

239

306

(21)

(20)

218

286

Inventories, net

170

159

279

281

1,659

1,583

24,557

23,107

5,672

5,168

1,749

1,480

Receivable from affiliates, noncurrent

2,625

2,541

2,622

1,022

995

307

347

8,250

8,075

34,466

32,765

323

130

350

500

683

527

390

385

103

118

Mark-to-market derivative liabilities, current

289

200

143

122

2,393

2,117

Long-term debt to financing trusts

8,633

7,991

205

Deferred income taxes and unamortized investment tax credits

4,341

4,021

126

128

173

180

Mark-to-market derivative liabilities, noncurrent

6,403

6,542

268

269

595

635

11,906

11,775

23,137

22,088

Retained deficit unappropriated

1,588

Other paid-in capital

8,285

7,572

(1,639)

Retained earnings appropriated

3,095

3,156

11,329

10,677

Commonwealth Edison Co [Member] | Common Stock [Member]

$ 34,466

$ 32,765

$ 12.50

250,000,000

127,000,000

PECO Energy Co [Member]

$ 19

$ 21

511

412

(116)

(55)

395

357

130

145

(8)

(7)

122

138

Receivable from Exelon/PHI intercompany money pool

662

722

10,181

9,292

3,843

3,718

776

554

Receivable from affiliates, noncurrent

475

480

375

365

1,688

1,455

12,531

11,469

300

479

387

129

101

Borrowings from Exelon/PHI intercompany money pool

121

1,208

722

Long-term debt to financing trusts

3,453

3,405

184

Deferred income taxes and unamortized investment tax credits

2,242

2,080

286

288

503

510

3,153

2,980

7,998

7,291

3,014

2,766

1,519

1,412

4,533

4,178

PECO Energy Co [Member] | Common Stock [Member]

$ 12,531

$ 11,469

500,000,000

Common Stock, No Par Value

170,000,000

$ 0

Baltimore Gas and Electric Company [Member]

$ 144

$ 24

487

329

(35)

(12)

452

317

117

152

(9)

(5)

108

147

Prepaid utility taxes

168

183

948

833

9,872

8,990

4,034

3,834

481

454

270

264

830

811

11,650

10,634

300

346

243

205

152

110

120

1,143

753

3,364

3,270

Deferred income taxes and unamortized investment tax credits

1,521

1,396

189

199

1,109

1,195

104

116

2,946

2,928

7,453

6,951

^[3]

2,318

1,907

1,879

1,776

4,197

3,683

Baltimore Gas and Electric Company [Member] | Common Stock [Member]

$ 11,650

$ 10,634

1,500

Common Stock, No Par Value

1,000

$ 0

$ 111

$ 131

611

516

(86)

(37)

525

479

260

190

(33)

(16)

227

174

198

190

440

412

1,599

1,480

15,377

14,296

1,811

1,213

1,933

2,061

140

135

4,005

365

406

307

323

6,760

6,943

23,736

22,719

368

208

347

103

539

462

299

296

Borrowings from Exelon/PHI intercompany money pool

104

106

117

137

115

141

131

2,154

1,612

6,659

6,460

Deferred income taxes and unamortized investment tax credits

2,439

2,278

Unamortized energy contract liabilities, noncurrent

1,438

1,707

235

327

622

577

4,879

5,039

^[4]

13,692

13,111

(68)

(10)

Membership interest

10,112

9,618

Total member’s equity

10,044

9,608

Total equity

10,044

9,608

Pepco Holdings LLC [Member] | Variable Interest Entity, Primary Beneficiary [Member]

23,736

22,719

Unamortized energy contract liabilities, noncurrent

Pepco Holdings LLC [Member] | Variable Interest Entity, Primary Beneficiary [Member] | Nonrecourse [Member]

Pepco Holdings LLC [Member] | Variable Interest Entity, Primary Beneficiary [Member] | Asset Pledged as Collateral [Member]

Potomac Electric Power Company [Member]

279

244

(32)

(13)

247

231

131

(13)

(7)

118

Inventories, net

111

112

214

188

770

696

7,456

6,909

3,697

3,517

570

584

115

110

284

296

1,038

1,056

9,264

8,661

226

195

164

156

Merger related obligation

Current portion of DC PLUG obligation

674

657

3,162

2,862

Deferred income taxes and unamortized investment tax credits

1,189

1,131

644

746

340

297

2,225

2,235

6,061

5,754

^[5]

2,058

1,796

1,145

1,111

3,203

2,907

Potomac Electric Power Company [Member] | Common Stock [Member]

$ 9,264

$ 8,661

$ 0.01

200,000,000

Delmarva Power & Light Company [Member]

100

$ 15

$ 13

176

152

(22)

(11)

154

141

(9)

(4)

Prepaid utility taxes

Renewable energy credits, current

368

325

4,314

4,035

1,533

1,425

222

162

171

458

470

5,140

4,830

146

126

112

535

414

1,595

1,487

Deferred income taxes and unamortized investment tax credits

715

655

493

574

1,334

1,349

3,464

3,250

^[6]

1,089

977

587

603

1,676

1,580

Delmarva Power & Light Company [Member] | Common Stock [Member]

$ 5,140

$ 4,830

$ 2.25

1,000

Atlantic City Electric Company [Member]

1,000

$ 17

$ 12

156

121

(32)

(13)

124

108

(11)

(5)

Inventories, net

326

270

3,475

3,190

1,303

1,210

395

368

485

473

^[7]

4,286

3,933

187

261

177

144

780

360

1,152

1,307

Deferred income taxes and unamortized investment tax credits

624

577

274

357

963

990

^[7]

2,895

2,657

1,271

1,154

120

122

1,391

1,276

Atlantic City Electric Company [Member] | Common Stock [Member]

$ 4,286

$ 3,933

$ 3

25,000,000

Atlantic City Electric Company [Member] | Variable Interest Entity, Primary Beneficiary [Member]

9,000,000

$ 0

Unamortized energy contract liabilities, noncurrent

Atlantic City Electric Company [Member] | Variable Interest Entity, Primary Beneficiary [Member] | Nonrecourse [Member]

Atlantic City Electric Company [Member] | Variable Interest Entity, Primary Beneficiary [Member] | Asset Pledged as Collateral [Member]

Significant Accounting Policies (All Registrants)

$ 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 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 (All Registrants)

12 Months Ended

Dec. 31, 2020

Accounting Policies [Abstract]

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
Company, LLC

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
Power Company

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. See 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 — Supplemental Financial Information for additional information regarding property, plant and equipment.

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. See Note 19 — Commitments and Contingencies for additional information regarding the cost of SNF storage and disposal.

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 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.

See Note 3 — Regulatory Matters and Note 24 — Supplemental Financial Information for additional information regarding Generation’s nuclear fuel and ARC, and the amortization of the Utility Registrants' regulatory assets.

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. See Note 10 — Asset Retirement Obligations for additional information.

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. See Note 19 — Commitments and Contingencies for additional information.

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.

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

hedges. See Note 3 — Regulatory Matters and Note 16 — Derivative Financial Instruments for additional information.

As part of Generation’s energy marketing business, Generation enters into contracts to buy and sell energy to meet the requirements of its customers. These contracts include short-term and long-term commitments to purchase and sell energy and energy-related products in the energy markets with the intent and ability to deliver or take delivery of the underlying physical commodity. NPNS are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period of time and will not be financially settled. Revenues and expenses on derivative contracts that qualify, and are designated, as NPNS are recognized when the underlying physical transaction is completed. While these contracts are considered derivative financial instruments, they are not required to be recorded at fair value, but rather are recorded on an accrual basis of accounting. See Note 16 — Derivative Financial Instruments for additional information.

Retirement Benefits (All Registrants)

Exelon sponsors defined benefit pension plans and OPEB plans for essentially all current employees.

The plan obligations and costs of providing benefits under these plans are measured as of December 31. The measurement involves various factors, assumptions, and accounting elections. The impact of assumption changes or experience different from that assumed on pension and OPEB obligations is recognized over time rather than immediately recognized in the Consolidated Statements of Operations and Comprehensive Income. Gains or losses in excess of the greater of ten percent of the projected benefit obligation or the MRV of plan assets are amortized over the expected average remaining service period of plan participants. See Note 15 — Retirement Benefits for additional information.

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.

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 Registrants)

12 Months Ended

Dec. 31, 2020

Regulated Operations [Abstract]

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 1st, 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

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

10.3

Third quarter of 2021

ACE - New Jersey(d)

December 9, 2020

Electric

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 1st 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

(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 requirement 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 1st.	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 PHI - 2045	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 1st.	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 Pepco (District of Columbia), ACE - No
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 Overcollection - To be determined by NJBPU	Stranded costs - Yes Overcollection - No


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. ComEd, BGE, Pepco, and DPL - Liability is reduced as costs are incurred.	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 million - 2021; $36 million not currently being recovered	Pepco, DPL - Yes ACE - No
Nuclear decommissioning	Estimated future decommissioning costs for the Regulatory Agreement Units that are less than the associated NDT fund assets. See Note 10 — Asset Retirement Obligations for additional information.	Not currently being refunded.	No
COVID-19	See COVID-19 section below for detail on the COVID-19 regulatory asset.	ComEd - 2024 BGE - 2025 PECO, Pepco, DPL, and ACE - Not currently being recovered.	ComEd and BGE - Yes PECO, Pepco, DPL, and ACE - No


Line Item	Description	End Date of Remaining Recovery/Refund Period	Return
Under (over) -recovered credit loss expense	For ComEd and ACE, amounts represent the difference between annual credit loss expense and revenues collected in rates through ICC and NJBPU-approved riders. The difference between net credit loss expense and revenues collected through the rider each calendar year for ComEd is recovered or refunded over a twelve-month period beginning in June of the following calendar year. ACE intends to recover/refund from June through May of each respective year, subject to approval of the NJBPU.	ComEd - 2023 ACE - To be determined by NJBPU.	No
Renewable portfolio standards costs	Represents an overcollection of funds from both ComEd customers and alternative retail electricity suppliers to be spent on future renewable energy procurements. Costs were $320 million as of December 31, 2019, which are included in Other in the 2019 table above.	To be determined by the IPA and ICC.	No

COVID-19 (Exelon and the Utility Registrants). Starting in March of 2020, the Utility Registrants temporarily suspended customer disconnections for non-payment and temporarily ceased new late payment fees for all customers and restored service to customers upon request who were disconnected in the last twelve months. The duration and extent of these measures varies by jurisdiction. While these measures are no longer in place for some jurisdictions as of December 31, 2020, they are expected to continue through the first quarter of 2021 in other jurisdictions. Typically, the Utility Registrants recover credit loss expense through regulatory required programs or distribution base rate cases. ComEd and ACE have existing mechanisms for recovery of credit loss expense. For those jurisdictions without an existing regulatory required program to recover credit loss expense, the Utility Registrants are pursuing strategies to recover incremental costs being incurred as a result of COVID-19:

•In the period of April to July of 2020, the MDPSC, the DCPSC, the DPSC, and the NJBPU issued orders authorizing the creation of regulatory assets to track incremental COVID-19 related costs.

•In May of 2020, the PAPUC issued a Secretarial Letter authorizing the creation of regulatory assets to track incremental credit loss expense related to COVID-19.

The Utility Registrants have also incurred direct costs related to COVID-19 consisting primarily of costs to acquire personal protective equipment, costs for cleaning supplies and services, and costs to hire healthcare professionals to monitor the health of their employees.

The Utility Registrants have recorded regulatory assets for the impacts of COVID-19 reflecting primarily incremental credit losses and direct costs, partially offset by a decrease in travel costs at BGE and PHI. Refer to the Regulatory assets table above for amounts as of December 31, 2020. The Utility Registrants expect to seek recovery in upcoming distribution base rate cases.

Capitalized Ratemaking Amounts Not Recognized

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.

(c)Pepco's and DPL's authorized amounts capitalized for ratemaking purposes relate to earnings on shareholders' investment on their respective AMI Programs and Energy Efficiency and Demand Response Programs. The earnings on energy efficiency are on Pepco DC and DPL DE programs only.

Generation Regulatory Matters (Exelon and Generation)

Illinois Regulatory Matters

Zero Emission Standard. Pursuant to FEJA, on January 25, 2018, the ICC announced that Generation’s Clinton Unit 1, Quad Cities Unit 1, and Quad Cities Unit 2 nuclear plants were selected as the winning bidders through the IPA's ZEC procurement event.

Generation executed the ZEC procurement contracts with Illinois utilities, including ComEd, effective January 26, 2018 and began recognizing revenue with compensation for the sale of ZECs retroactive to the June 1, 2017 effective date of FEJA. The ZEC price was initially established at $16.50 per MWh of production, subject to annual future adjustments determined by the IPA for specified escalation and pricing adjustment mechanisms designed to lower the ZEC price based on increases in underlying energy and capacity prices. Illinois utilities are required to purchase all ZECs delivered by the zero-emissions nuclear-powered generating facilities, subject to annual cost caps. For the initial delivery year, June 1, 2017 to May 31, 2018, and subsequent delivery year, June 1, 2018 to May 31, 2019, the ZEC annual cost cap was set at $235 million (ComEd’s share is approximately $170 million). For subsequent delivery years, the IPA-approved targeted ZEC procurement amounts will change based on forward energy and capacity prices. ZECs delivered to Illinois utilities in excess of the annual cost cap may be paid in subsequent years if the payments do not exceed the prescribed annual cost cap for that year. During the first quarter of 2018, Generation recognized $150 million of revenue related to ZECs generated from June 1, 2017 through December 31, 2017.

New Jersey Regulatory Matters

New Jersey Clean Energy Legislation. On May 23, 2018, New Jersey enacted legislation that established a ZEC program that provides compensation for nuclear plants that demonstrate to the NJBPU that they meet certain requirements, including that they make a significant contribution to air quality in the state and that their revenues are insufficient to cover their costs and risks. Under the legislation, the NJBPU will issue ZECs to qualifying nuclear power plants and the electric distribution utilities in New Jersey, including ACE, will be required to purchase those ZECs. On April 18, 2019, the NJBPU approved the award of ZECs to Salem 1 and Salem 2. Upon approval, Generation began recognizing revenue for the sale of New Jersey ZECs in the month they are generated and has recognized $69 million and $53 million for the year ended December 31, 2020 and 2019, respectively. On May 15, 2019, New Jersey Rate Counsel appealed the NJBPU's decision to the New Jersey Superior Court. Briefing has been completed, and on December 9, 2020, oral argument took place. On October 1, 2020, PSEG and Generation filed applications seeking ZECs for the second eligibility period (June 2022 through May 2025). The NJBPU will act on the applications by the end of April 2021. Exelon and Generation cannot predict the outcome of the appeal. See Note 7 - Early Plant Retirements for additional information related to Salem.

New York Regulatory Matters

New York Clean Energy Standard. On August 1, 2016, the NYPSC issued an order establishing the New York CES, a component of which is a Tier 3 ZEC program targeted at preserving the environmental attributes of zero-emissions nuclear-powered generating facilities that meet the criteria demonstrating public necessity as determined by the NYPSC to be Generation's FitzPatrick, Ginna, and Nine Mile Point nuclear facilities.

On November 30, 2016 (as amended on January 13, 2017), a group of parties filed a Petition in New York State court seeking to invalidate the ZEC program, which argued that the NYPSC did not have authority to establish the program, that it violated state environmental law and that it violated certain technical provisions of the State Administrative Procedures Act when adopting the ZEC program. On January 22, 2018, the court dismissed the environmental claims and the majority of the plaintiffs from the case but denied the motions to dismiss with respect to the remaining five plaintiffs and claims, without commenting on the merits of the case. On October 8, 2019, the court dismissed all remaining claims. The petitioners filed a notice of appeal on November 4, 2019 and originally had until May 4, 2020 to file their brief. Due to COVID-19 related restrictions, the court extended the deadline to July 29, 2020. Petitioners did not file a brief by the deadline, so the case is deemed dismissed. Petitioners are permitted up to one year from July 29, 2020 to file a motion to vacate the dismissal if they can show good cause for the delay.

See Note 7 — Early Plant Retirements for additional information related to Ginna and Nine Mile Point.

New England Regulatory Matters

Mystic Units 8 & 9 and Everett Marine Terminal Cost of Service Agreement (Exelon and Generation). On March 29, 2018, Generation notified grid operator ISO-NE of its plans to early retire Mystic Units 8 and 9 absent regulatory reforms on June 1, 2022. On May 16, 2018, Generation made a filing with FERC to establish cost-of-service compensation and terms and conditions of service for Mystic Units 8 & 9 for the period between June 1, 2022 - May 31, 2024. On December 20, 2018, FERC issued an order accepting the cost of service compensation, reflecting a number of adjustments to the annual fixed revenue requirement, and allowing for recovery of a substantial portion of the costs associated with the adjacent Everett Marine Terminal acquired by Generation in October 2018. Those adjustments were reflected in a compliance filing made on March 1, 2019. In the December 20, 2018 order, FERC also directed a paper hearing on ROE using a new methodology. On January 22, 2019, Exelon and several other parties filed requests for rehearing of certain findings in the order.

On July 17, 2020, FERC issued three orders, which together affirmed the recovery of key elements of Mystic's cost of service compensation, including recovery of costs associated with the operation of the Everett Marine Terminal. FERC directed a downward adjustment to the rate base for Mystic Units 8 and 9, the effect of which will be partially offset by elimination of a crediting mechanism for third party gas sales during the term of the cost of service agreement. A compliance filing was submitted on September 15, 2020 and is pending. Several parties filed protests to the compliance filing on the issue of how gross plant in-service was calculated and Generation filed an answer to the protests on October 21, 2020. On July 28, 2020, FERC ordered additional briefings in the ROE proceeding. On December 21, 2020, FERC issued an order on rehearing of the three July 17, 2020 orders, clarifying several cost of service provisions.

On August 25, 2020, a group of New England generators filed a complaint against Generation seeking to extend the scope of the claw back provision in the cost-of-service agreement, whereby Generation would refund certain amounts recovered during the term of the cost of service if it returns to market afterwards. On September 14, 2020, Generation filed an answer to the complaint arguing that the complaint is procedurally improper and a collateral attack on existing FERC orders, and pointing out that the ISO-NE tariff contains protections against the New England generators' concerns that they failed to mention. On September 28, 2020, New England generators filed an answer to Generation’s answer. Generation cannot predict the outcome of this proceeding.

On June 10, 2020, Generation filed a complaint with FERC against ISO-NE on the grounds that ISO-NE failed to follow its tariff with respect to its evaluation of Mystic 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 should have been filed with FERC for approval. On July 27, 2020, ISO-NE issued a memo to NEPOOL announcing its determination pursuant to its unfiled planning procedures that Mystic Units 8 and 9 are not needed for FCA 15 for transmission security. It had previously determined Mystic Units 8 and 9 are not needed for fuel security. On August 17, 2020, FERC issued an order denying the complaint. On September 16,

2020, Generation filed a request for rehearing with FERC. On October 19, 2020, FERC denied rehearing by operation of law and on December 18, 2020, Generation appealed to the U.S. Court of Appeals for the D.C. Circuit. The timing and the outcome of this proceeding is uncertain.

See Note 7 — Early Plant Retirements and Note 12 — Asset Impairments for additional information on the impacts of Generation’s August 2020 decision to retire Mystic Units 8 & 9 upon expiration of the cost of service agreement.

Federal Regulatory Matters

PJM and NYISO MOPR Proceedings. PJM and NYISO capacity markets include a MOPR. If a resource is subjected to a MOPR, its offer is adjusted to effectively remove the revenues it receives through a state government-provided financial support program - resulting in a higher offer that may not clear the capacity market. Prior to December 19, 2019, the MOPR in PJM applied only to certain new gas-fired resources. Currently, the MOPR in NYISO applies only to certain resources in downstate New York.

For Generation’s facilities in PJM and NYISO that are currently receiving ZEC compensation, an expanded MOPR would require exclusion of ZEC compensation when bidding into future capacity auctions, resulting in an increased risk of these facilities not receiving capacity revenues in future auctions.

On December 19, 2019, FERC required PJM to broadly apply the MOPR to all new and existing resources including nuclear, renewables, demand response, energy efficiency, storage, and all resources owned by vertically-integrated utilities. This greatly expands the breadth and scope of PJM’s MOPR, which is effective as of PJM’s next capacity auction. While FERC included some limited exemptions, no exemptions were available to state-supported nuclear resources.

FERC provided no new mechanism for accommodating state-supported resources other than the existing FRR mechanism (under which an entire utility zone would be removed from PJM’s capacity auction along with sufficient resources to support the load in such zone). In response to FERC’s order, PJM submitted a compliance filing on March 18, 2020 wherein PJM proposed tariff language interpreting and implementing FERC's directives, and proposed a schedule for resuming capacity auctions that is contingent on the timing of FERC's action on the compliance filing.

On April 16, 2020, FERC issued an order largely denying most requests for rehearing of FERC's December 2019 order but granting a few clarifications that required an additional PJM compliance filing which PJM submitted on June 1, 2020.

On October 15, 2020, FERC issued an order denying requests for rehearing of its April 16, 2020 order and accepting PJM’s two compliance filings, subject to a further compliance filing to revise minor aspects of the proposed MOPR methodology. As part of that order, FERC also accepted PJM’s proposal to condense the schedule of activities leading up to the next capacity auction. In November 2020, PJM announced that it will conduct its next capacity auction beginning on May 19, 2021 and ending on May 25, 2021 and will post the results on June 2, 2021.

Because neither Illinois nor New Jersey have implemented an FRR program in their PJM zones, the MOPR will apply in that next capacity auction to Generation's owned or jointly owned nuclear plants in those states receiving a benefit under the Illinois ZES, or the New Jersey ZEC program, as applicable, increasing the risk that those units may not clear the capacity market.

Exelon is currently working with PJM and other stakeholders to pursue the FRR option as an alternative to the PJM capacity auction. If Illinois implements the FRR option, Generation’s Illinois nuclear plants could be removed from PJM’s capacity auction and instead supply capacity, and be compensated under the FRR program, which has the potential to mitigate the current economic distress being experienced by Generation's nuclear plants in Illinois, as discussed in Note 7 — Early Plant Retirements. Implementing the FRR program in Illinois will require both legislative and regulatory changes. Whether legislation is needed in New Jersey would depend on how the state chooses to structure an FRR program. Exelon cannot predict whether or when such legislative and regulatory changes can be implemented.

On February 20, 2020, FERC issued an order rejecting requests to expand NYISO’s version of the MOPR (referred to as buyer-side mitigation rules) beyond its current limited applicability to certain resources in downstate. However, on October 14, 2020, two natural gas-fired generators in New York filed a complaint at FERC seeking to expand the MOPR in NYISO to apply to all resources, new and existing, across the entire NYISO market. Exelon is strenuously opposing expansion of FERC’s MOPR policies in the NYISO market. While it is too early in the proceeding to predict its outcome and there are significant differences between the NYISO and PJM markets that would justify a different result, if FERC follows its MOPR precedent in PJM and applies the MOPR in NYISO broadly as requested in the complaint, Generation’s facilities in NYISO that are receiving ZEC compensation may be at increased risk of not clearing the capacity auction.

If Generation’s state-supported nuclear plants in PJM or NYISO are subjected to the MOPR or equivalent without compensation under an FRR or similar program, it could have a material adverse impact on Exelon's and Generation's financial statements, which Exelon and Generation cannot reasonably estimate at this time.

Operating License Renewals

Conowingo Hydroelectric Project. On August 29, 2012, Generation submitted a hydroelectric license application to FERC for a new license for the Conowingo Hydroelectric Project (Conowingo). In connection with Generation’s efforts to obtain a water quality certification pursuant to Section 401 of the Clean Water Act (401 Certification) from MDE for Conowingo, Generation has been working with MDE and other stakeholders to resolve water quality licensing issues, including: (1) water quality, (2) fish habitat, and (3) sediment.

On April 21, 2016, Generation and the U.S. Fish and Wildlife Service of the U.S. Department of the Interior executed a settlement agreement (DOI Settlement) resolving all fish passage issues between the parties.

On April 27, 2018, MDE issued its 401 Certification for Conowingo. As issued, the 401 Certification contains numerous conditions, including those relating to reduction of nutrients from upstream sources, removal of all visible trash and debris from upstream sources, and implementation of measures relating to fish passage, which could have a material, unfavorable impact on Exelon’s and Generation’s financial statements through an increase in capital expenditures and operating costs if implemented. On May 25, 2018, Generation filed complaints in federal and state court, along with a petition for reconsideration with MDE, alleging that the conditions are unfair and onerous and in violation of MDE regulations and state, federal, and constitutional law. Generation also requested that FERC defer the issuance of the federal license while these significant state and federal law issues are pending. On February 28, 2019, Generation filed a Petition for Declaratory Order with FERC requesting that FERC issue an order declaring that MDE waived its right to issue a 401 Certification for Conowingo because it failed to timely act on Conowingo’s 401 Certification application and requesting that FERC decline to include the conditions required by MDE in April 2018.

On October 29, 2019, Generation and MDE filed with FERC a Joint Offer of Settlement (Offer of Settlement) that would resolve all outstanding issues relating to the 401 Certification. Pursuant to the Offer of Settlement, the parties submitted Proposed License Articles to FERC to be incorporated by FERC into the new license in accordance with FERC’s discretionary authority under the Federal Power Act. Among the Proposed License Articles are modifications to river flows to improve aquatic habitat, eel passage improvements, and initiatives to support rare, threatened and endangered wildlife. If FERC approves the Offer of Settlement and incorporates the Proposed License Articles into the new license without modification, then MDE would waive its rights to issue a 401 Certification and Generation would agree, pursuant to a separate agreement with MDE (MDE Settlement), to implement additional environmental protection, mitigation, and enhancement measures over the anticipated 50-year term of the new license. These measures address mussel restoration and other ecological and water quality matters, among other commitments. Exelon’s commitments under the various provisions of the Offer of Settlement and MDE Settlement are not effective unless and until FERC approves the Offer of Settlement, and issues the new license with the Proposed License Articles.

The financial impact of the DOI and MDE Settlements and other anticipated license commitments are estimated to be $11 million to $14 million per year, on average, recognized over the new license term, including capital and operating costs. The actual timing and amount of the majority of these costs are not currently fixed and will vary from year to year throughout the life of the new license. Generation cannot currently predict when FERC will issue the new license. As of December 31, 2020, $45 million of direct costs associated with Conowingo licensing efforts have been capitalized. Generation's current depreciation provision for Conowingo assumes renewal of the FERC license.

Peach Bottom Units 2 and 3. On July 10, 2018, Generation submitted a second 20-year license renewal application with the NRC for Peach Bottom Units 2 and 3, which was approved on March 6, 2020. Peach Bottom Units 2 and 3 are now licensed to operate through 2053 and 2054, respectively. See Note 8 – Property, Plant, and Equipment for additional information regarding the estimated useful life and depreciation provisions for Peach Bottom.

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.

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

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-URI http://asc.fasb.org/topic&trid=49130388

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 10
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130551-203045

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 13
-Subparagraph (b)(2)
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130556-203045

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130554-203045

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 9
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130550-203045

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (e)
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130554-203045

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130554-203045

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (d)
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130554-203045

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 15
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130558-203045

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (c)
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130554-203045

Segment Information (All Registrants)

Segment Information (All Registrants)

12 Months Ended

Dec. 31, 2020

Segment Reporting [Abstract]

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 Eliminations		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 Eliminations		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 Eliminations		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 Eliminations		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 Eliminations		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.

(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 customers(a)		Intersegment RNF		Total RNF		RNF from external customers(a)		Intersegment RNF		Total RNF		RNF from external customers(a)		Intersegment RNF		Total RNF
Mid-Atlantic	$	2,174	$	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 gains 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.

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

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 31
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e8924-108599

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 34
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e8981-108599

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 21
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e8721-108599

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 40
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e9031-108599

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 32
-Subparagraph (f)
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e8933-108599

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 32
-Subparagraph (e)
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e8933-108599

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 26
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e8844-108599

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 41
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e9038-108599

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 32
-Subparagraph (d)
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e8933-108599

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 22
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e8736-108599

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 42
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e9054-108599

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 15
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e8657-108599

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 21
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e8721-108599

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-URI http://asc.fasb.org/topic&trid=2134510

Loans, Notes, Trade and Other Receivables Disclosure

Accounts Receivable (All Registrants)

12 Months Ended

Dec. 31, 2020

Credit Loss [Abstract]

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, Generation)

12 Months Ended

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.

Exelon and Generation recorded incremental Depreciation and amortization expense of $26 million for the year ended December 31, 2020. See Note 12 — Asset Impairments for impairment assessment considerations of the New England Asset Group.

Property, Plant and Equipment (All Registrants)

12 Months Ended

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 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 Bottom			Salem			Nine Mile Point Unit 2			NJ/DE(a)
Operator	Generation			Generation			PSEG Nuclear			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 (All Registrants)

12 Months Ended

Dec. 31, 2020

Asset Retirement Obligation Disclosure [Abstract]

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 collected. Every five years, PECO files a rate adjustment with the PAPUC that reflects PECO’s calculations of the estimated amount needed to decommission each of the former PECO units based on updated fund balances and estimated decommissioning costs. The rate adjustment is used to determine the amount collectible from PECO customers. On March 31, 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)

12 Months Ended

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 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 information. 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. Exelon and Generation recorded a pre-tax impairment charge of $164 million in Equity in losses of unconsolidated affiliates and an offsetting pre-tax $96 million in Net income attributable to noncontrolling interests in their Consolidated Statements of Operations and Comprehensive Income. As a result, Generation accelerated the amortization of investment tax credits associated with these companies and Exelon and Generation recorded a benefit of $46 million in Income taxes. The impairment charge and the accelerated amortization of investment tax credits resulted in a net $15 million decrease to Exelon’s and Generation’s earnings. See Note 23 — Variable Interest Entities for additional information.

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)

12 Months Ended

Dec. 31, 2020

Income Tax Disclosure [Abstract]

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 unamortized investment tax credits	$	(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 effective 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, respectively, 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 Registrants)

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

+ References + Details

Retirement Benefits (All Registrants)

12 Months Ended

Dec. 31, 2020

Retirement Benefits [Abstract]

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)

Exelon Corporation Pension Plan for Bargaining Unit Employees(a)

Exelon New England Union Employees Pension Plan(a)

Exelon Employee Pension Plan for Clinton, TMI, and Oyster Creek(a)

Pension Plan of Constellation Energy Group, Inc.(b)

Pension Plan of Constellation Energy Nuclear Group, LLC(c)

Nine Mile Point Pension Plan(c)

Constellation Mystic Power, LLC Union Employees Pension Plan Including Plan A and Plan B(b)

Pepco Holdings LLC Retirement Plan(d)

Non-Qualified Pension Plans:

Exelon Corporation Supplemental Pension Benefit Plan and 2000 Excess Benefit Plan(a)

Exelon Corporation Supplemental Management Retirement Plan(a)

Constellation Energy Group, Inc. Senior Executive Supplemental Plan(b)

Constellation Energy Group, Inc. Supplemental Pension Plan(b)

Constellation Energy Group, Inc. Benefits Restoration Plan(b)

Constellation Energy Nuclear Plan, LLC Executive Retirement Plan(c)

Constellation Energy Nuclear Plan, LLC Benefits Restoration Plan(c)

Baltimore Gas & Electric Company Executive Benefit Plan(b)

Baltimore Gas & Electric Company Manager Benefit Plan(b)

Pepco Holdings LLC 2011 Supplemental Executive Retirement Plan(d)

Conectiv Supplemental Executive Retirement Plan(d)

Pepco Holdings LLC Combined Executive Retirement Plan(d)

Atlantic City Electric Director Retirement Plan(d)

Operating Company(e)

Name of Plan:

Generation

ComEd

PECO

BGE

PHI

Pepco

DPL

ACE

OPEB Plans:

PECO Energy Company Retiree Medical Plan(a)

Exelon Corporation Health Care Program(a)

Exelon Corporation Employees’ Life Insurance Plan(a)

Exelon Corporation Health Reimbursement Arrangement Plan(a)

Constellation Energy Group, Inc. Retiree Medical Plan(b)

Constellation Energy Group, Inc. Retiree Dental Plan(b)

Constellation Energy Group, Inc. Employee Life Insurance Plan and Family Life Insurance Plan(b)

Constellation Mystic Power, LLC

Post-Employment Medical Account Savings Plan(b)

Exelon New England Union Post-Employment Medical Savings Account Plan(a)

Retiree Medical Plan of Constellation Energy Nuclear Group, LLC(c)

Retiree Dental Plan of Constellation Energy Nuclear Group, LLC(c)

Nine Mile Point Nuclear Station, LLC Medical Care and Prescription Drug Plan for Retired Employees(c)

Pepco Holdings LLC Welfare Plan for Retirees(d)

__________

(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.

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 Benefits		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 Credit		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 reporting date	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 Credit		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

The entire disclosure for retirement benefits.

Reference 1: http://www.xbrl.org/2003/role/exampleRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 55
-Paragraph 17
-URI http://asc.fasb.org/extlink&oid=118257860&loc=d3e4179-114921

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section S99
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=21916913&loc=d3e273930-122802

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (d)(i)
-URI http://asc.fasb.org/extlink&oid=118255775&loc=d3e1928-114920

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (o)
-URI http://asc.fasb.org/extlink&oid=118255775&loc=d3e1928-114920

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (p)
-URI http://asc.fasb.org/extlink&oid=118255775&loc=d3e1928-114920

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 70
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=49170846&loc=d3e28014-114942

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-URI http://asc.fasb.org/topic&trid=2235017

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 60
-Section 50
-Paragraph 3
-Subparagraph (c)
-URI http://asc.fasb.org/extlink&oid=6414203&loc=d3e39689-114964

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (d)(iv)(03)
-URI http://asc.fasb.org/extlink&oid=118255775&loc=d3e1928-114920

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (q)
-URI http://asc.fasb.org/extlink&oid=118255775&loc=d3e1928-114920

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (r)(1)
-URI http://asc.fasb.org/extlink&oid=118255775&loc=d3e1928-114920

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (d)(iii)
-URI http://asc.fasb.org/extlink&oid=118255775&loc=d3e1928-114920

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (l)
-URI http://asc.fasb.org/extlink&oid=118255775&loc=d3e1928-114920

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (r)(2)
-URI http://asc.fasb.org/extlink&oid=118255775&loc=d3e1928-114920

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Financial Instruments (All Registrants)

12 Months Ended

Dec. 31, 2020

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 Derivatives		Economic Hedges		Proprietary Trading		Collateral (a)(b)		Netting(a)		Subtotal		Economic Hedges
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 Exposure Before Credit Collateral		Credit Collateral(a)		Net Exposure		Number of Counterparties Greater than 10% of Net Exposure	Net Exposure of Counterparties Greater than 10% of Net Exposure
Investment grade	$	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 Registrants)

12 Months Ended

Dec. 31, 2020

Debt Disclosure [Abstract]

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 Program Size at December 31,				Outstanding Commercial Paper at December 31,				Average Interest Rate on Commercial Paper Borrowings at December 31,
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 Commitment(b)		Facility Draws		Outstanding Letters of Credit		Actual		To Support Additional Commercial Paper(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

200

Generation(c)

October 25, 2019

N/A

100

Generation(c)

November 20, 2019

N/A

300

Generation(c)

November 21, 2019

N/A

150

Generation(c)

November 21, 2019

N/A

November 21, 2021

100

Generation(c)

May 15, 2020

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 Date	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 Date	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 Date	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 Date	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 Date	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 Date	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 Date	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 Date	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 Date	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 and Liabilities (All Registrants)

12 Months Ended

Dec. 31, 2020

Fair Value Disclosures [Abstract]

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 Derivatives			Total Generation		Mark-to-Market Derivatives			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 Derivatives			Total Generation		Mark-to-Market Derivatives			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 Revenues		Purchased Power and Fuel		Operating and Maintenance		Other, net		Operating Revenues		Purchased Power and Fuel		Other, net		Operating and Maintenance

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 Revenues		Purchased Power and Fuel		Operating and Maintenance		Other, net		Operating Revenues		Purchased Power and Fuel		Other, net		Operating and Maintenance

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 generally based on independent appraisals from sources with professional qualifications, typically using a combination of market comparables and discounted cash flows. These valuation inputs are unobservable. The fair value of real estate investments is determined using NAV or its equivalent as a practical expedient, and therefore, these investments are not classified within the fair value hierarchy.

Generation evaluated its NDT 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 (generally defined as greater than 10 percent) of risk in Generation's NDT assets.

See Note 10 — Asset Retirement Obligations for additional information on the NDT fund investments. See Note 15 — Retirement Benefits for the valuation techniques used for hedge fund investments.

Rabbi Trust Investments (Exelon, Generation, PECO, BGE, PHI, Pepco, DPL, and ACE). The Rabbi trusts were established to hold assets related to deferred compensation plans existing for certain active and retired members of Exelon’s executive management and directors. The Rabbi trusts' assets are included in investments in the Registrants’ Consolidated Balance Sheets and consist primarily of money market funds, mutual funds, fixed income securities, and life insurance policies. Money market funds and mutual funds are publicly quoted and have been categorized as Level 1 given the clear observability of the prices. The fair values of fixed income securities are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities, adjusted for observable differences and are categorized in Level 2. The life insurance policies are valued using the cash surrender value of the policies, net of loans against those policies, which is provided by a third-party. Certain life insurance policies, which consist primarily of mutual funds that are priced based on observable market data, have been categorized as Level 2 because the life insurance policies can be liquidated at the reporting date for the value of the underlying assets. Life insurance policies that are valued using unobservable inputs have been categorized as Level 3, where the fair value is determined based on the cash surrender value of the policy, which contains unobservable inputs and assumptions. Because Exelon relies on its third-party insurance provider to develop the inputs without adjustment for the valuations of its Level 3 investments, quantitative information about significant unobservable inputs used in valuing these investments is not reasonably available to Exelon. Therefore, Exelon has not disclosed such inputs.

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

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

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

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

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

For derivatives that trade in less liquid markets with limited pricing information, model inputs generally would include both observable and unobservable inputs. These valuations may include an estimated basis adjustment from an illiquid trading point to a liquid trading point for which active price quotations are available. Such instruments are categorized in Level 3.

For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations whose contract tenure extends into unobservable periods. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility, and contract duration. Such instruments are categorized in Level 3 as the model inputs generally are not observable. Forward price curves for the power market utilized by the front office to manage the portfolio, are reviewed and verified by the middle office, and used for financial reporting by the back office. The Registrants consider credit and nonperformance risk in the valuation of derivative contracts categorized in Level 2 and 3, including both historical and current market data, in their assessment of credit and nonperformance risk by counterparty. Due to master netting agreements and collateral posting requirements, the impacts of credit and nonperformance risk were not material to the financial statements.

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

For commodity derivatives, the primary input to the valuation models is the forward commodity price curve for each instrument. Forward commodity price curves are derived by risk management for liquid locations and by the traders and portfolio managers for illiquid locations. All locations are reviewed and verified by risk management considering published exchange transaction prices, executed bilateral transactions, broker quotes, and other observable or public data sources. The relevant forward commodity curve used to value each of the derivatives depends on a number of factors, including commodity type, delivery location, and delivery period. Price volatility varies by commodity and location. When appropriate, Generation discounts future cash flows using risk free interest rates with adjustments to reflect the credit quality of each counterparty for assets and Generation’s own credit quality for liabilities. The level of observability of a forward commodity price varies generally due to the delivery location and delivery period. Certain delivery locations including PJM West Hub (for power) and Henry Hub (for natural gas) are more liquid and prices are observable for up to three years in the future. The observability period of volatility is generally shorter than the underlying power curve used in option valuations. The forward curve for a less liquid location is estimated by using the forward curve from the liquid location and applying a spread to represent the cost to transport the commodity to the delivery location. This spread does not typically represent a majority of the instrument’s market price. As a result, the change in fair value is closely tied to liquid market movements and not a change in the applied spread. The change in fair value associated with a change in the spread is generally immaterial. An average spread calculated across all Level 3 power and gas delivery locations is approximately $2.49 and $0.38 for power and natural gas, respectively. Many of the commodity derivatives are short term in nature and thus a majority of the fair value may be based on observable inputs even though the contract as a whole must be classified as Level 3.

On December 17, 2010, ComEd entered into several 20-year floating to fixed energy swap contracts with unaffiliated suppliers for the procurement of long-term renewable energy and associated RECs. See Note 16 — Derivative Financial Instruments for additional information. The fair value of these swaps has been designated as a Level 3 valuation due to the long tenure of the positions and internal modeling assumptions. The modeling assumptions include using natural gas heat rates to project long term forward power curves adjusted by a renewable factor that incorporates time of day and seasonality factors to reflect accurate renewable energy pricing. In addition, marketability reserves are applied to the positions based on the tenor and supplier risk.

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

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


Type of trade	Fair Value at December 31, 2020		Fair Value at December 31, 2019		Valuation Technique	Unobservable Input	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 price	$2.25	-	$163	$30	$9	-	$180	$29
						Forward gas price	$1.57	-	$7.88	$2.59	$0.83	-	$10.72	$2.55
					Option Model	Volatility percentage	11%	-	237%	32%	8%	-	236%	70%

Mark-to-market derivatives—Proprietary trading (Exelon and Generation)(a)(b)	$	23	$	45	Discounted Cash Flow	Forward power price	$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 reserve	3%	-	8%	4.93%	3%	-	7%	4.95%
						Renewable factor	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.

The inputs listed above, which are as of the balance sheet date, would have a direct impact on the fair values of the above instruments if they were adjusted. The significant unobservable inputs used in the fair value measurement of Generation’s commodity derivatives are forward commodity prices and for options is price volatility. Increases (decreases) in the forward commodity price in isolation would result in significantly higher (lower) fair values for long positions (contracts that give Generation the obligation or option to purchase a commodity), with offsetting impacts to short positions (contracts that give Generation the obligation or right to sell a commodity). Increases (decreases) in volatility would increase (decrease) the value for the holder of the option (writer of the option). Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of volatility of prices. An increase to the reserves listed above would decrease the fair value of the positions. An increase to the heat rate or renewable factors would increase the fair value accordingly. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets.

Commitments and Contingencies Disclosure [Abstract]

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

+ References + Details

Commitments and Contingencies (All Registrants)

12 Months Ended

Dec. 31, 2020

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 Generation’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 accepting the SNF.

Under 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)Recorded in Accounts receivable, other. Represents amounts owed to the co-owners of Peach Bottom, Quad Cities, and Nine Mile Point Unit 2 generating facilities.

The Standard Contracts with the DOE also required the payment to the DOE of a one-time fee applicable to nuclear generation through April 6, 1983. The below table outlines the SNF liability recorded 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 has 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 investigation and remediation liabilities		Portion of total related to MGP investigation and remediation		Total environmental investigation and remediation liabilities		Portion of total related to MGP investigation and remediation
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 applicable law, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE can pay dividends only from retained, undistributed or current earnings. A significant loss recorded at Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, or ACE may limit the dividends that these companies can distribute to Exelon.

ComEd has agreed in connection with financings arranged through ComEd Financing III that it will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debt securities issued to ComEd Financing III; (2) it defaults on its guarantee of the payment of distributions on the preferred trust securities of ComEd Financing III; or (3) an event of default occurs under the Indenture under which the subordinated debt securities are issued. No such event has occurred.

PECO has agreed in connection with financings arranged through PEC L.P. and PECO Trust IV that PECO will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debentures, which were issued to PEC L.P. or PECO Trust IV; (2) it defaults on its guarantee of the payment of distributions on the Series D Preferred Securities of PEC L.P. or the preferred trust securities of PECO Trust IV; or (3) an event of default occurs under the Indenture under which the subordinated debentures are issued. No such event has occurred.

BGE is subject to restrictions established by the MDPSC that prohibit BGE from paying a dividend on its common shares if (a) after the dividend payment, BGE’s equity ratio would be below 48% as calculated pursuant to the MDPSC’s ratemaking precedents or (b) BGE’s senior unsecured credit rating is rated by two of the three major credit rating agencies below investment grade. No such event has occurred.

Pepco is subject to certain dividend restrictions established by settlements approved in Maryland and the District of Columbia. Pepco is prohibited from paying a dividend on its common shares if (a) after the dividend payment, Pepco's equity ratio would be 48% as equity levels are calculated under the ratemaking precedents of the MDPSC and DCPSC or (b) Pepco’s senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. No such event has occurred.

DPL is subject to certain dividend restrictions established by settlements approved in Delaware and Maryland. DPL is prohibited from paying a dividend on its common shares if (a) after the dividend payment, DPL's equity ratio would be 48% as equity levels are calculated under the ratemaking precedents of the DPSC and MDPSC or (b) DPL’s senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. No such event has occurred.

