0001109357-21-000110 | 10-Q | XBRL Viewer

$ (47)

$ (11)

$ 129

$ (66)

8,910

8,853

26,715

24,925

1,992

2,732

6,416

7,370

1,624

1,289

4,988

3,312

468

452

1,337

1,299

7,117

8,087

24,758

22,387

147

1,858

769

2,104

2,554

(391)

(398)

(1,161)

(1,222)

(6)

(19)

(55)

421

751

352

(452)

(429)

(889)

1,406

786

1,675

1,665

Equity in losses of unconsolidated affiliates

174

216

229

141

(3)

(1)

(5)

Net income (loss) attributable to noncontrolling interests

1,229

569

1,441

1,519

126

(85)

Net Income (Loss) Available to Common Stockholders, Basic

1,203

501

1,315

1,604

Other comprehensive income (loss), net of income taxes

Prior service benefit reclassified to periodic benefit cost

(1)

(10)

(4)

(30)

Actuarial loss reclassified to periodic benefit cost

167

142

Pension and non-pension postretirement benefit plan valuation adjustment

(13)

(17)

Unrealized (loss) gain on cash flow hedges

(1)

(2)

Unrealized gain (loss) on foreign currency translation

(3)

Other comprehensive income

177

Comprehensive income (loss) attributable to noncontrolling interests

1,295

597

1,618

1,609

126

(85)

Comprehensive income attributable to common shareholders/membership interest

$ 1,269

$ 529

$ 1,492

$ 1,694

Average shares of common stock outstanding:

Basic average shares of common stock outstanding

979

976

978

976

Assumed exercise and/or distributions of stock-based awards

Diluted average shares of common stock outstanding

^[1]

980

977

979

976

Earnings per average common share

Basic earnings per average common share

$ 1.23

$ 0.51

$ 1.34

$ 1.64

Diluted earnings per average common share

$ 1.23

$ 0.51

$ 1.34

$ 1.64

Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount

$ 324

$ 331

$ 872

$ 932

4,406

4,659

14,117

13,272

Purchased power and fuel from affiliates

(6)

761

1,605

2,955

3,779

177

132

458

409

866

558

2,735

1,161

115

118

354

364

3,465

4,727

14,605

12,674

144

1,006

(68)

(344)

610

(73)

(72)

(214)

(251)

(4)

(8)

(11)

(26)

(115)

367

561

199

(192)

287

336

(78)

814

219

(8)

532

Equity in losses of unconsolidated affiliates

177

100

108

(4)

(2)

(6)

Net income (loss) attributable to noncontrolling interests

633

117

(122)

485

125

(85)

Net income attributable to membership interest

607

(247)

570

Other comprehensive income (loss), net of income taxes

Unrealized (loss) gain on cash flow hedges

(1)

Unrealized gain (loss) on foreign currency translation

(4)

(3)

Other comprehensive income

(4)

(1)

(4)

Comprehensive income (loss) attributable to noncontrolling interests

629

120

(123)

481

125

(85)

Comprehensive income attributable to common shareholders/membership interest

603

(248)

566

Commonwealth Edison Co [Member]

(32)

(38)

(51)

1,789

1,643

4,840

4,499

256

252

257

252

752

964

217

209

304

294

893

841

243

227

1,428

1,302

3,833

3,798

361

341

1,007

701

(95)

(92)

(282)

(277)

(3)

(10)

(85)

(257)

(255)

276

256

750

446

141

142

Other comprehensive income (loss), net of income taxes

220

196

609

304

220

196

609

304

PECO Energy Co [Member]

818

813

2,399

2,306

141

144

220

214

580

628

126

114

259

143

131

677

658

1,908

1,900

141

155

491

406

(37)

(36)

(110)

(100)

(3)

(9)

(8)

(33)

(99)

(96)

108

122

392

310

(3)

(16)

(7)

Other comprehensive income (loss), net of income taxes

111

138

383

317

Baltimore Gas and Electric Company [Member]

111

138

383

317

(24)

(9)

(17)

(10)

770

731

2,426

2,284

193

249

159

152

458

445

137

122

142

133

434

405

211

200

709

642

2,080

1,903

346

381

(36)

(34)

(103)

(99)

(29)

(28)

(80)

(82)

266

299

(4)

(24)

Other comprehensive income (loss), net of income taxes

290

273

290

273

(15)

1,470

1,368

3,854

3,554

100

106

277

288

235

237

668

702

122

111

210

200

614

585

127

121

349

343

1,155

1,102

3,167

3,057

315

266

687

499

(67)

(201)

(51)

(149)

(159)

264

215

538

340

Equity in losses of unconsolidated affiliates

(2)

(1)

(77)

Other comprehensive income (loss), net of income taxes

266

216

535

418

Comprehensive income attributable to common shareholders/membership interest

266

216

535

418

Potomac Electric Power Company [Member]

660

611

1,736

1,650

200

219

186

184

155

152

104

302

282

105

100

282

279

501

465

1,396

1,364

159

146

340

286

(35)

(104)

(103)

(23)

(25)

(67)

(75)

136

121

273

211

(16)

Other comprehensive income (loss), net of income taxes

130

118

264

227

Delmarva Power and Light Company [Member]

130

118

264

227

(2)

(15)

360

337

1,040

954

132

160

117

112

157

143

295

296

858

843

182

111

(15)

(47)

(12)

(13)

(38)

(40)