ACE is subject to certain dividend restrictions established by settlements approved in New Jersey. ACE is prohibited from paying a dividend on its common shares if (a) after the dividend payment, ACE's equity ratio would be 48% as equity levels are calculated under the ratemaking precedents of the NJBPU or (b) ACE's senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. ACE is also subject to a dividend restriction which requires ACE to obtain the prior approval of the NJBPU before dividends can be paid if its equity as a percent of its total capitalization, excluding securitization debt, falls below 30%. No such events have occurred.

City of Everett Tax Increment Financing Agreement (Exelon and Generation). On April 10, 2017, the City of Everett petitioned the Massachusetts Economic Assistance Coordinating Council (EACC) to revoke the 1999 tax increment financing agreement (TIF Agreement) relating to Mystic Units 8 and 9 on the grounds that the total investment in Mystic Units 8 and 9 materially deviates from the investment set forth in the TIF Agreement. On October 31, 2017, a three-member panel of the EACC conducted an administrative hearing on the City’s petition. On November 30, 2017, the hearing panel issued a tentative decision denying the City’s petition, finding that

there was no material misrepresentation that would justify revocation of the TIF Agreement. On December 13, 2017, the tentative decision was adopted by the full EACC. On January 12, 2018, the City filed a complaint in Massachusetts Superior Court requesting, among other things, that the court set aside the EACC’s decision, grant the City’s request to decertify the Project and the TIF Agreement, and award the City damages for alleged underpaid taxes over the period of the TIF Agreement. On January 8, 2020, the Massachusetts Superior Court affirmed the decision of the EACC denying the City's petition. The City had until March 9, 2020 to appeal the decision and did not. As a result, the decision is final and the case is resolved. It is reasonably possible that property taxes assessed in future periods, including those following the expiration of the TIF Agreement on June 30, 2020, could be material to Generation’s financial statements.

Deferred Prosecution Agreement (DPA) and Related Matters (Exelon and ComEd). Exelon and ComEd received a grand jury subpoena in the second quarter of 2019 from the U.S. Attorney’s Office for the Northern District of Illinois (USAO) requiring production of information concerning their lobbying activities in the State of Illinois. On October 4, 2019, Exelon and ComEd received a second grand jury subpoena from the USAO requiring production of records of any communications with certain individuals and entities. On October 22, 2019, the SEC notified Exelon and ComEd that it had also opened an investigation into their lobbying activities. On July 17, 2020, ComEd entered into a DPA with the USAO to resolve the USAO investigation. Under the DPA, the USAO filed a single charge alleging that ComEd improperly gave and offered to give jobs, vendor subcontracts, and payments associated with those jobs and subcontracts for the benefit of the Speaker of the Illinois House of Representatives and the Speaker’s associates, with the intent to influence the Speaker’s action regarding legislation affecting ComEd’s interests. The DPA provides that the USAO will defer any prosecution of such charge and any other criminal or civil case against ComEd in connection with the matters identified therein for a three-year period subject to certain obligations of ComEd, including payment to the U.S. Treasury of $200 million, with $100 million payable within thirty days of the filing of the DPA with the United States District Court for the Northern District of Illinois and an additional $100 million within ninety days of such filing date. The payments were recorded within Operating and maintenance expense in Exelon’s and ComEd’s Consolidated Statements of Operations and Comprehensive Income in the second quarter of 2020. The payments will not be recovered in rates or charged to customers and ComEd will not seek or accept reimbursement or indemnification from any source other than Exelon. Exelon made equity contributions to ComEd of $200 million in 2020. On August 13, 2020, a motion was filed in the U.S. District Court for the Northern District of Illinois by a ComEd customer and on behalf of ComEd customers seeking to enjoin ComEd from paying these funds to the U.S. Treasury and requiring the U.S. government to establish a victims’ restitution fund from which the $200 million would be disbursed to ComEd customers. The motion was denied without prejudice on November 6, 2020 and ComEd submitted the $200 million payment to the U.S. Treasury. On January 6, 2021, the customer petitioned the Seventh Circuit for a writ of mandamus to seek review of the district court’s ruling, but on January 8, 2021, the Seventh Circuit denied the petition. On January 22, 2021, the customer petitioned the Seventh Circuit for rehearing of its denial of his petition for a writ of mandamus. On February 5, 2021, the Seventh Circuit denied the petition for rehearing.

Exelon was not made a party to the DPA, and therefore the investigation by the USAO into Exelon’s activities ended with no charges being brought against Exelon.

The SEC’s investigation remains ongoing and Exelon and ComEd have cooperated fully and intend to continue to cooperate fully with the SEC. Exelon and ComEd cannot predict the outcome of the SEC investigation. No loss contingency has been reflected in Exelon's and ComEd's consolidated financial statements with respect to the SEC investigation, as this contingency is neither probable nor reasonably estimable at this time.

Subsequent to Exelon announcing the receipt of the subpoenas, various lawsuits have been filed and various demand letters have been received related to the subject of the subpoenas, the conduct described in the DPA and the SEC's investigation, including:

•A putative class action lawsuit against Exelon and certain officers of Exelon and ComEd was filed in federal court in December 2019 alleging misrepresentations and omissions in Exelon’s SEC filings related to ComEd’s lobbying activities and the related investigations. The complaint was amended on September 16, 2020, to dismiss two of the original defendants and add other defendants, including ComEd. Defendants filed a motion to dismiss in November 2020. Briefing was completed on February 17, 2021.

•A derivative shareholder lawsuit was filed against Exelon, its directors and certain officers of Exelon and ComEd in April 2020 alleging, among other things, breaches of fiduciary duties also purporting to relate to matters that are the subject of the subpoenas and the SEC investigation. The plaintiff voluntarily dismissed this derivative action without prejudice to refile on July 28, 2020.

•Three putative class action lawsuits against ComEd and Exelon were filed in Illinois state court in the third quarter of 2020 seeking restitution and compensatory damages on behalf of ComEd customers. These three state cases were consolidated into a single action in October of 2020. In addition, on November 2, 2020, the Citizens Utility Board (CUB) filed a motion to intervene in the state cases pursuant to an Illinois statute allowing CUB to intervene as a party or otherwise participate on behalf of utility consumers in any proceeding which affects the interest of utility consumers. On November 23, 2020, the court allowed CUB’s intervention, but denied CUB’s request to stay these cases. Plaintiffs subsequently filed a consolidated complaint, and ComEd and Exelon filed a motion to dismiss on jurisdictional and substantive grounds on January 11, 2021. Briefing on that motion is ongoing.

•Four putative class action lawsuits against ComEd and Exelon were filed in federal court in the third quarter of 2020 alleging, among other things, civil violations of federal racketeering laws. In addition, CUB filed a motion to intervene in these cases on October 22, 2020 which was granted on December 23, 2020. In addition, on December 2, 2020, the court appointed interim lead plaintiffs in the federal cases which consisted of counsel for three of the four federal cases. These plaintiffs filed a consolidated complaint on January 5, 2021. CUB also filed its own complaint against ComEd only on the same day. The remaining federal case, Potter, et al. v. Exelon et al, differed from the other lawsuits as it named additional individual defendants not named in the consolidated complaint. On January 10, 2021, the Potter plaintiffs filed a motion asking the court to clarify that their class action complaint against ComEd, Exelon and the individual named defendants remains in effect, notwithstanding the consolidated amended complaint, and asked the court to stay the Potter case. On January 21, 2021, the court determined that the appointed lead counsel had sole discretion to determine which parties to name as plaintiffs and defendants, and that the Potter plaintiffs have the option to opt-out of that class and file a separate, individual action against the defendants named in their original complaint. The Potter plaintiffs have until March 23, 2021 to make that decision.

•Four shareholders sent letters to the Exelon Board of Directors in 2020 demanding, among other things, that the Exelon Board of Directors investigate and address alleged breaches of fiduciary duties and other alleged violations by Exelon and ComEd officers and directors related to the conduct described in the DPA.

No loss contingencies have been reflected in Exelon’s and ComEd’s consolidated financial statements with respect to these matters, as such contingencies are neither probable nor reasonably estimable at this time.

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

Shareholders' Equity (Exelon and Utility Registrants)

12 Months Ended

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

__________

(a)Includes 4,600,000 shares of unclassified preference securities and 1,900,000 shares of previously redeemed preference securities as of December 31, 2020 and 2019.

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 Grant Date Fair Value (per share)
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 to five years. However, certain restricted stock unit awards become fully vested upon the employee reaching retirement-eligibility. The value of the restricted stock units granted to retirement-eligible employees is either recognized ratably over the first six months in the year of grant if the employee reaches retirement eligibility prior to July 1st of the grant year or through the date of which the employee reaches retirement eligibility. Exelon processes forfeitures as they occur for employees who do not complete the requisite service period.

The following table summarizes Exelon’s nonvested restricted stock unit activity:


	Shares	Weighted Average Grant Date Fair Value (per share)
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 Average Exercise Price (per share)		Weighted Average Remaining Contractual Life (years)	Aggregate Intrinsic Value
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 Comprehensive Income (Exelon)

12 Months Ended

Dec. 31, 2020

Equity [Abstract]

Changes in Accumulated Other Comprehensive Income (Exelon)

The following tables present changes in Exelon's AOCI, net of tax, by component:


	Gains and (Losses) on Cash Flow Hedges		Unrealized Gains and (Losses) on Marketable Securities		Pension and Non-Pension Postretirement Benefit Plan Items (a)		Foreign Currency Items		AOCI of Investments Unconsolidated Affiliates (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 (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 Agreement VIEs		Equity Investment VIEs		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 of 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 Information (All Registrants)

12 Months Ended

Dec. 31, 2020

Supplemental Financial Information [Abstract]

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 Registrants)

12 Months Ended

Dec. 31, 2020

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 December 31,
	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

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.

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 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 December 31,
(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 December 31,
(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

Basis of PresentationExelon Corporate is a holding company that conducts substantially all of its business operations through its subsidiaries. These condensed financial statements and related footnotes have been prepared in accordance with Rule 12-04, Schedule I of Regulation S-X. These statements should be read in conjunction with the consolidated financial statements and notes thereto of Exelon Corporation.Exelon Corporate owns 100% of all of its significant subsidiaries, either directly or indirectly, except for Commonwealth Edison Company (ComEd), of which Exelon Corporate owns more than 99%Debt and Credit Agreements

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.

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 Date	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

Commitments and ContingenciesSee Note 19—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for Exelon Corporate’s commitments and contingencies related to environmental matters and fund transfer restrictions.Related Party Transactions

The financial statements of Exelon Corporate include related party transactions as presented in the tables below:


	For the Years Ended December 31,
(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 Qualifying Accounts

12 Months Ended

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 Beginning of Period		Charged to Costs and Expenses			Charged to Other Accounts			Deductions			Balance at End of Period
(In millions)
For the year ended December 31, 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 Beginning of Period		Charged to Costs and Expenses			Charged to Other Accounts			Deductions			Balance at End of Period
(In millions)
For the year ended December 31, 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 Beginning of Period		Charged to Costs and Expenses			Charged to Other Accounts		Deductions			Balance at End of Period
(In millions)
For the year ended December 31, 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 Beginning of Period		Charged to Costs and Expenses			Charged to Other Accounts		Deductions			Balance at End of Period
(In millions)
For the year ended December 31, 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

__________

(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 Beginning of Period		Charged to Costs and Expenses			Charged to Other Accounts		Deductions			Balance at End of Period
(In millions)
For the year ended December 31, 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 Beginning of Period		Charged to Costs and Expenses			Charged to Other Accounts		Deductions			Balance at End of Period
(In millions)
For the year ended December 31, 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 Beginning of Period		Charged to Costs and Expenses			Charged to Other Accounts		Deductions			Balance at End of Period
(In millions)
For the year ended December 31, 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 Beginning of Period		Charged to Costs and Expenses			Charged to Other Accounts		Deductions			Balance at End of Period
(In millions)
For the year ended December 31, 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 Beginning of Period		Charged to Costs and Expenses			Charged to Other Accounts		Deductions			Balance at End of Period
(In millions)
For the year ended December 31, 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 Policies (Policies)

12 Months Ended

Dec. 31, 2020

Accounting Policies [Abstract]

Business Description and Basis of Presentation (All Registrants)

Description of Business (All Registrants)

Name of Registrant

Business

Service Territories

Exelon Generation
Company, LLC

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
Power Company

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)

Use Of Estimates (All Registrants)

Use of Estimates (All Registrants)

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)

Revenues (All Registrants)

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

Leases (All Registrants)

Income Taxes (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)


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)

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

Inventories (All Registrants)

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.

Property Plant And Equipment (All Registrants)

Property, Plant, and Equipment (All Registrants)

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)

Depreciation, Depletion, and Amortization (All Registrants)

Depreciation and Amortization (All Registrants)

See Note 8 — Property, Plant, and Equipment for additional information regarding depreciation.

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

Derivatives Financial Instruments (All Registrants)

Derivative Financial Instruments (All Registrants)

hedges. See Note 3 — Regulatory Matters and Note 16 — Derivative Financial Instruments for additional information.As part of Generation’s energy marketing business, Generation enters into contracts to buy and sell energy to meet the requirements of its customers. These contracts include short-term and long-term commitments to purchase and sell energy and energy-related products in the energy markets with the intent and ability to deliver or take delivery of the underlying physical commodity. NPNS are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period of time and will not be financially settled. Revenues and expenses on derivative contracts that qualify, and are designated, as NPNS are recognized when the underlying physical transaction is completed. While these contracts are considered derivative financial instruments, they are not required to be recorded at fair value, but rather are recorded on an accrual basis of accounting.

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.

Regulatory Matters (Tables)

12 Months Ended

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

__________

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.

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

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

10.3

Third quarter of 2021

ACE - New Jersey(d)

December 9, 2020

Electric

10.3

Fourth quarter of 2021

_________

(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.

(c)Represents the weighted average debt and equity return on transmission rate bases.

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

(a)

8.38

December 2, 2020

January 1, 2021

_________

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]


	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 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]


	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

__________

Contract Liabilities [Member]

Contract Asset/Liabilities [Line Items]

Contract with Customer, Contract Asset, Contract Liability, and Receivable [Table Text Block]


	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

__________

Segment Information (Tables)

12 Months Ended

Dec. 31, 2020

Segment Reporting [Abstract]

Analysis and reconciliation of reportable segment information



	Generation		ComEd		PECO		BGE		PHI		Other(a)		Intersegment Eliminations		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 Eliminations		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 Eliminations		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.

PHI:


	Pepco		DPL		ACE		Other(a)		Intersegment Eliminations		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 Eliminations		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.

(c)Includes intersegment revenues with ComEd, BGE, and PECO, which are eliminated at Exelon.

Analysis and reconciliation of reportable segment revenues for Generation

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.

Revenues net of purchased power and fuel expense (Generation):


	2020						2019						2018
	RNF from external customers(a)		Intersegment RNF		Total RNF		RNF from external customers(a)		Intersegment RNF		Total RNF		RNF from external customers(a)		Intersegment RNF		Total RNF
Mid-Atlantic	$	2,174	$	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 gains of $295 million and losses of $215 million and $319 million for the years ended December 31, 2020, 2019, and 2018, respectively;

•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)

12 Months Ended

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

_________

(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


	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)

12 Months Ended

Dec. 31, 2020

Implications of Potential Early Plant Retirements [Abstract]

Restructuring and Related Costs [Table Text Block]


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.

Implications of Potential Early Plant Retirement on Balance Sheet [Table Text Block]


	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 (Tables)

12 Months Ended

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


	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 Utility Plant (Tables)

12 Months Ended

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 Bottom			Salem			Nine Mile Point Unit 2			NJ/DE(a)
Operator	Generation			Generation			PSEG Nuclear			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			—

__________

Asset Retirement Obligations (Tables)

12 Months Ended

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

__________

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.

Leases (Tables)

12 Months Ended

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

__________

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

__________


	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)

12 Months Ended

Dec. 31, 2020

Finite-Lived Intangible Assets [Line Items]

Schedule Of Goodwill


	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


	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)

__________

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)

12 Months Ended

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.

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 unamortized investment tax credits	$	(12,327)	$	(3,740)	$	(4,021)	$	(2,081)	$	(1,396)	$	(2,265)	$	(1,131)	$	(655)	$	(577)

Summary of Loss Carryforwards


	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

__________

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

__________

Summary of Positions for which Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Table Text Block]


	Exelon		Generation		PHI(a)



December 31, 2020	$	73	$	39	$	33
December 31, 2019	462		429		32
December 31, 2018	463		408		31

__________

Long-Term Marginal State Income Tax Rate [Table Text Block]


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


Net interest and penalties receivable as of	Exelon
December 31, 2020	$	314
December 31, 2019	318

Retirement Benefits (Tables)

12 Months Ended

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


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]


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]




	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]


	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

__________

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

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

__________

(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		—


	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 Benefits		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]


	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.

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 Credit		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 reporting date	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 Credit		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.

Schedule Of Defined Contributions [Table Text Block]


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 Instruments (Tables)

12 Months Ended

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 Derivatives		Economic Hedges		Proprietary Trading		Collateral (a)(b)		Netting(a)		Subtotal		Economic Hedges
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)

_________

(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]


Rating as of December 31, 2020	Total Exposure Before Credit Collateral		Credit Collateral(a)		Net Exposure		Number of Counterparties Greater than 10% of Net Exposure	Net Exposure of Counterparties Greater than 10% of Net Exposure
Investment grade	$	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

__________

Fair Value of Derivatives with Credit- Risk Related Contingent Features [Table Text Block] [Table Text Block]


	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.

Cash Collateral and Letters of Credit on Derivative Contracts [Table Text Block]


	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

Schedule of commercial paper, credit facilities, and borrowing rates

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

+ References + Details

Debt and Credit Agreements (Tables)

12 Months Ended

Dec. 31, 2020

Short-term Debt [Line Items]


	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

200

Generation(c)

October 25, 2019

N/A

100

Generation(c)

November 20, 2019

N/A

300

Generation(c)

November 21, 2019

N/A

150

Generation(c)

November 21, 2019

N/A

November 21, 2021

100

Generation(c)

May 15, 2020

N/A

100

__________

(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 Date	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

__________

(b)Amounts owed to these financing trusts are recorded as Long-term debt to financing trusts within Exelon’s Consolidated Balance Sheets.

Generation


						Maturity Date	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 Date	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 Date	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 Date	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 Date	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 Date	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 Date	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 Date	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 Program Size at December 31,				Outstanding Commercial Paper at December 31,				Average Interest Rate on Commercial Paper Borrowings at December 31,
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	%

__________

(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 Commitment(b)		Facility Draws		Outstanding Letters of Credit		Actual		To Support Additional Commercial Paper(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.

Tabular disclosure of long-debt instruments or arrangements, including identification, terms, features, collateral requirements and other information necessary to a fair presentation. These are debt arrangements that originally required repayment more than twelve months after issuance or greater than the normal operating cycle of the entity, if longer.

Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.22)
-URI http://asc.fasb.org/extlink&oid=120391452&loc=d3e13212-122682

Reference 2: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=119993939&loc=d3e28541-108399

Reference 3: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=109259400&loc=d3e21506-112644

Reference 4: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(e),(f))
-URI http://asc.fasb.org/extlink&oid=120395691&loc=d3e23780-122690

Reference 5: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=119993939&loc=d3e28551-108399

Reference 6: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 7
-URI http://asc.fasb.org/extlink&oid=109259400&loc=d3e21521-112644

Reference 7: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=109259400&loc=d3e21538-112644

Reference 8: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 942
-SubTopic 470
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=75038535&loc=d3e64711-112823

Reference 9: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 55
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=114775985&loc=d3e28878-108400

Reference 10: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=109259400&loc=d3e21475-112644

Fair Value of Financial Liabilities Recorded at Amortized Cost

Fair Value of Financial Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2020

Fair Value Disclosures [Abstract]


	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

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

__________

(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.

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

__________

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

__________

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 Derivatives			Total Generation		Mark-to-Market Derivatives			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 Derivatives			Total Generation		Mark-to-Market Derivatives			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	$	—

__________

Total Realized and Unrealized Gains (Losses) Included in Income for Level 3 Assets and Liabilities Measured at Fair Value on a Recurring Basis



	Exelon								Generation						PHI and Pepco
	Operating Revenues		Purchased Power and Fuel		Operating and Maintenance		Other, net		Operating Revenues		Purchased Power and Fuel		Other, net		Operating and Maintenance

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 Revenues		Purchased Power and Fuel		Operating and Maintenance		Other, net		Operating Revenues		Purchased Power and Fuel		Other, net		Operating and Maintenance

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 Technique	Unobservable Input	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 price	$2.25	-	$163	$30	$9	-	$180	$29
						Forward gas price	$1.57	-	$7.88	$2.59	$0.83	-	$10.72	$2.55
					Option Model	Volatility percentage	11%	-	237%	32%	8%	-	236%	70%

Mark-to-market derivatives—Proprietary trading (Exelon and Generation)(a)(b)	$	23	$	45	Discounted Cash Flow	Forward power price	$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 reserve	3%	-	8%	4.93%	3%	-	7%	4.95%
						Renewable factor	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.

Commitments and Contingencies (Tables)

12 Months Ended

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.

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

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

__________

Accrued environmental liabilities


	December 31, 2020				December 31, 2019
	Total environmental investigation and remediation liabilities		Portion of total related to MGP investigation and remediation		Total environmental investigation and remediation liabilities		Portion of total related to MGP investigation and remediation
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)

12 Months Ended

Dec. 31, 2020

Restructuring and Related Activities [Abstract]

Severance


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.

Shareholders' Equity (Tables)

12 Months Ended

Dec. 31, 2020

Shareholder [Abstract]

Common Stock Warrants [Table Text Block]


	December 31,
	2020	2019
Warrants outstanding	60,143	60,228
Common Stock reserved for conversion	20,048	20,076

Preferred Stock [Table Text Block]


			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.

Preference Securities [Table Text Block]


			Preference Securities Authorized
ComEd			6,810,451
BGE(a)			6,500,000
ACE			3,000,000

__________

(a)Includes 4,600,000 shares of unclassified preference securities and 1,900,000 shares of previously redeemed preference securities as of December 31, 2020 and 2019.

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]


	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 Grant Date Fair Value (per share)
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

__________

Schedule of Nonvested Restricted Stock Units Activity

The following table summarizes Exelon’s nonvested restricted stock unit activity:


	Shares	Weighted Average Grant Date Fair Value (per share)
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

__________

Schedule of Share-based Compensation, Stock Options, Activity

The following table presents information with respect to stock option activity:


	Shares	Weighted Average Exercise Price (per share)		Weighted Average Remaining Contractual Life (years)	Aggregate Intrinsic Value
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 Comprehensive Income (Tables)

12 Months Ended

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 (Losses) on Cash Flow Hedges		Unrealized Gains and (Losses) on Marketable Securities		Pension and Non-Pension Postretirement Benefit Plan Items (a)		Foreign Currency Items		AOCI of Investments Unconsolidated Affiliates (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)

__________

(b)All amounts are net of noncontrolling interests.

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 (Tables)

12 Months Ended

Dec. 31, 2020

Variable Interest Entity [Abstract]

Consolidated VIEs- Assets and Liabilities


	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.

liabilities as held for sale. Refer to Note 2 — Mergers, Acquisitions, and Dispositions for additional information on the sale of the solar business.

(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 Agreement VIEs		Equity Investment VIEs		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

__________

Supplemental Financial Information (Tables)

12 Months Ended

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

__________

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.

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)

__________

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


	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 (Tables)

12 Months Ended

Dec. 31, 2020


	For the Years Ended December 31,
	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.

(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.

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

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

__________

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

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 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 Dispositions - Narrative (Details) $ in Millions			12 Months Ended
	Feb. 28, 2018 USD ($)	Apr. 01, 2014 USD ($)	Dec. 31, 2020 USD ($) MW	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Dec. 08, 2020 USD ($)
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 (Details) - USD ($)	7 Months Ended	12 Months Ended				36 Months Ended	48 Months Ended		60 Months Ended	72 Months Ended
Regulatory Matters- Narrative (Details) - USD ($)	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]
Regulatory Matters Additional Narrative Information [Line Items]
Purchase Obligation												$ 170,000,000
Atlantic City Electric Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Proposed Capital Expenditure											$ 220,000,000
Maximum [Member] \| Exelon Generation Co L L C [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Purchase Obligation				$ 14,000,000
Minimum [Member] \| Exelon Generation Co L L C [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Purchase Obligation				11,000,000
Illinois Utilities [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Purchase Obligation												$ 235,000,000
Energy Commodities and Service [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax		$ 16,400,000,000	$ 17,754,000,000	19,168,000,000
Energy Commodities and Service [Member] \| Exelon Generation Co L L C [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax		16,392,000,000	17,752,000,000	$ 19,169,000,000
Zero Emission Standard [Member] \| Energy Commodities and Service [Member] \| Exelon Generation Co L L C [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	$ 150,000,000
Clean Energy Legislation [Member] \| Exelon Generation Co L L C [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Competitive businesses other revenues		69,000,000	$ 53,000,000
Conowingo [Member] \| Exelon Generation Co L L C [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Environmental Costs Recognized, Capitalized		45,000,000
Forecast [Member] \| Baltimore Gas and Electric Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Proposed Capital Expenditure									$ 732,000,000
Payments to Acquire Property, Plant, and Equipment									$ 200,000,000
Forecast [Member] \| Potomac Electric Power Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Proposed Capital Expenditure		$ 30,000,000				$ 70,000,000				$ 500,000,000
Forecast [Member] \| Atlantic City Electric Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Proposed Capital Expenditure								$ 338,000,000
Payments to Acquire Property, Plant, and Equipment							$ 96,000,000
ILLINOIS \| Exelon Generation Co L L C [Member]
Regulatory Matters Additional Narrative Information [Line Items]
exc_ZECChargeperMWh					$ 16.50

Regulatory Matters - Schedule of Completed Rate Cases (Details) - USD ($) $ in Millions											12 Months Ended
	Jan. 06, 2021	Dec. 16, 2020	Dec. 09, 2020	Oct. 09, 2020	Sep. 11, 2020	Jul. 14, 2020	Apr. 23, 2020	Apr. 16, 2020	Dec. 04, 2019	Apr. 08, 2019	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Commonwealth Edison Co [Member] \| Illinois 2019 Electric Distribution Base Rate Case
Regulatory Matters Completed Rate Cases [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount										$ (6)
Public Utilities, Approved Rate Increase (Decrease), Amount									$ (17)							$ (68)
Public Utilities, Approved Return on Equity, Percentage									8.91%
Basis points for ComEd's Revenue Requirement															580
Public Utilities, Approved Equity Capital Structure, Percentage															6.51%
Public Utilities, Interim Rate Increase (Decrease), Amount															$ 51
Commonwealth Edison Co [Member] \| Illinois 2020 Electric Distribution Base Rate Case
Regulatory Matters Completed Rate Cases [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount								$ (11)
Public Utilities, Approved Rate Increase (Decrease), Amount			$ (14)												$ (64)
Public Utilities, Approved Return on Equity, Percentage			8.38%
Basis points for ComEd's Revenue Requirement														580
Public Utilities, Approved Equity Capital Structure, Percentage														6.28%
Public Utilities, Interim Rate Increase (Decrease), Amount														$ 50
Baltimore Gas and Electric Company [Member] \| Maryland 2020 Electric Distribution Base Rate Case [Member]
Regulatory Matters Completed Rate Cases [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount					$ 137
Public Utilities, Approved Rate Increase (Decrease), Amount		$ 81
Public Utilities, Approved Return on Equity, Percentage		9.50%
Public Utilities, Interim Rate Increase (Decrease), Amount											$ 42	$ 39	$ 59
Baltimore Gas and Electric Company [Member] \| Maryland 2020 Gas Distribution Base Rate Case [Member]
Regulatory Matters Completed Rate Cases [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount					$ 91
Public Utilities, Approved Rate Increase (Decrease), Amount		$ 21
Public Utilities, Approved Return on Equity, Percentage		9.65%
Public Utilities, Interim Rate Increase (Decrease), Amount											$ 10	$ 11	$ 53
Delmarva Power & Light Company [Member] \| Maryland 2019 Electric Distribution Base Rate Case
Regulatory Matters Completed Rate Cases [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount							$ 17
Public Utilities, Approved Rate Increase (Decrease), Amount						$ 12
Public Utilities, Approved Return on Equity, Percentage						9.60%
Delmarva Power & Light Company [Member] \| Delaware 2020 Gas Distribution Base Rate Case
Regulatory Matters Completed Rate Cases [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount				$ 7
Public Utilities, Approved Rate Increase (Decrease), Amount	$ 2
Public Utilities, Approved Return on Equity, Percentage	9.60%

Regulatory Matters - Schedule of Pending Rate Cases (Details) - USD ($) $ in Millions	Feb. 02, 2021	Dec. 09, 2020	Oct. 26, 2020	Oct. 09, 2020	Sep. 30, 2020	Jun. 01, 2020
Pennsylvania 2020 Natural Gas Distribution Base Rate Case \| PECO Energy Co [Member]
Regulatory Matters Pending Rate Cases [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount					$ 69
Public Utilities, Requested Return on Equity, Percentage					10.95%
District of Columbia 2019 Electric Distribution Base Rate Case \| Potomac Electric Power Company [Member]
Regulatory Matters Pending Rate Cases [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount						$ 136
Public Utilities, Requested Return on Equity, Percentage						9.70%
District of Columbia 2019 Electric Distribution Base Rate Case \| Potomac Electric Power Company [Member] \| 2022 [Member]
Regulatory Matters Pending Rate Cases [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount						$ 73
District of Columbia 2019 Electric Distribution Base Rate Case \| Potomac Electric Power Company [Member] \| 2023 [Member]
Regulatory Matters Pending Rate Cases [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount						$ 63
Maryland 2020 Electric Distribution Base Rate Case [Member] \| Potomac Electric Power Company [Member]
Regulatory Matters Pending Rate Cases [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount			$ 110
Public Utilities, Requested Return on Equity, Percentage			10.20%
Maryland 2020 Electric Distribution Base Rate Case [Member] \| Potomac Electric Power Company [Member] \| 2023 [Member]
Regulatory Matters Pending Rate Cases [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount			$ 56
Maryland 2020 Electric Distribution Base Rate Case [Member] \| Potomac Electric Power Company [Member] \| 2024 [Member]
Regulatory Matters Pending Rate Cases [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount			$ 54
Delaware 2020 Gas Distribution Base Rate Case \| Delmarva Power & Light Company [Member]
Regulatory Matters Pending Rate Cases [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount				$ 7
Delaware 2020 Electric Distribution Base Rate Case \| Delmarva Power & Light Company [Member]
Regulatory Matters Pending Rate Cases [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount	$ 23
Public Utilities, Requested Return on Equity, Percentage	10.30%
New Jersey 2020 Electric Distribution Base Rate Case \| Atlantic City Electric Company [Member]
Regulatory Matters Pending Rate Cases [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount		$ 67
Public Utilities, Requested Return on Equity, Percentage		10.30%

Regulatory Matters - Annual Electric Transmission Filings (Details) $ in Millions		12 Months Ended
	May 15, 2020 USD ($)	Dec. 31, 2020 USD ($)
Commonwealth Edison Co [Member]
Public Utilities, General Disclosures [Line Items]
Additional basis points for RTO membership incentive		50
PECO Energy Co [Member]
Public Utilities, General Disclosures [Line Items]
Additional basis points for RTO membership incentive		50
Baltimore Gas and Electric Company [Member]
Public Utilities, General Disclosures [Line Items]
Additional basis points for RTO membership incentive	50
Potomac Electric Power Company [Member]
Public Utilities, General Disclosures [Line Items]
Additional basis points for RTO membership incentive		50
Delmarva Power & Light Company [Member]
Public Utilities, General Disclosures [Line Items]
Additional basis points for RTO membership incentive		50
Atlantic City Electric Company [Member]
Public Utilities, General Disclosures [Line Items]
Additional basis points for RTO membership incentive		50
2020 Transmission Formula Rate Annual Update [Domain] \| Commonwealth Edison Co [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount		$ 18
Annual Reconciliation Increase (Decrease)		(4)
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount		$ 14
Public Utilities, Approved Equity Capital Structure, Percentage		8.17%
Public Utilities, Approved Return on Equity, Percentage		11.50%
Cap on Equity Component of Rate of Return on Common Equity in Federal Energy Regulatory Committee Complaint		55.00%
2020 Transmission Formula Rate Annual Update [Domain] \| PECO Energy Co [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount		$ 5
Annual Reconciliation Increase (Decrease)		(28)
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount		$ (23)
Public Utilities, Approved Equity Capital Structure, Percentage		7.47%
Public Utilities, Approved Return on Equity, Percentage		10.35%
Cap on Equity Component of Rate of Return on Common Equity in Federal Energy Regulatory Committee Complaint		55.75%
2020 Transmission Formula Rate Annual Update [Domain] \| Baltimore Gas and Electric Company [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount		$ 16
Annual Reconciliation Increase (Decrease)		(3)
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount		$ 4
Public Utilities, Approved Equity Capital Structure, Percentage		7.26%
Public Utilities, Approved Return on Equity, Percentage		10.50%
2020 Transmission Formula Rate Annual Update [Domain] \| Potomac Electric Power Company [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount		$ 2
Annual Reconciliation Increase (Decrease)		(46)
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount		$ (44)
Public Utilities, Approved Equity Capital Structure, Percentage		7.81%
Public Utilities, Approved Return on Equity, Percentage		10.50%
2020 Transmission Formula Rate Annual Update [Domain] \| Delmarva Power & Light Company [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount		$ (4)
Annual Reconciliation Increase (Decrease)		(40)
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount		$ (44)
Public Utilities, Approved Equity Capital Structure, Percentage		7.20%
Public Utilities, Approved Return on Equity, Percentage		10.50%
2020 Transmission Formula Rate Annual Update [Domain] \| Atlantic City Electric Company [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount		$ 5
Annual Reconciliation Increase (Decrease)		(25)
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount		$ (20)
Public Utilities, Approved Equity Capital Structure, Percentage		7.40%
Public Utilities, Approved Return on Equity, Percentage		10.50%
2020 Transmission Formula Rate Revenue Reduction [Member] \| Baltimore Gas and Electric Company [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount	$ 9

Regulatory Matters - Energy Efficiency Formula Rate (Details) - ComEd 2020 Energy Efficiency Formula Rate [Domain] - Commonwealth Edison Co [Member] - USD ($) $ in Millions			12 Months Ended
	Dec. 02, 2020	May 21, 2020	Dec. 31, 2020	Dec. 31, 2019
Schedule of Energy Efficiency Formula Rate Updates [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount		$ 48
Public Utilities, Approved Rate Increase (Decrease), Amount	$ 48		$ 45	$ 3
Public Utilities, Requested Equity Capital Structure, Percentage	6.28%
Public Utilities, Approved Return on Equity, Percentage	8.38%			8.96%
Basis points for ComEd's Revenue Requirement	580
Public Utilities, Approved Equity Capital Structure, Percentage				6.56%

Regulatory Matters - Capitalized Ratemaking Amounts Not Recognized (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Public Utilities, Amount of Allowance for Earnings on Equity Capitalized for Rate Making Purposes	$ 51	$ 63
Commonwealth Edison Co [Member]
Public Utilities, Amount of Allowance for Earnings on Equity Capitalized for Rate Making Purposes	(1)	3
PECO Energy Co [Member]
Public Utilities, Amount of Allowance for Earnings on Equity Capitalized for Rate Making Purposes	0	0
Baltimore Gas and Electric Company [Member]
Public Utilities, Amount of Allowance for Earnings on Equity Capitalized for Rate Making Purposes	45	53
Pepco Holdings LLC [Member]
Public Utilities, Amount of Allowance for Earnings on Equity Capitalized for Rate Making Purposes	7	7
Potomac Electric Power Company [Member]
Public Utilities, Amount of Allowance for Earnings on Equity Capitalized for Rate Making Purposes	4	4
Delmarva Power & Light Company [Member]
Public Utilities, Amount of Allowance for Earnings on Equity Capitalized for Rate Making Purposes	3	3
Atlantic City Electric Company [Member]
Public Utilities, Amount of Allowance for Earnings on Equity Capitalized for Rate Making Purposes	$ 0	$ 0

Revenue from Contracts with Customers - Contract Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Contract Assets [Roll Forward]
Beginning Balance - Contract Assets	$ 174	$ 187
Amounts reclassified to receivables, contract assets	(86)	(143)
Revenues recognized, contract assets	68	130
Contract with Customer, Asset, Increase (Decrease) for Contract Acquired in Business Combination	(12)
Ending Balance - Contract Assets	144	174
Exelon Generation Co L L C [Member]
Contract Assets [Roll Forward]
Beginning Balance - Contract Assets	174	187
Amounts reclassified to receivables, contract assets	(86)	(143)
Revenues recognized, contract assets	68	130
Contract with Customer, Asset, Increase (Decrease) for Contract Acquired in Business Combination	(12)
Ending Balance - Contract Assets	$ 144	$ 174

Revenue from Contracts with Customers - Contract Liabilities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Contract Liabilities [Roll Forward]
Beginning Balance - Contract Liabilities	$ 33	$ 27	$ 35
Contract with Customer, Liability, Cumulative Catch-up Adjustment to Revenue, Modification of Contract	219	94	179
Contract with Customer, Liability, Revenue Recognized	(98)	(88)	(187)
Contract with Customer, Liability, Increase (Decrease) for Contract Acquired in Business Combination	(3)
Ending Balance - Contract Liabilities	151	33	27
Exelon Generation Co L L C [Member]
Contract Liabilities [Roll Forward]
Beginning Balance - Contract Liabilities	71	42	35
Contract with Customer, Liability, Cumulative Catch-up Adjustment to Revenue, Modification of Contract	282	287	465
Contract with Customer, Liability, Revenue Recognized	(266)	(258)	(458)
Contract with Customer, Liability, Increase (Decrease) for Contract Acquired in Business Combination	(3)
Ending Balance - Contract Liabilities	84	71	42
Pepco Holdings LLC [Member]
Contract Liabilities [Roll Forward]
Beginning Balance - Contract Liabilities	0	0	0
Contract with Customer, Liability, Cumulative Catch-up Adjustment to Revenue, Modification of Contract	122	0	0
Contract with Customer, Liability, Revenue Recognized	(4)	0	0
Contract with Customer, Liability, Increase (Decrease) for Contract Acquired in Business Combination	0
Ending Balance - Contract Liabilities	118	0	0
Potomac Electric Power Company [Member]
Contract Liabilities [Roll Forward]
Beginning Balance - Contract Liabilities	0	0	0
Contract with Customer, Liability, Cumulative Catch-up Adjustment to Revenue, Modification of Contract	98	0	0
Contract with Customer, Liability, Revenue Recognized	(4)	0	0
Contract with Customer, Liability, Increase (Decrease) for Contract Acquired in Business Combination	0
Ending Balance - Contract Liabilities	94	0	0
Delmarva Power & Light Company [Member]
Contract Liabilities [Roll Forward]
Beginning Balance - Contract Liabilities	0	0	0
Contract with Customer, Liability, Cumulative Catch-up Adjustment to Revenue, Modification of Contract	12	0	0
Contract with Customer, Liability, Revenue Recognized	0	0	0
Contract with Customer, Liability, Increase (Decrease) for Contract Acquired in Business Combination	0
Ending Balance - Contract Liabilities	12	0	0
Atlantic City Electric Company [Member]
Contract Liabilities [Roll Forward]
Beginning Balance - Contract Liabilities	0	0	0
Contract with Customer, Liability, Cumulative Catch-up Adjustment to Revenue, Modification of Contract	12	0	0
Contract with Customer, Liability, Revenue Recognized	0	0	0
Contract with Customer, Liability, Increase (Decrease) for Contract Acquired in Business Combination	0
Ending Balance - Contract Liabilities	$ 12	$ 0	$ 0

Revenue from Contracts with Customers - Prior Year Contract Revenues Recognized in Current Year (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Prior Year Revenue Recognized [Line Items]
Contract with Customer, Performance Obligation Satisfied in Previous Period	$ 27	$ 18	$ 11
Exelon Generation Co L L C [Member]
Prior Year Revenue Recognized [Line Items]
Contract with Customer, Performance Obligation Satisfied in Previous Period	$ 64	$ 32	$ 11

Segment Information - Narrative (Details)	12 Months Ended
Segment Information - Narrative (Details)	Dec. 31, 2020 Reportable_segment
Segment Reporting Information [Line Items]
Number of reportable segments	11
Exelon Generation Co L L C [Member]
Segment Reporting Information [Line Items]
Number of reportable segments	5
Pepco Holdings LLC [Member]
Segment Reporting Information [Line Items]
Number of reportable segments	3

Segment Information - Reconciliation to Consolidated Financial Statements (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2020

Dec. 31, 2019

Dec. 31, 2018

$ 33,039

$ 34,438

$ 35,978

5,014

4,252

4,353

30,240

30,096

32,143

1,635

1,616

1,554

2,333

3,985

2,225

373

774

118

1,954

3,028

2,079

8,048

7,248

7,594

^[1]

129,317

124,977

17,603

18,924

20,437

1,211

1,172

1,268

836

1,917

365

249

516

(108)

579

1,217

443

1,747

1,845

2,242

^[2]

48,094

48,995

PECO Energy Co [Member]

3,058

3,100

3,038

417

593

466

(30)

447

528

460

1,147

939

849

PECO Energy Co [Member] | Rate-Regulated Electric Revenues [Member]

12,531

11,469

4,663

4,806

4,798

418

514

425

(77)

495

477

393

1,604

1,355

1,375

Operating Segments [Member]

23,736

22,719

33,039

34,438

35,978

1,954

3,028

2,079

Intersegment Eliminations [Member]

129,317

124,977

(3,322)

(3,166)

(3,294)

(3,270)

(3,154)

(3,341)

(3)

(2)

(1)

(2)

(1)

Intersegment Eliminations [Member] | Pepco Holdings LLC [Member]

(10,165)

(10,089)

(374)

(396)

(437)

(375)

(397)

(437)

(375)

(396)

(435)

Exelon Generation Co L L C [Member] | Operating Segments [Member]

(33)

(40)

17,603

18,924

20,437

2,123

1,535

1,797

17,358

17,628

19,510

357

429

432

836

1,917

365

249

516

(108)

579

1,217

443

1,747

1,845

2,242

Exelon Generation Co L L C [Member] | Intersegment Eliminations [Member]

48,094

48,995

Commonwealth Edison Co [Member] | Operating Segments [Member]

1,211

1,172

1,269

5,904

5,747

5,882

1,133

1,033

940

4,950

4,580

4,741

382

359

347

615

851

832

177

163

168

438

688

664

2,217

1,915

2,126

Commonwealth Edison Co [Member] | Intersegment Eliminations [Member]

34,466

32,765

PECO Energy Co [Member] | Operating Segments [Member]

3,058

3,100

3,038

347

333

301

2,512

2,388

2,452

147

136

129

417

593

466

(30)

447

528

460

1,147

939

849

PECO Energy Co [Member] | Intersegment Eliminations [Member]

12,531

11,469

Baltimore Gas and Electric Company [Member] | Operating Segments [Member]

3,098

3,106

3,169

550

502

483

2,598

2,574

2,696

133

121

106

390

439

387

349

360

313

1,247

1,145

959

Baltimore Gas and Electric Company [Member] | Intersegment Eliminations [Member]

11,650

10,634

Pepco Holdings LLC [Member] | Operating Segments [Member]

4,663

4,806

4,798

782

754

740

4,045

4,084

4,156

268

263

261

418

514

425

(77)

495

477

393

1,604

1,355

1,375

Pepco Holdings LLC [Member] | Intersegment Eliminations [Member]

23,736

22,719

Potomac Electric Power Company [Member] | Operating Segments [Member]

2,149

2,260

2,232

377

374

385

1,799

1,899

1,919

138

133

128

259

216

(7)

266

243

205

773

626

656

Potomac Electric Power Company [Member] | Intersegment Eliminations [Member]

9,264

8,661

Delmarva Power & Light Company [Member] | Operating Segments [Member]

1,271

1,306

1,332

191

184

182

1,120

1,089

1,143

100

169

142

(25)

125

147

120

424

348

364

Delmarva Power & Light Company [Member] | Intersegment Eliminations [Member]

5,140

4,830

Atlantic City Electric Company [Member] | Operating Segments [Member]

1,245

1,240

1,236

180

157

136

1,123

1,089

1,087

(41)

112

401

375

335

Atlantic City Electric Company [Member] | Intersegment Eliminations [Member]

4,286

3,933

Corporate and Other [Member] | Corporate, Non-Segment [Member]

2,035

1,921

1,948

2,047

1,996

1,929

351

308

279

(343)

(327)

(249)

(87)

(55)

(354)

(240)

(193)

Corporate and Other [Member] | Corporate, Non-Segment [Member] | Pepco Holdings LLC [Member]

9,005

8,484

372

396

435

378

403

442

(12)

(13)

(20)

(4)

(12)

(8)

(12)

(7)

Corporate and Other [Member] | Corporate, Non-Segment [Member] | Pepco Holdings LLC [Member] | Revision of Prior Period, Adjustment [Member]

5,079

5,335

489

408

Corporate and Other [Member] | Intersegment Eliminations [Member]

5,700

Corporate and Other [Member] | Intersegment Eliminations [Member] | Pepco Holdings LLC [Member]

2,024

1,913

1,942

Segment Elimination [Member] | Intersegment Eliminations [Member]

372

396

435

Electricity, Generation [Member] | Operating Segments [Member]

(3,314)

(3,159)

(3,289)

Revenue from Contract with Customer, Including Assessed Tax

13,864

15,120

16,155

Electricity, Generation [Member] | Intersegment Eliminations [Member]

Revenue from Contract with Customer, Including Assessed Tax

(1,196)

(1,165)

(1,256)

Electricity, Generation [Member] | Exelon Generation Co L L C [Member] | Operating Segments [Member]

Revenue from Contract with Customer, Including Assessed Tax

15,060

16,285

17,411

Electricity, Generation [Member] | Commonwealth Edison Co [Member] | Operating Segments [Member]

Revenue from Contract with Customer, Including Assessed Tax

Electricity, Generation [Member] | PECO Energy Co [Member] | Operating Segments [Member]

Revenue from Contract with Customer, Including Assessed Tax

Electricity, Generation [Member] | Baltimore Gas and Electric Company [Member] | Operating Segments [Member]

Revenue from Contract with Customer, Including Assessed Tax

Electricity, Generation [Member] | Pepco Holdings LLC [Member] | Operating Segments [Member]

Revenue from Contract with Customer, Including Assessed Tax

Electricity, Generation [Member] | Corporate and Other [Member] | Corporate, Non-Segment [Member]

Revenue from Contract with Customer, Including Assessed Tax

Oil and Gas, Purchased [Member] | Operating Segments [Member]

Revenue from Contract with Customer, Including Assessed Tax

2,000

2,147

2,710

Oil and Gas, Purchased [Member] | Intersegment Eliminations [Member]

Revenue from Contract with Customer, Including Assessed Tax

(3)

(1)

(8)

Oil and Gas, Purchased [Member] | Exelon Generation Co L L C [Member] | Operating Segments [Member]

Revenue from Contract with Customer, Including Assessed Tax

2,003

2,148

2,718

Oil and Gas, Purchased [Member] | Commonwealth Edison Co [Member] | Operating Segments [Member]

Revenue from Contract with Customer, Including Assessed Tax

Oil and Gas, Purchased [Member] | PECO Energy Co [Member] | Operating Segments [Member]

Revenue from Contract with Customer, Including Assessed Tax

Oil and Gas, Purchased [Member] | Baltimore Gas and Electric Company [Member] | Operating Segments [Member]

Revenue from Contract with Customer, Including Assessed Tax

Oil and Gas, Purchased [Member] | Pepco Holdings LLC [Member] | Operating Segments [Member]

Revenue from Contract with Customer, Including Assessed Tax

Oil and Gas, Purchased [Member] | Corporate and Other [Member] | Corporate, Non-Segment [Member]

Revenue from Contract with Customer, Including Assessed Tax

Other Revenues [Member] | Operating Segments [Member]

Other Revenues [Member] | Intersegment Eliminations [Member]

536

487

303

Other Revenues [Member] | Exelon Generation Co L L C [Member] | Operating Segments [Member]

(4)

(5)

Other Revenues [Member] | Commonwealth Edison Co [Member] | Operating Segments [Member]

540

491

308

Other Revenues [Member] | PECO Energy Co [Member] | Operating Segments [Member]

Other Revenues [Member] | Baltimore Gas and Electric Company [Member] | Operating Segments [Member]

Other Revenues [Member] | Pepco Holdings LLC [Member] | Operating Segments [Member]

Other Revenues [Member] | Corporate and Other [Member] | Corporate, Non-Segment [Member]

Electricity, US Regulated [Member] | PECO Energy Co [Member]

Revenue from Contract with Customer, Including Assessed Tax

2,519

2,505

2,469

Electricity, US Regulated [Member] | Pepco Holdings LLC [Member]

Revenue from Contract with Customer, Including Assessed Tax

4,463

4,639

4,609

Electricity, US Regulated [Member] | Operating Segments [Member]

Revenue from Contract with Customer, Including Assessed Tax

15,207

15,195

15,337

Electricity, US Regulated [Member] | Intersegment Eliminations [Member]

Revenue from Contract with Customer, Including Assessed Tax

(61)

(47)

(45)

Electricity, US Regulated [Member] | Intersegment Eliminations [Member] | Pepco Holdings LLC [Member]

Revenue from Contract with Customer, Including Assessed Tax

(18)

(13)

(17)

Electricity, US Regulated [Member] | Exelon Generation Co L L C [Member] | Operating Segments [Member]

Revenue from Contract with Customer, Including Assessed Tax

Electricity, US Regulated [Member] | Commonwealth Edison Co [Member] | Operating Segments [Member]

Revenue from Contract with Customer, Including Assessed Tax

5,904

5,747

5,882

Electricity, US Regulated [Member] | PECO Energy Co [Member] | Operating Segments [Member]

Revenue from Contract with Customer, Including Assessed Tax

2,543

2,490

2,470

Electricity, US Regulated [Member] | Baltimore Gas and Electric Company [Member] | Operating Segments [Member]

Revenue from Contract with Customer, Including Assessed Tax

2,336

2,379

2,428

Electricity, US Regulated [Member] | Pepco Holdings LLC [Member] | Operating Segments [Member]

Revenue from Contract with Customer, Including Assessed Tax

4,485

4,626

4,602

Electricity, US Regulated [Member] | Potomac Electric Power Company [Member] | Operating Segments [Member]

Revenue from Contract with Customer, Including Assessed Tax

2,149

2,260

2,232

Electricity, US Regulated [Member] | Delmarva Power & Light Company [Member] | Operating Segments [Member]

Revenue from Contract with Customer, Including Assessed Tax

1,109

1,139

1,151

Electricity, US Regulated [Member] | Atlantic City Electric Company [Member] | Operating Segments [Member]

Revenue from Contract with Customer, Including Assessed Tax

1,245

1,240

1,236

Electricity, US Regulated [Member] | Corporate and Other [Member] | Corporate, Non-Segment [Member]

Revenue from Contract with Customer, Including Assessed Tax

Electricity, US Regulated [Member] | Corporate and Other [Member] | Corporate, Non-Segment [Member] | Pepco Holdings LLC [Member]

Revenue from Contract with Customer, Including Assessed Tax

Natural Gas, US Regulated [Member] | PECO Energy Co [Member]

Revenue from Contract with Customer, Including Assessed Tax

514

610

568

Natural Gas, US Regulated [Member] | Pepco Holdings LLC [Member]

Revenue from Contract with Customer, Including Assessed Tax

162

167

181

Natural Gas, US Regulated [Member] | Operating Segments [Member]

Revenue from Contract with Customer, Including Assessed Tax

1,432

1,489

1,470

Natural Gas, US Regulated [Member] | Intersegment Eliminations [Member]

Revenue from Contract with Customer, Including Assessed Tax

(7)

(15)

(20)

Natural Gas, US Regulated [Member] | Intersegment Eliminations [Member] | Pepco Holdings LLC [Member]

Revenue from Contract with Customer, Including Assessed Tax

Natural Gas, US Regulated [Member] | Exelon Generation Co L L C [Member] | Operating Segments [Member]

Revenue from Contract with Customer, Including Assessed Tax

Natural Gas, US Regulated [Member] | Commonwealth Edison Co [Member] | Operating Segments [Member]

Revenue from Contract with Customer, Including Assessed Tax

Natural Gas, US Regulated [Member] | PECO Energy Co [Member] | Operating Segments [Member]

Revenue from Contract with Customer, Including Assessed Tax

515

610

568

Natural Gas, US Regulated [Member] | Baltimore Gas and Electric Company [Member] | Operating Segments [Member]

Revenue from Contract with Customer, Including Assessed Tax

762

727

741

Natural Gas, US Regulated [Member] | Pepco Holdings LLC [Member] | Operating Segments [Member]

Revenue from Contract with Customer, Including Assessed Tax

162

167

181

Natural Gas, US Regulated [Member] | Potomac Electric Power Company [Member] | Operating Segments [Member]

Revenue from Contract with Customer, Including Assessed Tax

Natural Gas, US Regulated [Member] | Delmarva Power & Light Company [Member] | Operating Segments [Member]

Revenue from Contract with Customer, Including Assessed Tax

162

167

181

Natural Gas, US Regulated [Member] | Atlantic City Electric Company [Member] | Operating Segments [Member]

Revenue from Contract with Customer, Including Assessed Tax

Natural Gas, US Regulated [Member] | Corporate and Other [Member] | Corporate, Non-Segment [Member]

Revenue from Contract with Customer, Including Assessed Tax

Natural Gas, US Regulated [Member] | Corporate and Other [Member] | Corporate, Non-Segment [Member] | Pepco Holdings LLC [Member]

Revenue from Contract with Customer, Including Assessed Tax

Service, Other [Member] | Operating Segments [Member]

Revenue from Contract with Customer, Including Assessed Tax

Service, Other [Member] | Intersegment Eliminations [Member]

Revenue from Contract with Customer, Including Assessed Tax

(2,051)

(1,934)

(1,960)

Service, Other [Member] | Intersegment Eliminations [Member] | Pepco Holdings LLC [Member]

Revenue from Contract with Customer, Including Assessed Tax

(356)

(383)

(420)

Service, Other [Member] | Exelon Generation Co L L C [Member] | Operating Segments [Member]

Revenue from Contract with Customer, Including Assessed Tax

Service, Other [Member] | Commonwealth Edison Co [Member] | Operating Segments [Member]

Revenue from Contract with Customer, Including Assessed Tax

Service, Other [Member] | PECO Energy Co [Member] | Operating Segments [Member]

Revenue from Contract with Customer, Including Assessed Tax

Service, Other [Member] | Baltimore Gas and Electric Company [Member] | Operating Segments [Member]

Revenue from Contract with Customer, Including Assessed Tax

Service, Other [Member] | Pepco Holdings LLC [Member] | Operating Segments [Member]

Revenue from Contract with Customer, Including Assessed Tax

Service, Other [Member] | Potomac Electric Power Company [Member] | Operating Segments [Member]

Revenue from Contract with Customer, Including Assessed Tax

Service, Other [Member] | Delmarva Power & Light Company [Member] | Operating Segments [Member]

Revenue from Contract with Customer, Including Assessed Tax

Service, Other [Member] | Atlantic City Electric Company [Member] | Operating Segments [Member]

Revenue from Contract with Customer, Including Assessed Tax

Service, Other [Member] | Corporate and Other [Member] | Corporate, Non-Segment [Member]

Revenue from Contract with Customer, Including Assessed Tax

2,035

1,921

1,948

Service, Other [Member] | Corporate and Other [Member] | Corporate, Non-Segment [Member] | Pepco Holdings LLC [Member]

Revenue from Contract with Customer, Including Assessed Tax

$ 372

$ 396

$ 435

[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.

Segment Information - Generation Total Revenues (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Segment Reporting Information [Line Items]
Revenues	$ 33,039	$ 34,438	$ 35,978
Generation Mid Atlantic [Member]
Segment Reporting Information [Line Items]
Revenues	4,645	5,074	5,487
Generation Midwest [Member]
Segment Reporting Information [Line Items]
Revenues	4,024	4,293	4,706
Generation New York [Member]
Segment Reporting Information [Line Items]
Revenues	1,431	1,596	1,687
Generation ERCOT [Member]
Segment Reporting Information [Line Items]
Revenues	958	1,013	1,133
Generation Other Regions [Member]
Segment Reporting Information [Line Items]
Revenues	4,002	4,246	4,335
Generation Reportable Segments Total [Member]
Segment Reporting Information [Line Items]
Revenues	15,060	16,222	17,348
Generation Natural Gas [Member]
Segment Reporting Information [Line Items]
Revenues	2,003	2,210	2,780
Generation All Other Segments [Member]
Segment Reporting Information [Line Items]
Revenues	540	492	309
Unrealized Gain (Loss) on Securities	110	(4)	(262)
Generation Total Consolidated Group [Member]
Segment Reporting Information [Line Items]
Revenues	17,603	18,924	20,437
Operating Segments [Member]
Segment Reporting Information [Line Items]
Revenues	33,039	34,438	35,978
Operating Segments [Member] \| Generation Mid Atlantic [Member]
Segment Reporting Information [Line Items]
Revenues	4,617	5,070	5,474
Operating Segments [Member] \| Generation Midwest [Member]
Segment Reporting Information [Line Items]
Revenues	4,029	4,327	4,717
Operating Segments [Member] \| Generation New York [Member]
Segment Reporting Information [Line Items]
Revenues	1,432	1,596	1,687
Operating Segments [Member] \| Generation ERCOT [Member]
Segment Reporting Information [Line Items]
Revenues	933	997	1,132
Operating Segments [Member] \| Generation Other Regions [Member]
Segment Reporting Information [Line Items]
Revenues	4,049	4,295	4,401
Operating Segments [Member] \| Generation Reportable Segments Total [Member]
Segment Reporting Information [Line Items]
Revenues	15,060	16,285	17,411
Operating Segments [Member] \| Generation Natural Gas [Member]
Segment Reporting Information [Line Items]
Revenues	2,003	2,148	2,718
Operating Segments [Member] \| Generation All Other Segments [Member]
Segment Reporting Information [Line Items]
Unrealized Gain (Loss) on Securities	295	(215)	(319)
Operating Segments [Member] \| Generation Total Consolidated Group [Member]
Segment Reporting Information [Line Items]
Revenues	17,603	18,924	20,437
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	(3,322)	(3,166)	(3,294)
Revenue from Related Parties	4	2	1
Intersegment Eliminations [Member] \| Generation Mid Atlantic [Member]
Segment Reporting Information [Line Items]
Revenue from Related Parties	28	4	13
Intersegment Eliminations [Member] \| Generation Midwest [Member]
Segment Reporting Information [Line Items]
Revenue from Related Parties	(5)	(34)	(11)
Intersegment Eliminations [Member] \| Generation New York [Member]
Segment Reporting Information [Line Items]
Revenue from Related Parties	(1)	0	0
Intersegment Eliminations [Member] \| Generation ERCOT [Member]
Segment Reporting Information [Line Items]
Revenue from Related Parties	25	16	1
Intersegment Eliminations [Member] \| Generation Other Regions [Member]
Segment Reporting Information [Line Items]
Revenue from Related Parties	(47)	(49)	(66)
Intersegment Eliminations [Member] \| Generation Reportable Segments Total [Member]
Segment Reporting Information [Line Items]
Revenue from Related Parties	0	(63)	(63)
Intersegment Eliminations [Member] \| Generation Natural Gas [Member]
Segment Reporting Information [Line Items]
Revenue from Related Parties	0	62	62
Intersegment Eliminations [Member] \| Generation All Other Segments [Member]
Segment Reporting Information [Line Items]
Revenue from Related Parties	0	1	1
Intersegment Eliminations [Member] \| Generation Total Consolidated Group [Member]
Segment Reporting Information [Line Items]
Revenue from Related Parties	0	0	0
Corporate, Non-Segment [Member] \| Generation All Other Segments [Member]
Segment Reporting Information [Line Items]
Revenues	540	491	308
Contracts with Customers [Member] \| Operating Segments [Member] \| Generation Mid Atlantic [Member]
Segment Reporting Information [Line Items]
Revenues	4,785	5,053	5,241
Contracts with Customers [Member] \| Operating Segments [Member] \| Generation Midwest [Member]
Segment Reporting Information [Line Items]
Revenues	3,717	4,095	4,527
Contracts with Customers [Member] \| Operating Segments [Member] \| Generation New York [Member]
Segment Reporting Information [Line Items]
Revenues	1,444	1,571	1,723
Contracts with Customers [Member] \| Operating Segments [Member] \| Generation ERCOT [Member]
Segment Reporting Information [Line Items]
Revenues	735	768	572
Contracts with Customers [Member] \| Operating Segments [Member] \| Generation Other Regions [Member]
Segment Reporting Information [Line Items]
Revenues	3,586	3,687	3,530
Contracts with Customers [Member] \| Operating Segments [Member] \| Generation Reportable Segments Total [Member]
Segment Reporting Information [Line Items]
Revenues	14,267	15,174	15,593
Contracts with Customers [Member] \| Operating Segments [Member] \| Generation Natural Gas [Member]
Segment Reporting Information [Line Items]
Revenues	1,283	1,446	1,524
Contracts with Customers [Member] \| Operating Segments [Member] \| Generation Total Consolidated Group [Member]
Segment Reporting Information [Line Items]
Revenues	15,905	17,060	17,627
Contracts with Customers [Member] \| Corporate, Non-Segment [Member] \| Generation All Other Segments [Member]
Segment Reporting Information [Line Items]
Revenues	355	440	510
Other [Member] \| Operating Segments [Member] \| Generation Mid Atlantic [Member]
Segment Reporting Information [Line Items]
Revenues	(168)	17	233
Other [Member] \| Operating Segments [Member] \| Generation Midwest [Member]
Segment Reporting Information [Line Items]
Revenues	312	232	190
Other [Member] \| Operating Segments [Member] \| Generation New York [Member]
Segment Reporting Information [Line Items]
Revenues	(12)	25	(36)
Other [Member] \| Operating Segments [Member] \| Generation ERCOT [Member]
Segment Reporting Information [Line Items]
Revenues	198	229	560
Other [Member] \| Operating Segments [Member] \| Generation Other Regions [Member]
Segment Reporting Information [Line Items]
Revenues	463	608	871
Other [Member] \| Operating Segments [Member] \| Generation Reportable Segments Total [Member]
Segment Reporting Information [Line Items]
Revenues	793	1,111	1,818
Other [Member] \| Operating Segments [Member] \| Generation Natural Gas [Member]
Segment Reporting Information [Line Items]
Revenues	720	702	1,194
Other [Member] \| Operating Segments [Member] \| Generation Total Consolidated Group [Member]
Segment Reporting Information [Line Items]
Revenues	1,698	1,864	2,810
Other [Member] \| Corporate, Non-Segment [Member] \| Generation All Other Segments [Member]
Segment Reporting Information [Line Items]
Revenues	$ 185	$ 51	$ (202)

Segment Information - Generation Total Revenues Net of Purchased Power and Fuel Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Generation Mid Atlantic [Member]
Segment Reporting Information [Line Items]
Revenue Net of Purchase Power And Fuel	$ 2,204	$ 2,655	$ 3,073
Generation Midwest [Member]
Segment Reporting Information [Line Items]
Revenue Net of Purchase Power And Fuel	2,902	2,962	3,135
Generation New York [Member]
Segment Reporting Information [Line Items]
Revenue Net of Purchase Power And Fuel	997	1,094	1,122
Generation ERCOT [Member]
Segment Reporting Information [Line Items]
Revenue Net of Purchase Power And Fuel	426	308	258
Generation Other Regions [Member]
Segment Reporting Information [Line Items]
Revenue Net of Purchase Power And Fuel	665	620	729
Generation Reportable Segments Total [Member]
Segment Reporting Information [Line Items]
Revenue Net of Purchase Power And Fuel	7,194	7,639	8,317
Generation All Other Segments [Member]
Segment Reporting Information [Line Items]
Revenue Net of Purchase Power And Fuel	824	429	427
Unrealized Gain (Loss) on Securities	110	(4)	(262)
Generation Total Consolidated Group [Member]
Segment Reporting Information [Line Items]
Revenue Net of Purchase Power And Fuel	8,018	8,068	8,744
Operating Segments [Member] \| Generation Mid Atlantic [Member]
Segment Reporting Information [Line Items]
RNF from external customers	2,174	2,637	3,022
Operating Segments [Member] \| Generation Midwest [Member]
Segment Reporting Information [Line Items]
RNF from external customers	2,902	2,994	3,112
Operating Segments [Member] \| Generation New York [Member]
Segment Reporting Information [Line Items]
RNF from external customers	983	1,081	1,112
Operating Segments [Member] \| Generation ERCOT [Member]
Segment Reporting Information [Line Items]
RNF from external customers	407	338	501
Operating Segments [Member] \| Generation Other Regions [Member]
Segment Reporting Information [Line Items]
RNF from external customers	759	694	883
Operating Segments [Member] \| Generation Reportable Segments Total [Member]
Segment Reporting Information [Line Items]
RNF from external customers	7,225	7,744	8,630
Operating Segments [Member] \| Generation All Other Segments [Member]
Segment Reporting Information [Line Items]
RNF from external customers	793	324	114
Unrealized Gain (Loss) on Securities	295	(215)	(319)
Nuclear Fuel Amortization	60	13	57
Operating Segments [Member] \| Generation Total Consolidated Group [Member]
Segment Reporting Information [Line Items]
RNF from external customers	8,018	8,068	8,744
Intersegment Eliminations [Member] \| Generation Mid Atlantic [Member]
Segment Reporting Information [Line Items]
Intersegment Revenue Net Of Purchase Power And Fuel	30	18	51
Intersegment Eliminations [Member] \| Generation Midwest [Member]
Segment Reporting Information [Line Items]
Intersegment Revenue Net Of Purchase Power And Fuel	0	(32)	23
Intersegment Eliminations [Member] \| Generation New York [Member]
Segment Reporting Information [Line Items]
Intersegment Revenue Net Of Purchase Power And Fuel	14	13	10
Intersegment Eliminations [Member] \| Generation ERCOT [Member]
Segment Reporting Information [Line Items]
Intersegment Revenue Net Of Purchase Power And Fuel	19	(30)	(243)
Intersegment Eliminations [Member] \| Generation Other Regions [Member]
Segment Reporting Information [Line Items]
Intersegment Revenue Net Of Purchase Power And Fuel	(94)	(74)	(154)
Intersegment Eliminations [Member] \| Generation Reportable Segments Total [Member]
Segment Reporting Information [Line Items]
Intersegment Revenue Net Of Purchase Power And Fuel	(31)	(105)	(313)
Intersegment Eliminations [Member] \| Generation All Other Segments [Member]
Segment Reporting Information [Line Items]
Intersegment Revenue Net Of Purchase Power And Fuel	31	105	313
Intersegment Eliminations [Member] \| Generation Total Consolidated Group [Member]
Segment Reporting Information [Line Items]
Intersegment Revenue Net Of Purchase Power And Fuel	$ 0	$ 0	$ 0

Accounts Receivable - Narrative (Details) - Sale of Accounts Receivable [Member] - USD ($) $ in Millions	Feb. 17, 2021	Dec. 31, 2020	Apr. 08, 2020
Accounts, Notes, Loans and Financing Receivable [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		$ 750
Derecognized receivables transferred at fair value		1,139	$ 1,200
Cash proceeds received		500	500
Deferred purchase price		639	650
Subsequent Event [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Cash proceeds received	$ 250
Exelon Generation Co L L C [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		750
Derecognized receivables transferred at fair value		1,139	1,200
Cash proceeds received		500	500
Deferred purchase price		$ 639	$ 650

Accounts Receivable - Unbilled Customer Revenue (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Accounts, Notes, Loans and Financing Receivable [Line Items]
Unbilled customer revenues	$ 998	$ 1,535
Exelon Generation Co L L C [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Unbilled customer revenues	258	807
Commonwealth Edison Co [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Unbilled customer revenues	218	218
PECO Energy Co [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Unbilled customer revenues	147	146
Baltimore Gas and Electric Company [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Unbilled customer revenues	197	170
Pepco Holdings LLC [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Unbilled customer revenues	178	194
Potomac Electric Power Company [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Unbilled customer revenues	87	100
Delmarva Power & Light Company [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Unbilled customer revenues	62	61
Atlantic City Electric Company [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Unbilled customer revenues	$ 29	$ 33

Accounts Receivable - Purchases and Sales of Accounts Receivable (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Feb. 17, 2021	Apr. 08, 2020
Accounts, Notes, Loans and Financing Receivable [Line Items]
Loss on Sale of Receivables	$ 30
Proceeds from New Transfers	2,816
Cash Collections received on Deferred Purchase Price	3,771
Cash Collections Reinvested in the Facility	6,587
Accounts Receivable, Purchase	3,529
Accounts Receivable, Sale	572
Exelon Generation Co L L C [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Loss on Sale of Receivables	30
Proceeds from New Transfers	2,816
Cash Collections received on Deferred Purchase Price	3,771
Cash Collections Reinvested in the Facility	6,587
Accounts Receivable, Purchase	0
Accounts Receivable, Sale	824
Exelon Generation Co L L C [Member] \| Exelon Utility Registrants Affiliates [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Related Parties, Sale	252
Commonwealth Edison Co [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Purchase	1,094
Accounts Receivable, Sale	0
Commonwealth Edison Co [Member] \| Exelon Generation Co LLC Affiliate [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Related Parties, Purchase	34
PECO Energy Co [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Purchase	1,020
Accounts Receivable, Sale	0
PECO Energy Co [Member] \| Exelon Generation Co LLC Affiliate [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Related Parties, Purchase	67
Baltimore Gas and Electric Company [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Purchase	652
Accounts Receivable, Sale	0
Baltimore Gas and Electric Company [Member] \| Exelon Generation Co LLC Affiliate [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Related Parties, Purchase	79
Pepco Holdings LLC [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Purchase	1,015
Accounts Receivable, Sale	0
Pepco Holdings LLC [Member] \| Exelon Generation Co LLC Affiliate [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Related Parties, Purchase	72
Potomac Electric Power Company [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Purchase	622
Accounts Receivable, Sale	0
Potomac Electric Power Company [Member] \| Exelon Generation Co LLC Affiliate [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Related Parties, Purchase	51
Delmarva Power & Light Company [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Purchase	207
Accounts Receivable, Sale	0
Delmarva Power & Light Company [Member] \| Exelon Generation Co LLC Affiliate [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Related Parties, Purchase	13
Atlantic City Electric Company [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Purchase	186
Accounts Receivable, Sale	0
Atlantic City Electric Company [Member] \| Exelon Generation Co LLC Affiliate [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Related Parties, Purchase	8
Sale of Accounts Receivable [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Derecognized receivables transferred at fair value	1,139		$ 1,200
Cash proceeds received	500		500
Deferred purchase price	639		650
Transfer of Financial Assets Accounted for as Sale, Additional Transfers	6,608
Sale of Accounts Receivable [Member] \| Subsequent Event [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Cash proceeds received		$ 250
Sale of Accounts Receivable [Member] \| Exelon Generation Co L L C [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Derecognized receivables transferred at fair value	1,139		1,200
Cash proceeds received	500		500
Deferred purchase price	639		$ 650
Transfer of Financial Assets Accounted for as Sale, Additional Transfers	$ 6,608

Early Plant Retirements - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Property, Plant and Equipment [Line Items]
Operating Expenses	$ 30,240	$ 30,096	$ 32,143
Depreciation and Amortization	5,014	4,252	4,353
Midwest Asset Group [Member] \| Facility Closing [Member]
Property, Plant and Equipment [Line Items]
Severance Costs	81
Exelon Generation Co L L C [Member]
Property, Plant and Equipment [Line Items]
Depreciation and Amortization	$ 2,123	$ 1,535	$ 1,797
Exelon Generation Co L L C [Member] \| Salem [Member] \| Nuclear Plant [Member]
Property, Plant and Equipment [Line Items]
Ownership interest	42.59%
Exelon Generation Co L L C [Member] \| Midwest Asset Group [Member] \| Facility Closing [Member]
Property, Plant and Equipment [Line Items]
Severance Costs	$ 81
Exelon Generation Co L L C [Member] \| Generation New England [Member]
Property, Plant and Equipment [Line Items]
Operating Expenses	22
Depreciation and Amortization	$ 26

Early Plant Retirements - Pretax Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Asset Retirement Obligation, Revision of Estimate			$ 20
Exelon Generation Co L L C [Member]
Asset Retirement Obligation, Revision of Estimate			0
Exelon Generation Co L L C [Member] \| Facility Closing [Member] \| Three Mile Island [Member]
Accelerated depreciation		$ 216
Accelerated nuclear fuel amortization		13
Restructuring and Related Cost, Incurred Cost		176
Asset Retirement Obligation, Revision of Estimate		(53)
Exelon Generation Co L L C [Member] \| Facility Closing [Member] \| TMI, Oyster Creek [Member]
Accelerated depreciation		216	539
Accelerated nuclear fuel amortization		13	57
Operating and maintenance		0	32
Restructuring and Related Cost, Incurred Cost		176	628
Asset Retirement Obligation, Revision of Estimate		(53)	0
Asset Retirement Obligation Contractual Offset		$ 0	$ 0
Exelon Generation Co L L C [Member] \| Facility Closing [Member] \| Byron Dresden [Member]
Accelerated depreciation	$ 895
Accelerated nuclear fuel amortization	60
Operating and maintenance	255
Restructuring and Related Cost, Incurred Cost	880
Asset Retirement Obligation, Revision of Estimate	34
Asset Retirement Obligation Contractual Offset	$ (364)

Early Plant Retirements - Implications of Potential Early Plant Retirement on Balance Sheet (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Implications of Potential Early Plant Retirement [Line Items]
Materials and supplies	$ 1,425	$ 1,456
Property, plant and equipment, net	82,584	80,233
Exelon Generation Co L L C [Member]
Implications of Potential Early Plant Retirement [Line Items]
Materials and supplies	978	1,026
Property, plant and equipment, net	22,214	$ 24,193
Exelon Generation Co L L C [Member] \| Braidwood [Member] \| Facility Closing [Member]
Implications of Potential Early Plant Retirement [Line Items]
Materials and supplies	84
Nuclear Fuel, Net of Amortization	120
Property, plant and equipment, net	1,397
Construction in Progress, Gross	31
Asset retirement obligation	(570)
Exelon Generation Co L L C [Member] \| LaSalle [Member] \| Facility Closing [Member]
Implications of Potential Early Plant Retirement [Line Items]
Materials and supplies	106
Nuclear Fuel, Net of Amortization	285
Property, plant and equipment, net	1,590
Construction in Progress, Gross	30
Asset retirement obligation	(954)
Exelon Generation Co L L C [Member] \| Braidwood LaSalle [Member] \| Facility Closing [Member]
Implications of Potential Early Plant Retirement [Line Items]
Materials and supplies	190
Nuclear Fuel, Net of Amortization	405
Property, plant and equipment, net	2,987
Construction in Progress, Gross	61
Asset retirement obligation	$ (1,524)

Property, Plant and Equipment - Annual Depreciation Provisions as Percentage of Average Service Life (Details)	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Electric—transmission and distribution
Property, Plant and Equipment [Line Items]
Annual depreciation rate	2.79%	2.80%	2.73%
Electric—generation
Property, Plant and Equipment [Line Items]
Annual depreciation rate	6.11%	4.35%	5.37%
Gas Distribution Equipment
Property, Plant and Equipment [Line Items]
Annual depreciation rate	2.14%	2.04%	2.07%
Common—electric and gas
Property, Plant and Equipment [Line Items]
Annual depreciation rate	7.01%	7.37%	6.98%
Exelon Generation Co L L C [Member] \| Electric—generation
Property, Plant and Equipment [Line Items]
Annual depreciation rate	6.11%	4.35%	5.37%
Commonwealth Edison Co [Member] \| Electric—transmission and distribution
Property, Plant and Equipment [Line Items]
Annual depreciation rate	2.95%	2.99%	2.95%
PECO Energy Co [Member] \| Electric—transmission and distribution
Property, Plant and Equipment [Line Items]
Annual depreciation rate	2.31%	2.36%	2.35%
PECO Energy Co [Member] \| Gas Distribution Equipment
Property, Plant and Equipment [Line Items]
Annual depreciation rate	1.85%	1.89%	1.90%
PECO Energy Co [Member] \| Common—electric and gas
Property, Plant and Equipment [Line Items]
Annual depreciation rate	6.39%	6.06%	5.44%
Baltimore Gas and Electric Company [Member] \| Electric—transmission and distribution
Property, Plant and Equipment [Line Items]
Annual depreciation rate	2.69%	2.60%	2.61%
Baltimore Gas and Electric Company [Member] \| Gas Distribution Equipment
Property, Plant and Equipment [Line Items]
Annual depreciation rate	2.56%	2.30%	2.36%
Baltimore Gas and Electric Company [Member] \| Common—electric and gas
Property, Plant and Equipment [Line Items]
Annual depreciation rate	7.45%	8.30%	8.50%
Pepco Holdings LLC [Member] \| Electric—transmission and distribution
Property, Plant and Equipment [Line Items]
Annual depreciation rate	2.81%	2.77%	2.61%
Pepco Holdings LLC [Member] \| Gas Distribution Equipment
Property, Plant and Equipment [Line Items]
Annual depreciation rate	1.50%	1.55%	1.59%
Pepco Holdings LLC [Member] \| Common—electric and gas
Property, Plant and Equipment [Line Items]
Annual depreciation rate	7.36%	8.25%	6.30%
Potomac Electric Power Company [Member] \| Electric—transmission and distribution
Property, Plant and Equipment [Line Items]
Annual depreciation rate	2.53%	2.47%	2.40%
Delmarva Power & Light Company [Member] \| Electric—transmission and distribution
Property, Plant and Equipment [Line Items]
Annual depreciation rate	2.85%	2.86%	2.77%
Delmarva Power & Light Company [Member] \| Gas Distribution Equipment
Property, Plant and Equipment [Line Items]
Annual depreciation rate	1.50%	1.55%	1.59%
Delmarva Power & Light Company [Member] \| Common—electric and gas
Property, Plant and Equipment [Line Items]
Annual depreciation rate	6.72%	6.24%	3.70%
Atlantic City Electric Company [Member] \| Electric—transmission and distribution
Property, Plant and Equipment [Line Items]
Annual depreciation rate	3.08%	2.94%	2.45%

Property, Plant and Equipment - Summary of Capitalized Interest and AFUDC (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Capitalized Interest And AFUDC [Line Items]
Interest Costs Capitalized	$ 22	$ 24	$ 31
Allowance for Funds Used During Construction, Capitalized Interest	150	132	109
Exelon Generation Co L L C [Member]
Capitalized Interest And AFUDC [Line Items]
Interest Costs Capitalized	22	24	31
Allowance for Funds Used During Construction, Capitalized Interest	0	0	0
Commonwealth Edison Co [Member]
Capitalized Interest And AFUDC [Line Items]
Interest Costs Capitalized	0	0	0
Allowance for Funds Used During Construction, Capitalized Interest	42	32	30
PECO Energy Co [Member]
Capitalized Interest And AFUDC [Line Items]
Interest Costs Capitalized	0	0	0
Allowance for Funds Used During Construction, Capitalized Interest	23	17	12
Baltimore Gas and Electric Company [Member]
Capitalized Interest And AFUDC [Line Items]
Interest Costs Capitalized	0	0	0
Allowance for Funds Used During Construction, Capitalized Interest	30	29	24
Pepco Holdings LLC [Member]
Capitalized Interest And AFUDC [Line Items]
Interest Costs Capitalized	0	0	0
Allowance for Funds Used During Construction, Capitalized Interest	55	54	44
Potomac Electric Power Company [Member]
Capitalized Interest And AFUDC [Line Items]
Interest Costs Capitalized	0	0	0
Allowance for Funds Used During Construction, Capitalized Interest	42	39	34
Delmarva Power & Light Company [Member]
Capitalized Interest And AFUDC [Line Items]
Interest Costs Capitalized	0	0	0
Allowance for Funds Used During Construction, Capitalized Interest	6	6	4
Atlantic City Electric Company [Member]
Capitalized Interest And AFUDC [Line Items]
Interest Costs Capitalized	0	0	0
Allowance for Funds Used During Construction, Capitalized Interest	$ 7	$ 9	$ 4

Jointly Owned Electric Utility Plant - Ownership Interests in Jointly Owned Electric Plants and Transmission Facilities (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020 USD ($) V mi	Dec. 31, 2019 USD ($)
Delaware And New Jersey [Member]
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Miles of transmission voltage lines \| mi	151.3
Transmission line capacity \| V	500
Delaware River Crossing [Member]
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Miles of transmission voltage lines \| mi	2.5
Transmission line capacity \| V	500
New Freedom Switching [Member]
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Transmission line capacity \| V	500
Electric Transmission [Member] \| Delaware And New Jersey [Member]
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Plant	$ 103	$ 102
Accumulated depreciation	54	53
Construction work in progress	$ 0	0
Exelon Generation Co L L C [Member] \| Nuclear Plant [Member] \| Quad Cities [Member]
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Ownership interest	75.00%
Plant	$ 1,188	1,161
Accumulated depreciation	670	627
Construction work in progress	$ 13	13
Exelon Generation Co L L C [Member] \| Nuclear Plant [Member] \| Peach Bottom [Member]
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Ownership interest	50.00%
Plant	$ 1,506	1,466
Accumulated depreciation	601	571
Construction work in progress	$ 13	21
Exelon Generation Co L L C [Member] \| Nuclear Plant [Member] \| Salem [Member]
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Ownership interest	42.59%
Plant	$ 717	663
Accumulated depreciation	265	249
Construction work in progress	$ 39	53
Exelon Generation Co L L C [Member] \| Nuclear Plant [Member] \| Nine Mile Point [Member]
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Ownership interest	82.00%
Plant	$ 990	951
Accumulated depreciation	187	156
Construction work in progress	$ 25	$ 27
PECO Energy Co [Member] \| Delaware And New Jersey [Member]
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Ownership interest	42.55%
PECO Energy Co [Member] \| Delaware River Crossing [Member]
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Ownership interest	42.55%
Delmarva Power & Light Company [Member] \| Delaware And New Jersey [Member]
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Ownership interest	1.00%
Delmarva Power & Light Company [Member] \| Delaware River Crossing [Member]
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Ownership interest	7.45%
Atlantic City Electric Company [Member] \| Delaware And New Jersey [Member]
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Ownership interest	13.90%
Atlantic City Electric Company [Member] \| Delaware River Crossing [Member]
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Ownership interest	7.45%
Atlantic City Electric Company [Member] \| New Freedom Switching [Member]
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Ownership interest	21.78%

Asset Retirement Obligations - Narrative (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Sep. 30, 2017	Mar. 31, 2013	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Asset Retirement Obligations [Line Items]
Increase (Decrease) in ARO Due to Early Retirement			$ 800	$ (410)
Increase (Decrease) in ARO Due to Change in DOE Spent Fuel Acceptance Date			360
Increase (Decrease) in ARO for Impacts of Revised Decommissioning Cost Estimates			(220)
Asset Retirement Obligation, Revision of Estimate					$ 20
Increase (Decrease) in ARO Due to Change in Retirement Timing Probabilities				780
Increase (Decrease) in ARO for Other Impacts				490
Shortfall of decommissioning funds with recourse			$ 50
Percent of additional decommissioning shortfall with recourse			5.00%
Nuclear decommissioning trust funds			$ 14,464	13,190
Estimated annual after tax return on nuclear decommissioning funds			2.00%
Annual average accretion of the ARO			4.00%
Historical five-year annual average after-tax return on NDT funds			9.00%
Minimum [Member]
Asset Retirement Obligations [Line Items]
Estimated annual after tax return on nuclear decommissioning funds			5.60%
Maximum [Member]
Asset Retirement Obligations [Line Items]
Estimated annual after tax return on nuclear decommissioning funds			6.10%
Exelon Generation Co L L C [Member]
Asset Retirement Obligations [Line Items]
Increase (Decrease) in ARO Due to Early Retirement			$ 800	(410)
Increase (Decrease) in ARO Due to Change in DOE Spent Fuel Acceptance Date			360
Increase (Decrease) in ARO for Impacts of Revised Decommissioning Cost Estimates			(220)
Asset Retirement Obligation, Revision of Estimate					0
Increase (Decrease) in ARO Due to Change in Retirement Timing Probabilities				780
Increase (Decrease) in ARO for Other Impacts				490
Shortfall of decommissioning funds with recourse			$ 50
Percent of additional decommissioning shortfall with recourse			5.00%
Nuclear decommissioning trust funds			$ 14,464	13,190
Estimated annual after tax return on nuclear decommissioning funds			2.00%
Number Of Years Used In Present Value Measurement			30 years
Annual average accretion of the ARO			4.00%
Historical five-year annual average after-tax return on NDT funds			9.00%
Exelon Generation Co L L C [Member] \| Minimum [Member]
Asset Retirement Obligations [Line Items]
Estimated annual after tax return on nuclear decommissioning funds			5.60%
Number Of Years Used In Present Value Measurement			10 years
Exelon Generation Co L L C [Member] \| Maximum [Member]
Asset Retirement Obligations [Line Items]
Estimated annual after tax return on nuclear decommissioning funds			6.10%
Number Of Years Used In Present Value Measurement			70 years
PECO Energy Co [Member]
Asset Retirement Obligations [Line Items]
Asset Retirement Obligation, Revision of Estimate					0
Estimated annual after tax return on nuclear decommissioning funds			3.00%
Nuclear decommissioning
Asset Retirement Obligations [Line Items]
Net increase/decrease due to changes in, and timing of, estimated future cash flows			$ 1,022	864
Asset Retirement Obligation			11,922	10,504	10,005
Nuclear decommissioning \| Exelon Generation Co L L C [Member]
Asset Retirement Obligations [Line Items]
Net increase/decrease due to changes in, and timing of, estimated future cash flows			1,022	864
Asset Retirement Obligation			$ 11,922	10,504	10,005
Nine Mile Point [Member]
Asset Retirement Obligations [Line Items]
Percent of additional decommissioning shortfall with recourse			50.00%
Nine Mile Point [Member] \| Exelon Generation Co L L C [Member]
Asset Retirement Obligations [Line Items]
Percent of additional decommissioning shortfall with recourse			50.00%
Zion Station [Member]
Asset Retirement Obligations [Line Items]
Asset Retirement Obligation			$ 175
Zion Station [Member] \| Exelon Generation Co L L C [Member]
Asset Retirement Obligations [Line Items]
Asset Retirement Obligation			175
Nonnuclear Decommissioning Asset Retirement Obligation [Member]
Asset Retirement Obligations [Line Items]
Asset Retirement Obligation, Revision of Estimate			7	17
Asset Retirement Obligation			461	460	471
Nonnuclear Decommissioning Asset Retirement Obligation [Member] \| Exelon Generation Co L L C [Member]
Asset Retirement Obligations [Line Items]
Asset Retirement Obligation, Revision of Estimate			2	7
Asset Retirement Obligation			212	216	238
Nonnuclear Decommissioning Asset Retirement Obligation [Member] \| PECO Energy Co [Member]
Asset Retirement Obligations [Line Items]
Asset Retirement Obligation, Revision of Estimate			2	0
Asset Retirement Obligation			29	28	$ 28
Nuclear Decommissioning Trust Fund Investments [Member]
Asset Retirement Obligations [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount	$ 4	$ 24
Nuclear Decommissioning Trust Fund Investments [Member] \| Exelon Generation Co L L C [Member]
Asset Retirement Obligations [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount	$ 4	$ 24
Lessee, Operating Lease, Renewal Term	20 years
Assets, Total [Member]
Asset Retirement Obligations [Line Items]
Nuclear decommissioning trust funds			14,599	13,353
Assets, Total [Member] \| Exelon Generation Co L L C [Member]
Asset Retirement Obligations [Line Items]
Nuclear decommissioning trust funds			14,599	13,353
Assets, Total [Member] \| Zion Station [Member]
Asset Retirement Obligations [Line Items]
Nuclear decommissioning trust funds			66
Assets, Total [Member] \| Zion Station [Member] \| Exelon Generation Co L L C [Member]
Asset Retirement Obligations [Line Items]
Nuclear decommissioning trust funds			66
Other Current Assets [Member]
Asset Retirement Obligations [Line Items]
Nuclear decommissioning trust funds			134	163
Other Current Assets [Member] \| Exelon Generation Co L L C [Member]
Asset Retirement Obligations [Line Items]
Nuclear decommissioning trust funds			134	163
Operating Expense [Member]
Asset Retirement Obligations [Line Items]
Asset Retirement Obligation, Revision of Estimate			60	(150)
Operating Expense [Member] \| Exelon Generation Co L L C [Member]
Asset Retirement Obligations [Line Items]
Asset Retirement Obligation, Revision of Estimate			60	$ (150)
Disposal Group, Held-for-sale or Disposed of by Sale, Not Discontinued Operations [Member] \| Nonnuclear Decommissioning Asset Retirement Obligation [Member]
Asset Retirement Obligations [Line Items]
Asset Retirement Obligation, Revision of Estimate			10
Disposal Group, Held-for-sale or Disposed of by Sale, Not Discontinued Operations [Member] \| Nonnuclear Decommissioning Asset Retirement Obligation [Member] \| Exelon Generation Co L L C [Member]
Asset Retirement Obligations [Line Items]
Asset Retirement Obligation, Revision of Estimate			$ 10

Asset Retirement Obligations - Nuclear Decommissioning Asset Retirement Obligation Rollforward (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Accretion expense	$ 500	$ 491	$ 489
Exelon Generation Co L L C [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Accretion expense	500	491	489
Nuclear decommissioning
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
ARO beginning balance	10,504	10,005
Net increase/decrease due to changes in, and timing of, estimated future cash flows	1,022	864
Sale of Oyster Creek		(755)
Accretion expense	489	479
Cost incurred related to decommissioning plants	(93)	(89)
ARO ending balance	11,922	10,504	10,005
Asset Retirement Obligation, Current	80	112
Nuclear decommissioning \| Exelon Generation Co L L C [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
ARO beginning balance	10,504	10,005
Net increase/decrease due to changes in, and timing of, estimated future cash flows	1,022	864
Sale of Oyster Creek		(755)
Accretion expense	489	479
Cost incurred related to decommissioning plants	(93)	(89)
ARO ending balance	11,922	10,504	$ 10,005
Asset Retirement Obligation, Current	$ 80	$ 112

Asset Retirement Obligations - Non-Nuclear Asset Retirement Obligations Rollforward (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Accretion expense	$ 500	$ 491	$ 489
Asset Retirement Obligation, Revision of Estimate			20
Exelon Generation Co L L C [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Accretion expense	500	491	489
Asset Retirement Obligation, Revision of Estimate			0
Commonwealth Edison Co [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Accretion expense	0	0	0
Asset Retirement Obligation, Revision of Estimate			0
PECO Energy Co [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Accretion expense	0	0	0
Asset Retirement Obligation, Revision of Estimate			0
Baltimore Gas and Electric Company [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Accretion expense	0	0	0
Asset Retirement Obligation, Revision of Estimate			0
Pepco Holdings LLC [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Accretion expense	0	0	0
Asset Retirement Obligation, Revision of Estimate			20
Potomac Electric Power Company [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Accretion expense	0	0	0
Asset Retirement Obligation, Revision of Estimate			22
Delmarva Power & Light Company [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Accretion expense	0	0	0
Asset Retirement Obligation, Revision of Estimate			(1)
Atlantic City Electric Company [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Accretion expense	0	0	0
Asset Retirement Obligation, Revision of Estimate			(1)
Nonnuclear Decommissioning Asset Retirement Obligation [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
ARO beginning balance	460	471
Development Projects	1	2
Accretion expense	16	16
Sale of Oyster Creek	(4)	(42)
Payments	(9)	(4)
Asset Retirement Obligation, Revision of Estimate	7	17
ARO ending balance	461	460	471
Nonnuclear Decommissioning Asset Retirement Obligation [Member] \| Disposal Group, Held-for-sale or Disposed of by Sale, Not Discontinued Operations [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset Retirement Obligation, Revision of Estimate	10
Nonnuclear Decommissioning Asset Retirement Obligation [Member] \| Exelon Generation Co L L C [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
ARO beginning balance	216	238
Development Projects	1	2
Accretion expense	11	12
Sale of Oyster Creek	(4)	(42)
Payments	(4)	(1)
Asset Retirement Obligation, Revision of Estimate	2	7
ARO ending balance	212	216	238
Nonnuclear Decommissioning Asset Retirement Obligation [Member] \| Exelon Generation Co L L C [Member] \| Disposal Group, Held-for-sale or Disposed of by Sale, Not Discontinued Operations [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset Retirement Obligation, Revision of Estimate	10
Nonnuclear Decommissioning Asset Retirement Obligation [Member] \| Commonwealth Edison Co [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
ARO beginning balance	129	121
Development Projects	0	0
Accretion expense	1	1
Sale of Oyster Creek	0	0
Payments	(1)	(1)
Asset Retirement Obligation, Revision of Estimate	0	8
ARO ending balance	129	129	121
Nonnuclear Decommissioning Asset Retirement Obligation [Member] \| PECO Energy Co [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
ARO beginning balance	28	28
Development Projects	0	0
Accretion expense	1	1
Sale of Oyster Creek	0	0
Payments	(2)	(1)
Asset Retirement Obligation, Revision of Estimate	2	0
ARO ending balance	29	28	28
Nonnuclear Decommissioning Asset Retirement Obligation [Member] \| Baltimore Gas and Electric Company [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
ARO beginning balance	23	25
Development Projects	0	0
Accretion expense	1	1
Sale of Oyster Creek	0	0
Payments	(2)	(1)
Asset Retirement Obligation, Revision of Estimate	1	(2)
ARO ending balance	23	23	25
Nonnuclear Decommissioning Asset Retirement Obligation [Member] \| Pepco Holdings LLC [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
ARO beginning balance	57	52
Development Projects	0	0
Accretion expense	1	1
Sale of Oyster Creek	0	0
Payments	0	0
Asset Retirement Obligation, Revision of Estimate	1	4
ARO ending balance	59	57	52
Nonnuclear Decommissioning Asset Retirement Obligation [Member] \| Potomac Electric Power Company [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
ARO beginning balance	41	37
Development Projects	0	0
Accretion expense	1	1
Sale of Oyster Creek	0	0
Payments	0	0
Asset Retirement Obligation, Revision of Estimate	(3)	3
ARO ending balance	39	41	37
Nonnuclear Decommissioning Asset Retirement Obligation [Member] \| Delmarva Power & Light Company [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
ARO beginning balance	12	11
Development Projects	0	0
Accretion expense	0	0
Sale of Oyster Creek	0	0
Payments	0	0
Asset Retirement Obligation, Revision of Estimate	2	1
ARO ending balance	14	12	11
Nonnuclear Decommissioning Asset Retirement Obligation [Member] \| Atlantic City Electric Company [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
ARO beginning balance	4	4
Development Projects	0	0
Accretion expense	0	0
Sale of Oyster Creek	0	0
Payments	0	0
Asset Retirement Obligation, Revision of Estimate	2	0
ARO ending balance	$ 6	$ 4	$ 4

Lessee - Narrative (Details)	12 Months Ended
Lessee - Narrative (Details)	Dec. 31, 2020	Dec. 31, 2019
Lessee, Lease, Description [Line Items]
Operating Lease, Weighted Average Remaining Lease Term	10 years 1 month 6 days	10 years 1 month 6 days
Operating Lease, Weighted Average Discount Rate, Percent	4.70%	4.60%
Long-term Contract for Purchase of Electric Power [Member]
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Description	●
Real Estate [Member]
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Description	●
Vehicles [Member]
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Description	●
Minimum [Member]
Lessee, Lease, Description [Line Items]
Remaining lease terms, Lessee, Operating Lease	1 year
Options to extend the term, Lessee, Operating Lease	2 years
Option to terminate within, Lessee, Operating Lease	1 years
Maximum [Member]
Lessee, Lease, Description [Line Items]
Remaining lease terms, Lessee, Operating Lease	85 years
Options to extend the term, Lessee, Operating Lease	30 years
Option to terminate within, Lessee, Operating Lease	12 years
Exelon Generation Co L L C [Member]
Lessee, Lease, Description [Line Items]
Operating Lease, Weighted Average Remaining Lease Term	10 years 6 months	10 years 7 months 6 days
Operating Lease, Weighted Average Discount Rate, Percent	4.90%	4.80%
Exelon Generation Co L L C [Member] \| Long-term Contract for Purchase of Electric Power [Member]
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Description	●
Exelon Generation Co L L C [Member] \| Real Estate [Member]
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Description	●
Exelon Generation Co L L C [Member] \| Vehicles [Member]
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Description	●
Exelon Generation Co L L C [Member] \| Minimum [Member]
Lessee, Lease, Description [Line Items]
Remaining lease terms, Lessee, Operating Lease	1 year
Options to extend the term, Lessee, Operating Lease	2 years
Option to terminate within, Lessee, Operating Lease	1 years
Exelon Generation Co L L C [Member] \| Maximum [Member]
Lessee, Lease, Description [Line Items]
Remaining lease terms, Lessee, Operating Lease	35 years
Options to extend the term, Lessee, Operating Lease	30 years
Option to terminate within, Lessee, Operating Lease	4 years
Commonwealth Edison Co [Member]
Lessee, Lease, Description [Line Items]
Operating Lease, Weighted Average Remaining Lease Term	3 years 9 months 18 days	4 years 7 months 6 days
Operating Lease, Weighted Average Discount Rate, Percent	3.00%	3.00%
Commonwealth Edison Co [Member] \| Real Estate [Member]
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Description	●
Commonwealth Edison Co [Member] \| Vehicles [Member]
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Description	●
Commonwealth Edison Co [Member] \| Minimum [Member]
Lessee, Lease, Description [Line Items]
Remaining lease terms, Lessee, Operating Lease	1 year
Options to extend the term, Lessee, Operating Lease	5 years
Option to terminate within, Lessee, Operating Lease	2 years
Commonwealth Edison Co [Member] \| Maximum [Member]
Lessee, Lease, Description [Line Items]
Remaining lease terms, Lessee, Operating Lease	4 years
Options to extend the term, Lessee, Operating Lease	5 years
Option to terminate within, Lessee, Operating Lease	2 years
PECO Energy Co [Member]
Lessee, Lease, Description [Line Items]
Operating Lease, Weighted Average Remaining Lease Term	4 years 2 months 12 days	4 years 4 months 24 days
Operating Lease, Weighted Average Discount Rate, Percent	2.90%	3.20%
PECO Energy Co [Member] \| Real Estate [Member]
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Description	●
PECO Energy Co [Member] \| Vehicles [Member]
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Description	●
PECO Energy Co [Member] \| Minimum [Member]
Lessee, Lease, Description [Line Items]
Remaining lease terms, Lessee, Operating Lease	1 year
PECO Energy Co [Member] \| Maximum [Member]
Lessee, Lease, Description [Line Items]
Remaining lease terms, Lessee, Operating Lease	13 years
Baltimore Gas and Electric Company [Member]
Lessee, Lease, Description [Line Items]
Operating Lease, Weighted Average Remaining Lease Term	8 years 3 months 18 days	5 years 4 months 24 days
Operating Lease, Weighted Average Discount Rate, Percent	3.80%	3.60%
Baltimore Gas and Electric Company [Member] \| Real Estate [Member]
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Description	●
Baltimore Gas and Electric Company [Member] \| Vehicles [Member]
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Description	●
Baltimore Gas and Electric Company [Member] \| Minimum [Member]
Lessee, Lease, Description [Line Items]
Remaining lease terms, Lessee, Operating Lease	1 year
Option to terminate within, Lessee, Operating Lease	1 years
Baltimore Gas and Electric Company [Member] \| Maximum [Member]
Lessee, Lease, Description [Line Items]
Remaining lease terms, Lessee, Operating Lease	85 years
Option to terminate within, Lessee, Operating Lease	1 years
Pepco Holdings LLC [Member]
Lessee, Lease, Description [Line Items]
Operating Lease, Weighted Average Remaining Lease Term	8 years 2 months 12 days	9 years
Finance Lease, Weighted Average Remaining Lease Term	6 years 6 months
Operating Lease, Weighted Average Discount Rate, Percent	4.20%	4.20%
Finance Lease, Weighted Average Discount Rate, Percent	2.50%
Pepco Holdings LLC [Member] \| Real Estate [Member]
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Description	●
Pepco Holdings LLC [Member] \| Vehicles [Member]
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Description	●
Pepco Holdings LLC [Member] \| Minimum [Member]
Lessee, Lease, Description [Line Items]
Remaining lease terms, Lessee, Operating Lease	1 year
Options to extend the term, Lessee, Operating Lease	3 years
Pepco Holdings LLC [Member] \| Maximum [Member]
Lessee, Lease, Description [Line Items]
Remaining lease terms, Lessee, Operating Lease	11 years
Options to extend the term, Lessee, Operating Lease	30 years
Potomac Electric Power Company [Member]
Lessee, Lease, Description [Line Items]
Operating Lease, Weighted Average Remaining Lease Term	9 years 1 month 6 days	9 years 9 months 18 days
Finance Lease, Weighted Average Remaining Lease Term	6 years 3 months 18 days
Operating Lease, Weighted Average Discount Rate, Percent	4.00%	4.00%
Finance Lease, Weighted Average Discount Rate, Percent	2.60%
Potomac Electric Power Company [Member] \| Real Estate [Member]
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Description	●
Potomac Electric Power Company [Member] \| Vehicles [Member]
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Description	●
Potomac Electric Power Company [Member] \| Minimum [Member]
Lessee, Lease, Description [Line Items]
Remaining lease terms, Lessee, Operating Lease	1 year
Options to extend the term, Lessee, Operating Lease	5 years
Potomac Electric Power Company [Member] \| Maximum [Member]
Lessee, Lease, Description [Line Items]
Remaining lease terms, Lessee, Operating Lease	11 years
Options to extend the term, Lessee, Operating Lease	5 years
Delmarva Power & Light Company [Member]
Lessee, Lease, Description [Line Items]
Operating Lease, Weighted Average Remaining Lease Term	9 years 1 month 6 days	9 years 8 months 12 days
Finance Lease, Weighted Average Remaining Lease Term	6 years 6 months
Operating Lease, Weighted Average Discount Rate, Percent	4.00%	4.00%
Finance Lease, Weighted Average Discount Rate, Percent	2.40%
Delmarva Power & Light Company [Member] \| Real Estate [Member]
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Description	●
Delmarva Power & Light Company [Member] \| Vehicles [Member]
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Description	●
Delmarva Power & Light Company [Member] \| Minimum [Member]
Lessee, Lease, Description [Line Items]
Remaining lease terms, Lessee, Operating Lease	1 year
Options to extend the term, Lessee, Operating Lease	3 years
Delmarva Power & Light Company [Member] \| Maximum [Member]
Lessee, Lease, Description [Line Items]
Remaining lease terms, Lessee, Operating Lease	11 years
Options to extend the term, Lessee, Operating Lease	30 years
Atlantic City Electric Company [Member]
Lessee, Lease, Description [Line Items]
Operating Lease, Weighted Average Remaining Lease Term	4 years	4 years 8 months 12 days
Finance Lease, Weighted Average Remaining Lease Term	6 years 6 months
Operating Lease, Weighted Average Discount Rate, Percent	3.50%	3.60%
Finance Lease, Weighted Average Discount Rate, Percent	2.40%
Atlantic City Electric Company [Member] \| Real Estate [Member]
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Description	●
Atlantic City Electric Company [Member] \| Vehicles [Member]
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Description	●
Atlantic City Electric Company [Member] \| Minimum [Member]
Lessee, Lease, Description [Line Items]
Remaining lease terms, Lessee, Operating Lease	1 year
Options to extend the term, Lessee, Operating Lease	5 years
Atlantic City Electric Company [Member] \| Maximum [Member]
Lessee, Lease, Description [Line Items]
Remaining lease terms, Lessee, Operating Lease	7 years
Options to extend the term, Lessee, Operating Lease	5 years

Lessee - Components of Lease Cost (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Schedule of Components of Lease Cost [Line Items]
Operating Lease, Cost	$ 292	$ 320
Variable Lease, Cost	241	300
Short-term Lease, Cost	2	19
Total Lease Cost	535	639
Sublease Income	48	51
Exelon Generation Co L L C [Member]
Schedule of Components of Lease Cost [Line Items]
Operating Lease, Cost	194	222
Variable Lease, Cost	234	282
Short-term Lease, Cost	2	19
Total Lease Cost	430	523
Sublease Income	44	44
Commonwealth Edison Co [Member]
Schedule of Components of Lease Cost [Line Items]
Operating Lease, Cost	3	3
Variable Lease, Cost	1	2
Short-term Lease, Cost	0	0
Total Lease Cost	4	5
PECO Energy Co [Member]
Schedule of Components of Lease Cost [Line Items]
Operating Lease, Cost	1	1
Variable Lease, Cost	0	0
Short-term Lease, Cost	0	0
Total Lease Cost	1	1
Baltimore Gas and Electric Company [Member]
Schedule of Components of Lease Cost [Line Items]
Operating Lease, Cost	33	33
Variable Lease, Cost	1	2
Short-term Lease, Cost	0	0
Total Lease Cost	34	35
Pepco Holdings LLC [Member]
Schedule of Components of Lease Cost [Line Items]
Operating Lease, Cost	46	48
Variable Lease, Cost	2	6
Short-term Lease, Cost	0	0
Total Lease Cost	48	54
Sublease Income	4	7
Finance Lease, Cost	9
Potomac Electric Power Company [Member]
Schedule of Components of Lease Cost [Line Items]
Operating Lease, Cost	11	12
Variable Lease, Cost	1	2
Short-term Lease, Cost	0	0
Total Lease Cost	12	14
Finance Lease, Cost	3
Delmarva Power & Light Company [Member]
Schedule of Components of Lease Cost [Line Items]
Operating Lease, Cost	13	14
Variable Lease, Cost	1	2
Short-term Lease, Cost	0	0
Total Lease Cost	14	16
Sublease Income	4	7
Finance Lease, Cost	4
Atlantic City Electric Company [Member]
Schedule of Components of Lease Cost [Line Items]
Operating Lease, Cost	6	7
Variable Lease, Cost	0	1
Short-term Lease, Cost	0	0
Total Lease Cost	6	$ 8
Finance Lease, Cost	$ 2

Lessee - Schedule of Rent Expense Under Prior Lease Guidance (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2020	Dec. 31, 2019
Operating Leases, Rent Expense	$ 670
Operating Lease, Liability		$ 1,302	$ 1,532
Exelon Generation Co L L C [Member]
Operating Leases, Rent Expense	558
Operating Lease, Liability		907	1,082
Commonwealth Edison Co [Member]
Operating Leases, Rent Expense	7
Operating Lease, Liability		8	11
PECO Energy Co [Member]
Operating Leases, Rent Expense	10
Operating Lease, Liability		1	1
Baltimore Gas and Electric Company [Member]
Operating Leases, Rent Expense	35
Operating Lease, Liability		64	82
Pepco Holdings LLC [Member]
Operating Leases, Rent Expense	48
Operating Lease, Liability		255	285
Potomac Electric Power Company [Member]
Operating Leases, Rent Expense	10
Operating Lease, Liability		52	57
Delmarva Power & Light Company [Member]
Operating Leases, Rent Expense	13
Operating Lease, Liability		65	74
Atlantic City Electric Company [Member]
Operating Leases, Rent Expense	8
Operating Lease, Liability		15	18
Long-term Contract for Purchase of Electric Power [Member]
Operating Lease, Liability		528	664
Long-term Contract for Purchase of Electric Power [Member] \| Exelon Generation Co L L C [Member]
Operating Lease, Liability	$ 493	$ 528	$ 664

Lessee - Supplemental Balance Sheet Information (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Supplemental Balance Sheet Information [Line Items]
Other current liabilities	$ 1,264	$ 1,331
Other deferred credits and other liabilities	2,942	3,064
Total operating lease liabilities	1,302	1,532
Other Noncurrent Assets [Member]
Supplemental Balance Sheet Information [Line Items]
Operating Lease, Right-of-Use Asset	1,064	1,305
Other Current Liabilities [Member]
Supplemental Balance Sheet Information [Line Items]
Other current liabilities	213	225
Other deferred credits and other liabilities [Member]
Supplemental Balance Sheet Information [Line Items]
Other deferred credits and other liabilities	1,089	1,307
Long-term Contract for Purchase of Electric Power [Member]
Supplemental Balance Sheet Information [Line Items]
Operating Lease, Right-of-Use Asset	387	515
Total operating lease liabilities	528	664
Exelon Generation Co L L C [Member]
Supplemental Balance Sheet Information [Line Items]
Other current liabilities	444	517
Other deferred credits and other liabilities	1,308	1,415
Total operating lease liabilities	907	1,082
Exelon Generation Co L L C [Member] \| Other Noncurrent Assets [Member]
Supplemental Balance Sheet Information [Line Items]
Operating Lease, Right-of-Use Asset	726	895
Exelon Generation Co L L C [Member] \| Other Current Liabilities [Member]
Supplemental Balance Sheet Information [Line Items]
Other current liabilities	132	157
Exelon Generation Co L L C [Member] \| Other deferred credits and other liabilities [Member]
Supplemental Balance Sheet Information [Line Items]
Other deferred credits and other liabilities	775	925
Exelon Generation Co L L C [Member] \| Long-term Contract for Purchase of Electric Power [Member]
Supplemental Balance Sheet Information [Line Items]
Operating Lease, Right-of-Use Asset	387	515
Total operating lease liabilities	528	664	$ 493
Commonwealth Edison Co [Member]
Supplemental Balance Sheet Information [Line Items]
Other current liabilities	143	122
Other deferred credits and other liabilities	595	635
Total operating lease liabilities	8	11
Commonwealth Edison Co [Member] \| Other Noncurrent Assets [Member]
Supplemental Balance Sheet Information [Line Items]
Operating Lease, Right-of-Use Asset	7	9
Commonwealth Edison Co [Member] \| Other Current Liabilities [Member]
Supplemental Balance Sheet Information [Line Items]
Other current liabilities	3	3
Commonwealth Edison Co [Member] \| Other deferred credits and other liabilities [Member]
Supplemental Balance Sheet Information [Line Items]
Other deferred credits and other liabilities	5	8
PECO Energy Co [Member]
Supplemental Balance Sheet Information [Line Items]
Other current liabilities	30	19
Other deferred credits and other liabilities	93	74
Total operating lease liabilities	1	1
PECO Energy Co [Member] \| Other Noncurrent Assets [Member]
Supplemental Balance Sheet Information [Line Items]
Operating Lease, Right-of-Use Asset	1	2
PECO Energy Co [Member] \| Other Current Liabilities [Member]
Supplemental Balance Sheet Information [Line Items]
Other current liabilities	0	0
PECO Energy Co [Member] \| Other deferred credits and other liabilities [Member]
Supplemental Balance Sheet Information [Line Items]
Other deferred credits and other liabilities	1	1
Baltimore Gas and Electric Company [Member]
Supplemental Balance Sheet Information [Line Items]
Other current liabilities	91	63
Other deferred credits and other liabilities	104	116
Total operating lease liabilities	64	82
Baltimore Gas and Electric Company [Member] \| Other Noncurrent Assets [Member]
Supplemental Balance Sheet Information [Line Items]
Operating Lease, Right-of-Use Asset	46	77
Baltimore Gas and Electric Company [Member] \| Other Current Liabilities [Member]
Supplemental Balance Sheet Information [Line Items]
Other current liabilities	45	32
Baltimore Gas and Electric Company [Member] \| Other deferred credits and other liabilities [Member]
Supplemental Balance Sheet Information [Line Items]
Other deferred credits and other liabilities	19	50
Pepco Holdings LLC [Member]
Supplemental Balance Sheet Information [Line Items]
Other current liabilities	141	131
Other deferred credits and other liabilities	622	577
Total operating lease liabilities	255	285
Finance Lease, Liability, Current	7
Finance Lease, Liability, Noncurrent	43
Finance lease, liability	50
Pepco Holdings LLC [Member] \| Other Noncurrent Assets [Member]
Supplemental Balance Sheet Information [Line Items]
Operating Lease, Right-of-Use Asset	241	273
Pepco Holdings LLC [Member] \| Other Current Liabilities [Member]
Supplemental Balance Sheet Information [Line Items]
Other current liabilities	31	31
Pepco Holdings LLC [Member] \| Other deferred credits and other liabilities [Member]
Supplemental Balance Sheet Information [Line Items]
Other deferred credits and other liabilities	224	254
Pepco Holdings LLC [Member] \| Property, Plant and Equipment
Supplemental Balance Sheet Information [Line Items]
Finance Lease, Right-of-Use Asset, after Accumulated Amortization	50
Potomac Electric Power Company [Member]
Supplemental Balance Sheet Information [Line Items]
Other current liabilities	31	22
Other deferred credits and other liabilities	340	297
Total operating lease liabilities	52	57
Finance Lease, Liability, Current	2
Finance Lease, Liability, Noncurrent	15
Finance lease, liability	17
Potomac Electric Power Company [Member] \| Other Noncurrent Assets [Member]
Supplemental Balance Sheet Information [Line Items]
Operating Lease, Right-of-Use Asset	49	56
Potomac Electric Power Company [Member] \| Other Current Liabilities [Member]
Supplemental Balance Sheet Information [Line Items]
Other current liabilities	6	6
Potomac Electric Power Company [Member] \| Other deferred credits and other liabilities [Member]
Supplemental Balance Sheet Information [Line Items]
Other deferred credits and other liabilities	46	51
Potomac Electric Power Company [Member] \| Property, Plant and Equipment
Supplemental Balance Sheet Information [Line Items]
Finance Lease, Right-of-Use Asset, after Accumulated Amortization	17
Delmarva Power & Light Company [Member]
Supplemental Balance Sheet Information [Line Items]
Other current liabilities	20	15
Other deferred credits and other liabilities	97	92
Total operating lease liabilities	65	74
Finance Lease, Liability, Current	3
Finance Lease, Liability, Noncurrent	17
Finance lease, liability	20
Delmarva Power & Light Company [Member] \| Other Noncurrent Assets [Member]
Supplemental Balance Sheet Information [Line Items]
Operating Lease, Right-of-Use Asset	54	63
Delmarva Power & Light Company [Member] \| Other Current Liabilities [Member]
Supplemental Balance Sheet Information [Line Items]
Other current liabilities	9	9
Delmarva Power & Light Company [Member] \| Other deferred credits and other liabilities [Member]
Supplemental Balance Sheet Information [Line Items]
Other deferred credits and other liabilities	56	65
Delmarva Power & Light Company [Member] \| Property, Plant and Equipment
Supplemental Balance Sheet Information [Line Items]
Finance Lease, Right-of-Use Asset, after Accumulated Amortization	20
Atlantic City Electric Company [Member]
Supplemental Balance Sheet Information [Line Items]
Other current liabilities	11	9
Other deferred credits and other liabilities	48	39
Total operating lease liabilities	15	18
Finance Lease, Liability, Current	2
Finance Lease, Liability, Noncurrent	11
Finance lease, liability	13
Atlantic City Electric Company [Member] \| Other Noncurrent Assets [Member]
Supplemental Balance Sheet Information [Line Items]
Operating Lease, Right-of-Use Asset	15	18
Atlantic City Electric Company [Member] \| Other Current Liabilities [Member]
Supplemental Balance Sheet Information [Line Items]
Other current liabilities	4	4
Atlantic City Electric Company [Member] \| Other deferred credits and other liabilities [Member]
Supplemental Balance Sheet Information [Line Items]
Other deferred credits and other liabilities	11	$ 14
Atlantic City Electric Company [Member] \| Property, Plant and Equipment
Supplemental Balance Sheet Information [Line Items]
Finance Lease, Right-of-Use Asset, after Accumulated Amortization	$ 13

Lessee - Lessee Future Minimum Operating Lease Maturity Payments (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Schedule of Lessee, Operating Lease, Liability, Maturity [Line Items]
2021	$ 239
2022	177
2023	146
2024	141
2025	140
Remaining years	834
Lessee, Operating Lease, Liability, to be Paid	1,677
Interest	375
Operating Lease, Liability	1,302	$ 1,532
Exelon Generation Co L L C [Member]
Schedule of Lessee, Operating Lease, Liability, Maturity [Line Items]
2021	145
2022	113
2023	100
2024	98
2025	99
Remaining years	640
Lessee, Operating Lease, Liability, to be Paid	1,195
Interest	288
Operating Lease, Liability	907	1,082
Commonwealth Edison Co [Member]
Schedule of Lessee, Operating Lease, Liability, Maturity [Line Items]
2021	3
2022	2
2023	1
2024	1
2025	1
Remaining years	0
Lessee, Operating Lease, Liability, to be Paid	8
Interest	0
Operating Lease, Liability	8	11
PECO Energy Co [Member]
Schedule of Lessee, Operating Lease, Liability, Maturity [Line Items]
2021	1
2022	0
2023	0
2024	0
2025	0
Remaining years	0
Lessee, Operating Lease, Liability, to be Paid	1
Interest	0
Operating Lease, Liability	1	1
Baltimore Gas and Electric Company [Member]
Schedule of Lessee, Operating Lease, Liability, Maturity [Line Items]
2021	46
2022	16
2023	1
2024	0
2025	0
Remaining years	18
Lessee, Operating Lease, Liability, to be Paid	81
Interest	17
Operating Lease, Liability	64	82
Pepco Holdings LLC [Member]
Schedule of Lessee, Operating Lease, Liability, Maturity [Line Items]
2021	40
2022	39
2023	38
2024	36
2025	33
Remaining years	120
Lessee, Operating Lease, Liability, to be Paid	306
Interest	51
Operating Lease, Liability	255	285
Schedule of Lessee, Finance Lease, Liability, Maturity [Line Items]
2021	8
2022	8
2023	8
2024	8
2025	8
Remaining years	13
Finance Lease, Liability, to be Paid	53
Interest	3
Finance lease, liability	50
Potomac Electric Power Company [Member]
Schedule of Lessee, Operating Lease, Liability, Maturity [Line Items]
2021	8
2022	8
2023	7
2024	6
2025	6
Remaining years	28
Lessee, Operating Lease, Liability, to be Paid	63
Interest	11
Operating Lease, Liability	52	57
Schedule of Lessee, Finance Lease, Liability, Maturity [Line Items]
2021	3
2022	3
2023	3
2024	3
2025	3
Remaining years	3
Finance Lease, Liability, to be Paid	18
Interest	1
Finance lease, liability	17
Delmarva Power & Light Company [Member]
Schedule of Lessee, Operating Lease, Liability, Maturity [Line Items]
2021	11
2022	10
2023	9
2024	8
2025	7
Remaining years	35
Lessee, Operating Lease, Liability, to be Paid	80
Interest	15
Operating Lease, Liability	65	74
Schedule of Lessee, Finance Lease, Liability, Maturity [Line Items]
2021	3
2022	3
2023	3
2024	3
2025	3
Remaining years	6
Finance Lease, Liability, to be Paid	21
Interest	1
Finance lease, liability	20
Atlantic City Electric Company [Member]
Schedule of Lessee, Operating Lease, Liability, Maturity [Line Items]
2021	5
2022	4
2023	3
2024	2
2025	2
Remaining years	0
Lessee, Operating Lease, Liability, to be Paid	16
Interest	1
Operating Lease, Liability	15	$ 18
Schedule of Lessee, Finance Lease, Liability, Maturity [Line Items]
2021	2
2022	2
2023	2
2024	2
2025	2
Remaining years	4
Finance Lease, Liability, to be Paid	14
Interest	1
Finance lease, liability	$ 13

Lessee - Supplemental Cash Flow Information Related to Leases (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Supplemental Cash Flow Information [Line Items]
Operating cash flows from operating leases	$ 271	$ 287
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	1	52
Exelon Generation Co L L C [Member]
Supplemental Cash Flow Information [Line Items]
Operating cash flows from operating leases	204	206
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	3	14
Commonwealth Edison Co [Member]
Supplemental Cash Flow Information [Line Items]
Operating cash flows from operating leases	3	3
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	0	6
PECO Energy Co [Member]
Supplemental Cash Flow Information [Line Items]
Operating cash flows from operating leases	1	0
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	1	0
Baltimore Gas and Electric Company [Member]
Supplemental Cash Flow Information [Line Items]
Operating cash flows from operating leases	20	33
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	0	2
Pepco Holdings LLC [Member]
Supplemental Cash Flow Information [Line Items]
Operating cash flows from operating leases	39	37
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	(1)	(3)
Finance Lease, Principal Payments	6
Right-of-Use Asset Obtained in Exchange for Finance Lease Liability	29
Potomac Electric Power Company [Member]
Supplemental Cash Flow Information [Line Items]
Operating cash flows from operating leases	8	9
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	0	(1)
Finance Lease, Principal Payments	2
Right-of-Use Asset Obtained in Exchange for Finance Lease Liability	8
Delmarva Power & Light Company [Member]
Supplemental Cash Flow Information [Line Items]
Operating cash flows from operating leases	9	6
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	(1)	(2)
Finance Lease, Principal Payments	3
Right-of-Use Asset Obtained in Exchange for Finance Lease Liability	14
Atlantic City Electric Company [Member]
Supplemental Cash Flow Information [Line Items]
Operating cash flows from operating leases	4	5
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	0	$ (1)
Finance Lease, Principal Payments	1
Right-of-Use Asset Obtained in Exchange for Finance Lease Liability	$ 7

Lessor - Components of Operating Lease Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Schedule of Operating Lease, Lease Income [Line Items]
Operating Lease Income	$ 52	$ 54
Variable Lease Income	283	261
Exelon Generation Co L L C [Member]
Schedule of Operating Lease, Lease Income [Line Items]
Operating Lease Income	47	47
Variable Lease Income	282	258
Commonwealth Edison Co [Member]
Schedule of Operating Lease, Lease Income [Line Items]
Operating Lease Income	0	0
Variable Lease Income	0	0
PECO Energy Co [Member]
Schedule of Operating Lease, Lease Income [Line Items]
Operating Lease Income	0	0
Variable Lease Income	0	0
Baltimore Gas and Electric Company [Member]
Schedule of Operating Lease, Lease Income [Line Items]
Operating Lease Income	0	0
Variable Lease Income	0	0
Pepco Holdings LLC [Member]
Schedule of Operating Lease, Lease Income [Line Items]
Operating Lease Income	3	5
Variable Lease Income	1	3
Potomac Electric Power Company [Member]
Schedule of Operating Lease, Lease Income [Line Items]
Operating Lease Income	0	0
Variable Lease Income	0	0
Delmarva Power & Light Company [Member]
Schedule of Operating Lease, Lease Income [Line Items]
Operating Lease Income	3	4
Variable Lease Income	1	3
Atlantic City Electric Company [Member]
Schedule of Operating Lease, Lease Income [Line Items]
Operating Lease Income	0	0
Variable Lease Income	$ 0	$ 0

Lessor - Operating Lease, Payments, Fiscal Year Maturity (Details) $ in Millions	Dec. 31, 2020 USD ($)
Schedule of Lessor, Operating Lease, Payments to be Received, Maturity [Line Items]
2021	$ 51
2022	50
2023	49
2024	49
2025	48
Remaining years	217
Total Lessor, Operating Lease, Payments to be Received	464
Exelon Generation Co L L C [Member]
Schedule of Lessor, Operating Lease, Payments to be Received, Maturity [Line Items]
2021	45
2022	45
2023	45
2024	45
2025	45
Remaining years	182
Total Lessor, Operating Lease, Payments to be Received	407
Commonwealth Edison Co [Member]
Schedule of Lessor, Operating Lease, Payments to be Received, Maturity [Line Items]
2021	0
2022	0
2023	0
2024	0
2025	0
Remaining years	1
Total Lessor, Operating Lease, Payments to be Received	1
PECO Energy Co [Member]
Schedule of Lessor, Operating Lease, Payments to be Received, Maturity [Line Items]
2021	0
2022	0
2023	0
2024	0
2025	0
Remaining years	4
Total Lessor, Operating Lease, Payments to be Received	4
Baltimore Gas and Electric Company [Member]
Schedule of Lessor, Operating Lease, Payments to be Received, Maturity [Line Items]
2021	0
2022	0
2023	0
2024	0
2025	0
Remaining years	1
Total Lessor, Operating Lease, Payments to be Received	1
Pepco Holdings LLC [Member]
Schedule of Lessor, Operating Lease, Payments to be Received, Maturity [Line Items]
2021	4
2022	4
2023	4
2024	3
2025	4
Remaining years	31
Total Lessor, Operating Lease, Payments to be Received	50
Potomac Electric Power Company [Member]
Schedule of Lessor, Operating Lease, Payments to be Received, Maturity [Line Items]
2021	1
2022	0
2023	0
2024	0
2025	0
Remaining years	0
Total Lessor, Operating Lease, Payments to be Received	1
Delmarva Power & Light Company [Member]
Schedule of Lessor, Operating Lease, Payments to be Received, Maturity [Line Items]
2021	3
2022	3
2023	4
2024	3
2025	4
Remaining years	31
Total Lessor, Operating Lease, Payments to be Received	48
Atlantic City Electric Company [Member]
Schedule of Lessor, Operating Lease, Payments to be Received, Maturity [Line Items]
2021	0
2022	0
2023	0
2024	0
2025	0
Remaining years	0
Total Lessor, Operating Lease, Payments to be Received	$ 0

Asset Impairments - Narrative (Details) $ in Millions	3 Months Ended				12 Months Ended
Asset Impairments - Narrative (Details) $ in Millions	Sep. 30, 2020 USD ($)	Sep. 30, 2019 USD ($)	Mar. 31, 2019 USD ($)	Mar. 31, 2018 USD ($)	Dec. 31, 2020 USD ($) MW	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)
Impaired Long-Lived Assets Held and Used [Line Items]
Asset impairments					$ 591	$ 201	$ 50
Net income (loss) attributable to noncontrolling interests					(9)	92	74
Deferred Income Taxes and Tax Credits					$ 309	681	(108)
Certain Distributed Energy Companies [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Equity Method Investment, Other than Temporary Impairment		$ 164
Net income (loss) attributable to noncontrolling interests		96
Deferred Income Taxes and Tax Credits		(46)
Income (Loss) from Equity Method Investments		(15)
Antelope Valley [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Capacity Of Facility Of Company Owned Solar Distribution Generation Facilities \| MW					242
Asset impairments			$ 0
Generation New England [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Asset impairments				$ 0
Impairment of Long-Lived Assets to be Disposed of	$ 500
Generation Midwest [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Long-Lived Assets to be Disposed of	0
Exelon Generation Co L L C [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Asset impairments					$ 563	201	50
Net income (loss) attributable to noncontrolling interests					(10)	92	73
Deferred Income Taxes and Tax Credits					$ 78	$ 361	$ (451)
Exelon Generation Co L L C [Member] \| Certain Distributed Energy Companies [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Equity Method Investment, Other than Temporary Impairment		164
Net income (loss) attributable to noncontrolling interests		96
Deferred Income Taxes and Tax Credits		(46)
Income (Loss) from Equity Method Investments		$ (15)
Exelon Generation Co L L C [Member] \| Antelope Valley [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Capacity Of Facility Of Company Owned Solar Distribution Generation Facilities \| MW					242
Asset impairments			$ 0
Exelon Generation Co L L C [Member] \| Generation New England [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Asset impairments				$ 0
Impairment of Long-Lived Assets to be Disposed of	500
Exelon Generation Co L L C [Member] \| Generation Midwest [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Long-Lived Assets to be Disposed of	$ 0

Intangible Assets - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Mar. 24, 2016	Oct. 20, 2000
Goodwill [Line Items]
Goodwill, Additions	$ 0	$ 0
Goodwill Impairment Loss	0	0
Goodwill	6,677	6,677
Commonwealth Edison Co [Member]
Goodwill [Line Items]
Goodwill	2,625	2,625		$ 2,600
Pepco Holdings LLC [Member]
Goodwill [Line Items]
Goodwill	4,005	4,005	$ 4,000
Potomac Electric Power Company [Member]
Goodwill [Line Items]
Goodwill			2,100
Delmarva Power & Light Company [Member]
Goodwill [Line Items]
Goodwill	$ 8	$ 8	1,400
Atlantic City Electric Company [Member]
Goodwill [Line Items]
Goodwill			$ 500

Intangible Assets - Schedule of Goodwill (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Mar. 24, 2016	Oct. 20, 2000
Goodwill [Line Items]
Goodwill, Gross	$ 8,660	$ 8,660
Accumulated Impairment Loss	1,983	1,983
Carrying amount	6,677	6,677
Commonwealth Edison Co [Member]
Goodwill [Line Items]
Goodwill, Gross	4,608	4,608
Accumulated Impairment Loss	1,983	1,983
Carrying amount	2,625	2,625		$ 2,600
Pepco Holdings LLC [Member]
Goodwill [Line Items]
Goodwill, Gross	4,005	4,005
Accumulated Impairment Loss	0	0
Carrying amount	$ 4,005	$ 4,005	$ 4,000

Intangible Assets - Schedule of Other Intangible Assets (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Finite-Lived Intangible Assets [Line Items]
Gross	$ 1,253	$ 1,295
Accumulated Amortization	(1,081)	(1,121)
Net	172	174
Exelon Generation Co L L C [Member] \| Unamortized Energy Contracts [Member]
Finite-Lived Intangible Assets [Line Items]
Gross	1,963	1,967
Accumulated Amortization	(1,642)	(1,612)
Net	321	355
Exelon Generation Co L L C [Member] \| Customer Relationships [Member]
Finite-Lived Intangible Assets [Line Items]
Gross	326	343
Accumulated Amortization	(215)	(190)
Net	111	153
Exelon Generation Co L L C [Member] \| Trade Names [Member]
Finite-Lived Intangible Assets [Line Items]
Gross	222	243
Accumulated Amortization	(197)	(193)
Net	25	50
Commonwealth Edison Co [Member] \| Intangible Asset Nineteen Ninety Nine Chicago Settlement Agreement [Member]
Finite-Lived Intangible Assets [Line Items]
Gross	162	162
Accumulated Amortization	(162)	(155)
Net	0	7
Pepco Holdings LLC [Member] \| Unamortized Energy Contracts [Member]
Finite-Lived Intangible Assets [Line Items]
Gross	(1,515)	(1,515)
Accumulated Amortization	1,188	1,073
Net	(327)	(442)
Business Services Company [Member] \| Licensing Agreements [Member]
Finite-Lived Intangible Assets [Line Items]
Gross	95	95
Accumulated Amortization	(53)	(44)
Net	$ 42	$ 51

Intangible Assets Intangible Assets - Summary of Amortization Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Finite-Lived Intangible Assets [Line Items]
Intangible asset amortization expense	$ (17)	$ (28)	$ (109)
Exelon Generation Co L L C [Member]
Finite-Lived Intangible Assets [Line Items]
Intangible asset amortization expense	81	74	63
Commonwealth Edison Co [Member]
Finite-Lived Intangible Assets [Line Items]
Intangible asset amortization expense	7	7	7
Pepco Holdings LLC [Member]
Finite-Lived Intangible Assets [Line Items]
Intangible asset amortization expense	(115)	(119)	(188)
Unamortized Energy Contracts [Member]
Finite-Lived Intangible Assets [Line Items]
Amortization of Power Contracts Emission Credits	30	21	14
Unamortized Energy Contracts [Member] \| Exelon Generation Co L L C [Member]
Finite-Lived Intangible Assets [Line Items]
Amortization of Power Contracts Emission Credits	30	21	14
Unamortized Energy Contracts [Member] \| Commonwealth Edison Co [Member]
Finite-Lived Intangible Assets [Line Items]
Amortization of Power Contracts Emission Credits	0	0	0
Unamortized Energy Contracts [Member] \| Pepco Holdings LLC [Member]
Finite-Lived Intangible Assets [Line Items]
Amortization of Power Contracts Emission Credits	$ 0	$ 0	$ 0

Intangible Assets Intangible Assets - Schedule of Finite-Lived Intangible Assets, Future Amortization Expense (Details) $ in Millions	Dec. 31, 2020 USD ($)
Finite-Lived Intangible Assets [Line Items]
2021	$ (1)
2022	(22)
2023	(20)
2024	20
2025	40
Exelon Generation Co L L C [Member]
Finite-Lived Intangible Assets [Line Items]
2021	81
2022	57
2023	51
2024	48
2025	41
Pepco Holdings LLC [Member]
Finite-Lived Intangible Assets [Line Items]
2021	(92)
2022	(89)
2023	(81)
2024	(38)
2025	$ (5)

Intangible Assets - Renewable and Alternative Energy Credits (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Renewable energy credit current [Member]
Finite-Lived Intangible Assets [Line Items]
Acquired Finite-lived Intangible Asset, Residual Value	$ 632	$ 345
Renewable energy credit noncurrent [Member]
Finite-Lived Intangible Assets [Line Items]
Acquired Finite-lived Intangible Asset, Residual Value	0	86
Exelon Generation Co L L C [Member] \| Renewable energy credit current [Member]
Finite-Lived Intangible Assets [Line Items]
Acquired Finite-lived Intangible Asset, Residual Value	621	336
Exelon Generation Co L L C [Member] \| Renewable energy credit noncurrent [Member]
Finite-Lived Intangible Assets [Line Items]
Acquired Finite-lived Intangible Asset, Residual Value	$ 0	$ 86

Income Taxes - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
Income Taxes - Narrative (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Mar. 31, 2019
Income Taxes [Line Items]
Income Tax Credits and Adjustments		$ 108
Current Federal, State and Local, Tax Expense (Benefit)		97
Decrease in Unrecognized Tax Benefits is Reasonably Possible	$ 411
Like kind exchange [Member]
Income Taxes [Line Items]
Decrease in Unrecognized Tax Benefits is Reasonably Possible				$ 33
Exelon Generation Co L L C [Member]
Income Taxes [Line Items]
Income Tax Credits and Adjustments		75
Current Federal, State and Local, Tax Expense (Benefit)		66
Decrease in Unrecognized Tax Benefits is Reasonably Possible	411
Commonwealth Edison Co [Member] \| Like kind exchange [Member]
Income Taxes [Line Items]
Decrease in Unrecognized Tax Benefits is Reasonably Possible				$ 2
Atlantic City Electric Company [Member]
Income Taxes [Line Items]
Increase in Unrecognized Tax Benefits is Reasonably Possible	14	14	$ 14
State and Local Jurisdiction [Member]
Income Taxes [Line Items]
Increase (Decrease) in Income Taxes	(66)	(23)	50
State and Local Jurisdiction [Member] \| Exelon Generation Co L L C [Member]
Income Taxes [Line Items]
Increase (Decrease) in Income Taxes	26	$ (9)	$ 53
State and Local Jurisdiction [Member] \| Atlantic City Electric Company [Member]
Income Taxes [Line Items]
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecorded Benefit	14
State and Local Jurisdiction [Member] \| Pepco Holdings LLC [Member]
Income Taxes [Line Items]
Decrease in Unrecognized Tax Benefits is Reasonably Possible	14
Tax Year 2019 [Member] \| State and Local Jurisdiction [Member] \| Pepco Holdings LLC [Member]
Income Taxes [Line Items]
Decrease in Unrecognized Tax Benefits is Reasonably Possible	$ 21

Income Taxes - Components of Income Tax Expense (Benefit) from Continuing Operations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Income Taxes [Line Items]
Income taxes	$ 373	$ 774	$ 118
Exelon Generation Co L L C [Member]
Income Taxes [Line Items]
Income taxes	249	516	(108)
Commonwealth Edison Co [Member]
Income Taxes [Line Items]
Income taxes	177	163	168
PECO Energy Co [Member]
Income Taxes [Line Items]
Income taxes	(30)	65	6
Baltimore Gas and Electric Company [Member]
Income Taxes [Line Items]
Income taxes	41	79	74
Pepco Holdings LLC [Member]
Income Taxes [Line Items]
Income taxes	(77)	38	33
Potomac Electric Power Company [Member]
Income Taxes [Line Items]
Income taxes	(7)	16	11
Delmarva Power & Light Company [Member]
Income Taxes [Line Items]
Income taxes	(25)	22	22
Atlantic City Electric Company [Member]
Income Taxes [Line Items]
Income taxes	(41)	0	12
Internal Revenue Service (IRS) [Member]
Income Taxes [Line Items]
Current	26	85	226
Deferred	156	489	(99)
Investment Tax Credit	(28)	(72)	(24)
Income taxes	67
Internal Revenue Service (IRS) [Member] \| Exelon Generation Co L L C [Member]
Income Taxes [Line Items]
Current	130	147	337
Deferred	150	346	(347)
Investment Tax Credit	(25)	(69)	(21)
Income taxes	67
Internal Revenue Service (IRS) [Member] \| Commonwealth Edison Co [Member]
Income Taxes [Line Items]
Current	(24)	59	(63)
Deferred	112	15	145
Investment Tax Credit	(2)	(2)	(2)
Internal Revenue Service (IRS) [Member] \| PECO Energy Co [Member]
Income Taxes [Line Items]
Current	(7)	45	11
Deferred	1	20	10
Investment Tax Credit	0	0	0
Internal Revenue Service (IRS) [Member] \| Baltimore Gas and Electric Company [Member]
Income Taxes [Line Items]
Current	4	(51)	(5)
Deferred	10	95	47
Investment Tax Credit	0	0	0
Internal Revenue Service (IRS) [Member] \| Pepco Holdings LLC [Member]
Income Taxes [Line Items]
Current	25	43	(4)
Deferred	(129)	(34)	23
Investment Tax Credit	(1)	(1)	(1)
Internal Revenue Service (IRS) [Member] \| Potomac Electric Power Company [Member]
Income Taxes [Line Items]
Current	40	16	28
Deferred	(62)	(6)	(22)
Investment Tax Credit	0	0	0
Internal Revenue Service (IRS) [Member] \| Delmarva Power & Light Company [Member]
Income Taxes [Line Items]
Current	(13)	29	(3)
Deferred	(20)	(21)	13
Investment Tax Credit	0	0	0
Internal Revenue Service (IRS) [Member] \| Atlantic City Electric Company [Member]
Income Taxes [Line Items]
Current	(4)	(3)	(14)
Deferred	(43)	(6)	18
Investment Tax Credit	0	0	0
State and Local Jurisdiction [Member]
Income Taxes [Line Items]
Current	42	5	(1)
Deferred	177	267	16
State and Local Jurisdiction [Member] \| Exelon Generation Co L L C [Member]
Income Taxes [Line Items]
Current	40	10	6
Deferred	(46)	82	(83)
State and Local Jurisdiction [Member] \| Commonwealth Edison Co [Member]
Income Taxes [Line Items]
Current	(27)	(5)	(29)
Deferred	118	96	117
State and Local Jurisdiction [Member] \| PECO Energy Co [Member]
Income Taxes [Line Items]
Current	0	0	1
Deferred	(24)	0	(16)
State and Local Jurisdiction [Member] \| Baltimore Gas and Electric Company [Member]
Income Taxes [Line Items]
Current	0	0	0
Deferred	27	35	32
State and Local Jurisdiction [Member] \| Pepco Holdings LLC [Member]
Income Taxes [Line Items]
Current	(5)	3	7
Deferred	33	27	8
State and Local Jurisdiction [Member] \| Potomac Electric Power Company [Member]
Income Taxes [Line Items]
Current	0	0	0
Deferred	15	6	5
State and Local Jurisdiction [Member] \| Delmarva Power & Light Company [Member]
Income Taxes [Line Items]
Current	0	0	0
Deferred	8	14	12
State and Local Jurisdiction [Member] \| Atlantic City Electric Company [Member]
Income Taxes [Line Items]
Current	0	0	0
Deferred	$ 6	$ 9	$ 8

Income Taxes - Reconciliation to Effective Tax Rate (Details)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Effective Income Tax Rate Reconciliation At Federal Statutory Income Tax Rate [Line Items]
U.S. Federal statutory rate	21.00%	21.00%	21.00%
State income taxes, net of Federal income tax benefit	7.80%	5.40%	0.50%
Qualified nuclear decommissioning trust fund income	8.40%	5.90%	(1.90%)
Effective Income Tax Rate Reconciliation, Deferred Prosecution Agreement payments	1.80%
Amortization of investment tax credit, including deferred taxes on basis difference	(1.10%)	(1.50%)	(1.20%)
Plant basis differences	(4.00%)	(1.40%)	(3.50%)
Production tax credits and other credits	(2.20%)	(3.10%)	(2.20%)
Noncontrolling interests	1.10%	(0.60%)	(1.00%)
Excess deferred tax amortization	(13.60%)	(5.50%)	(8.30%)
Effective Income Tax Rate Reconciliation, Tax Settlement, Percent	(3.70%)
Tax Cuts and Jobs Act of 2017			0.90%
Other	0.50%	(0.80%)	1.00%
Effective income tax rate	16.00%	19.40%	5.30%
Exelon Generation Co L L C [Member]
Effective Income Tax Rate Reconciliation At Federal Statutory Income Tax Rate [Line Items]
U.S. Federal statutory rate	21.00%	21.00%	21.00%
State income taxes, net of Federal income tax benefit	0.50%	3.80%	(16.60%)
Qualified nuclear decommissioning trust fund income	23.50%	12.30%	(11.80%)
Effective Income Tax Rate Reconciliation, Deferred Prosecution Agreement payments	0.00%
Amortization of investment tax credit, including deferred taxes on basis difference	(2.60%)	(3.00%)	(6.50%)
Plant basis differences	0.00%	0.00%	0.00%
Production tax credits and other credits	(5.40%)	(4.80%)	(13.50%)
Noncontrolling interests	3.20%	(1.20%)	(6.10%)
Excess deferred tax amortization	0.00%	0.00%	0.00%
Effective Income Tax Rate Reconciliation, Tax Settlement, Percent	(10.30%)
Tax Cuts and Jobs Act of 2017			2.70%
Other	(0.10%)	(1.20%)	1.30%
Effective income tax rate	29.80%	26.90%	(29.50%)
Commonwealth Edison Co [Member]
Effective Income Tax Rate Reconciliation At Federal Statutory Income Tax Rate [Line Items]
U.S. Federal statutory rate	21.00%	21.00%	21.00%
State income taxes, net of Federal income tax benefit	11.60%	8.50%	8.30%
Qualified nuclear decommissioning trust fund income	0.00%	0.00%	0.00%
Effective Income Tax Rate Reconciliation, Deferred Prosecution Agreement payments	6.80%
Amortization of investment tax credit, including deferred taxes on basis difference	(0.30%)	(0.20%)	(0.20%)
Plant basis differences	(0.60%)	0.00%	(0.20%)
Production tax credits and other credits	(0.30%)	1.20%	0.00%
Noncontrolling interests	0.00%	0.00%	0.00%
Excess deferred tax amortization	(11.20%)	(9.70%)	(9.10%)
Effective Income Tax Rate Reconciliation, Tax Settlement, Percent	0.00%
Tax Cuts and Jobs Act of 2017			(0.10%)
Other	1.80%	0.80%	0.50%
Effective income tax rate	28.80%	19.20%	20.20%
PECO Energy Co [Member]
Effective Income Tax Rate Reconciliation At Federal Statutory Income Tax Rate [Line Items]
U.S. Federal statutory rate	21.00%	21.00%	21.00%
State income taxes, net of Federal income tax benefit	(4.50%)	0.00%	(2.60%)
Qualified nuclear decommissioning trust fund income	0.00%	0.00%	0.00%
Effective Income Tax Rate Reconciliation, Deferred Prosecution Agreement payments	0.00%
Amortization of investment tax credit, including deferred taxes on basis difference	0.00%	0.00%	(0.10%)
Plant basis differences	(18.70%)	(7.20%)	(14.10%)
Production tax credits and other credits	0.00%	0.00%	0.00%
Noncontrolling interests	0.00%	0.00%	0.00%
Excess deferred tax amortization	(4.60%)	(2.80%)	(3.20%)
Effective Income Tax Rate Reconciliation, Tax Settlement, Percent	0.00%
Tax Cuts and Jobs Act of 2017			0.00%
Other	(0.40%)	0.00%	0.30%
Effective income tax rate	(7.20%)	11.00%	1.30%
Baltimore Gas and Electric Company [Member]
Effective Income Tax Rate Reconciliation At Federal Statutory Income Tax Rate [Line Items]
U.S. Federal statutory rate	21.00%	21.00%	21.00%
State income taxes, net of Federal income tax benefit	5.50%	6.40%	6.60%
Qualified nuclear decommissioning trust fund income	0.00%	0.00%	0.00%
Effective Income Tax Rate Reconciliation, Deferred Prosecution Agreement payments	0.00%
Amortization of investment tax credit, including deferred taxes on basis difference	(0.10%)	(0.10%)	(0.10%)
Plant basis differences	(1.50%)	(1.20%)	(1.30%)
Production tax credits and other credits	(0.40%)	1.30%	0.00%
Noncontrolling interests	0.00%	0.00%	0.00%
Excess deferred tax amortization	(13.90%)	(6.80%)	(8.00%)
Effective Income Tax Rate Reconciliation, Tax Settlement, Percent	0.00%
Tax Cuts and Jobs Act of 2017			0.00%
Other	(0.10%)	0.00%	0.90%
Effective income tax rate	10.50%	18.00%	19.10%
Pepco Holdings LLC [Member]
Effective Income Tax Rate Reconciliation At Federal Statutory Income Tax Rate [Line Items]
U.S. Federal statutory rate	21.00%	21.00%	21.00%
State income taxes, net of Federal income tax benefit	5.10%	4.70%	2.90%
Qualified nuclear decommissioning trust fund income	0.00%	0.00%	0.00%
Effective Income Tax Rate Reconciliation, Deferred Prosecution Agreement payments	0.00%
Amortization of investment tax credit, including deferred taxes on basis difference	(0.20%)	(0.20%)	(0.20%)
Plant basis differences	(1.60%)	(1.20%)	(1.60%)
Production tax credits and other credits	(0.30%)	(0.20%)	0.00%
Noncontrolling interests	0.00%	0.00%	0.00%
Excess deferred tax amortization	(42.00%)	(17.50%)	(14.80%)
Effective Income Tax Rate Reconciliation, Tax Settlement, Percent	0.00%
Tax Cuts and Jobs Act of 2017			0.10%
Other	(0.40%)	0.80%	0.40%
Effective income tax rate	(18.40%)	7.40%	7.80%
Potomac Electric Power Company [Member]
Effective Income Tax Rate Reconciliation At Federal Statutory Income Tax Rate [Line Items]
U.S. Federal statutory rate	21.00%	21.00%	21.00%
State income taxes, net of Federal income tax benefit	4.50%	2.00%	2.00%
Qualified nuclear decommissioning trust fund income	0.00%	0.00%	0.00%
Effective Income Tax Rate Reconciliation, Deferred Prosecution Agreement payments	0.00%
Amortization of investment tax credit, including deferred taxes on basis difference	(0.10%)	(0.10%)	(0.10%)
Plant basis differences	(1.70%)	(1.80%)	(2.80%)
Production tax credits and other credits	(0.30%)	0.10%	0.00%
Noncontrolling interests	0.00%	0.00%	0.00%
Excess deferred tax amortization	(25.40%)	(15.10%)	(15.30%)
Effective Income Tax Rate Reconciliation, Tax Settlement, Percent	0.00%
Tax Cuts and Jobs Act of 2017			0.00%
Other	(0.70%)	0.30%	0.30%
Effective income tax rate	(2.70%)	6.20%	5.10%
Delmarva Power & Light Company [Member]
Effective Income Tax Rate Reconciliation At Federal Statutory Income Tax Rate [Line Items]
U.S. Federal statutory rate	21.00%	21.00%	21.00%
State income taxes, net of Federal income tax benefit	6.60%	6.80%	6.70%
Qualified nuclear decommissioning trust fund income	0.00%	0.00%	0.00%
Effective Income Tax Rate Reconciliation, Deferred Prosecution Agreement payments	0.00%
Amortization of investment tax credit, including deferred taxes on basis difference	(0.30%)	(0.20%)	(0.30%)
Plant basis differences	(0.40%)	(0.40%)	(0.30%)
Production tax credits and other credits	(0.30%)	0.00%	0.00%
Noncontrolling interests	0.00%	0.00%	0.00%
Excess deferred tax amortization	(51.70%)	(14.20%)	(12.00%)
Effective Income Tax Rate Reconciliation, Tax Settlement, Percent	0.00%
Tax Cuts and Jobs Act of 2017			0.00%
Other	0.10%	0.00%	0.40%
Effective income tax rate	(25.00%)	13.00%	15.50%
Atlantic City Electric Company [Member]
Effective Income Tax Rate Reconciliation At Federal Statutory Income Tax Rate [Line Items]
U.S. Federal statutory rate	21.00%	21.00%	21.00%
State income taxes, net of Federal income tax benefit	7.00%	7.00%	7.40%
Qualified nuclear decommissioning trust fund income	0.00%	0.00%	0.00%
Effective Income Tax Rate Reconciliation, Deferred Prosecution Agreement payments	0.00%
Amortization of investment tax credit, including deferred taxes on basis difference	(0.50%)	(0.30%)	(0.40%)
Plant basis differences	(3.00%)	(0.70%)	(0.50%)
Production tax credits and other credits	(0.50%)	0.10%	0.00%
Noncontrolling interests	0.00%	0.00%	0.00%
Excess deferred tax amortization	(82.10%)	(27.00%)	(14.90%)
Effective Income Tax Rate Reconciliation, Tax Settlement, Percent	0.00%
Tax Cuts and Jobs Act of 2017			0.00%
Other	0.40%	0.10%	1.20%
Effective income tax rate	(57.70%)	0.00%	13.80%

Income Taxes - Tax Effects of Temporary Differences and Carryforwards (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Operating Loss Carryforwards [Line Items]
Plant basis differences	$ (13,868)	$ (13,413)
Deferred Tax Liabilities, Other Finite-Lived Assets	40	61
Derivatives and other financial instruments	41	165
Deferred pension and postretirement obligation	1,559	1,504
Deferred Tax Liabilities, Investments	(742)	(503)
Deferred debt refinancing costs	169	183
Deferred Tax Liabilities, Regulatory Assets and Liabilities	(1,107)	(884)
Tax loss carryforward	286	240
Tax credit carryforward	841	892
Investment in partnerships	(835)	(830)
Other, net	1,070	926
Deferred income tax liabilities (net)	(12,546)	(11,659)
Unamortized investment tax credits(a)	(464)	(668)
Total deferred income tax liabilities (net) and unamortized investment tax credits	(13,010)	(12,327)
State and Local Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
Increase (Decrease) in Deferred Income Taxes	66	23	$ (50)
Exelon Generation Co L L C [Member]
Operating Loss Carryforwards [Line Items]
Plant basis differences	(2,592)	(2,814)
Deferred Tax Liabilities, Other Finite-Lived Assets	(37)	(43)
Derivatives and other financial instruments	(41)	88
Deferred pension and postretirement obligation	(236)	(220)
Deferred Tax Liabilities, Investments	(742)	(503)
Deferred debt refinancing costs	16	20
Deferred Tax Liabilities, Regulatory Assets and Liabilities	0	0
Tax loss carryforward	55	55
Tax credit carryforward	838	897
Investment in partnerships	(813)	(808)
Other, net	347	236
Deferred income tax liabilities (net)	(3,205)	(3,092)
Unamortized investment tax credits(a)	(445)	(648)
Total deferred income tax liabilities (net) and unamortized investment tax credits	(3,650)	(3,740)
Exelon Generation Co L L C [Member] \| State and Local Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
Increase (Decrease) in Deferred Income Taxes	(26)	9	$ (53)
Commonwealth Edison Co [Member]
Operating Loss Carryforwards [Line Items]
Plant basis differences	(4,432)	(4,197)
Deferred Tax Liabilities, Other Finite-Lived Assets	0	0
Derivatives and other financial instruments	84	84
Deferred pension and postretirement obligation	(288)	(270)
Deferred Tax Liabilities, Investments	0	0
Deferred debt refinancing costs	(6)	(7)
Deferred Tax Liabilities, Regulatory Assets and Liabilities	87	183
Tax loss carryforward	0	0
Tax credit carryforward	0	0
Investment in partnerships	0	0
Other, net	223	196
Deferred income tax liabilities (net)	(4,332)	(4,011)
Unamortized investment tax credits(a)	(9)	(10)
Total deferred income tax liabilities (net) and unamortized investment tax credits	(4,341)	(4,021)
PECO Energy Co [Member]
Operating Loss Carryforwards [Line Items]
Plant basis differences	(2,131)	(1,978)
Deferred Tax Liabilities, Other Finite-Lived Assets	0	0
Derivatives and other financial instruments	0	0
Deferred pension and postretirement obligation	(30)	(28)
Deferred Tax Liabilities, Investments	0	0
Deferred debt refinancing costs	0	0
Deferred Tax Liabilities, Regulatory Assets and Liabilities	(231)	(169)
Tax loss carryforward	47	25
Tax credit carryforward	0	0
Investment in partnerships	0	0
Other, net	104	70
Deferred income tax liabilities (net)	(2,241)	(2,080)
Unamortized investment tax credits(a)	(1)	(1)
Total deferred income tax liabilities (net) and unamortized investment tax credits	(2,242)	(2,081)
Baltimore Gas and Electric Company [Member]
Operating Loss Carryforwards [Line Items]
Plant basis differences	(1,711)	(1,578)
Deferred Tax Liabilities, Other Finite-Lived Assets	0	0
Derivatives and other financial instruments	0	0
Deferred pension and postretirement obligation	(33)	(28)
Deferred Tax Liabilities, Investments	0	0
Deferred debt refinancing costs	(2)	(3)
Deferred Tax Liabilities, Regulatory Assets and Liabilities	142	157
Tax loss carryforward	57	49
Tax credit carryforward	0	0
Investment in partnerships	0	0
Other, net	29	10
Deferred income tax liabilities (net)	(1,518)	(1,393)
Unamortized investment tax credits(a)	(3)	(3)
Total deferred income tax liabilities (net) and unamortized investment tax credits	(1,521)	(1,396)
Pepco Holdings LLC [Member]
Operating Loss Carryforwards [Line Items]
Plant basis differences	(2,822)	(2,681)
Deferred Tax Liabilities, Other Finite-Lived Assets	77	104
Derivatives and other financial instruments	2	2
Deferred pension and postretirement obligation	(80)	(89)
Deferred Tax Liabilities, Investments	0	0
Deferred debt refinancing costs	131	142
Deferred Tax Liabilities, Regulatory Assets and Liabilities	(41)	(10)
Tax loss carryforward	90	93
Tax credit carryforward	0	0
Investment in partnerships	0	0
Other, net	220	181
Deferred income tax liabilities (net)	(2,423)	(2,258)
Unamortized investment tax credits(a)	(6)	(7)
Total deferred income tax liabilities (net) and unamortized investment tax credits	(2,429)	(2,265)
Potomac Electric Power Company [Member]
Operating Loss Carryforwards [Line Items]
Plant basis differences	(1,259)	(1,204)
Deferred Tax Liabilities, Other Finite-Lived Assets	0	0
Derivatives and other financial instruments	0	0
Deferred pension and postretirement obligation	(74)	(75)
Deferred Tax Liabilities, Investments	0	0
Deferred debt refinancing costs	(3)	(3)
Deferred Tax Liabilities, Regulatory Assets and Liabilities	38	55
Tax loss carryforward	4	13
Tax credit carryforward	0	0
Investment in partnerships	0	0
Other, net	107	85
Deferred income tax liabilities (net)	(1,187)	(1,129)
Unamortized investment tax credits(a)	(2)	(2)
Total deferred income tax liabilities (net) and unamortized investment tax credits	(1,189)	(1,131)
Delmarva Power & Light Company [Member]
Operating Loss Carryforwards [Line Items]
Plant basis differences	(806)	(753)
Deferred Tax Liabilities, Other Finite-Lived Assets	0	0
Derivatives and other financial instruments	0	0
Deferred pension and postretirement obligation	(40)	(42)
Deferred Tax Liabilities, Investments	0	0
Deferred debt refinancing costs	(1)	(2)
Deferred Tax Liabilities, Regulatory Assets and Liabilities	67	88
Tax loss carryforward	49	44
Tax credit carryforward	0	0
Investment in partnerships	0	0
Other, net	18	12
Deferred income tax liabilities (net)	(713)	(653)
Unamortized investment tax credits(a)	(2)	(2)
Total deferred income tax liabilities (net) and unamortized investment tax credits	(715)	(655)
Atlantic City Electric Company [Member]
Operating Loss Carryforwards [Line Items]
Plant basis differences	(725)	(687)
Deferred Tax Liabilities, Other Finite-Lived Assets	0	0
Derivatives and other financial instruments	0	0
Deferred pension and postretirement obligation	(7)	(10)
Deferred Tax Liabilities, Investments	0	0
Deferred debt refinancing costs	(1)	(1)
Deferred Tax Liabilities, Regulatory Assets and Liabilities	46	77
Tax loss carryforward	38	31
Tax credit carryforward	0	0
Investment in partnerships	0	0
Other, net	27	16
Deferred income tax liabilities (net)	(622)	(574)
Unamortized investment tax credits(a)	(3)	(3)
Total deferred income tax liabilities (net) and unamortized investment tax credits	$ (625)	$ (577)

Income Taxes - Schedule of Carryforwards and Corresponding Valuation Allowances (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020 USD ($)
Operating Loss Carryforwards [Line Items]
Decrease in Unrecognized Tax Benefits is Reasonably Possible	$ 411
Exelon Generation Co L L C [Member]
Operating Loss Carryforwards [Line Items]
Decrease in Unrecognized Tax Benefits is Reasonably Possible	411
Internal Revenue Service (IRS) [Member] \| General Business Tax Credit Carryforward [Member]
Operating Loss Carryforwards [Line Items]
Federal general business credits carryforwards and other carryforwards	858
Internal Revenue Service (IRS) [Member] \| General Business Tax Credit Carryforward [Member] \| Exelon Generation Co L L C [Member]
Operating Loss Carryforwards [Line Items]
Federal general business credits carryforwards and other carryforwards	852
Internal Revenue Service (IRS) [Member] \| General Business Tax Credit Carryforward [Member] \| PECO Energy Co [Member]
Operating Loss Carryforwards [Line Items]
Federal general business credits carryforwards and other carryforwards	0
Internal Revenue Service (IRS) [Member] \| General Business Tax Credit Carryforward [Member] \| Baltimore Gas and Electric Company [Member]
Operating Loss Carryforwards [Line Items]
Federal general business credits carryforwards and other carryforwards	0
Internal Revenue Service (IRS) [Member] \| General Business Tax Credit Carryforward [Member] \| Pepco Holdings LLC [Member]
Operating Loss Carryforwards [Line Items]
Federal general business credits carryforwards and other carryforwards	0
Internal Revenue Service (IRS) [Member] \| General Business Tax Credit Carryforward [Member] \| Potomac Electric Power Company [Member]
Operating Loss Carryforwards [Line Items]
Federal general business credits carryforwards and other carryforwards	0
Internal Revenue Service (IRS) [Member] \| General Business Tax Credit Carryforward [Member] \| Delmarva Power & Light Company [Member]
Operating Loss Carryforwards [Line Items]
Federal general business credits carryforwards and other carryforwards	0
Internal Revenue Service (IRS) [Member] \| General Business Tax Credit Carryforward [Member] \| Atlantic City Electric Company [Member]
Operating Loss Carryforwards [Line Items]
Federal general business credits carryforwards and other carryforwards	0
State and Local Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
State net operating losses and other carryforwards	5,202
Deferred taxes on state tax attributes (net)	324
Valuation allowance on state tax attributes	$ 27
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2034
Tax Credit Carryforward, Expiration Date	Dec. 31, 2034
State and Local Jurisdiction [Member] \| ILLINOIS
Operating Loss Carryforwards [Line Items]
Tax Credit Carryforward, Expiration Date	Dec. 31, 2029
State and Local Jurisdiction [Member] \| Exelon Generation Co L L C [Member]
Operating Loss Carryforwards [Line Items]
State net operating losses and other carryforwards	$ 1,118
Deferred taxes on state tax attributes (net)	76
Valuation allowance on state tax attributes	$ 23
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2034
Tax Credit Carryforward, Expiration Date	Dec. 31, 2034
State and Local Jurisdiction [Member] \| PECO Energy Co [Member]
Operating Loss Carryforwards [Line Items]
State net operating losses and other carryforwards	$ 616
Deferred taxes on state tax attributes (net)	49
Valuation allowance on state tax attributes	$ 1
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2032
Tax Credit Carryforward, Expiration Date	Dec. 31, 2021
State and Local Jurisdiction [Member] \| Baltimore Gas and Electric Company [Member]
Operating Loss Carryforwards [Line Items]
State net operating losses and other carryforwards	$ 902
Deferred taxes on state tax attributes (net)	59
Valuation allowance on state tax attributes	$ 0
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2033
Tax Credit Carryforward, Expiration Date	Dec. 31, 2021
State and Local Jurisdiction [Member] \| Pepco Holdings LLC [Member]
Operating Loss Carryforwards [Line Items]
State net operating losses and other carryforwards	$ 1,436
Deferred taxes on state tax attributes (net)	98
Valuation allowance on state tax attributes	$ 0
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2029
Decrease in Unrecognized Tax Benefits is Reasonably Possible	$ 14
State and Local Jurisdiction [Member] \| Potomac Electric Power Company [Member]
Operating Loss Carryforwards [Line Items]
State net operating losses and other carryforwards	63
Deferred taxes on state tax attributes (net)	4
Valuation allowance on state tax attributes	$ 0
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2029
State and Local Jurisdiction [Member] \| Delmarva Power & Light Company [Member]
Operating Loss Carryforwards [Line Items]
State net operating losses and other carryforwards	$ 728
Deferred taxes on state tax attributes (net)	49
Valuation allowance on state tax attributes	$ 0
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2032
State and Local Jurisdiction [Member] \| Atlantic City Electric Company [Member]
Operating Loss Carryforwards [Line Items]
State net operating losses and other carryforwards	$ 531
Deferred taxes on state tax attributes (net)	38
Valuation allowance on state tax attributes	$ 0
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2031

Income Taxes - Reconciliation of Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized Tax Benefits - Beginning Balance	$ 507	$ 477	$ 743
Unrecognized Tax Benefits, Period Increase (Decrease)	6	26	15
Increases based on tax positions related to current year	3	2
Increases based on tax positions prior to current year	26	34	30
Decreases based on tax positions prior to current year	348	3	251
Decrease from settlements with taxing authorities	(69)	(29)	(53)
Unrecognized Tax Benefits, Reduction Resulting from Lapse of Applicable Statute of Limitations			(7)
Unrecognized tax benefits - Ending Balance	125	507	477
Decrease in Unrecognized Tax Benefits is Reasonably Possible	411
Tax Adjustments, Settlements, and Unusual Provisions	76
Exelon Generation Co L L C [Member]
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized Tax Benefits - Beginning Balance	441	408	468
Unrecognized Tax Benefits, Period Increase (Decrease)	0	12	15
Increases based on tax positions related to current year	1	1
Increases based on tax positions prior to current year	23	19	21
Decreases based on tax positions prior to current year	346	3	36
Decrease from settlements with taxing authorities	(69)	4	(53)
Unrecognized Tax Benefits, Reduction Resulting from Lapse of Applicable Statute of Limitations			(7)
Unrecognized tax benefits - Ending Balance	50	441	408
Decrease in Unrecognized Tax Benefits is Reasonably Possible	411
Tax Adjustments, Settlements, and Unusual Provisions	73
Commonwealth Edison Co [Member]
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized Tax Benefits - Beginning Balance	6	2	2
Unrecognized Tax Benefits, Period Increase (Decrease)	2	3	0
Increases based on tax positions related to current year	0	0
Increases based on tax positions prior to current year	1	3	0
Decreases based on tax positions prior to current year	0	0	0
Decrease from settlements with taxing authorities	0	(2)	0
Unrecognized Tax Benefits, Reduction Resulting from Lapse of Applicable Statute of Limitations			0
Unrecognized tax benefits - Ending Balance	9	6	2
PECO Energy Co [Member]
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized Tax Benefits - Beginning Balance	3	0	0
Unrecognized Tax Benefits, Period Increase (Decrease)	3	1	0
Increases based on tax positions related to current year	0	0
Increases based on tax positions prior to current year	0	2	0
Decreases based on tax positions prior to current year	0	0	0
Decrease from settlements with taxing authorities	0	0	0
Unrecognized Tax Benefits, Reduction Resulting from Lapse of Applicable Statute of Limitations			0
Unrecognized tax benefits - Ending Balance	6	3	0
Baltimore Gas and Electric Company [Member]
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized Tax Benefits - Beginning Balance	7	0	120
Unrecognized Tax Benefits, Period Increase (Decrease)	3	4	0
Increases based on tax positions related to current year	0	0
Increases based on tax positions prior to current year	0	3	0
Decreases based on tax positions prior to current year	0	0	120
Decrease from settlements with taxing authorities	0	0	0
Unrecognized Tax Benefits, Reduction Resulting from Lapse of Applicable Statute of Limitations			0
Unrecognized tax benefits - Ending Balance	10	7	0
Pepco Holdings LLC [Member]
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized Tax Benefits - Beginning Balance	48	45	125
Unrecognized Tax Benefits, Period Increase (Decrease)	3	3	0
Increases based on tax positions related to current year	0	0
Increases based on tax positions prior to current year	1	0	8
Decreases based on tax positions prior to current year	0	0	88
Decrease from settlements with taxing authorities	0	0	0
Unrecognized Tax Benefits, Reduction Resulting from Lapse of Applicable Statute of Limitations			0
Unrecognized tax benefits - Ending Balance	52	48	45
Potomac Electric Power Company [Member]
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized Tax Benefits - Beginning Balance	2	0	59
Unrecognized Tax Benefits, Period Increase (Decrease)	1	2	0
Increases based on tax positions related to current year	0	0
Increases based on tax positions prior to current year	0	0	7
Decreases based on tax positions prior to current year	0	0	66
Decrease from settlements with taxing authorities	0	0	0
Unrecognized Tax Benefits, Reduction Resulting from Lapse of Applicable Statute of Limitations			0
Unrecognized tax benefits - Ending Balance	3	2	0
Delmarva Power & Light Company [Member]
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized Tax Benefits - Beginning Balance	1	0	21
Unrecognized Tax Benefits, Period Increase (Decrease)	0	1	0
Increases based on tax positions related to current year	0	0
Increases based on tax positions prior to current year	0	0	1
Decreases based on tax positions prior to current year	0	0	22
Decrease from settlements with taxing authorities	0	0	0
Unrecognized Tax Benefits, Reduction Resulting from Lapse of Applicable Statute of Limitations			0
Unrecognized tax benefits - Ending Balance	1	1	0
Atlantic City Electric Company [Member]
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized Tax Benefits - Beginning Balance	14	14	14
Unrecognized Tax Benefits, Period Increase (Decrease)	1	0	0
Increases based on tax positions related to current year	0	0
Increases based on tax positions prior to current year	0	0	0
Decreases based on tax positions prior to current year	0	0	0
Decrease from settlements with taxing authorities	0	0	0
Unrecognized Tax Benefits, Reduction Resulting from Lapse of Applicable Statute of Limitations			0
Unrecognized tax benefits - Ending Balance	15	$ 14	$ 14
State and Local Jurisdiction [Member] \| Pepco Holdings LLC [Member]
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Decrease in Unrecognized Tax Benefits is Reasonably Possible	$ 14

Income Taxes - Recognition of Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Recognition of Unrecognized Tax Benefits [Line Items]
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	$ 73	$ 462	$ 463
Decrease in Unrecognized Tax Benefits is Reasonably Possible	411
Exelon Generation Co L L C [Member]
Recognition of Unrecognized Tax Benefits [Line Items]
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	39	429	408
Decrease in Unrecognized Tax Benefits is Reasonably Possible	411
Pepco Holdings LLC [Member]
Recognition of Unrecognized Tax Benefits [Line Items]
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	33	32	31
Atlantic City Electric Company [Member]
Recognition of Unrecognized Tax Benefits [Line Items]
Increase in Unrecognized Tax Benefits is Reasonably Possible	14	$ 14	$ 14
State and Local Jurisdiction [Member] \| Pepco Holdings LLC [Member]
Recognition of Unrecognized Tax Benefits [Line Items]
Decrease in Unrecognized Tax Benefits is Reasonably Possible	14
State and Local Jurisdiction [Member] \| Atlantic City Electric Company [Member]
Recognition of Unrecognized Tax Benefits [Line Items]
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecorded Benefit	14
Tax Year 2019 [Member] \| State and Local Jurisdiction [Member] \| Pepco Holdings LLC [Member]
Recognition of Unrecognized Tax Benefits [Line Items]
Decrease in Unrecognized Tax Benefits is Reasonably Possible	$ 21

Income Taxes - Summary of Interest Receivable (Payable) (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Income Taxes [Line Items]
Net Interest Receivable Payable Related To Uncertain Tax Positions	$ 314	$ 318

Income Taxes - Long-Term Marginal State Income Tax Rate (Details) - State and Local Jurisdiction [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Long-Term Marginal State Income Tax Rate [Line Items]
Increase (Decrease) in Deferred Income Taxes	$ 66	$ 23	$ (50)
Increase (Decrease) in Income Taxes	66	23	(50)
Exelon Generation Co L L C [Member]
Long-Term Marginal State Income Tax Rate [Line Items]
Increase (Decrease) in Deferred Income Taxes	(26)	9	(53)
Increase (Decrease) in Income Taxes	$ (26)	$ 9	$ (53)

Income Taxes - Allocation of Tax Benefits (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Exelon Generation Co L L C [Member]
Income Taxes [Line Items]
Allocation Of Federal Tax Benefit Under Tax Sharing Agreement	$ 64	$ 41	$ 155
Commonwealth Edison Co [Member]
Income Taxes [Line Items]
Allocation Of Federal Tax Benefit Under Tax Sharing Agreement	14	0	1
PECO Energy Co [Member]
Income Taxes [Line Items]
Allocation Of Federal Tax Benefit Under Tax Sharing Agreement	17	14	48
Baltimore Gas and Electric Company [Member]
Income Taxes [Line Items]
Allocation Of Federal Tax Benefit Under Tax Sharing Agreement	0	3	26
Pepco Holdings LLC [Member]
Income Taxes [Line Items]
Allocation Of Federal Tax Benefit Under Tax Sharing Agreement	17	7	2
Potomac Electric Power Company [Member]
Income Taxes [Line Items]
Allocation Of Federal Tax Benefit Under Tax Sharing Agreement	8	6	0
Delmarva Power and Light Company [Member]
Income Taxes [Line Items]
Allocation Of Federal Tax Benefit Under Tax Sharing Agreement	6	1	0
Atlantic City Electric Company [Member]
Income Taxes [Line Items]
Allocation Of Federal Tax Benefit Under Tax Sharing Agreement	$ 1	$ 0	$ 0

Retirement Benefits- Narrative (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2020	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Increase (Decrease) in Obligation, Pension Benefits	$ 8
Benefit obligation increase (decrease) reflecting actual census data	31
Accumulated Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss), after Tax	7
Regulatory asset increase (decrease) due to updated valuation adjustment	19
Defined benefit plan, amounts increased (decrease) in regulatory liabilities, before tax	$ (10)
Defined Contribution Plan, Employer Discretionary Contribution Amount		$ 158	$ 161	$ 179
Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Regulatory asset increase (decrease) due to updated valuation adjustment		$ 140	$ 3	$ (6)
Expected return on plan assets		7.00%	7.00%	7.00%
Discount rate		3.34%	4.31%	3.62%
Defined Contribution Plan, Employer Discretionary Contribution Amount		$ 500
Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Regulatory asset increase (decrease) due to updated valuation adjustment		$ (20)	$ 106	$ (57)
Expected return on plan assets		6.69%	6.67%	6.60%
Discount rate		3.31%	4.30%	3.61%
Pension and other post retirement benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Mortality Rate			0.75%
Change in Assumptions for Defined Benefit Plans [Member] \| Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Expected return on plan assets		7.00%
Discount rate		3.34%
Change in Assumptions for Defined Benefit Plans [Member] \| Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Expected return on plan assets		6.69%
Discount rate		3.31%
Assets [Member] \| Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Actual Asset Returns		14.45%
Assets [Member] \| Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Actual Asset Returns		9.14%
Subsequent Event [Member] \| Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Expected return on plan assets		7.00%
Subsequent Event [Member] \| Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Expected return on plan assets		6.46%

Retirement Benefits - Summary of Changes in Benefit Obligations and Plan Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Pension Plan, Defined Benefit [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Net benefit obligation at beginning of year	$ 22,868	$ 20,692
Service cost	387	357	$ 405
Interest cost	757	883	802
Defined Benefit Plan, Benefit Obligation, Contributions by Plan Participant	0	0
Actuarial loss(a)	2,217	2,322
Plan amendments	0	68
Defined Benefit Plan, Benefit Obligation, (Increase) Decrease for Curtailment	0	(3)
Defined Benefit Plan, Benefit Obligation, (Increase) Decrease for Remeasurement due to Settlement	(45)	(35)
Defined Benefit Plan, Benefit Obligation, Special and Contractual Termination Benefits	0	1
Defined Benefit Plan, Benefit Obligation, Benefits Paid	(1,290)	(1,417)
Net benefit obligation at end of year	24,894	22,868	20,692
Fair value of net plan assets at beginning of year	18,590	16,678
Actual return on plan assets	2,547	3,008
Employer contributions	542	356
Defined Benefit Plan, Plan Assets, Contributions by Plan Participant	0	0
Defined Benefit Plan, Plan Assets, Benefits Paid	(1,290)	(1,417)
Defined Benefit Plan, Plan Assets, Payment for Settlement	(45)	(35)
Defined Benefit Plan, Plan Assets, Amount	20,344	18,590	16,678
Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Net benefit obligation at beginning of year	4,658	4,369
Service cost	90	93	112
Interest cost	154	188	175
Defined Benefit Plan, Benefit Obligation, Contributions by Plan Participant	49	44
Actuarial loss(a)	49	250
Plan amendments	(111)	0
Defined Benefit Plan, Benefit Obligation, (Increase) Decrease for Curtailment	0	0
Defined Benefit Plan, Benefit Obligation, (Increase) Decrease for Remeasurement due to Settlement	(5)	(4)
Defined Benefit Plan, Benefit Obligation, Special and Contractual Termination Benefits	0	0
Defined Benefit Plan, Benefit Obligation, Benefits Paid	(280)	(282)
Net benefit obligation at end of year	4,604	4,658	4,369
Fair value of net plan assets at beginning of year	2,541	2,408
Actual return on plan assets	190	324
Employer contributions	59	51
Defined Benefit Plan, Plan Assets, Contributions by Plan Participant	49	44
Defined Benefit Plan, Plan Assets, Benefits Paid	(280)	(282)
Defined Benefit Plan, Plan Assets, Payment for Settlement	(5)	(4)
Defined Benefit Plan, Plan Assets, Amount	$ 2,554	$ 2,541	$ 2,408

Retirement Benefits - Benefit Obligations and Plan Assets in Balance Sheet (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Pension Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Other current liabilities	$ 47	$ 31
Pension obligations	4,503	4,247
Non-pension postretirement benefit obligations	0	0
Unfunded status (net benefit obligation less plan assets)	4,550	4,278
Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Other current liabilities	42	41
Pension obligations	0	0
Non-pension postretirement benefit obligations	2,008	2,076
Unfunded status (net benefit obligation less plan assets)	$ 2,050	$ 2,117

Retirement Benefits- Projected Benefit Obligations and Accumulated Benefit Obligations in Excess of Plan Assets (Details) - Accumulated Benefit Obligation In Excess Of Plan Assets [Member] - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Defined Benefit Plan Disclosure [Line Items]
ABO	$ 23,514	$ 21,727
Fair value of net plan assets	$ 20,344	$ 18,590

Retirement Benefits - Components of Net Periodic Benefit Cost (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Amortization of:
Net periodic benefit cost	$ 53	$ 13	$ (47)
Pension Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	387	357	405
Interest cost	757	883	802
Expected return on assets	(1,270)	(1,225)	(1,252)
Amortization of:
Prior service cost (credit)	4	0	2
Actuarial loss	512	414	629
Curtailment benefits	0	0	0
Settlement and other charges	14	17	3
Contractual termination benefits	0	1	0
Net periodic benefit cost	404	447	589
Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	90	93	112
Interest cost	154	188	175
Expected return on assets	(163)	(153)	(173)
Amortization of:
Prior service cost (credit)	(124)	(179)	(186)
Actuarial loss	49	45	66
Curtailment benefits	(1)	0	0
Settlement and other charges	1	1	1
Contractual termination benefits	0	0	0
Net periodic benefit cost	$ 6	$ (5)	$ (5)

Retirement Benefits - Components of Accumulated Other Comprehensive Income and Regulatory Assets (Liabilities) related to Retirement Plans (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2020	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, amounts recognized in regulatory assets, before tax	$ 19
Pension Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Current year actuarial loss (gain)		$ 941	$ 538	$ 635
Amortization of actuarial loss		(512)	(414)	(629)
Current year prior service cost (credit)		0	68	(4)
Amortization of prior service (cost) credit		(4)	0	(2)
Curtailments		0	(3)	0
Settlements		(14)	(17)	(3)
Total recognized in AOCI and regulatory assets (liabilities)		411	172	(3)
Defined benefit plan, amounts recognized in OCI, before tax		271	169	3
Defined benefit plan, amounts recognized in regulatory assets, before tax		140	3	(6)
Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Current year actuarial loss (gain)		22	80	(232)
Amortization of actuarial loss		(49)	(45)	(66)
Current year prior service cost (credit)		(111)	0	0
Amortization of prior service (cost) credit		124	179	186
Curtailments		1	0	0
Settlements		(1)	(1)	0
Total recognized in AOCI and regulatory assets (liabilities)		(14)	213	(112)
Defined benefit plan, amounts recognized in OCI, before tax		6	107	(55)
Defined benefit plan, amounts recognized in regulatory assets, before tax		$ (20)	$ 106	$ (57)

Retirement Benefits - Gross Accumulated Other Comprehensive Loss and Regulatory Assets (Liabilities) not Recognized as Components of Periodic Benefit Cost (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Pension Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Prior service cost (credit)	$ 35	$ 39
Actuarial loss	8,077	7,662
Total	8,112	7,701
Benefits included in accumulated other comprehensive income	4,339	4,068
Benefits included in regulatory assets	3,773	3,633
Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Prior service cost (credit)	(145)	(158)
Actuarial loss	538	565
Total	393	407
Benefits included in accumulated other comprehensive income	183	177
Benefits included in regulatory assets	$ 210	$ 230

Retirement Benefits - Assumptions Used in Calculations (Details)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Pension Plan, Defined Benefit [Member]
Defined Benefit Plan Assumptions Used In Calculations [Line Items]
Discount rate - Benefit Obligation	2.58%	3.34%
Benefit Obligation Investment Crediting Rate	3.72%	3.82%
Discount rate - Net Periodic Benefit Costs	3.34%	4.31%	3.62%
Net Periodic Benefit Cost Investment Crediting Rate	3.82%	4.46%	4.00%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets	7.00%	7.00%	7.00%
Pension Plan, Defined Benefit [Member] \| CENG Legacy Benefit Plans [Member] \| Minimum [Member]
Defined Benefit Plan Assumptions Used In Calculations [Line Items]
Defined Benefit Plan Assumptions Used Calculating Benefit Obligation Discount Rate Design Changes	2.11%	3.02%
Defined Benefit Plan Assumptions Used Calculating Net Periodic Benefit Cost Discount Rate Design Changes	3.02%	4.13%	3.49%
Pension Plan, Defined Benefit [Member] \| CENG Legacy Benefit Plans [Member] \| Maximum [Member]
Defined Benefit Plan Assumptions Used In Calculations [Line Items]
Defined Benefit Plan Assumptions Used Calculating Benefit Obligation Discount Rate Design Changes	2.73%	3.44%
Defined Benefit Plan Assumptions Used Calculating Net Periodic Benefit Cost Discount Rate Design Changes	3.44%	4.36%	3.65%
Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan Assumptions Used In Calculations [Line Items]
Discount rate - Benefit Obligation	2.51%	3.31%
Health care cost trend rate	5.00%	5.00%	5.00%
Ultimate health care cost trend rate	5.00%	5.00%	5.00%
Discount rate - Net Periodic Benefit Costs	3.31%	4.30%	3.61%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets	6.69%	6.67%	6.60%
Other Postretirement Benefit Plan, Defined Benefit [Member] \| CENG Legacy Benefit Plans [Member] \| Minimum [Member]
Defined Benefit Plan Assumptions Used In Calculations [Line Items]
Defined Benefit Plan Assumptions Used Calculating Benefit Obligation Discount Rate Design Changes	2.45%	3.27%
Defined Benefit Plan Assumptions Used Calculating Net Periodic Benefit Cost Discount Rate Design Changes	3.27%	4.27%	3.57%
Other Postretirement Benefit Plan, Defined Benefit [Member] \| CENG Legacy Benefit Plans [Member] \| Maximum [Member]
Defined Benefit Plan Assumptions Used In Calculations [Line Items]
Defined Benefit Plan Assumptions Used Calculating Benefit Obligation Discount Rate Design Changes	2.63%	3.40%
Defined Benefit Plan Assumptions Used Calculating Net Periodic Benefit Cost Discount Rate Design Changes	3.40%	4.38%	3.68%
Pension and other post retirement benefit [Member] \| Period One [Member]
Defined Benefit Plan Assumptions Used In Calculations [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase	3.25%
Pension and other post retirement benefit [Member] \| Period Two [Member]
Defined Benefit Plan Assumptions Used In Calculations [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase	3.75%

Retirement Benefits - Estimated Future Benefit Payments (Details) $ in Millions	Dec. 31, 2020 USD ($)
Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
2021	$ 1,279
2022	1,280
2023	1,315
2024	1,325
2025	1,338
2026 through 2030	6,759
Total estimated future benefit payments through 2030	13,296
Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
2021	257
2022	259
2023	261
2024	262
2025	265
2026 through 2030	1,320
Total estimated future benefit payments through 2030	$ 2,624

Retirement Benefits - Pension and Other Postretirement Benefit Plan Target Asset Allocations (Details)	Dec. 31, 2020	Dec. 31, 2019
Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target asset allocation percentage	100.00%	100.00%
Pension Plan, Defined Benefit [Member] \| Equity Securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target asset allocation percentage	34.00%	33.00%
Pension Plan, Defined Benefit [Member] \| Fixed Income Securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target asset allocation percentage	43.00%	44.00%
Pension Plan, Defined Benefit [Member] \| Alternative Investments [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target asset allocation percentage	23.00%	23.00%
Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target asset allocation percentage	100.00%	100.00%
Other Postretirement Benefit Plan, Defined Benefit [Member] \| Equity Securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target asset allocation percentage	45.00%	46.00%
Other Postretirement Benefit Plan, Defined Benefit [Member] \| Fixed Income Securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target asset allocation percentage	39.00%	32.00%
Other Postretirement Benefit Plan, Defined Benefit [Member] \| Alternative Investments [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target asset allocation percentage	16.00%	22.00%

Retirement Benefits - Reconciliation of Level 3 Assets and Liabilities measured at Fair Value for Pension and Other Postretirement Benefit Plans (Details) - Pension and other post retirement benefit [Member] - Fair Value, Inputs, Level 3 [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of net plan assets at beginning of year	$ 487	$ 486
Relating to assets still held at the reporting date	31	59
Relating to assets sold during the period		(7)
Defined Benefit Plan Purchases	58	67
Defined Benefit Plan Sales		(4)
Settlements	(45)	(102)
Transfers into (out of) Level 3	299	(12)
Defined Benefit Plan, Plan Assets, Amount	830	487
Debt Securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of net plan assets at beginning of year	245	216
Relating to assets still held at the reporting date	19	28
Relating to assets sold during the period		(7)
Defined Benefit Plan Purchases	34	26
Defined Benefit Plan Sales		(4)
Settlements	(3)	(2)
Transfers into (out of) Level 3	299	(12)
Defined Benefit Plan, Plan Assets, Amount	594	245
Private Placement [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of net plan assets at beginning of year	237	268
Relating to assets still held at the reporting date	15	28
Relating to assets sold during the period		0
Defined Benefit Plan Purchases	24	41
Defined Benefit Plan Sales		0
Settlements	(42)	(100)
Transfers into (out of) Level 3	0	0
Defined Benefit Plan, Plan Assets, Amount	234	237
Equity Securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of net plan assets at beginning of year	5	2
Relating to assets still held at the reporting date	(3)	3
Relating to assets sold during the period		0
Defined Benefit Plan Purchases	0	0
Defined Benefit Plan Sales		0
Settlements	0	0
Transfers into (out of) Level 3	0	0
Defined Benefit Plan, Plan Assets, Amount	$ 2	$ 5

Retirement Benefits - Defined Contribution Savings Plan (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Savings plan matching contributions	$ 158	$ 161	$ 179
Exelon Generation Co L L C [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Savings plan matching contributions	63	73	86
Commonwealth Edison Co [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Savings plan matching contributions	36	35	37
PECO Energy Co [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Savings plan matching contributions	12	11	9
Baltimore Gas and Electric Company [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Savings plan matching contributions	13	12	12
Pepco Holdings LLC [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Savings plan matching contributions	14	13	13
Potomac Electric Power Company [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Savings plan matching contributions	4	3	3
Delmarva Power & Light Company [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Savings plan matching contributions	3	3	2
Atlantic City Electric Company [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Savings plan matching contributions	$ 3	$ 2	$ 2

Derivative Financial Instruments - Narrative (Details) MWh in Millions, $ in Millions	1 Months Ended	12 Months Ended
	Jun. 30, 2012 MWh	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)
Derivative [Line Items]
Derivative, Notional Amount		$ 6,879	$ 6,668
Incremental collateral for loss of investment grade credit rating		1,432	1,509
ExGenRenewablesIVDec2020 [Member] \| Non Recourse Debt [Member]
Derivative [Line Items]
Non Recourse Debt Interest Rate Swap		$ 516
Non Recourse Debt Hedge Percentage		1.05%
Not Designated as Hedging Instrument, Economic Hedge [Member] \| Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount		$ 516	1,269
Exelon Generation Co L L C [Member]
Derivative [Line Items]
Incremental collateral for loss of investment grade credit rating		1,432	1,509
Exelon Generation Co L L C [Member] \| ExGenRenewablesIVDec2020 [Member] \| Non Recourse Debt [Member]
Derivative [Line Items]
Non Recourse Debt Interest Rate Swap		$ 516
Non Recourse Debt Hedge Percentage		1.05%
Exelon Generation Co L L C [Member] \| Not Designated as Hedging Instrument, Economic Hedge [Member] \| Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount		$ 516	569
Exelon Generation Co L L C [Member] \| Not Designated as Hedging Instrument, Economic Hedge [Member] \| Foreign Exchange Contract [Member]
Derivative [Line Items]
Derivative, Notional Amount		$ 149	$ 231
Exelon Generation Co L L C [Member] \| Minimum [Member]
Derivative [Line Items]
Expected generation hedged in next twelve months		94.00%
Exelon Generation Co L L C [Member] \| Maximum [Member]
Derivative [Line Items]
Expected generation hedged in next twelve months		97.00%
Commonwealth Edison Co [Member]
Derivative [Line Items]
Long-term Purchase Commitment, Minimum Energy Volume Required \| MWh	1.3
PECO Energy Co [Member]
Derivative [Line Items]
Incremental collateral for loss of investment grade credit rating		$ 34
Baltimore Gas and Electric Company [Member]
Derivative [Line Items]
Incremental collateral for loss of investment grade credit rating		54
Delmarva Power & Light Company [Member]
Derivative [Line Items]
Incremental collateral for loss of investment grade credit rating		$ 9

Derivative Financial Instruments - Summary of Derivative Fair Value Balances (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Derivative [Line Items]
Mark-to-market derivative assets, current	$ 644	$ 679
Mark-to-market derivative assets, noncurrent	555	508
Mark-to-market derivative liabilities, current	(295)	(247)
Mark-to-market derivative liabilities, noncurrent	(473)	(393)
Total mark-to-market derivative net assets (liabilities)	2	2
Margin Deposit Assets	209	511
Exelon Generation Co L L C [Member]
Derivative [Line Items]
Mark-to-market derivative assets, current	644	675
Mark-to-market derivative assets, noncurrent	555	508
Mark-to-market derivative liabilities, current	(262)	(215)
Mark-to-market derivative liabilities, noncurrent	(205)	(123)
Margin Deposit Assets	209	511
Commonwealth Edison Co [Member]
Derivative [Line Items]
Mark-to-market derivative liabilities, current	(33)	(32)
Mark-to-market derivative liabilities, noncurrent	(268)	(269)
Commodity Contract [Member]
Derivative [Line Items]
Mark-to-market derivative assets, current	639	675
Mark-to-market derivative assets, noncurrent	554	508
Total mark-to-market derivative assets	1,193	1,183
Mark-to-market derivative liabilities, current	(293)	(236)
Mark-to-market derivative liabilities, noncurrent	(472)	(380)
Total mark-to-market derivative liabilities	(765)	(616)
Total mark-to-market derivative net assets (liabilities)	428	567
Commodity Contract [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Mark-to-market derivative assets, current	639	675
Mark-to-market derivative assets, noncurrent	554	508
Total mark-to-market derivative assets	1,193	1,183
Mark-to-market derivative liabilities, current	(260)	(204)
Mark-to-market derivative liabilities, noncurrent	(204)	(111)
Total mark-to-market derivative liabilities	(464)	(315)
Total mark-to-market derivative net assets (liabilities)	729	868
Commodity Contract [Member] \| Collateral [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Mark-to-market derivative assets, current	103	287
Mark-to-market derivative assets, noncurrent	64	122
Total mark-to-market derivative assets	167	409
Mark-to-market derivative liabilities, current	131	357
Mark-to-market derivative liabilities, noncurrent	118	163
Total mark-to-market derivative liabilities	249	520
Total mark-to-market derivative net assets (liabilities)	416	929
Commodity Contract [Member] \| Netting [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Mark-to-market derivative assets, current	(2,261)	(3,190)
Mark-to-market derivative assets, noncurrent	(1,015)	(877)
Total mark-to-market derivative assets	(3,276)	(4,067)
Mark-to-market derivative liabilities, current	2,261	3,190
Mark-to-market derivative liabilities, noncurrent	1,015	877
Total mark-to-market derivative liabilities	3,276	4,067
Total mark-to-market derivative net assets (liabilities)	0	0
Commodity Contract [Member] \| Not Designated as Hedging Instrument, Economic Hedge [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Mark-to-market derivative assets, current	2,757	3,506
Mark-to-market derivative assets, noncurrent	1,501	1,238
Total mark-to-market derivative assets	4,258	4,744
Mark-to-market derivative liabilities, current	(2,629)	(3,713)
Mark-to-market derivative liabilities, noncurrent	(1,335)	(1,140)
Total mark-to-market derivative liabilities	(3,964)	(4,853)
Total mark-to-market derivative net assets (liabilities)	294	(109)
Commodity Contract [Member] \| Not Designated as Hedging Instrument, Economic Hedge [Member] \| Commonwealth Edison Co [Member]
Derivative [Line Items]
Mark-to-market derivative assets, current	0	0
Mark-to-market derivative assets, noncurrent	0	0
Total mark-to-market derivative assets	0	0
Mark-to-market derivative liabilities, current	(33)	(32)
Mark-to-market derivative liabilities, noncurrent	(268)	(269)
Total mark-to-market derivative liabilities	(301)	(301)
Total mark-to-market derivative net assets (liabilities)	(301)	(301)
Commodity Contract [Member] \| Not Designated as Hedging Instrument, Trading [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Mark-to-market derivative assets, current	40	72
Mark-to-market derivative assets, noncurrent	4	25
Total mark-to-market derivative assets	44	97
Mark-to-market derivative liabilities, current	(23)	(38)
Mark-to-market derivative liabilities, noncurrent	(2)	(11)
Total mark-to-market derivative liabilities	(25)	(49)
Total mark-to-market derivative net assets (liabilities)	$ 19	$ 48

Derivative Financial Instruments - Summary of Economic Hedges (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	$ 268	$ (222)	$ (294)
Exelon Generation Co L L C [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	270	(228)	(307)
Not Designated as Hedging Instrument, Economic Hedge [Member] \| Commodity Contract [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	280	(204)	(317)
Not Designated as Hedging Instrument, Economic Hedge [Member] \| Exelon Generation Co L L C [Member] \| Commodity Contract [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	280	(204)	(317)
Not Designated as Hedging Instrument, Economic Hedge [Member] \| Operating Revenue [Member] \| Commodity Contract [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	112	0	(270)
Not Designated as Hedging Instrument, Economic Hedge [Member] \| Operating Revenue [Member] \| Exelon Generation Co L L C [Member] \| Commodity Contract [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	112	0	(270)
Not Designated as Hedging Instrument, Economic Hedge [Member] \| Purchased Power And Fuel [Member] \| Commodity Contract [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	168	(204)	(47)
Not Designated as Hedging Instrument, Economic Hedge [Member] \| Purchased Power And Fuel [Member] \| Exelon Generation Co L L C [Member] \| Commodity Contract [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	$ 168	$ (204)	$ (47)

Derivative Financial Instruments - Summary of Credit Risk Exposure (Details) - Exelon Generation Co L L C [Member] $ in Millions	Dec. 31, 2020 USD ($)
Derivative [Line Items]
Cash collateral held	$ 31
Letters of credit held	25
Total Exposure Before Credit Collateral [Member]
Derivative [Line Items]
Investment grade	577
Non-investment grade	32
Internally rated — investment grade	165
Internally rated — non-investment grade	80
Total	854
Credit Collateral [Member]
Derivative [Line Items]
Investment grade	27
Non-investment grade	0
Internally rated — investment grade	1
Internally rated — non-investment grade	28
Total	56
Net Exposure [Member]
Derivative [Line Items]
Investment grade	550
Non-investment grade	32
Internally rated — investment grade	164
Internally rated — non-investment grade	52
Total	798
Financial institutions	15
Investor-owned utilities, marketers, power producers	607
Energy cooperatives and municipalities	138
Other	38
Total	798
Number Of Counterparties Greater Than Ten Percent Of Net Exposure [Member]
Derivative [Line Items]
Investment grade	0
Total	0
Net Exposure Of Counterparties Greater Than Ten Percent Of Net Exposure [Member]
Derivative [Line Items]
Investment grade	0
Total	$ 0

Derivative Financial Instruments - Summary of Credit Risk Related Contingent Features (Details) - Exelon Generation Co L L C [Member] - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Liability	$ (834)	$ (956)
Offsetting Fair Value of In-the-Money Contracts Under Master Netting Arrangements	537	649
Derivative liabilities, fair value	$ (297)	$ (307)

Derivative Financial Instruments - Summary of Cash Collateral and Letters of Credit (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Collateral, Right to Reclaim Cash	$ 511	$ 982
Derivative, Collateral, Right to Reclaim Securities	226	264
Derivative, Collateral, Obligation to Return Cash	110	103
Derivative, Collateral, Obligation to Return Securities	40	112
Incremental Collateral For Loss Of Investment Grade Credit Rating	1,432	1,509
Exelon Generation Co L L C [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Collateral, Right to Reclaim Cash	511	982
Derivative, Collateral, Right to Reclaim Securities	226	264
Derivative, Collateral, Obligation to Return Cash	110	103
Derivative, Collateral, Obligation to Return Securities	40	112
Incremental Collateral For Loss Of Investment Grade Credit Rating	$ 1,432	$ 1,509

Debt and Credit Agreements - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020 USD ($) MW	Dec. 31, 2019 USD ($)
Debt Instrument [Line Items]
Long-term Debt, Current Maturities	$ (1,819)	$ (4,710)
Debt Instrument, Collateral Amount	2,200
Long-term line of credit/facility draws	0
Letters of Credit Outstanding, Amount	1,230
Long-term Debt	36,906
Long-term debt, gross	$ 36,516	35,560
Maximum [Member]
Debt Instrument [Line Items]
Basis Points For Prime Based Borrowings	0.65%
Basis Points For Libor Based Borrowings	1.65%
DOE Project Financing, 2.82% January 5, 2037 [Member] \| Non Recourse Debt [Member]
Debt Instrument [Line Items]
Long-term line of credit/facility draws	$ 646
Debt, Weighted Average Interest Rate	2.82%
Non-recourse debt	$ 460	485
Letters of Credit Outstanding, Amount	$ 37
Debt Instrument, Basis Spread on Variable Rate	0.375%
Renewable Power Generation [Member] \| Non Recourse Debt [Member]
Debt Instrument [Line Items]
Non-recourse debt	$ 95	106
Debt Instrument, Face Amount	$ 150
Debt instrument, interest rate, stated percentage	4.11%
SolGen [Member] \| Non Recourse Debt [Member]
Debt Instrument [Line Items]
Non-recourse debt	$ 125	$ 131
Debt Instrument, Face Amount	$ 150
Debt instrument, interest rate, stated percentage	3.93%
ExGenRenewablesIVNov2024 [Member] \| Non Recourse Debt [Member]
Debt Instrument [Line Items]
Non-recourse debt	$ 709
Long-term Debt	850
Non Recourse Debt Interest Rate Swap	636
Non Recourse Debt Hedge Percentage		2.32%
Continetal Wind [Member] \| Non Recourse Debt [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	122
Non-recourse debt	415	$ 447
Letters of Credit Outstanding, Amount	114
Debt Instrument, Face Amount	$ 613
Non Recourse Debt Megawatts \| MW	667
Debt instrument, interest rate, stated percentage	6.00%
Aggregate Bank Commitments Under Unsecured Revolving Credit Facilities	$ 4
ExGenRenewablesIVDec2020 [Member] \| Non Recourse Debt [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	2.75%
Long-term Debt	$ 750
Non Recourse Debt Interest Rate Swap	$ 516
Non Recourse Debt Hedge Percentage	1.05%
Non Recourse Debt Minimum Rate	1.00%
Long-term debt, gross	$ 750
Corporate, Non-Segment [Member] \| London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	0.65%	0.95%
Exelon Corporate [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount	$ 6
Long-term Debt	7,589
Long-term debt, gross	7,589	$ 7,039
Exelon Corporate [Member] \| Corporate, Non-Segment [Member]
Debt Instrument [Line Items]
Short-Term Loan Agreements	500
Exelon Generation Co L L C [Member]
Debt Instrument [Line Items]
Long-term Debt, Current Maturities	(197)	(3,182)
Debt Instrument, Collateral Amount	2,200
Long-term Debt	6,072
Long-term debt, gross	6,072	7,943
Exelon Generation Co L L C [Member] \| ShortTermDebt03192020 [Member]
Debt Instrument [Line Items]
Short-Term Loan Agreements	$ 200
Exelon Generation Co L L C [Member] \| ShortTermDebt03192020 [Member] \| London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	0.50%
Exelon Generation Co L L C [Member] \| ShortTermDebt03312020 [Member]
Debt Instrument [Line Items]
Short-Term Loan Agreements	$ 300
Exelon Generation Co L L C [Member] \| ShortTermDebt03312020 [Member] \| London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	0.75%
Exelon Generation Co L L C [Member] \| DOE Project Financing, 2.82% January 5, 2037 [Member] \| Non Recourse Debt [Member]
Debt Instrument [Line Items]
Long-term line of credit/facility draws	$ 646
Debt, Weighted Average Interest Rate	2.82%
Non-recourse debt	$ 460	485
Letters of Credit Outstanding, Amount	$ 37
Debt Instrument, Basis Spread on Variable Rate	0.375%
Exelon Generation Co L L C [Member] \| Renewable Power Generation [Member] \| Non Recourse Debt [Member]
Debt Instrument [Line Items]
Non-recourse debt	$ 95	106
Debt Instrument, Face Amount	$ 150
Debt instrument, interest rate, stated percentage	4.11%
Exelon Generation Co L L C [Member] \| SolGen [Member] \| Non Recourse Debt [Member]
Debt Instrument [Line Items]
Non-recourse debt	$ 125	$ 131
Debt Instrument, Face Amount	$ 150
Debt instrument, interest rate, stated percentage	3.93%
Exelon Generation Co L L C [Member] \| ExGenRenewablesIVNov2024 [Member] \| Non Recourse Debt [Member]
Debt Instrument [Line Items]
Non-recourse debt	$ 709
Long-term Debt	850
Non Recourse Debt Interest Rate Swap	636
Non Recourse Debt Hedge Percentage		2.32%
Exelon Generation Co L L C [Member] \| Continetal Wind [Member] \| Non Recourse Debt [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	122
Non-recourse debt	415	$ 447
Letters of Credit Outstanding, Amount	114
Debt Instrument, Face Amount	$ 613
Non Recourse Debt Megawatts \| MW	667
Debt instrument, interest rate, stated percentage	6.00%
Aggregate Bank Commitments Under Unsecured Revolving Credit Facilities	$ 4
Exelon Generation Co L L C [Member] \| ExGenRenewablesIVDec2020 [Member] \| Non Recourse Debt [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	2.75%
Long-term Debt	$ 750
Non Recourse Debt Interest Rate Swap	$ 516
Non Recourse Debt Hedge Percentage	1.05%
Non Recourse Debt Minimum Rate	1.00%
Long-term debt, gross	$ 750
Commonwealth Edison Co [Member]
Debt Instrument [Line Items]
Long-term Debt, Current Maturities	(350)	(500)
Long-term line of credit/facility draws	0
Letters of Credit Outstanding, Amount	2
Long-term Debt	9,292
Long-term debt, gross	9,087	8,586
Commonwealth Edison Co [Member] \| ShortTermDebt752021 [Member]
Debt Instrument [Line Items]
Short-Term Loan Agreements	125
Commonwealth Edison Co [Member] \| ShortTermDebt502021 [Member]
Debt Instrument [Line Items]
Short-Term Loan Agreements	$ 125
Commonwealth Edison Co [Member] \| ShortTermDebt502021 [Member] \| London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	0.50%
Delmarva Power & Light Company [Member]
Debt Instrument [Line Items]
Long-term Debt, Current Maturities	$ 79	79
Long-term line of credit/facility draws	0
Letters of Credit Outstanding, Amount	0
Long-term Debt	1,687
Long-term debt, gross	1,687	$ 1,578
Exelon Corporate [Member] \| Corporate, Non-Segment [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	550
Revolving Credit Facility
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	10,644
Revolving Credit Facility \| Exelon Corporate [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	600
Revolving Credit Facility \| Exelon Corporate [Member] \| Corporate, Non-Segment [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	550
Revolving Credit Facility \| Exelon Generation Co L L C [Member]
Debt Instrument [Line Items]
Line of credit facility, fair value of amount outstanding	1,500
Line of Credit Facility, Maximum Borrowing Capacity	5,300
Long-term line of credit/facility draws	0
Letters of Credit Outstanding, Amount	262
Revolving Credit Facility \| Commonwealth Edison Co [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	1,000
Revolving Credit Facility \| Delmarva Power & Light Company [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 300
Line of credit \| Corporate, Non-Segment [Member] \| London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	1.75%
Line of credit \| Exelon Generation Co L L C [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 1,500
Long-term line of credit/facility draws	0
Letters of Credit Outstanding, Amount	$ 840
Line of credit \| Commonwealth Edison Co [Member] \| ShortTermDebt752021 [Member] \| London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	0.75%

Debt and Credit Agreements - Commercial Paper Borrowings (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Short-term Debt [Line Items]
Letters of Credit Outstanding, Amount	$ 1,230
Credit facility agreements with minority and community banks	135	$ 142
Line of credit facility, remaining borrowing capacity	9,414
Commercial Paper
Short-term Debt [Line Items]
Line of credit facility, maximum borrowing capacity	9,000	9,000
Commercial Paper	$ 1,031	$ 870
Average interest rate on commercial paper borrowings	0.25%	2.25%
Exelon Corporate [Member]
Short-term Debt [Line Items]
Letters of Credit Outstanding, Amount	$ 6
Exelon Corporate [Member] \| Commercial Paper
Short-term Debt [Line Items]
Line of credit facility, maximum borrowing capacity	600
Commercial Paper	0	$ 136
Average interest rate on commercial paper borrowings		1.92%
Exelon Generation Co L L C [Member]
Short-term Debt [Line Items]
Credit facility agreements with minority and community banks	38	$ 44
Exelon Generation Co L L C [Member] \| Commercial Paper
Short-term Debt [Line Items]
Line of credit facility, maximum borrowing capacity	5,300	5,300
Commercial Paper	$ 340	$ 320
Average interest rate on commercial paper borrowings	0.27%	1.84%
Exelon Generation Co L L C [Member] \| Revolving Credit Facility
Short-term Debt [Line Items]
Letters of Credit Outstanding, Amount	$ 1,500	$ 1,400
Exelon Generation Co L L C [Member] \| Secured debt
Short-term Debt [Line Items]
Letters of Credit Outstanding, Amount	144	159
Commonwealth Edison Co [Member]
Short-term Debt [Line Items]
Letters of Credit Outstanding, Amount	2
Credit facility agreements with minority and community banks	32	33
Line of credit facility, remaining borrowing capacity	998
Commonwealth Edison Co [Member] \| Commercial Paper
Short-term Debt [Line Items]
Line of credit facility, maximum borrowing capacity	1,000	1,000
Commercial Paper	$ 323	$ 130
Average interest rate on commercial paper borrowings	0.23%	2.38%
PECO Energy Co [Member]
Short-term Debt [Line Items]
Letters of Credit Outstanding, Amount	$ 0
Credit facility agreements with minority and community banks	33	$ 33
Line of credit facility, remaining borrowing capacity	600
PECO Energy Co [Member] \| Commercial Paper
Short-term Debt [Line Items]
Line of credit facility, maximum borrowing capacity	600	600
Commercial Paper	$ 0	$ 0
Average interest rate on commercial paper borrowings	0.00%	2.39%
Baltimore Gas and Electric Company [Member]
Short-term Debt [Line Items]
Letters of Credit Outstanding, Amount	$ 0
Credit facility agreements with minority and community banks	8	$ 8
Line of credit facility, remaining borrowing capacity	600
Baltimore Gas and Electric Company [Member] \| Commercial Paper
Short-term Debt [Line Items]
Line of credit facility, maximum borrowing capacity	600	600
Commercial Paper	$ 0	$ 76
Average interest rate on commercial paper borrowings	0.00%	2.46%
Pepco Holdings LLC [Member]
Short-term Debt [Line Items]
Letters of Credit Outstanding, Amount	$ 1
Line of credit facility, remaining borrowing capacity	899
Pepco Holdings LLC [Member] \| Commercial Paper
Short-term Debt [Line Items]
Line of credit facility, maximum borrowing capacity	900	$ 900
Commercial Paper	$ 368	208
Average interest rate on commercial paper borrowings	0.24%
Pepco Holdings LLC [Member] \| Maximum [Member] \| Revolving Credit Facility
Short-term Debt [Line Items]
Line of credit facility, maximum borrowing capacity	$ 900
Potomac Electric Power Company [Member]
Short-term Debt [Line Items]
Letters of Credit Outstanding, Amount	1
Credit facility agreements with minority and community banks	8	8
Line of credit facility, remaining borrowing capacity	299
Potomac Electric Power Company [Member] \| Commercial Paper
Short-term Debt [Line Items]
Line of credit facility, maximum borrowing capacity	300	300
Commercial Paper	$ 35	$ 82
Average interest rate on commercial paper borrowings	0.22%	2.56%
Line of credit facility, remaining borrowing capacity	$ 500
Delmarva Power & Light Company [Member]
Short-term Debt [Line Items]
Letters of Credit Outstanding, Amount	0
Credit facility agreements with minority and community banks	8	$ 8
Line of credit facility, remaining borrowing capacity	300
Delmarva Power & Light Company [Member] \| Commercial Paper
Short-term Debt [Line Items]
Line of credit facility, maximum borrowing capacity	300	300
Commercial Paper	$ 146	$ 56
Average interest rate on commercial paper borrowings	0.24%	2.02%
Line of credit facility, remaining borrowing capacity	$ 500
Atlantic City Electric Company [Member]
Short-term Debt [Line Items]
Letters of Credit Outstanding, Amount	0
Credit facility agreements with minority and community banks	8	$ 8
Line of credit facility, remaining borrowing capacity	300
Atlantic City Electric Company [Member] \| Commercial Paper
Short-term Debt [Line Items]
Line of credit facility, maximum borrowing capacity	300	300
Commercial Paper	$ 187	$ 70
Average interest rate on commercial paper borrowings	0.25%	2.43%
Line of credit facility, remaining borrowing capacity	$ 350

Debt and Credit Agreements - Summary of Bank Commitments, Credit Facility Borrowings and Available Capacity (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Short-term Debt [Line Items]
Long-term line of credit/facility draws	$ 0
Outstanding letters of credit	1,230
Actual available capacity	9,414
Credit facility agreements with minority and community banks	$ 135	$ 142
Minimum [Member] \| Prime Rate [Member]
Short-term Debt [Line Items]
Line of credit facility, interest rate at period end	0.00%
Minimum [Member] \| London Interbank Offered Rate (LIBOR) [Member]
Short-term Debt [Line Items]
Line of credit facility, interest rate at period end	0.90%
Maximum [Member] \| Prime Rate [Member]
Short-term Debt [Line Items]
Line of credit facility, interest rate at period end	0.275%
Maximum [Member] \| London Interbank Offered Rate (LIBOR) [Member]
Short-term Debt [Line Items]
Line of credit facility, interest rate at period end	1.275%
Revolving Credit Facility
Short-term Debt [Line Items]
Line of credit facility, maximum borrowing capacity	$ 10,644
To support additional commercial paper	7,698
Exelon Corporate [Member]
Short-term Debt [Line Items]
Outstanding letters of credit	$ 6
Exelon Corporate [Member] \| Prime Rate [Member]
Short-term Debt [Line Items]
Line of credit facility, interest rate at period end	0.275%
Exelon Corporate [Member] \| London Interbank Offered Rate (LIBOR) [Member]
Short-term Debt [Line Items]
Line of credit facility, interest rate at period end	1.275%
Exelon Corporate [Member] \| Revolving Credit Facility
Short-term Debt [Line Items]
Line of credit facility, maximum borrowing capacity	$ 600
To support additional commercial paper	594
Exelon Generation Co L L C [Member]
Short-term Debt [Line Items]
To support additional commercial paper	4,698
Credit facility agreements with minority and community banks	$ 38	44
Exelon Generation Co L L C [Member] \| Prime Rate [Member]
Short-term Debt [Line Items]
Line of credit facility, interest rate at period end	0.275%
Exelon Generation Co L L C [Member] \| London Interbank Offered Rate (LIBOR) [Member]
Short-term Debt [Line Items]
Line of credit facility, interest rate at period end	1.275%
Exelon Generation Co L L C [Member] \| Secured debt
Short-term Debt [Line Items]
Outstanding letters of credit	$ 144	159
Exelon Generation Co L L C [Member] \| Revolving Credit Facility
Short-term Debt [Line Items]
Outstanding letters of credit	1,500	1,400
Exelon Generation Co L L C [Member] \| Line of credit
Short-term Debt [Line Items]
Actual available capacity	660
To support additional commercial paper	0
Exelon Generation Co L L C [Member] \| Line of credit
Short-term Debt [Line Items]
Line of credit facility, maximum borrowing capacity	1,500
Long-term line of credit/facility draws	0
Outstanding letters of credit	840
Exelon Generation Co L L C [Member] \| Line of credit \| Secured debt
Short-term Debt [Line Items]
Line of credit facility, maximum borrowing capacity	144
Long-term line of credit/facility draws	0
Outstanding letters of credit	119
Actual available capacity	25
To support additional commercial paper	0
Exelon Generation Co L L C [Member] \| Revolving Credit Facility
Short-term Debt [Line Items]
Line of credit facility, maximum borrowing capacity	5,300
Long-term line of credit/facility draws	0
Outstanding letters of credit	262
Actual available capacity	5,038
Exelon Generation Co L L C [Member] \| Letter of credit \| Community and Minority Facilities [Member]
Short-term Debt [Line Items]
Outstanding letters of credit	5
Commonwealth Edison Co [Member]
Short-term Debt [Line Items]
Long-term line of credit/facility draws	0
Outstanding letters of credit	2
Actual available capacity	998
To support additional commercial paper	675
Credit facility agreements with minority and community banks	$ 32	33
Commonwealth Edison Co [Member] \| Prime Rate [Member]
Short-term Debt [Line Items]
Line of credit facility, interest rate at period end	0.00%
Commonwealth Edison Co [Member] \| London Interbank Offered Rate (LIBOR) [Member]
Short-term Debt [Line Items]
Line of credit facility, interest rate at period end	1.00%
Commonwealth Edison Co [Member] \| Revolving Credit Facility
Short-term Debt [Line Items]
Line of credit facility, maximum borrowing capacity	$ 1,000
Commonwealth Edison Co [Member] \| Letter of credit \| Community and Minority Facilities [Member]
Short-term Debt [Line Items]
Outstanding letters of credit	5
PECO Energy Co [Member]
Short-term Debt [Line Items]
Long-term line of credit/facility draws	0
Outstanding letters of credit	0
Actual available capacity	600
To support additional commercial paper	600
Credit facility agreements with minority and community banks	$ 33	33
PECO Energy Co [Member] \| Prime Rate [Member]
Short-term Debt [Line Items]
Line of credit facility, interest rate at period end	0.00%
PECO Energy Co [Member] \| London Interbank Offered Rate (LIBOR) [Member]
Short-term Debt [Line Items]
Line of credit facility, interest rate at period end	0.90%
PECO Energy Co [Member] \| Revolving Credit Facility
Short-term Debt [Line Items]
Line of credit facility, maximum borrowing capacity	$ 600
Baltimore Gas and Electric Company [Member]
Short-term Debt [Line Items]
Long-term line of credit/facility draws	0
Outstanding letters of credit	0
Actual available capacity	600
To support additional commercial paper	600
Credit facility agreements with minority and community banks	$ 8	8
Baltimore Gas and Electric Company [Member] \| Prime Rate [Member]
Short-term Debt [Line Items]
Line of credit facility, interest rate at period end	0.00%
Baltimore Gas and Electric Company [Member] \| London Interbank Offered Rate (LIBOR) [Member]
Short-term Debt [Line Items]
Line of credit facility, interest rate at period end	0.90%
Baltimore Gas and Electric Company [Member] \| Revolving Credit Facility
Short-term Debt [Line Items]
Line of credit facility, maximum borrowing capacity	$ 600
Baltimore Gas and Electric Company [Member] \| Letter of credit \| Community and Minority Facilities [Member]
Short-term Debt [Line Items]
Outstanding letters of credit	2
Pepco Holdings LLC [Member]
Short-term Debt [Line Items]
Long-term line of credit/facility draws	0
Outstanding letters of credit	1
Actual available capacity	899
To support additional commercial paper	531
Pepco Holdings LLC [Member] \| Revolving Credit Facility \| Maximum [Member]
Short-term Debt [Line Items]
Line of credit facility, maximum borrowing capacity	900
Pepco Holdings LLC [Member] \| Revolving Credit Facility
Short-term Debt [Line Items]
Line of credit facility, maximum borrowing capacity	900
Potomac Electric Power Company [Member]
Short-term Debt [Line Items]
Long-term line of credit/facility draws	0
Outstanding letters of credit	1
Actual available capacity	299
To support additional commercial paper	264
Credit facility agreements with minority and community banks	$ 8	8
Potomac Electric Power Company [Member] \| Prime Rate [Member]
Short-term Debt [Line Items]
Line of credit facility, interest rate at period end	0.075%
Potomac Electric Power Company [Member] \| London Interbank Offered Rate (LIBOR) [Member]
Short-term Debt [Line Items]
Line of credit facility, interest rate at period end	1.075%
Potomac Electric Power Company [Member] \| Revolving Credit Facility
Short-term Debt [Line Items]
Line of credit facility, maximum borrowing capacity	$ 300
Delmarva Power & Light Company [Member]
Short-term Debt [Line Items]
Long-term line of credit/facility draws	0
Outstanding letters of credit	0
Actual available capacity	300
To support additional commercial paper	154
Credit facility agreements with minority and community banks	$ 8	8
Delmarva Power & Light Company [Member] \| Prime Rate [Member]
Short-term Debt [Line Items]
Line of credit facility, interest rate at period end	0.00%
Delmarva Power & Light Company [Member] \| London Interbank Offered Rate (LIBOR) [Member]
Short-term Debt [Line Items]
Line of credit facility, interest rate at period end	1.00%
Delmarva Power & Light Company [Member] \| Revolving Credit Facility
Short-term Debt [Line Items]
Line of credit facility, maximum borrowing capacity	$ 300
Atlantic City Electric Company [Member]
Short-term Debt [Line Items]
Long-term line of credit/facility draws	0
Outstanding letters of credit	0
Actual available capacity	300
To support additional commercial paper	113
Credit facility agreements with minority and community banks	$ 8	$ 8
Atlantic City Electric Company [Member] \| Prime Rate [Member]
Short-term Debt [Line Items]
Line of credit facility, interest rate at period end	0.075%
Atlantic City Electric Company [Member] \| London Interbank Offered Rate (LIBOR) [Member]
Short-term Debt [Line Items]
Line of credit facility, interest rate at period end	1.075%
Atlantic City Electric Company [Member] \| Revolving Credit Facility
Short-term Debt [Line Items]
Line of credit facility, maximum borrowing capacity	$ 300

Debt and Credit Agreements - Summary of Credit Facility Thresholds (Details) - Exelon Generation Co L L C [Member] $ in Millions	Dec. 31, 2020 USD ($)
Line of credit
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 1,500
BilateralOct2012 [Member] \| Line of credit
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	200
BilateralJan2013 [Member] \| Line of credit
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	100
BilateralJan2016 [Member] \| Line of credit
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	150
BilateralFeb2019 [Member] \| Line of credit
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	100
BilateralOct2019a [Member] \| Line of credit
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	200
BilateralOct2019b [Member] \| Line of credit
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	100
BilateralNov2019a [Member] \| Line of credit
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	300
BilateralNov2019b [Member] \| Line of credit
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	150
BilateralNov2019c [Member] \| Line of credit
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	100
ExGenBilat100May152020
Line of Credit Facility [Line Items]
Line of credit facility, fair value of amount outstanding	0
ExGenBilat100May152020 \| Line of credit
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 100

Debt and Credit Agreements - Schedule of Long-term Debt Maturities (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Debt Instrument [Line Items]
2021	$ 1,819
2022	3,092
2023	859
2024	814
2025	2,215
Thereafter	28,107
Long-term Debt	36,906
Long-term debt to financing trusts	390	$ 390
Long-term debt to financing trusts
Debt Instrument [Line Items]
Long-term debt to financing trusts	390	390
ComEd Financing III Affiliate [Member]
Debt Instrument [Line Items]
Long-term debt to financing trusts	206	206
ComEd Financing III Affiliate [Member] \| Long-term debt to financing trusts
Debt Instrument [Line Items]
Long-term debt to financing trusts		206
Exelon Generation Co L L C [Member]
Debt Instrument [Line Items]
2021	197
2022	1,025
2023	1
2024	1
2025	900
Thereafter	3,948
Long-term Debt	6,072
Commonwealth Edison Co [Member]
Debt Instrument [Line Items]
2021	350
2022	0
2023	0
2024	250
2025	0
Thereafter	8,692
Long-term Debt	9,292
Long-term debt to financing trusts	205	205
Commonwealth Edison Co [Member] \| Long-term debt to financing trusts
Debt Instrument [Line Items]
Long-term debt to financing trusts	206	206
Commonwealth Edison Co [Member] \| ComEd Financing III Affiliate [Member]
Debt Instrument [Line Items]
Long-term debt to financing trusts	205	205
Commonwealth Edison Co [Member] \| ComEd Financing III Affiliate [Member] \| Long-term debt to financing trusts
Debt Instrument [Line Items]
Long-term debt to financing trusts	206	206
PECO Energy Co [Member]
Debt Instrument [Line Items]
2021	300
2022	350
2023	50
2024	0
2025	350
Thereafter	2,934
Long-term Debt	3,984
Long-term debt to financing trusts	184	184
PECO Energy Co [Member] \| ComEd Financing III Affiliate [Member]
Debt Instrument [Line Items]
Long-term debt to financing trusts	0	$ 0
PECO Energy Co [Member] \| PECO Financing Trusts [Member] \| Long-term debt to financing trusts
Debt Instrument [Line Items]
Long-term debt to financing trusts	184
Baltimore Gas and Electric Company [Member]
Debt Instrument [Line Items]
2021	300
2022	250
2023	300
2024	0
2025	0
Thereafter	2,850
Long-term Debt	3,700
Pepco Holdings LLC [Member]
Debt Instrument [Line Items]
2021	347
2022	317
2023	508
2024	558
2025	158
Thereafter	4,608
Long-term Debt	6,496
Potomac Electric Power Company [Member]
Debt Instrument [Line Items]
2021	3
2022	312
2023	3
2024	403
2025	3
Thereafter	2,479
Long-term Debt	3,203
Delmarva Power & Light Company [Member]
Debt Instrument [Line Items]
2021	82
2022	3
2023	503
2024	3
2025	3
Thereafter	1,093
Long-term Debt	1,687
Atlantic City Electric Company [Member]
Debt Instrument [Line Items]
2021	261
2022	2
2023	2
2024	152
2025	152
Thereafter	852
Long-term Debt	$ 1,421

Fair Value of Financial Assets and Liabilities - Narrative (Details) - USD ($)	Dec. 31, 2020	Dec. 31, 2019
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity Securities without Readily Determinable Fair Value, Amount	$ 73,000,000	$ 69,000,000
Forward Power Basis	2.49
Forward Gas Basis	0.38
Exelon Generation Co L L C [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity Securities without Readily Determinable Fair Value, Amount	55,000,000	$ 69,000,000
Forward Power Basis	2.49
Forward Gas Basis	0.38
Private Credit [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Unfunded Commitments	195,000,000
Private Credit [Member] \| Exelon Generation Co L L C [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Unfunded Commitments	195,000,000
Private Equity Funds [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Unfunded Commitments	254,000,000
Private Equity Funds [Member] \| Exelon Generation Co L L C [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Unfunded Commitments	254,000,000
Real Estate Funds [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Unfunded Commitments	369,000,000
Real Estate Funds [Member] \| Exelon Generation Co L L C [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Unfunded Commitments	$ 369,000,000

Fair Value of Financial Assets and Liabilities - Fair Value Reconciliation of Level 3 Assets and Liabilities Measured on a Recurring Basis (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning Balance	$ 1,068	$ 907
Total realized / unrealized gains (losses)
Included in net income	(409)	(23)
Included in noncurrent payables to affiliates	0	0
Included in regulatory assets/liabilities	21	(18)
Change in collateral	53	(138)
Purchases, sales, issuances and settlements
Purchases	151	176
Sales	(27)	(23)
Settlements	(55)	(89)
Transfers into Level 3	(12)	5
Transfers out of Level 3	(24)	(5)
Ending Balance	660	1,068
Fair Value, Asset, Recurring Basis, Still Held, Unrealized Gain (Loss)	11	359
Fair Value, Inputs, Level 3 [Member] \| Consolidation, Eliminations [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning Balance	0	0
Total realized / unrealized gains (losses)
Included in net income	0	0
Included in noncurrent payables to affiliates	(21)	(34)
Included in regulatory assets/liabilities	21	34
Change in collateral	0	0
Purchases, sales, issuances and settlements
Purchases	0	0
Sales	0	0
Settlements	0	0
Transfers into Level 3	0	0
Transfers out of Level 3	0	0
Ending Balance	0	0
Fair Value, Asset, Recurring Basis, Still Held, Unrealized Gain (Loss)	0	0
Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning Balance	1,328	1,118
Total realized / unrealized gains (losses)
Included in net income	(412)	(26)
Included in noncurrent payables to affiliates	21	34
Included in regulatory assets/liabilities	0	0
Change in collateral	53	(138)
Purchases, sales, issuances and settlements
Purchases	151	176
Sales	(27)	(23)
Settlements	(45)	(89)
Transfers into Level 3	(12)	5
Transfers out of Level 3	(24)	(5)
Ending Balance	927	1,328
Fair Value, Asset, Recurring Basis, Still Held, Unrealized Gain (Loss)	8	356
Exelon Generation Co L L C [Member] \| Nuclear Decommissioning Trust Fund Investments [Member] \| Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning Balance	511	543
Total realized / unrealized gains (losses)
Included in net income	2	5
Included in noncurrent payables to affiliates	21	34
Included in regulatory assets/liabilities	0	0
Change in collateral	0	0
Purchases, sales, issuances and settlements
Purchases	8	44
Sales	0	(21)
Settlements	(45)	(94)
Transfers into Level 3	0	0
Transfers out of Level 3	0	0
Ending Balance	497	511
Fair Value, Asset, Recurring Basis, Still Held, Unrealized Gain (Loss)	2	5
Exelon Generation Co L L C [Member] \| Derivative [Member] \| Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning Balance	817	575
Total realized / unrealized gains (losses)
Included in net income	(414)	(31)
Included in noncurrent payables to affiliates	0	0
Included in regulatory assets/liabilities	0	0
Change in collateral	53	(138)
Purchases, sales, issuances and settlements
Purchases	143	132
Sales	(27)	(2)
Settlements	0	5
Transfers into Level 3	(12)	5
Transfers out of Level 3	(24)	(5)
Ending Balance	430	817
Fair Value, Asset, Recurring Basis, Still Held, Unrealized Gain (Loss)	6	351
Fair Value, Assets and Liabilities Measured on Recurring Basis, Gain (Loss) Included in Earnings	420	377
Commonwealth Edison Co [Member] \| Derivative [Member] \| Interest Rate Swap [Member]
Purchases, sales, issuances and settlements
Realized Investment Gains (Losses)	33	26
Commonwealth Edison Co [Member] \| Derivative [Member] \| Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning Balance	(301)	(249)
Total realized / unrealized gains (losses)
Included in net income	0	0
Included in noncurrent payables to affiliates	0	0
Included in regulatory assets/liabilities	0	(52)
Change in collateral	0	0
Purchases, sales, issuances and settlements
Purchases	0	0
Sales	0	0
Settlements	0	0
Transfers into Level 3	0	0
Transfers out of Level 3	0	0
Ending Balance	(301)	(301)
Fair Value, Asset, Recurring Basis, Still Held, Unrealized Gain (Loss)	0	0
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Period Increase (Decrease)	33	78
Pepco Holdings LLC [Member] \| 6311 Life Insurance [Member] \| Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning Balance	41	38
Total realized / unrealized gains (losses)
Included in net income	3	3
Included in noncurrent payables to affiliates	0	0
Included in regulatory assets/liabilities	0	0
Change in collateral	0	0
Purchases, sales, issuances and settlements
Purchases	0	0
Sales	0	0
Settlements	(10)	0
Transfers into Level 3	0	0
Transfers out of Level 3	0	0
Ending Balance	34	41
Fair Value, Asset, Recurring Basis, Still Held, Unrealized Gain (Loss)	3	3
Potomac Electric Power Company [Member] \| 6311 Life Insurance [Member] \| Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning Balance	41	38
Total realized / unrealized gains (losses)
Included in net income	3	3
Included in noncurrent payables to affiliates	0	0
Included in regulatory assets/liabilities	0	0
Change in collateral	0	0
Purchases, sales, issuances and settlements
Purchases	0	0
Sales	0	0
Settlements	(10)	0
Transfers into Level 3	0	0
Transfers out of Level 3	0	0
Ending Balance	34	41
Fair Value, Asset, Recurring Basis, Still Held, Unrealized Gain (Loss)	$ 3	$ 3

Fair Value of Financial Assets and Liabilities - Fair Value Inputs Assets Quantitative Information (Details)	12 Months Ended
	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)
Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Cash Collateral Posted	$ 162,000,000	$ 214,000,000
Economic Hedges [Member] \| Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative assets, fair value	$ 245,000,000	$ 558,000,000
Economic Hedges [Member] \| Fair Value, Inputs, Level 3 [Member] \| Minimum [Member] \| Discounted Cash Flow [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Forward power price assets	2.25	9
Forward gas price assets	1.57	0.83
Economic Hedges [Member] \| Fair Value, Inputs, Level 3 [Member] \| Minimum [Member] \| Option Model Valuation Technique [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative Asset (Liability) Net, Measurement Input	0.11	0.08
Economic Hedges [Member] \| Fair Value, Inputs, Level 3 [Member] \| Maximum [Member] \| Discounted Cash Flow [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Forward power price assets	163	180
Forward gas price assets	7.88	10.72
Economic Hedges [Member] \| Fair Value, Inputs, Level 3 [Member] \| Maximum [Member] \| Option Model Valuation Technique [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative Asset (Liability) Net, Measurement Input	2.37	2.36
Economic Hedges [Member] \| Fair Value, Inputs, Level 3 [Member] \| Arithmetic Average [Member] \| Discounted Cash Flow [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Forward power price assets	30	29
Forward gas price assets	2.59	2.55
Economic Hedges [Member] \| Fair Value, Inputs, Level 3 [Member] \| Arithmetic Average [Member] \| Option Model Valuation Technique [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative Asset (Liability) Net, Measurement Input	0.32	0.70
Proprietary Trading [Member] \| Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative assets, fair value	$ 23,000,000	$ 45,000,000
Proprietary Trading [Member] \| Fair Value, Inputs, Level 3 [Member] \| Minimum [Member] \| Discounted Cash Flow [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Forward power price assets	10	25
Proprietary Trading [Member] \| Fair Value, Inputs, Level 3 [Member] \| Maximum [Member] \| Discounted Cash Flow [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Forward power price assets	106	180
Proprietary Trading [Member] \| Fair Value, Inputs, Level 3 [Member] \| Arithmetic Average [Member] \| Discounted Cash Flow [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Forward power price assets	27	33
Derivative [Member] \| Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	$ (301,000,000)	$ (301,000,000)
Derivative [Member] \| Fair Value, Inputs, Level 3 [Member] \| Minimum [Member] \| Discounted Cash Flow [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative Asset (Liability) Net, Measurement Input	0.03	0.03
Fair Value Inputs Forward Heat Rate	800.00%	900.00%
Renewable factor	91.00%	91.00%
Derivative [Member] \| Fair Value, Inputs, Level 3 [Member] \| Maximum [Member] \| Discounted Cash Flow [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative Asset (Liability) Net, Measurement Input	0.08	0.07
Fair Value Inputs Forward Heat Rate	900.00%	1000.00%
Renewable factor	123.00%	123.00%
Derivative [Member] \| Fair Value, Inputs, Level 3 [Member] \| Arithmetic Average [Member] \| Discounted Cash Flow [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative Asset (Liability) Net, Measurement Input	0.0493	0.0495
Fair Value Inputs Forward Heat Rate	885.00%	968.00%
Renewable factor	99.00%	99.00%
Exelon Generation Co L L C [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	$ (297,000,000)	$ (307,000,000)
Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Cash Collateral Posted	162,000,000	214,000,000
Exelon Generation Co L L C [Member] \| Economic Hedges [Member] \| Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative assets, fair value	$ 245,000,000	$ 558,000,000
Exelon Generation Co L L C [Member] \| Economic Hedges [Member] \| Fair Value, Inputs, Level 3 [Member] \| Minimum [Member] \| Discounted Cash Flow [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Forward power price assets	2.25	9
Forward gas price assets	1.57	0.83
Exelon Generation Co L L C [Member] \| Economic Hedges [Member] \| Fair Value, Inputs, Level 3 [Member] \| Minimum [Member] \| Option Model Valuation Technique [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative Asset (Liability) Net, Measurement Input	0.11	0.08
Exelon Generation Co L L C [Member] \| Economic Hedges [Member] \| Fair Value, Inputs, Level 3 [Member] \| Maximum [Member] \| Discounted Cash Flow [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Forward power price assets	163	180
Forward gas price assets	7.88	10.72
Exelon Generation Co L L C [Member] \| Economic Hedges [Member] \| Fair Value, Inputs, Level 3 [Member] \| Maximum [Member] \| Option Model Valuation Technique [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative Asset (Liability) Net, Measurement Input	2.37	2.36
Exelon Generation Co L L C [Member] \| Economic Hedges [Member] \| Fair Value, Inputs, Level 3 [Member] \| Arithmetic Average [Member] \| Discounted Cash Flow [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Forward power price assets	30	29
Forward gas price assets	2.59	2.55
Exelon Generation Co L L C [Member] \| Economic Hedges [Member] \| Fair Value, Inputs, Level 3 [Member] \| Arithmetic Average [Member] \| Option Model Valuation Technique [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative Asset (Liability) Net, Measurement Input	0.32	0.70
Exelon Generation Co L L C [Member] \| Proprietary Trading [Member] \| Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative assets, fair value	$ 23,000,000	$ 45,000,000
Exelon Generation Co L L C [Member] \| Proprietary Trading [Member] \| Fair Value, Inputs, Level 3 [Member] \| Minimum [Member] \| Discounted Cash Flow [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Forward power price assets	10	25
Exelon Generation Co L L C [Member] \| Proprietary Trading [Member] \| Fair Value, Inputs, Level 3 [Member] \| Maximum [Member] \| Discounted Cash Flow [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Forward power price assets	106	180
Exelon Generation Co L L C [Member] \| Proprietary Trading [Member] \| Fair Value, Inputs, Level 3 [Member] \| Arithmetic Average [Member] \| Discounted Cash Flow [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Forward power price assets	27	33
Commonwealth Edison Co [Member] \| Derivative [Member] \| Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	$ (301,000,000)	$ (301,000,000)
Commonwealth Edison Co [Member] \| Derivative [Member] \| Fair Value, Inputs, Level 3 [Member] \| Minimum [Member] \| Discounted Cash Flow [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative Asset (Liability) Net, Measurement Input	0.03	0.03
Fair Value Inputs Forward Heat Rate	800.00%	900.00%
Renewable factor	91.00%	91.00%
Commonwealth Edison Co [Member] \| Derivative [Member] \| Fair Value, Inputs, Level 3 [Member] \| Maximum [Member] \| Discounted Cash Flow [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative Asset (Liability) Net, Measurement Input	0.08	0.07
Fair Value Inputs Forward Heat Rate	900.00%	1000.00%
Renewable factor	123.00%	123.00%
Commonwealth Edison Co [Member] \| Derivative [Member] \| Fair Value, Inputs, Level 3 [Member] \| Arithmetic Average [Member] \| Discounted Cash Flow [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative Asset (Liability) Net, Measurement Input	0.0493	0.0495
Fair Value Inputs Forward Heat Rate	885.00%	968.00%
Renewable factor	99.00%	99.00%

Commitments and Contingencies - Narrative (Details)			12 Months Ended
Commitments and Contingencies - Narrative (Details)	Oct. 30, 2020 USD ($)	Mar. 23, 2016 USD ($) MW	Dec. 31, 2022 MW	Dec. 31, 2020 USD ($) MGPSite Open_claim MW	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($) MW	Dec. 31, 2017 MW	Sep. 30, 2020 USD ($)	Mar. 31, 2018 USD ($)
Commitments and Contingencies [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted				$ 71,000,000
Other Commitment				2,719,000,000
Accrual for Environmental Loss Contingencies, Gross				483,000,000	$ 478,000,000
Asbestos Liability Reserve				89,000,000	83,000,000
Contributions from parent					0	$ 0
West Lake [Member]
Commitments and Contingencies [Line Items]
Accrual for Environmental Loss Contingencies, Gross				280,000,000
Exelon Generation Co L L C [Member]
Commitments and Contingencies [Line Items]
Other Commitment				2,154,000,000
Nuclear financial protection pool value				450,000,000
Maximum recovery limit from a nuclear industry mutual insurance company in the event of multiple losses				13,300,000,000
Maximum annual assessment payment mandated by Price-Anderson Act for a nuclear incident				2,900,000,000
Mutual Insurance Total Retrospective Premium Obligation				252,000,000
Mutual Replacement Power Cost Insurance Maximum Retrospective Premium Obligation				3,200,000,000
Cost of spent nuclear fuel disposal per kWh of net nuclear generation				$ 0.001
Spent Nuclear Fuel Treasury Interest Rate				0.096%
Accrual for Environmental Loss Contingencies, Gross				$ 121,000,000	105,000,000
Asbestos Liability Reserve				89,000,000	83,000,000
Contributions from parent				$ 64,000,000	41,000,000	155,000,000
Spent Nuclear Fuel Treasury Interest Rate - FitzPatrick				0.101%
Exelon Generation Co L L C [Member] \| West Lake [Member]
Commitments and Contingencies [Line Items]
Accrual for Environmental Loss Contingencies, Gross				$ 30,000,000
Environmental loss contingencies				90,000,000
Exelon Generation Co L L C [Member] \| Nuclear Insurance Premiums [Member]
Commitments and Contingencies [Line Items]
Nuclear insurance liability limit per incident				13,800,000,000
Exelon Generation Co L L C [Member] \| Nuclear Insurance Premiums [Member] \| Maximum [Member]
Commitments and Contingencies [Line Items]
Nuclear financial protection pool value				434,000,000
Exelon Generation Co L L C [Member] \| Guarantees Other Than Letters Of Credit and Nuclear Insurance Premiums [Member]
Commitments and Contingencies [Line Items]
Mutual Property Insurance Distribution To Members				75,000,000	136,000,000	58,000,000			$ 31,000,000
Commonwealth Edison Co [Member]
Commitments and Contingencies [Line Items]
Other Commitment				$ 223,000,000
Sites under study/remediation \| MGPSite				21
Accrual for Environmental Loss Contingencies, Gross				$ 293,000,000	304,000,000
Estimated Litigation Liability, Current								$ 200,000,000
Estimated Litigation Liability, Current, Due within 30 days								100,000,000
Estimated Litigation Liability, Current, Due within 90 days								100,000,000
Contributions from parent				713,000,000	250,000,000	500,000,000
Commonwealth Edison Co [Member] \| Deferred Prosecution Agreement Payments
Commitments and Contingencies [Line Items]
Estimated Litigation Liability, Current								$ 200,000,000
Contributions from parent	$ 200,000,000
Litigation Settlement, Amount Awarded to Other Party				200,000,000
PECO Energy Co [Member]
Commitments and Contingencies [Line Items]
Other Commitment				$ 180,000,000
Sites under study/remediation \| MGPSite				8
Accrual for Environmental Loss Contingencies, Gross				$ 23,000,000	19,000,000
Contributions from parent				248,000,000	188,000,000	89,000,000
Baltimore Gas and Electric Company [Member]
Commitments and Contingencies [Line Items]
Other Commitment				$ 5,000,000
Sites under study/remediation \| MGPSite				4
Accrual for Environmental Loss Contingencies, Gross				$ 2,000,000	2,000,000
Banking Regulation, Common Equity Tier One Risk-Based Capital Ratio, Actual				0.48
Pepco Holdings LLC [Member]
Commitments and Contingencies [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted				$ 71,000,000
Other Commitment				50,000,000
Accrual for Environmental Loss Contingencies, Gross				44,000,000	48,000,000
Contributions from parent				494,000,000	398,000,000	385,000,000
Potomac Electric Power Company [Member]
Commitments and Contingencies [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted				24,000,000
Other Commitment				23,000,000
Accrual for Environmental Loss Contingencies, Gross				$ 42,000,000	46,000,000
Banking Regulation, Common Equity Tier One Risk-Based Capital Ratio, Actual				0.48
Contributions from parent				$ 262,000,000	160,000,000	166,000,000
Delmarva Power & Light Company [Member]
Commitments and Contingencies [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted				30,000,000
Other Commitment				$ 16,000,000
Total number of MGP sites \| MGPSite				1
Accrual for Environmental Loss Contingencies, Gross				$ 1,000,000	1,000,000
Banking Regulation, Common Equity Tier One Risk-Based Capital Ratio, Actual				0.48
Contributions from parent				$ 112,000,000	63,000,000	150,000,000
Atlantic City Electric Company [Member]
Commitments and Contingencies [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted				17,000,000
Other Commitment				11,000,000
Accrual for Environmental Loss Contingencies, Gross				$ 1,000,000	1,000,000
Banking Regulation, Common Equity Tier One Risk-Based Capital Ratio, Actual				0.48
Contributions from parent				$ 117,000,000	$ 175,000,000	$ 67,000,000
Atlantic City Electric Company [Member] \| Minimum [Member]
Commitments and Contingencies [Line Items]
Banking Regulation, Common Equity Tier One Risk-Based Capital Ratio, Actual				0.30
PEPCO Holdings Inc [Member]
Commitments and Contingencies [Line Items]
Other Commitment				$ 513,000,000
PEPCO Holdings Inc [Member] \| Pepco Holdings LLC [Member]
Commitments and Contingencies [Line Items]
Other Commitment				320,000,000
PEPCO Holdings Inc [Member] \| Potomac Electric Power Company [Member]
Commitments and Contingencies [Line Items]
Other Commitment				120,000,000
PEPCO Holdings Inc [Member] \| Delmarva Power & Light Company [Member]
Commitments and Contingencies [Line Items]
Other Commitment				89,000,000
PEPCO Holdings Inc [Member] \| Atlantic City Electric Company [Member]
Commitments and Contingencies [Line Items]
Other Commitment				$ 111,000,000
PEPCO Holdings Inc [Member] \| Other Solar Projects [Member]
Commitments and Contingencies [Line Items]
Business Acquisition, Expected New Generation Mwh \| MW		37		27
Other Commitment		$ 135,000,000		$ 119,000,000
PEPCO Holdings Inc [Member] \| Other Solar Projects [Member] \| Exelon Generation Co L L C [Member]
Commitments and Contingencies [Line Items]
Other Commitment				119,000,000
PEPCO Holdings Inc [Member] \| Wind Assets [Member]
Commitments and Contingencies [Line Items]
OtherNonFinancialCommitment1 \| MW		100
PEPCO Holdings Inc [Member] \| Wind Assets [Member] \| Delmarva Power & Light Company [Member]
Commitments and Contingencies [Line Items]
Purchase Commitment \| MW		120				40	40
Subsequent Event [Member] \| PEPCO Holdings Inc [Member] \| Wind Assets [Member] \| Delmarva Power & Light Company [Member]
Commitments and Contingencies [Line Items]
Purchase Commitment \| MW			40
Open Claims [Member] \| Exelon Generation Co L L C [Member]
Commitments and Contingencies [Line Items]
Asbestos Liability Reserve				$ 25,000,000
Open Asbestos Liability Claims \| Open_claim				261
Estimated Future Claims [Member] \| Exelon Generation Co L L C [Member]
Commitments and Contingencies [Line Items]
Asbestos Liability Reserve				$ 64,000,000
Remaining Commitment [Member] \| PEPCO Holdings Inc [Member]
Commitments and Contingencies [Line Items]
Other Commitment				82,000,000
Remaining Commitment [Member] \| PEPCO Holdings Inc [Member] \| Pepco Holdings LLC [Member]
Commitments and Contingencies [Line Items]
Other Commitment				67,000,000
Remaining Commitment [Member] \| PEPCO Holdings Inc [Member] \| Potomac Electric Power Company [Member]
Commitments and Contingencies [Line Items]
Other Commitment				55,000,000
Remaining Commitment [Member] \| PEPCO Holdings Inc [Member] \| Delmarva Power & Light Company [Member]
Commitments and Contingencies [Line Items]
Other Commitment				7,000,000
Remaining Commitment [Member] \| PEPCO Holdings Inc [Member] \| Atlantic City Electric Company [Member]
Commitments and Contingencies [Line Items]
Other Commitment				$ 5,000,000

Commitments and Contingencies - Schedule of PHI Merger Commitments (Details) $ in Millions	Dec. 31, 2020 USD ($)
PHI Merger Commitments [Line Items]
Other Commitment	$ 2,719
PEPCO Holdings Inc [Member]
PHI Merger Commitments [Line Items]
Other Commitment	513
Pepco Holdings LLC [Member]
PHI Merger Commitments [Line Items]
Other Commitment	50
Pepco Holdings LLC [Member] \| PEPCO Holdings Inc [Member]
PHI Merger Commitments [Line Items]
Other Commitment	320
Potomac Electric Power Company [Member]
PHI Merger Commitments [Line Items]
Other Commitment	23
Potomac Electric Power Company [Member] \| PEPCO Holdings Inc [Member]
PHI Merger Commitments [Line Items]
Other Commitment	120
Delmarva Power & Light Company [Member]
PHI Merger Commitments [Line Items]
Other Commitment	16
Delmarva Power & Light Company [Member] \| PEPCO Holdings Inc [Member]
PHI Merger Commitments [Line Items]
Other Commitment	89
Atlantic City Electric Company [Member]
PHI Merger Commitments [Line Items]
Other Commitment	11
Atlantic City Electric Company [Member] \| PEPCO Holdings Inc [Member]
PHI Merger Commitments [Line Items]
Other Commitment	111
Remaining Commitment [Member] \| PEPCO Holdings Inc [Member]
PHI Merger Commitments [Line Items]
Other Commitment	82
Remaining Commitment [Member] \| Pepco Holdings LLC [Member] \| PEPCO Holdings Inc [Member]
PHI Merger Commitments [Line Items]
Other Commitment	67
Remaining Commitment [Member] \| Potomac Electric Power Company [Member] \| PEPCO Holdings Inc [Member]
PHI Merger Commitments [Line Items]
Other Commitment	55
Remaining Commitment [Member] \| Delmarva Power & Light Company [Member] \| PEPCO Holdings Inc [Member]
PHI Merger Commitments [Line Items]
Other Commitment	7
Remaining Commitment [Member] \| Atlantic City Electric Company [Member] \| PEPCO Holdings Inc [Member]
PHI Merger Commitments [Line Items]
Other Commitment	$ 5

Commitments and Contingencies - Settlement Agreements (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Guarantor Obligations [Line Items]
Nontrade Receivables, Current	$ 129	$ 249
Nontrade Receivables, Noncurrent	70	30
Accounts Payable, Other, Current	(23)	$ (37)
Exelon Generation Co L L C [Member]
Guarantor Obligations [Line Items]
Spent Nuclear Fuel Storage Reimbursement	1,455
Spent Nuclear Fuel Storage Reimbursement Net Co Owners	$ 1,266

Commitments and Contingencies - Schedule of Spent Nuclear Fuel Obligation (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Spent Nuclear Fuel Obligation [Line Items]
Spent Nuclear Fuel Obligation, Noncurrent	$ 1,208	$ 1,199
Spent Nuclear Fuel One Time Fee		34
Exelon Generation Co L L C [Member]
Spent Nuclear Fuel Obligation [Line Items]
Spent Nuclear Fuel Obligation, Noncurrent	1,208	1,199
Spent Nuclear Fuel One Time Fee		277
Nuclear Plant [Member]
Spent Nuclear Fuel Obligation [Line Items]
Spent Nuclear Fuel Obligation, Noncurrent	1,082	1,075
Nuclear Plant [Member] \| Exelon Generation Co L L C [Member]
Spent Nuclear Fuel Obligation [Line Items]
Spent Nuclear Fuel Obligation, Noncurrent	1,082	1,075
Fitzpatrick [Member]
Spent Nuclear Fuel Obligation [Line Items]
Spent Nuclear Fuel Obligation, Noncurrent	126	124
Fitzpatrick [Member] \| Exelon Generation Co L L C [Member]
Spent Nuclear Fuel Obligation [Line Items]
Spent Nuclear Fuel Obligation, Noncurrent	$ 126	$ 124

Commitments and Contingencies - Schedule of Environmental Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies, Gross	$ 483	$ 478
Exelon Generation Co L L C [Member]
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies, Gross	121	105
Commonwealth Edison Co [Member]
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies, Gross	293	304
PECO Energy Co [Member]
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies, Gross	23	19
Baltimore Gas and Electric Company [Member]
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies, Gross	2	2
Pepco Holdings LLC [Member]
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies, Gross	44	48
Potomac Electric Power Company [Member]
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies, Gross	42	46
Delmarva Power & Light Company [Member]
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies, Gross	1	1
Atlantic City Electric Company [Member]
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies, Gross	1	1
Accrual For MGP Investigation And Remediation [Member]
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies, Gross	314	320
Accrual For MGP Investigation And Remediation [Member] \| Exelon Generation Co L L C [Member]
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies, Gross	0	0
Accrual For MGP Investigation And Remediation [Member] \| Commonwealth Edison Co [Member]
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies, Gross	293	303
Accrual For MGP Investigation And Remediation [Member] \| PECO Energy Co [Member]
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies, Gross	21	17
Accrual For MGP Investigation And Remediation [Member] \| Baltimore Gas and Electric Company [Member]
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies, Gross	0	0
Accrual For MGP Investigation And Remediation [Member] \| Pepco Holdings LLC [Member]
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies, Gross	0	0
Accrual For MGP Investigation And Remediation [Member] \| Potomac Electric Power Company [Member]
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies, Gross	0	0
Accrual For MGP Investigation And Remediation [Member] \| Delmarva Power & Light Company [Member]
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies, Gross	0	0
Accrual For MGP Investigation And Remediation [Member] \| Atlantic City Electric Company [Member]
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies, Gross	$ 0	$ 0

Shareholders' Equity - Narrative (Details) shares in Millions	Dec. 31, 2020 shares
Schedule of Capitalization, Equity [Line Items]
Stock Repurchase Program, Number of Shares Authorized to be Repurchased	0

Shareholders' Equity - Schedule of Common Stock Warrants (Details) - Commonwealth Edison Co [Member] - shares	Dec. 31, 2020	Dec. 31, 2019
Class of Warrant or Right [Line Items]
Class of Warrant or Right, Outstanding	60,143	60,228
Common Stock [Member]
Class of Warrant or Right [Line Items]
Common Stock Shares Reserved For Warrant Conversion	20,048	20,076

Shareholders' Equity - Schedule of Preferred Stock (Details) - shares	Dec. 31, 2020	Dec. 31, 2019
Preferred Stock [Member]
Class of Stock [Line Items]
Preferred Stock, Shares Outstanding	0	0
Preferred Stock, Shares Authorized	100,000,000	100,000,000
Preferred Stock [Member] \| Commonwealth Edison Co [Member]
Class of Stock [Line Items]
Preferred Stock, Shares Outstanding	0	0
Preferred Stock, Shares Authorized	850,000	850,000
Preferred Stock [Member] \| PECO Energy Co [Member]
Class of Stock [Line Items]
Preferred Stock, Shares Outstanding	0	0
Preferred Stock, Shares Authorized	15,000,000	15,000,000
Preferred Stock [Member] \| Baltimore Gas and Electric Company [Member]
Class of Stock [Line Items]
Preferred Stock, Shares Outstanding	0	0
Preferred Stock, Shares Authorized	1,000,000	1,000,000
Preferred Stock [Member] \| Potomac Electric Power Company [Member]
Class of Stock [Line Items]
Preferred Stock, Shares Outstanding	0	0
Preferred Stock, Shares Authorized	6,000,000	6,000,000
Preferred Stock [Member] \| Atlantic City Electric Company [Member]
Class of Stock [Line Items]
Preferred Stock, Shares Outstanding	0	0
Preferred Stock, Shares Authorized	2,799,979	2,799,979
Preferred Stock [Member] \| Delmarva Power & Light Company [Member]
Class of Stock [Line Items]
Preferred Stock, Shares Authorized	0
Cumulative Preferred Stock [Member] \| Atlantic City Electric Company [Member]
Class of Stock [Line Items]
Preferred Stock, Shares Authorized	799,979	799,979
No-Par Preferred Stock [Member] \| Atlantic City Electric Company [Member]
Class of Stock [Line Items]
Preferred Stock, Shares Authorized	2,000,000	2,000,000

Shareholders' Equity - Schedule of Preference Stock (Details) - shares	Dec. 31, 2020	Dec. 31, 2019
Class of Stock [Line Items]
Preference Stock, Shares Authorized	0
Commonwealth Edison Co [Member]
Class of Stock [Line Items]
Preference Stock, Shares Outstanding	0	0
Preference Stock, Shares Authorized	6,810,451	6,810,451
Baltimore Gas and Electric Company [Member]
Class of Stock [Line Items]
Preference Stock, Shares Outstanding	0	0
Preference Stock, Shares Authorized	6,500,000	6,500,000
Atlantic City Electric Company [Member]
Class of Stock [Line Items]
Preference Stock, Shares Outstanding	0	0
Preference Stock, Shares Authorized	3,000,000	3,000,000
PECO Energy Co [Member]
Class of Stock [Line Items]
Preference Stock, Shares Authorized	0
Potomac Electric Power Company [Member]
Class of Stock [Line Items]
Preference Stock, Shares Authorized	0
Delmarva Power & Light Company [Member]
Class of Stock [Line Items]
Preference Stock, Shares Authorized	0
Unclassified Preference Stock [Member] \| Baltimore Gas and Electric Company [Member]
Class of Stock [Line Items]
Preference Stock, Shares Authorized	4,600,000	4,600,000
Preference Stock Redeemed [Member] \| Baltimore Gas and Electric Company [Member]
Class of Stock [Line Items]
Preference Stock, Shares Authorized	1,900,000	1,900,000

Stock-Based Compensation Plans - Narrative (Details) shares in Millions	12 Months Ended
	Dec. 31, 2020 shares
Performance Shares [Member]
Common Stock Narrative Information [Line Items]
Percentage to be settled as common stock	50.00%
Percentage to be settled as cash	50.00%
Percentage to be settled as cash if ownership requirements are met	100.00%
Vesting period	3 years
Minimum [Member] \| Restricted Stock Units (RSUs) [Member]
Common Stock Narrative Information [Line Items]
Requisite service period	3 years
Maximum [Member] \| Restricted Stock Units (RSUs) [Member]
Common Stock Narrative Information [Line Items]
Requisite service period	5 years
LTIP [Member]
Common Stock Narrative Information [Line Items]
Shares authorized	34

Stock-Based Compensation Plans - Schedule of Stock-based Compensation Expense (Details) - Share-based Payment Arrangement [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Payment Arrangement, Expense	$ 64	$ 77	$ 208
Share-based Payment Arrangement, Expense, Tax Benefit	(16)	(20)	(54)
Share-based Payment Arrangement, Expense, after Tax	48	57	154
Exelon Generation Co L L C [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Payment Arrangement, Expense	27	37	77
Share-based Payment Arrangement, Expense, Tax Benefit	(7)	(10)	(20)
Share-based Payment Arrangement, Expense, after Tax	$ 20	$ 27	$ 57

Stock-Based Compensation Plans - Components of Tax Benefits from Stock-based Compensation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Performance Shares [Member]
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Tax benefit on stock compensation	$ 21	$ 41	$ 16
Restricted Stock Units (RSUs) [Member]
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Tax benefit on stock compensation	$ 15	$ 24	$ 28

Stock-Based Compensation Plans - Summary of Performance Share Awards Activity (Details) - Performance Shares [Member] - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Beginning Balance	1,709,755
Granted	1,122,378
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Period Increase (Decrease)	(751,309)
Vested	(747,551)
Forfeited	(67,964)
Undistributed vested awards	(334,917)
Ending Balance	930,392	1,709,755
Nonvested, Weighted Average Exercise Price (in usd per share)	$ 43.67	$ 39.21
Granted, Weighted Average Grant Date Fair Value (in usd per share)	46.61	$ 47.37	$ 38.15
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Change in Performance, Weighted Average Grant Date Fair Value	42.51
Vested, Weighted Average Exercise Price (in usd per share)	35.70
Forfeited, Weighted Average Exercise Price (in usd per share)	45.59
Undistributed Vested Awards, Weighted Average Grant Date Fair Value (in usd per share)	$ 50.76
Fully Vested Stock Based Compensation Issued To Retirement Eligible Employees	1,414,661	2,017,870
Fair Value Of Settled Performance Share Awards	$ 39	$ 158	$ 61
Performance Share Awards Obligations Settled In Cash	63	$ 131	$ 49
Share-based Payment Arrangement, Nonvested Award, Excluding Option, Cost Not yet Recognized, Amount	$ 13
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Period for Recognition	1 year 9 months 18 days

Stock-Based Compensation Plans - Summary of Nonvested Restricted Stock Unit Activity (Details) - Restricted Stock Units (RSUs) [Member] - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Beginning Balance	1,498,713
Granted	847,382
Vested	(725,151)
Forfeited	(52,046)
Undistributed vested awards	(454,768)
Ending Balance	1,114,130	1,498,713
Nonvested, Weighted Average Exercise Price (in usd per share)	$ 43.67	$ 40.35
Granted, Weighted Average Grant Date Fair Value (in usd per share)	46.33	$ 45.65	$ 38.60
Vested, Weighted Average Exercise Price (in usd per share)	38.38
Forfeited, Weighted Average Exercise Price (in usd per share)	45.20
Undistributed Vested Awards, Weighted Average Grant Date Fair Value (in usd per share)	$ 45.91
Fully Vested Stock Based Compensation Issued To Retirement Eligible Employees	748,165	863,196
Fair Value Of Settled Restricted Stock Units	$ 54	$ 92	$ 106
Share-based Payment Arrangement, Nonvested Award, Excluding Option, Cost Not yet Recognized, Amount	$ 23
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Period for Recognition	2 years 3 months 18 days

Stock-Based Compensation Plans - Summary of Stock Option Activity (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Aggregate value	$ 5	$ 9	$ 12
Cash received for exercise price	$ 18	$ 59	$ 56
Share-based Payment Arrangement, Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Beginning Balance	1,889,045
Options exercised	(475,827)
Options expired	(147,808)
Ending Balance	1,265,410	1,889,045
Exercisable at December 31, 2020	1,265,410
Weighted Average Exercise Price (in usd per share)	$ 40.57	$ 40.43
Options Exercised, Weighted Average Exercise Price (in usd per share)	38.30
Options Expired, Weighted Average Exercise Price (in usd per share)	46.07
Shares Exercisable, Weighted Average Exercise Price (in usd per share)	$ 40.57
Shares Outstanding, Weighted Average Remaining Contractual Life	10 months 28 days	1 year 6 months 21 days
Shares Exercisable, Weighted Average Remaining Contractual Life	10 months 28 days
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Intrinsic Value	$ 3	$ 10
Aggregate value	5
Shares Exercisable, Aggregate Intrinsic Value	$ 3

Changes in Accumulated Other Comprehensive Income - Schedule of Changes in AOCI (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning Balance	$ 34,573	$ 33,047	$ 32,169
Other comprehensive income (loss)	(206)	(198)	42
Ending Balance	34,868	34,573	33,047
Accounting Standards Update 2016-01 [Member]
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard			(10)
Gains and (Losses) on Cash Flow Hedges
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning Balance	(2)	(2)	(14)
OCI before reclassifications	(3)	0	11
Amounts reclassified from AOCI	0	0	1
Other comprehensive income (loss)	(3)	0	12
Ending Balance	(5)	(2)	(2)
Gains and (Losses) on Cash Flow Hedges \| Accounting Standards Update 2016-01 [Member]
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard			0
Unrealized Gains and (Losses) on Marketable Securities
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning Balance	0	0	10
OCI before reclassifications	0	0	0
Amounts reclassified from AOCI	0	0	0
Other comprehensive income (loss)	0	0	0
Ending Balance	0	0	0
Unrealized Gains and (Losses) on Marketable Securities \| Accounting Standards Update 2016-01 [Member]
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard			(10)
Pension and Non-Pension Postretirement Benefit Plan Items (a)
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning Balance	(3,165)	(2,960)	(2,998)
OCI before reclassifications	(357)	(289)	(143)
Amounts reclassified from AOCI	150	84	181
Other comprehensive income (loss)	(207)	(205)	38
Ending Balance	(3,372)	(3,165)	(2,960)
Pension and Non-Pension Postretirement Benefit Plan Items (a) \| Accounting Standards Update 2016-01 [Member]
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard			0
Foreign Currency Items
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning Balance	(27)	(33)	(23)
OCI before reclassifications	4	6	(10)
Amounts reclassified from AOCI	0	0	0
Other comprehensive income (loss)	4	6	(10)
Ending Balance	(23)	(27)	(33)
Foreign Currency Items \| Accounting Standards Update 2016-01 [Member]
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard			0
AOCI of Investments Unconsolidated Affiliates (b)
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning Balance	0	0	(1)
OCI before reclassifications	0	(2)	1
Amounts reclassified from AOCI	0	2	0
Other comprehensive income (loss)	0	0	1
Ending Balance	0	0	0
AOCI of Investments Unconsolidated Affiliates (b) \| Accounting Standards Update 2016-01 [Member]
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard			0
Total
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning Balance	(3,194)	(2,995)	(3,026)
OCI before reclassifications	(356)	(285)	(141)
Amounts reclassified from AOCI	150	86	182
Other comprehensive income (loss)	(206)	(199)	41
Ending Balance	$ (3,400)	$ (3,194)	$ (2,995)

Changes in Accumulated Other Comprehensive Income - Income Taxes Allocated to Other Comprehensive Income (Loss) Components (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Prior service costs
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), Tax	$ 16	$ 23	$ 24
Actuarial losses
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), Tax	(66)	(52)	(86)
Pension and Non-Pension Postretirement Benefit Plan Items (a)
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), Tax	$ 122	$ 100	$ 50

Amount of tax expense (benefit) allocated to other comprehensive income (loss).

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 20
-Section 45
-Paragraph 11
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=120385591&loc=d3e39076-109324

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 830
-SubTopic 30
-Section 45
-Paragraph 17
-URI http://asc.fasb.org/extlink&oid=118261656&loc=d3e32136-110900

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 830
-SubTopic 30
-Section 45
-Paragraph 20
-Subparagraph (c)
-URI http://asc.fasb.org/extlink&oid=118261656&loc=d3e32211-110900

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 20
-Section 45
-Paragraph 2
-Subparagraph (d)
-URI http://asc.fasb.org/extlink&oid=120385591&loc=d3e38679-109324

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 942
-SubTopic 220
-Section S99
-Paragraph 1
-Subparagraph (SX 210.9-04(23))
-URI http://asc.fasb.org/extlink&oid=120399700&loc=SL114874048-224260

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section S99
-Paragraph 2
-Subparagraph (SX 210.5-03(21))
-URI http://asc.fasb.org/extlink&oid=120395209&loc=SL114868664-224227

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 10
-URI http://asc.fasb.org/extlink&oid=84230637&loc=d3e32672-109319

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 830
-SubTopic 30
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6450520&loc=d3e32583-110901

Reference 9: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 12
-URI http://asc.fasb.org/extlink&oid=121641772&loc=d3e640-108580

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 944
-SubTopic 220
-Section S99
-Paragraph 1
-Subparagraph (SX 210.7-04(19))
-URI http://asc.fasb.org/extlink&oid=120400993&loc=SL114874131-224263

Variable Interest Entities - Narrative (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Apr. 01, 2014
Variable Interest Entity [Line Items]
Guarantee obligations maximum exposure	$ 71
Exelon Generation Co L L C [Member] \| Distributed Energy Company [Member]
Variable Interest Entity [Line Items]
Equity Method Investment, Ownership Percentage		90.00%
Exelon Generation Co L L C [Member] \| VIE Distributed Energy Company [Member]
Variable Interest Entity [Line Items]
Equity Method Investment, Ownership Percentage		90.00%
CENG [Member]
Variable Interest Entity [Line Items]
Equity Method Investment, Ownership Percentage	50.01%
Due from Affiliates	$ 619		$ 400
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners	49.99%
CENG [Member] \| Exelon Generation Co L L C [Member]
Variable Interest Entity [Line Items]
Equity Method Investment, Ownership Percentage	50.01%	50.01%
Due from Affiliates	$ 619		400
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners	49.99%
EGRP [Member] \| Exelon Generation Co L L C [Member]
Variable Interest Entity [Line Items]
Equity Method Investment, Ownership Percentage		51.00%
Antelope Valley [Member] \| Exelon Generation Co L L C [Member]
Variable Interest Entity [Line Items]
Equity Method Investment, Ownership Percentage		100.00%
Distributed Energy Company [Member] \| Exelon Generation Co L L C [Member]
Variable Interest Entity [Line Items]
Equity Method Investment, Ownership Percentage		31.00%
NER [Member] \| Exelon Generation Co L L C [Member]
Variable Interest Entity [Line Items]
Equity Method Investment, Ownership Percentage		100.00%
Variable Interest Entity, Primary Beneficiary [Member] \| CENG [Member] \| Payment Guarantee [Member]
Variable Interest Entity [Line Items]
Guarantee obligations maximum exposure			245
Variable Interest Entity, Primary Beneficiary [Member] \| CENG [Member] \| Financial Guarantee [Member]
Variable Interest Entity [Line Items]
Guarantee obligations maximum exposure			$ 165
Variable Interest Entity, Primary Beneficiary [Member] \| CENG [Member] \| Exelon Generation Co L L C [Member]
Variable Interest Entity [Line Items]
Parental guarantee provided	$ 688
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners		49.99%
Variable Interest Entity, Primary Beneficiary [Member] \| EGRP [Member] \| Exelon Generation Co L L C [Member] \| Wind project entities [Member]
Variable Interest Entity [Line Items]
Equity Method Investment, Ownership Percentage		100.00%
Variable Interest Entity, Primary Beneficiary [Member] \| EGRP [Member] \| Exelon Generation Co L L C [Member] \| Solar project entities [Member]
Variable Interest Entity [Line Items]
Equity Method Investment, Ownership Percentage		100.00%

Variable Interest Entities - Assets and Liabilities of Consolidated VIEs (Details) - USD ($)
$ in Millions

Dec. 31, 2020

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

$ 663

$ 587

$ 1,349

$ 898

438

358

247

207

3,231

4,592

644

679

1,425

1,456

958

1,609

905

12,562

12,037

82,584

80,233

14,464

13,190

294

336

2,982

3,197

^[1]

129,317

124,977

1,819

4,710

3,562

3,560

Market-to-market derivative liabilities, current

2,078

1,981

295

247

100

132

375

1,264

1,331

12,771

14,185

35,093

31,329

Liability, Defined Benefit Pension Plan, Noncurrent

12,300

10,846

4,503

4,247

238

338

2,942

3,064

^[1]

94,449

90,404

226

303

750

416

146

153

138

1,298

2,893

644

675

978

1,026

958

1,357

605

6,947

7,076

22,214

24,193

14,464

13,190

293

336

1,826

1,960

^[2]

48,094

48,995

197

2,624

1,253

1,692

Market-to-market derivative liabilities, current

788

786

262

215

375

444

517

5,219

7,289

5,566

4,464

12,054

10,603

1,308

1,415

^[2]

33,418

33,165

111

131

124

525

479

198

190

1,599

1,480

15,377

14,296

307

323

23,736

22,719

347

103

539

462

299

296

115

141

131

2,154

1,612

6,659

6,460

235

327

622

577

Atlantic City Electric Company [Member]

^[3]

13,692

13,111

$ 4

$ 6

124

108

326

270

3,475

3,190

^[4]

4,286

3,933

261

177

144

780

360

1,152

1,307

Variable Interest Entity, Primary Beneficiary [Member]

^[4]

2,895

2,657

163

148

151

244

227

101

674

1,370

723

5,803

6,022

3,007

2,741

249

250

9,111

9,102

10,481

9,825

544

106

270

731

889

527

2,318

2,128

129

3,336

2,745

PP&E - unrestricted asset

3,606

3,476

AHFS - unrestricted asset

Variable Interest Entity, Primary Beneficiary [Member] | Recourse [Member]

Variable Interest Entity, Primary Beneficiary [Member] | Exelon Generation Co L L C [Member]

163

148

151

244

227

101

669

1,362

719

5,803

6,022

3,007

2,741

249

250

9,101

9,086

10,463

9,805

523

106

244

710

889

504

2,318

2,128

129

3,336

2,722

PP&E - unrestricted asset

3,580

3,432

AHFS - unrestricted asset

Variable Interest Entity, Primary Beneficiary [Member] | Exelon Generation Co L L C [Member] | Recourse [Member]

Variable Interest Entity, Primary Beneficiary [Member] | Pepco Holdings LLC [Member]

Variable Interest Entity, Primary Beneficiary [Member] | Atlantic City Electric Company [Member]

$ 21

$ 41

[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]	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.
[4]	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.

Variable Interest Entities - Summary of Significant Unconsolidated VIEs (Details) - USD ($)
$ in Millions

Dec. 31, 2020

Dec. 31, 2019

^[1]

$ 129,317

$ 124,977

^[1]

94,449

90,404

^[2]

48,094

48,995

Variable Interest Entity, Not Primary Beneficiary [Member]

^[2]

33,418

33,165

1,178

1,079

284

260

157

191

Variable Interest Entity, Not Primary Beneficiary [Member] | Exelon Generation Co L L C [Member]

737

629

1,178

1,079

284

260

157

191

Variable Interest Entity, Primary Beneficiary [Member]

737

629

10,481

9,825

Variable Interest Entity, Primary Beneficiary [Member] | Exelon Generation Co L L C [Member]

3,606

3,476

10,463

9,805

Commercial Agreement VIE [Member] | Variable Interest Entity, Not Primary Beneficiary [Member]

3,580

3,432

777

636

Commercial Agreement VIE [Member] | Variable Interest Entity, Not Primary Beneficiary [Member] | Exelon Generation Co L L C [Member]

716

604

777

636

Equity Investment VIE [Member] | Variable Interest Entity, Not Primary Beneficiary [Member]

716

604

401

443

223

227

157

191

Equity Investment VIE [Member] | Variable Interest Entity, Not Primary Beneficiary [Member] | Exelon Generation Co L L C [Member]

401

443

223

227

157

191

$ 21

$ 25

[1]

[2]

Supplemental Financial Information - Summary of Taxes other than income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Supplemental Statement of Operations Information [Line Items]
Utility	$ 859	$ 881	$ 919
Property	602	595	557
Payroll	235	232	247
Exelon Generation Co L L C [Member]
Supplemental Statement of Operations Information [Line Items]
Utility	99	112	114
Property	265	274	273
Payroll	113	115	130
Commonwealth Edison Co [Member]
Supplemental Statement of Operations Information [Line Items]
Utility	238	242	243
Property	30	29	30
Payroll	27	27	27
PECO Energy Co [Member]
Supplemental Statement of Operations Information [Line Items]
Utility	135	132	131
Property	16	17	15
Payroll	16	15	16
Baltimore Gas and Electric Company [Member]
Supplemental Statement of Operations Information [Line Items]
Utility	87	90	94
Property	164	153	143
Payroll	17	17	17
Pepco Holdings LLC [Member]
Supplemental Statement of Operations Information [Line Items]
Utility	299	304	337
Property	126	122	94
Payroll	25	24	24
Potomac Electric Power Company [Member]
Supplemental Statement of Operations Information [Line Items]
Utility	275	286	316
Property	84	85	58
Payroll	7	7	5
Delmarva Power & Light Company [Member]
Supplemental Statement of Operations Information [Line Items]
Utility	21	18	21
Property	39	34	32
Payroll	5	4	3
Atlantic City Electric Company [Member]
Supplemental Statement of Operations Information [Line Items]
Utility	3	0	0
Property	3	2	3
Payroll	$ 3	$ 2	$ 2

Supplemental Financial Information - Summary of Other Income (Expense) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Decommissioning-Related Activities [Abstract]
Net realized income on NDT funds - Regulatory agreement units	$ 185	$ 297	$ 506
Net realized income on NDT funds - Non-regulatory agreement units	160	363	302
Net unrealized gains (losses) on NDT funds - Regulatory agreement units	724	795	(715)
Net unrealized gains (losses) on NDT funds - Non-regulatory agreement	391	411	(483)
Regulatory offset to NDT fund-related activities	(729)	(876)	171
Total decommissioning-related activities	731	990	(219)
AFUDC—Equity	104	85	69
Non-service net periodic benefit cost	53	13	(47)
Unrealized Gain (Loss) on Investments	186	0	0
Exelon Generation Co L L C [Member]
Decommissioning-Related Activities [Abstract]
Net realized income on NDT funds - Regulatory agreement units	185	297	506
Net realized income on NDT funds - Non-regulatory agreement units	160	363	302
Net unrealized gains (losses) on NDT funds - Regulatory agreement units	724	795	(715)
Net unrealized gains (losses) on NDT funds - Non-regulatory agreement	391	411	(483)
Regulatory offset to NDT fund-related activities	(729)	(876)	171
Total decommissioning-related activities	731	990	(219)
AFUDC—Equity	0	0	0
Non-service net periodic benefit cost	0	0	0
Unrealized Gain (Loss) on Investments	186	0	0
Commonwealth Edison Co [Member]
Decommissioning-Related Activities [Abstract]
Net realized income on NDT funds - Regulatory agreement units	0	0	0
Net realized income on NDT funds - Non-regulatory agreement units	0	0	0
Net unrealized gains (losses) on NDT funds - Regulatory agreement units	0	0	0
Net unrealized gains (losses) on NDT funds - Non-regulatory agreement	0	0	0
Regulatory offset to NDT fund-related activities	0	0	0
Total decommissioning-related activities	0	0	0
AFUDC—Equity	29	17	19
Non-service net periodic benefit cost	0	0	0
Unrealized Gain (Loss) on Investments	0
PECO Energy Co [Member]
Decommissioning-Related Activities [Abstract]
Net realized income on NDT funds - Regulatory agreement units	0	0	0
Net realized income on NDT funds - Non-regulatory agreement units	0	0	0
Net unrealized gains (losses) on NDT funds - Regulatory agreement units	0	0	0
Net unrealized gains (losses) on NDT funds - Non-regulatory agreement	0	0	0
Regulatory offset to NDT fund-related activities	0	0	0
Total decommissioning-related activities	0	0	0
AFUDC—Equity	17	13	7
Non-service net periodic benefit cost	0	0	0
Unrealized Gain (Loss) on Investments	0
Baltimore Gas and Electric Company [Member]
Decommissioning-Related Activities [Abstract]
Net realized income on NDT funds - Regulatory agreement units	0	0	0
Net realized income on NDT funds - Non-regulatory agreement units	0	0	0
Net unrealized gains (losses) on NDT funds - Regulatory agreement units	0	0	0
Net unrealized gains (losses) on NDT funds - Non-regulatory agreement	0	0	0
Regulatory offset to NDT fund-related activities	0	0	0
Total decommissioning-related activities	0	0	0
AFUDC—Equity	22	21	18
Non-service net periodic benefit cost	0	0	0
Unrealized Gain (Loss) on Investments	0
Pepco Holdings LLC [Member]
Decommissioning-Related Activities [Abstract]
Net realized income on NDT funds - Regulatory agreement units	0	0	0
Net realized income on NDT funds - Non-regulatory agreement units	0	0	0
Net unrealized gains (losses) on NDT funds - Regulatory agreement units	0	0	0
Net unrealized gains (losses) on NDT funds - Non-regulatory agreement	0	0	0
Regulatory offset to NDT fund-related activities	0	0	0
Total decommissioning-related activities	0	0	0
AFUDC—Equity	36	34	25
Non-service net periodic benefit cost	0	0	0
Unrealized Gain (Loss) on Investments	0
Potomac Electric Power Company [Member]
Decommissioning-Related Activities [Abstract]
Net realized income on NDT funds - Regulatory agreement units	0	0	0
Net realized income on NDT funds - Non-regulatory agreement units	0	0	0
Net unrealized gains (losses) on NDT funds - Regulatory agreement units	0	0	0
Net unrealized gains (losses) on NDT funds - Non-regulatory agreement	0	0	0
Regulatory offset to NDT fund-related activities	0	0	0
Total decommissioning-related activities	0	0	0
AFUDC—Equity	28	25	22
Non-service net periodic benefit cost	0	0	0
Unrealized Gain (Loss) on Investments	0
Delmarva Power & Light Company [Member]
Decommissioning-Related Activities [Abstract]
Net realized income on NDT funds - Regulatory agreement units	0	0	0
Net realized income on NDT funds - Non-regulatory agreement units	0	0	0
Net unrealized gains (losses) on NDT funds - Regulatory agreement units	0	0	0
Net unrealized gains (losses) on NDT funds - Non-regulatory agreement	0	0	0
Regulatory offset to NDT fund-related activities	0	0	0
Total decommissioning-related activities	0	0	0
AFUDC—Equity	4	4	2
Non-service net periodic benefit cost	0	0	0
Unrealized Gain (Loss) on Investments	0
Atlantic City Electric Company [Member]
Decommissioning-Related Activities [Abstract]
Net realized income on NDT funds - Regulatory agreement units	0	0	0
Net realized income on NDT funds - Non-regulatory agreement units	0	0	0
Net unrealized gains (losses) on NDT funds - Regulatory agreement units	0	0	0
Net unrealized gains (losses) on NDT funds - Non-regulatory agreement	0	0	0
Regulatory offset to NDT fund-related activities	0	0	0
Total decommissioning-related activities	0	0	0
AFUDC—Equity	4	5	1
Non-service net periodic benefit cost	0	$ 0	$ 0
Unrealized Gain (Loss) on Investments	$ 0

Supplemental Financial Information - Supplemental Cash Flow Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Depreciation, amortization and accretion
Depreciation	$ 4,364	$ 3,665	$ 3,740
Amortization of Regulatory Asset	588	528	555
Amortization of Intangible Assets	(17)	(28)	(109)
Amortization of Nuclear Fuel Lease	983	1,016	1,115
Accretion expense	500	491	489
Total depreciation, amortization and accretion	6,527	5,780	5,971
Cash paid (refunded) during the year:
Interest (net of amount capitalized)	1,521	1,470	1,421
Income taxes (net of refunds)	10	265	95
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	411	438	583
Provision for uncollectible accounts	150	120	159
Other decommissioning related-activity	(659)	(506)	(2)
Energy-related options	104	22	10
True-up Adjustments to Decoupling Mechanisms and Formula Rate	(6)	124	49
Restructuring Costs	105
Inventory Write-down	131
Asset Retirement Obligation, Revision of Estimate			20
Long-term incentive plan	56	10	140
Operating Leases, Income Statement, Depreciation Expense on Property Subject to or Held-for-lease	222	244
Change in environmental liabilities		23
Asset impairments	591	201	50
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	(104)	(85)	(69)
Other Non- Cash
Other non-cash operating activities:
Asset impairments	0
Return on borrowed funds
Other non-cash operating activities:
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	(104)	(85)	(69)
Exelon Generation Co L L C [Member]
Depreciation, amortization and accretion
Depreciation	2,070	1,485	1,748
Amortization of Regulatory Asset	0	0	0
Amortization of Intangible Assets	81	74	63
Amortization of Nuclear Fuel Lease	983	1,016	1,115
Accretion expense	500	491	489
Total depreciation, amortization and accretion	3,636	3,063	3,415
Cash paid (refunded) during the year:
Interest (net of amount capitalized)	331	373	369
Income taxes (net of refunds)	70	(44)	746
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	115	135	204
Provision for uncollectible accounts	17	31	48
Other decommissioning related-activity	(659)	(506)	(2)
Energy-related options	104	22	10
True-up Adjustments to Decoupling Mechanisms and Formula Rate	0	0	0
Restructuring Costs	90
Inventory Write-down	128
Asset Retirement Obligation, Revision of Estimate			0
Long-term incentive plan	0	0	0
Operating Leases, Income Statement, Depreciation Expense on Property Subject to or Held-for-lease	155	172
Change in environmental liabilities		0
Asset impairments	563	201	50
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	0	0	0
Exelon Generation Co L L C [Member] \| Other Non- Cash
Other non-cash operating activities:
Asset impairments	0
Exelon Generation Co L L C [Member] \| Return on borrowed funds
Other non-cash operating activities:
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	0	0	0
Commonwealth Edison Co [Member]
Depreciation, amortization and accretion
Depreciation	922	886	820
Amortization of Regulatory Asset	211	147	120
Amortization of Intangible Assets	7	7	7
Amortization of Nuclear Fuel Lease	0	0	0
Accretion expense	0	0	0
Total depreciation, amortization and accretion	1,133	1,033	940
Cash paid (refunded) during the year:
Interest (net of amount capitalized)	371	343	332
Income taxes (net of refunds)	(61)	(42)	(153)
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	114	96	177
Provision for uncollectible accounts	32	33	40
Other decommissioning related-activity	0	0	0
Energy-related options	0	0	0
True-up Adjustments to Decoupling Mechanisms and Formula Rate	47	128	28
Restructuring Costs	1
Inventory Write-down	2
Asset Retirement Obligation, Revision of Estimate			0
Long-term incentive plan	0	0	0
Operating Leases, Income Statement, Depreciation Expense on Property Subject to or Held-for-lease	2	3
Change in environmental liabilities		0
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	(29)	(17)	(19)
Commonwealth Edison Co [Member] \| Other Non- Cash
Other non-cash operating activities:
Asset impairments	15
Commonwealth Edison Co [Member] \| Return on borrowed funds
Other non-cash operating activities:
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	(29)	(17)	(19)
PECO Energy Co [Member]
Depreciation, amortization and accretion
Depreciation	319	303	274
Amortization of Regulatory Asset	28	30	27
Amortization of Nuclear Fuel Lease	0	0	0
Accretion expense	0	0	0
Total depreciation, amortization and accretion	347	333	301
Cash paid (refunded) during the year:
Interest (net of amount capitalized)	144	129	125
Income taxes (net of refunds)	(37)	82	(2)
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	5	12	18
Provision for uncollectible accounts	42	31	33
Other decommissioning related-activity	0	0	0
Energy-related options	0	0	0
True-up Adjustments to Decoupling Mechanisms and Formula Rate	(16)	0	0
Restructuring Costs	1
Inventory Write-down	1
Asset Retirement Obligation, Revision of Estimate			0
Long-term incentive plan	0	0	0
Operating Leases, Income Statement, Depreciation Expense on Property Subject to or Held-for-lease	1	0
Change in environmental liabilities		0
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	(17)	(13)	(7)
PECO Energy Co [Member] \| Other Non- Cash
Other non-cash operating activities:
Asset impairments	0
PECO Energy Co [Member] \| Return on borrowed funds
Other non-cash operating activities:
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	(17)	(13)	(7)
Baltimore Gas and Electric Company [Member]
Depreciation, amortization and accretion
Depreciation	397	359	335
Amortization of Regulatory Asset	153	143	148
Amortization of Nuclear Fuel Lease	0	0	0
Accretion expense	0	0	0
Total depreciation, amortization and accretion	550	502	483
Cash paid (refunded) during the year:
Interest (net of amount capitalized)	125	106	94
Income taxes (net of refunds)	(57)	17	14
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	62	61	59
Provision for uncollectible accounts	15	8	10
Other decommissioning related-activity	0	0	0
Energy-related options	0	0	0
True-up Adjustments to Decoupling Mechanisms and Formula Rate	(16)	0	0
Restructuring Costs	0
Inventory Write-down	0
Asset Retirement Obligation, Revision of Estimate			0
Long-term incentive plan	0	0	0
Operating Leases, Income Statement, Depreciation Expense on Property Subject to or Held-for-lease	31	30
Change in environmental liabilities		0
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	(22)	(21)	(18)
Baltimore Gas and Electric Company [Member] \| Other Non- Cash
Other non-cash operating activities:
Asset impairments	0
Baltimore Gas and Electric Company [Member] \| Return on borrowed funds
Other non-cash operating activities:
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	(22)	(21)	(18)
Pepco Holdings LLC [Member]
Depreciation, amortization and accretion
Depreciation	586	547	480
Amortization of Regulatory Asset	196	207	260
Amortization of Intangible Assets	(115)	(119)	(188)
Amortization of Nuclear Fuel Lease	0	0	0
Accretion expense	0	0	0
Total depreciation, amortization and accretion	782	754	740
Cash paid (refunded) during the year:
Interest (net of amount capitalized)	257	255	250
Income taxes (net of refunds)	46	29	(32)
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	70	95	67
Provision for uncollectible accounts	43	17	28
Other decommissioning related-activity	0	0	0
Energy-related options	0	0	0
True-up Adjustments to Decoupling Mechanisms and Formula Rate	(21)	(4)	21
Restructuring Costs	0
Inventory Write-down	0
Asset Retirement Obligation, Revision of Estimate			20
Long-term incentive plan	0	0	0
Operating Leases, Income Statement, Depreciation Expense on Property Subject to or Held-for-lease	28	33
Change in environmental liabilities		23
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	(36)	(34)	(25)
Pepco Holdings LLC [Member] \| Other Non- Cash
Other non-cash operating activities:
Asset impairments	13
Pepco Holdings LLC [Member] \| Return on borrowed funds
Other non-cash operating activities:
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	(36)	(34)	(25)
Potomac Electric Power Company [Member]
Depreciation, amortization and accretion
Depreciation	257	239	218
Amortization of Regulatory Asset	120	135	167
Amortization of Nuclear Fuel Lease	0	0	0
Accretion expense	0	0	0
Total depreciation, amortization and accretion	377	374	385
Cash paid (refunded) during the year:
Interest (net of amount capitalized)	129	130	123
Income taxes (net of refunds)	40	7	41
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	15	25	15
Provision for uncollectible accounts	24	7	11
Other decommissioning related-activity	0	0	0
Energy-related options	0	0	0
True-up Adjustments to Decoupling Mechanisms and Formula Rate	(40)	(4)	21
Restructuring Costs	0
Inventory Write-down	0
Asset Retirement Obligation, Revision of Estimate			22
Long-term incentive plan	0	0	0
Operating Leases, Income Statement, Depreciation Expense on Property Subject to or Held-for-lease	7	8
Change in environmental liabilities		23
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	(28)	(25)	(22)
Potomac Electric Power Company [Member] \| Other Non- Cash
Other non-cash operating activities:
Asset impairments	0
Potomac Electric Power Company [Member] \| Return on borrowed funds
Other non-cash operating activities:
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	(28)	(25)	(22)
Delmarva Power & Light Company [Member]
Depreciation, amortization and accretion
Depreciation	155	146	131
Amortization of Regulatory Asset	36	38	51
Amortization of Nuclear Fuel Lease	0	0	0
Accretion expense	0	0	0
Total depreciation, amortization and accretion	191	184	182
Cash paid (refunded) during the year:
Interest (net of amount capitalized)	61	59	56
Income taxes (net of refunds)	12	19	(6)
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	7	15	6
Provision for uncollectible accounts	16	4	6
Other decommissioning related-activity	0	0	0
Energy-related options	0	0	0
True-up Adjustments to Decoupling Mechanisms and Formula Rate	7	0	0
Restructuring Costs	0
Inventory Write-down	0
Asset Retirement Obligation, Revision of Estimate			(1)
Long-term incentive plan	0	0	0
Operating Leases, Income Statement, Depreciation Expense on Property Subject to or Held-for-lease	8	8
Change in environmental liabilities		0
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	(4)	(4)	(2)
Delmarva Power & Light Company [Member] \| Other Non- Cash
Other non-cash operating activities:
Asset impairments	7
Delmarva Power & Light Company [Member] \| Return on borrowed funds
Other non-cash operating activities:
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	(4)	(4)	(2)
Atlantic City Electric Company [Member]
Depreciation, amortization and accretion
Depreciation	140	123	94
Amortization of Regulatory Asset	40	34	42
Amortization of Nuclear Fuel Lease	0	0	0
Accretion expense	0	0	0
Total depreciation, amortization and accretion	180	157	136
Cash paid (refunded) during the year:
Interest (net of amount capitalized)	57	55	61
Income taxes (net of refunds)	(3)	(5)	(12)
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	14	16	12
Provision for uncollectible accounts	2	5	11
Other decommissioning related-activity	0	0	0
Energy-related options	0	0	0
True-up Adjustments to Decoupling Mechanisms and Formula Rate	12	0	0
Restructuring Costs	0
Inventory Write-down	0
Asset Retirement Obligation, Revision of Estimate			(1)
Long-term incentive plan	0	0	0
Operating Leases, Income Statement, Depreciation Expense on Property Subject to or Held-for-lease	3	4
Change in environmental liabilities		0
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	(4)	(5)	(1)
Atlantic City Electric Company [Member] \| Other Non- Cash
Other non-cash operating activities:
Asset impairments	6
Atlantic City Electric Company [Member] \| Return on borrowed funds
Other non-cash operating activities:
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	(4)	(5)	(1)
Other Intangible Assets [Member]
Depreciation, amortization and accretion
Amortization of Intangible Assets	62	59	58
Other Intangible Assets [Member] \| Exelon Generation Co L L C [Member]
Depreciation, amortization and accretion
Amortization of Intangible Assets	53	50	49
Other Intangible Assets [Member] \| Commonwealth Edison Co [Member]
Depreciation, amortization and accretion
Amortization of Intangible Assets	0	0	0
Other Intangible Assets [Member] \| PECO Energy Co [Member]
Depreciation, amortization and accretion
Amortization of Intangible Assets	0	0	0
Other Intangible Assets [Member] \| Baltimore Gas and Electric Company [Member]
Depreciation, amortization and accretion
Amortization of Intangible Assets	0	0	0
Other Intangible Assets [Member] \| Pepco Holdings LLC [Member]
Depreciation, amortization and accretion
Amortization of Intangible Assets	0	0	0
Other Intangible Assets [Member] \| Potomac Electric Power Company [Member]
Depreciation, amortization and accretion
Amortization of Intangible Assets	0	0	0
Other Intangible Assets [Member] \| Delmarva Power & Light Company [Member]
Depreciation, amortization and accretion
Amortization of Intangible Assets	0	0	0
Other Intangible Assets [Member] \| Atlantic City Electric Company [Member]
Depreciation, amortization and accretion
Amortization of Intangible Assets	0	0	0
Unamortized Energy Contracts [Member]
Depreciation, amortization and accretion
Amortization of Power Contracts Emission Credits	30	21	14
Unamortized Energy Contracts [Member] \| Exelon Generation Co L L C [Member]
Depreciation, amortization and accretion
Amortization of Power Contracts Emission Credits	30	21	14
Unamortized Energy Contracts [Member] \| Commonwealth Edison Co [Member]
Depreciation, amortization and accretion
Amortization of Power Contracts Emission Credits	0	0	0
Unamortized Energy Contracts [Member] \| PECO Energy Co [Member]
Depreciation, amortization and accretion
Amortization of Power Contracts Emission Credits	0	0	0
Unamortized Energy Contracts [Member] \| Baltimore Gas and Electric Company [Member]
Depreciation, amortization and accretion
Amortization of Power Contracts Emission Credits	0	0	0
Unamortized Energy Contracts [Member] \| Pepco Holdings LLC [Member]
Depreciation, amortization and accretion
Amortization of Power Contracts Emission Credits	0	0	0
Unamortized Energy Contracts [Member] \| Potomac Electric Power Company [Member]
Depreciation, amortization and accretion
Amortization of Power Contracts Emission Credits	0	0	0
Unamortized Energy Contracts [Member] \| Delmarva Power & Light Company [Member]
Depreciation, amortization and accretion
Amortization of Power Contracts Emission Credits	0	0	0
Unamortized Energy Contracts [Member] \| Atlantic City Electric Company [Member]
Depreciation, amortization and accretion
Amortization of Power Contracts Emission Credits	$ 0	$ 0	$ 0

Supplemental Financial Information - Supplemental Balance Sheet Information (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]
Cash and cash equivalents	$ 663	$ 587	$ 1,349	$ 898
Restricted cash	438	358	247	207
Restricted cash included in other long-term assets	53	177	185	85
Total cash, cash equivalents and restricted cash	1,166	1,122	1,781	1,190
Contracts Receivable [Abstract]
Unbilled customer revenues	998	1,535
Investments [Abstract]
Equity investments without readily determinable fair values	73	69
Total Investments	440	464
Accrued Expenses [Abstract]
Compensation-related accruals	1,069	1,052
Taxes accrued	527	414
Interest accrued	331	337
Held for Sale
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]
Total cash, cash equivalents and restricted cash	12
Other Equity Method Investments
Investments [Abstract]
Equity Method Investments	81	92
Employee benefit trusts and investments
Investments [Abstract]
Available for sale investments	283	262
Other available for sale investments
Investments [Abstract]
Available for sale investments	3	41
Exelon Generation Co L L C [Member]
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]
Cash and cash equivalents	226	303	750	416
Restricted cash	89	146	153	138
Restricted cash included in other long-term assets	0	0	0	0
Total cash, cash equivalents and restricted cash	327	449	903	554
Contracts Receivable [Abstract]
Unbilled customer revenues	258	807
Investments [Abstract]
Equity investments without readily determinable fair values	55	69
Total Investments	184	235
Accrued Expenses [Abstract]
Compensation-related accruals	426	422
Taxes accrued	229	222
Interest accrued	44	65
Exelon Generation Co L L C [Member] \| Held for Sale
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]
Total cash, cash equivalents and restricted cash	12
Exelon Generation Co L L C [Member] \| Other Equity Method Investments
Investments [Abstract]
Equity Method Investments	65	71
Exelon Generation Co L L C [Member] \| Employee benefit trusts and investments
Investments [Abstract]
Available for sale investments	61	54
Exelon Generation Co L L C [Member] \| Other available for sale investments
Investments [Abstract]
Available for sale investments	3	41
Commonwealth Edison Co [Member]
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]
Cash and cash equivalents	83	90	135	76
Restricted cash	279	150	29	5
Restricted cash included in other long-term assets	43	163	166	63
Total cash, cash equivalents and restricted cash	405	403	330	144
Contracts Receivable [Abstract]
Unbilled customer revenues	218	218
Investments [Abstract]
Equity investments without readily determinable fair values	0	0
Total Investments	6	6
Accrued Expenses [Abstract]
Compensation-related accruals	170	171
Taxes accrued	94	83
Interest accrued	109	110
Commonwealth Edison Co [Member] \| Held for Sale
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]
Total cash, cash equivalents and restricted cash	0
Commonwealth Edison Co [Member] \| Other Equity Method Investments
Investments [Abstract]
Equity Method Investments	6	6
Commonwealth Edison Co [Member] \| Employee benefit trusts and investments
Investments [Abstract]
Available for sale investments	0	0
Commonwealth Edison Co [Member] \| Other available for sale investments
Investments [Abstract]
Available for sale investments	0	0
PECO Energy Co [Member]
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]
Cash and cash equivalents	19	21	130	271
Restricted cash	7	6	5	4
Restricted cash included in other long-term assets	0	0	0	0
Total cash, cash equivalents and restricted cash	26	27	135	275
Contracts Receivable [Abstract]
Unbilled customer revenues	147	146
Investments [Abstract]
Equity investments without readily determinable fair values	0	0
Total Investments	30	27
Accrued Expenses [Abstract]
Compensation-related accruals	73	58
Taxes accrued	16	3
Interest accrued	37	37
PECO Energy Co [Member] \| Held for Sale
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]
Total cash, cash equivalents and restricted cash	0
PECO Energy Co [Member] \| Other Equity Method Investments
Investments [Abstract]
Equity Method Investments	8	8
PECO Energy Co [Member] \| Employee benefit trusts and investments
Investments [Abstract]
Available for sale investments	22	19
PECO Energy Co [Member] \| Other available for sale investments
Investments [Abstract]
Available for sale investments	0	0
Baltimore Gas and Electric Company [Member]
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]
Cash and cash equivalents	144	24	7	17
Restricted cash	1	1	6	1
Restricted cash included in other long-term assets	0	0	0	0
Total cash, cash equivalents and restricted cash	145	25	13	18
Contracts Receivable [Abstract]
Unbilled customer revenues	197	170
Investments [Abstract]
Equity investments without readily determinable fair values	0	0
Total Investments	10	7
Accrued Expenses [Abstract]
Compensation-related accruals	84	78
Taxes accrued	73	26
Interest accrued	46	46
Baltimore Gas and Electric Company [Member] \| Held for Sale
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]
Total cash, cash equivalents and restricted cash	0
Baltimore Gas and Electric Company [Member] \| Other Equity Method Investments
Investments [Abstract]
Equity Method Investments	0	0
Baltimore Gas and Electric Company [Member] \| Employee benefit trusts and investments
Investments [Abstract]
Available for sale investments	10	7
Baltimore Gas and Electric Company [Member] \| Other available for sale investments
Investments [Abstract]
Available for sale investments	0	0
Pepco Holdings LLC [Member]
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]
Cash and cash equivalents	111	131	124	30
Restricted cash	39	36	43	42
Restricted cash included in other long-term assets	10	14	19	23
Total cash, cash equivalents and restricted cash	160	181	186	95
Contracts Receivable [Abstract]
Unbilled customer revenues	178	194
Investments [Abstract]
Equity investments without readily determinable fair values	0	0
Total Investments	140	135
Accrued Expenses [Abstract]
Compensation-related accruals	109	101
Taxes accrued	117	117
Interest accrued	51	49
Pepco Holdings LLC [Member] \| Held for Sale
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]
Total cash, cash equivalents and restricted cash	0
Pepco Holdings LLC [Member] \| Other Equity Method Investments
Investments [Abstract]
Equity Method Investments	0	0
Pepco Holdings LLC [Member] \| Employee benefit trusts and investments
Investments [Abstract]
Available for sale investments	140	135
Pepco Holdings LLC [Member] \| Other available for sale investments
Investments [Abstract]
Available for sale investments	0	0
Potomac Electric Power Company [Member]
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]
Cash and cash equivalents	30	30	16	5
Restricted cash	35	33	37	35
Restricted cash included in other long-term assets	0	0	0	0
Total cash, cash equivalents and restricted cash	65	63	53	40
Contracts Receivable [Abstract]
Unbilled customer revenues	87	100
Investments [Abstract]
Equity investments without readily determinable fair values	0	0
Total Investments	115	110
Accrued Expenses [Abstract]
Compensation-related accruals	36	28
Taxes accrued	90	90
Interest accrued	26	23
Potomac Electric Power Company [Member] \| Held for Sale
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]
Total cash, cash equivalents and restricted cash	0
Potomac Electric Power Company [Member] \| Other Equity Method Investments
Investments [Abstract]
Equity Method Investments	0	0
Potomac Electric Power Company [Member] \| Employee benefit trusts and investments
Investments [Abstract]
Available for sale investments	115	110
Potomac Electric Power Company [Member] \| Other available for sale investments
Investments [Abstract]
Available for sale investments	0	0
Delmarva Power & Light Company [Member]
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]
Cash and cash equivalents	15	13	23	2
Restricted cash	0	0	1	0
Restricted cash included in other long-term assets	0	0	0	0
Total cash, cash equivalents and restricted cash	15	13	24	2
Contracts Receivable [Abstract]
Unbilled customer revenues	62	61
Investments [Abstract]
Equity investments without readily determinable fair values	0	0
Total Investments	0	0
Accrued Expenses [Abstract]
Compensation-related accruals	18	19
Taxes accrued	18	14
Interest accrued	7	8
Delmarva Power & Light Company [Member] \| Held for Sale
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]
Total cash, cash equivalents and restricted cash	0
Delmarva Power & Light Company [Member] \| Other Equity Method Investments
Investments [Abstract]
Equity Method Investments	0	0
Delmarva Power & Light Company [Member] \| Employee benefit trusts and investments
Investments [Abstract]
Available for sale investments	0	0
Delmarva Power & Light Company [Member] \| Other available for sale investments
Investments [Abstract]
Available for sale investments	0	0
Atlantic City Electric Company [Member]
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]
Cash and cash equivalents	17	12	7	2
Restricted cash	3	2	4	6
Restricted cash included in other long-term assets	10	14	19	23
Total cash, cash equivalents and restricted cash	30	28	$ 30	$ 31
Contracts Receivable [Abstract]
Unbilled customer revenues	29	33
Investments [Abstract]
Equity investments without readily determinable fair values	0	0
Total Investments	0	0
Accrued Expenses [Abstract]
Compensation-related accruals	17	15
Taxes accrued	12	8
Interest accrued	12	12
Atlantic City Electric Company [Member] \| Held for Sale
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]
Total cash, cash equivalents and restricted cash	0
Atlantic City Electric Company [Member] \| Other Equity Method Investments
Investments [Abstract]
Equity Method Investments	0	0
Atlantic City Electric Company [Member] \| Employee benefit trusts and investments
Investments [Abstract]
Available for sale investments	0	0
Atlantic City Electric Company [Member] \| Other available for sale investments
Investments [Abstract]
Available for sale investments	$ 0	$ 0

Related Party Transactions - Operating Revenues and Purchased Power and Fuel From Affiliates (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Exelon Generation Co L L C [Member]
Related Party Transaction [Line Items]
Revenue from Related Parties	$ 1,211	$ 1,172	$ 1,268
Related Party Transaction, Purchases from Related Party	7	(7)	(14)
Exelon Generation Co L L C [Member] \| Commonwealth Edison Co Affiliate [Member]
Related Party Transaction [Line Items]
Revenue from Related Parties	330	369	523
Related Party Transaction, Purchases from Related Party	(15)	(7)
Exelon Generation Co L L C [Member] \| PECO Energy Co Affiliate [Member]
Related Party Transaction [Line Items]
Revenue from Related Parties	190	158	128
Exelon Generation Co L L C [Member] \| Baltimore Gas And Electric Company Affiliate [Member]
Related Party Transaction [Line Items]
Revenue from Related Parties	315	289	260
Exelon Generation Co L L C [Member] \| Pepco Holdings LLC Affiliate [Member]
Related Party Transaction [Line Items]
Revenue from Related Parties	367	353	355
Exelon Generation Co L L C [Member] \| Potomac Electric Power Co Affiliate [Member]
Related Party Transaction [Line Items]
Revenue from Related Parties	279	264	206
Exelon Generation Co L L C [Member] \| Delmarva Power and Light Co Affiliate [Member]
Related Party Transaction [Line Items]
Revenue from Related Parties	75	70	120
Exelon Generation Co L L C [Member] \| Atlantic City Electric Co Affiliate [Member]
Related Party Transaction [Line Items]
Revenue from Related Parties	13	19	29
Exelon Generation Co L L C [Member] \| Exelon Business Services Co Affiliate [Member]
Related Party Transaction [Line Items]
Revenue from Related Parties	9	3	2
Commonwealth Edison Co [Member]
Related Party Transaction [Line Items]
Revenue from Related Parties	37	30	27
Related Party Transaction, Purchases from Related Party	(345)	(376)	$ (529)
Commonwealth Edison Co [Member] \| Exelon Generation Co LLC Affiliate [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Purchases from Related Party	$ (345)	$ (376)

Related Party Transactions - Noncurrent Receivables from/Payables to affiliates (Details) - Exelon Generation Co L L C [Member] - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Related Party Transaction [Line Items]
Accounts Payable, Related Parties, Noncurrent	$ 3,017	$ 3,103
Commonwealth Edison Co Affiliate [Member]
Related Party Transaction [Line Items]
Accounts Payable, Related Parties, Noncurrent	2,541	2,622
PECO Energy Co Affiliate [Member]
Related Party Transaction [Line Items]
Accounts Payable, Related Parties, Noncurrent	$ 475	$ 480

Related Party Transactions - Long Term Debt to Financing Trusts (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Related Party Transaction [Line Items]
Long-term debt to financing trusts	$ 390	$ 390
ComEd Financing III Affiliate [Member]
Related Party Transaction [Line Items]
Long-term debt to financing trusts	206	206
PECO Trust III Affiliate [Member]
Related Party Transaction [Line Items]
Long-term debt to financing trusts	81	81
PECO Trust IV Affiliate [Member]
Related Party Transaction [Line Items]
Long-term debt to financing trusts	103	103
Commonwealth Edison Co [Member]
Related Party Transaction [Line Items]
Long-term debt to financing trusts	205	205
Commonwealth Edison Co [Member] \| ComEd Financing III Affiliate [Member]
Related Party Transaction [Line Items]
Long-term debt to financing trusts	205	205
Commonwealth Edison Co [Member] \| PECO Trust III Affiliate [Member]
Related Party Transaction [Line Items]
Long-term debt to financing trusts	0	0
Commonwealth Edison Co [Member] \| PECO Trust IV Affiliate [Member]
Related Party Transaction [Line Items]
Long-term debt to financing trusts	0	0
PECO Energy Co [Member]
Related Party Transaction [Line Items]
Long-term debt to financing trusts	184	184
PECO Energy Co [Member] \| ComEd Financing III Affiliate [Member]
Related Party Transaction [Line Items]
Long-term debt to financing trusts	0	0
PECO Energy Co [Member] \| PECO Trust III Affiliate [Member]
Related Party Transaction [Line Items]
Long-term debt to financing trusts	81	81
PECO Energy Co [Member] \| PECO Trust IV Affiliate [Member]
Related Party Transaction [Line Items]
Long-term debt to financing trusts	$ 103	$ 103

Subsequent Events - Narrative (Details) - USD ($)		3 Months Ended
Subsequent Events - Narrative (Details) - USD ($)	Feb. 15, 2021	Mar. 31, 2021	Feb. 22, 2021	Dec. 31, 2020
Subsequent Event [Line Items]
Debt Instrument, Collateral Amount				$ 2,200,000,000
Line of credit facility, remaining borrowing capacity				9,414,000,000
Subsequent Event [Member] \| Texas-based generating assets
Subsequent Event [Line Items]
Debt Instrument, Collateral Amount			$ 1,400,000,000
Line of credit facility, remaining borrowing capacity			2,400,000,000
Subsequent Event [Member] \| Maximum [Member] \| Texas-based generating assets
Subsequent Event [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount	$ 9,000
Other Cost and Expense, Operating		$ 560,000,000
Subsequent Event [Member] \| Minimum [Member] \| Texas-based generating assets
Subsequent Event [Line Items]
Other Cost and Expense, Operating		710,000,000
Exelon Generation Co L L C [Member]
Subsequent Event [Line Items]
Debt Instrument, Collateral Amount				$ 2,200,000,000
Exelon Generation Co L L C [Member] \| Subsequent Event [Member] \| Texas-based generating assets
Subsequent Event [Line Items]
Debt Instrument, Collateral Amount			1,400,000,000
Line of credit facility, remaining borrowing capacity			$ 2,400,000,000
Exelon Generation Co L L C [Member] \| Subsequent Event [Member] \| Maximum [Member] \| Texas-based generating assets
Subsequent Event [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount	$ 9,000
Other Cost and Expense, Operating		560,000,000
Exelon Generation Co L L C [Member] \| Subsequent Event [Member] \| Minimum [Member] \| Texas-based generating assets
Subsequent Event [Line Items]
Other Cost and Expense, Operating		$ 710,000,000

Schedule I - Condensed Financial Information of Parent (Exelon Corporate) - Condensed Statements of Operations and Other Comprehensive Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Operating Expenses [Abstract]
Total operating expenses	$ 30,240	$ 30,096	$ 32,143
Operating income (loss)	2,823	4,374	3,891
Other income and (deductions)
Interest expense, net	(1,610)	(1,591)	(1,529)
Other, net	1,145	1,227	(112)
Total other income and (deductions)	(490)	(389)	(1,666)
Income taxes	373	774	118
Net income (loss)	1,954	3,028	2,079
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic cost	(40)	(65)	(66)
Actuarial loss reclassified to periodic cost	190	149	247
Unrealized gain on cash flow hedges	(3)	0	12
Unrealized (loss) gain on foreign currency translation	4	6	(10)
Other comprehensive income (loss)	(206)	(198)	42
Comprehensive Income	1,757	2,737	2,046
Exelon Corporate [Member]
Operating Expenses [Abstract]
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 income (loss)	(10)	(43)	(8)
Other income and (deductions)
Interest expense, net	(378)	(321)	(312)
Equity in earnings (losses) of unconsolidated affiliates	2,313	3,254	2,183
Interest income from affiliates, net	30	39	42
Other, net	15	14	3
Total other income and (deductions)	1,980	2,986	1,916
Income before income taxes	1,970	2,943	1,908
Income taxes	7	7	(97)
Net income (loss)	1,963	2,936	2,005
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic cost	(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 gain on cash flow hedges	(1)	1	12
Unrealized gain (loss) on equity investments	0	0	1
Unrealized (loss) gain on foreign currency translation	0	0	(10)
Other comprehensive income (loss)	(208)	(204)	41
Comprehensive Income	$ 1,755	$ 2,732	$ 2,046

Schedule I - Condensed Financial Information of Parent (Exelon Corporate) - Condensed Statements of Cash Flows (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Net cash flows provided by operating activities	$ 4,235	$ 6,659	$ 8,644
Cash flows from investing activities
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
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)
(Decrease) Increase in cash, cash equivalents and restricted cash	44	(659)	591
Cash, cash equivalents and restricted cash at beginning of period	587	1,349	898
Cash, cash equivalents and restricted cash at end of period	663	587	1,349
Exelon Corporate [Member]
Net cash flows provided by operating activities	3,018	1,948	2,576
Cash flows from investing activities
Changes in Exelon/PHI intercompany money pool	(477)	95	1
Notes receivable from affiliates	550	0	0
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	0
Issuance of long-term debt	2,000	0	0
Retirement of long-term debt	(1,450)	0	0
Dividends paid on common stock	(1,492)	(1,408)	(1,332)
Proceeds from employee stock plans	45	112	105
Other financing activities	(27)	0	(4)
Net cash flows provided by (used in) financing activities	(1,060)	(1,160)	(1,231)
(Decrease) Increase in cash, cash equivalents and restricted cash	62	(188)	115
Cash, cash equivalents and restricted cash at beginning of period	1	189	74
Cash, cash equivalents and restricted cash at end of period	$ 63	$ 1	$ 189

Schedule I - Condensed Financial Information of Parent (Exelon Corporate) - Condensed Balance Sheet (Details) - USD ($)
shares in Millions, $ in Millions

Dec. 31, 2020

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

$ 663

$ 587

$ 1,349

$ 898

644

679

1,228

1,170

1,609

905

12,562

12,037

82,584

80,233

8,759

8,335

2,982

3,197

^[1]

129,317

124,977

2,031

1,370

1,819

4,710

3,562

3,560

2,078

1,981

581

406

1,264

1,331

12,771

14,185

35,093

31,329

9,485

9,986

4,503

4,247

2,011

2,076

2,942

3,064

46,195

44,500

^[1]

94,449

90,404

19,373

19,274

Treasury stock, at cost

(123)

Retained earnings

16,735

16,267

(3,400)

(3,194)

32,585

32,224

$ 129,317

$ 124,977

2,000

Exelon Corporate [Member]

976

973

Treasury Stock, Shares

$ 63

$ 1

$ 189

$ 74

Accounts receivable from affiliates, current

354

168

Note receivable from affiliates, current

598

679

315

253

1,345

1,149

Investments in affiliates

3,816

3,772

43,149

42,245

Notes receivable from affiliates, noncurrent

1,625

1,524

324

329

312

308

49,226

48,178

50,617

49,374

500

636

300

1,458

131

457

363

1,434

2,689

7,418

5,717

8,351

7,960

387

403

348

263

9,180

8,744

18,032

17,150

19,373

19,274

Treasury stock, at cost

(123)

Retained earnings

16,735

16,267

(3,400)

(3,194)

32,585

32,224

$ 50,617

$ 49,374

2,000