144

(20)

Other comprehensive income (loss), net of income taxes

135

Atlantic City Electric Company [Member]

135

(20)

451

420

1,080

952

128

140

103

133

134

359

338

911

847

169

107

(14)

(15)

(43)

(45)

(13)

(14)

(40)

129

(11)

(7)

(12)

(39)

Other comprehensive income (loss), net of income taxes

141

106

Generation commodities and services [Member]

141

106

Revenue from Contract with Customer, Including Assessed Tax

4,084

4,331

13,250

12,348

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

1,541

2,311

8,103

6,967

Revenue from Contract with Customer, Including Assessed Tax

4,082

4,328

13,245

12,340

Rate-regulated utility revenues [Member]

1,542

2,311

8,103

6,967

Revenue from Contract with Customer, Including Assessed Tax

4,873

4,533

13,336

12,643

Electricity, US Regulated [Member]

1,492

1,303

3,914

3,439

Revenue from Contract with Customer, Including Assessed Tax

4,657

4,365

12,432

11,585

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

Revenue from Contract with Customer, Including Assessed Tax

1,812

1,666

4,789

4,519

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

610

535

1,472

1,305

Revenue from Contract with Customer, Including Assessed Tax

757

751

2,008

1,931

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

206

190

540

495

Revenue from Contract with Customer, Including Assessed Tax

694

649

1,874

1,775

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

206

155

501

376

Revenue from Contract with Customer, Including Assessed Tax

1,438

1,308

3,632

3,440

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

431

393

1,087

979

Revenue from Contract with Customer, Including Assessed Tax

649

590

1,678

1,624

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

103

271

248

Revenue from Contract with Customer, Including Assessed Tax

337

303

899

846

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

103

289

270

Revenue from Contract with Customer, Including Assessed Tax

450

414

1,055

969

Natural Gas, US Regulated [Member]

225

207

527

460

Revenue from Contract with Customer, Including Assessed Tax

169

159

1,035

990

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

Revenue from Contract with Customer, Including Assessed Tax

365

358

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

119

129

Revenue from Contract with Customer, Including Assessed Tax

549

503

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

146

106

Revenue from Contract with Customer, Including Assessed Tax

118

116

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

Revenue from Contract with Customer, Including Assessed Tax

118

116

$ 9

$ 7

$ 50

$ 49

[1]	The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was zero for the three and nine months ended September 30, 2021 and approximately 1 million for the three and nine months ended September 30, 2020, respectively.

Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020
Cash flows from operating activities
Net income (loss)	$ 1,441	$ 1,519
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization	6,204	4,419
Asset impairments	541	567
Gain on sales of assets and businesses	(147)	(16)
Deferred income taxes and amortization of investment tax credits	(45)	164
Net fair value changes related to derivatives	(1,244)	(448)
Net realized and unrealized (gains) losses on NDT funds	(383)	(59)
Unrealized loss on equity investments	83	0
Other non-cash operating activities	(293)	988
Changes in assets and liabilities:
Accounts receivable	(254)	1,195
Inventories	(101)	(67)
Accounts payable and accrued expenses	354	(519)
Option premiums paid, net	(186)	(131)
Collateral received (posted), net	2,111	644
Income taxes	250	(31)
Pension and non-pension postretirement benefit contributions	(602)	(580)
Other assets and liabilities	(3,588)	(3,423)
Net cash flows provided by operating activities	4,141	4,222
Cash flows from investing activities
Capital expenditures	(5,970)	(5,606)
Proceeds from NDT fund sales	5,766	3,370
Investment in NDT funds	(5,900)	(3,438)
Collection of deferred purchase price	3,052	2,518
Proceeds from sales of assets and businesses	801	46
Other investing activities	40	(2)
Net cash flows provided by (used in) investing activities	(2,211)	(3,112)
Cash flows from financing activities
Changes in short-term borrowings	(744)	(689)
Proceeds from short-term borrowings with maturities greater than 90 days	1,380	500
Issuance of long-term debt	3,406	6,756
Retirement of long-term debt	(1,618)	(5,158)
Dividends paid on common stock	(1,121)	(1,119)
Acquisition of CENG noncontrolling interest	(885)	0
Proceeds from employee stock plans	63	62
Other financing activities	(93)	(104)
Net cash flows provided by (used in) financing activities	388	248
Increase (decrease) in cash, restricted cash, and cash equivalents	2,318	1,358
Cash, restricted cash, and cash equivalents at beginning of period	1,166	1,122
Cash, restricted cash, and cash equivalents at end of period	3,484	2,480
Supplemental Cash Flow Information
Increase (decrease) in capital expenditures not paid	(334)	(11)
Increase in deferred purchase price	2,933	3,275
Increase in PPE related to ARO update	574	775
Exelon Generation Co L L C [Member]
Cash flows from operating activities
Net income (loss)	(122)	485
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization	3,951	2,266
Asset impairments	537	552
Gain on sales of assets and businesses	(144)	(12)
Deferred income taxes and amortization of investment tax credits	(204)	(51)
Net fair value changes related to derivatives	(1,244)	(448)
Net realized and unrealized (gains) losses on NDT funds	(383)	(59)
Unrealized loss on equity investments	83	0
Other non-cash operating activities	(582)	293
Changes in assets and liabilities:
Accounts receivable	(207)	1,463
Change in Receivables From Payables To Affiliates, Net	82	75
Inventories	(29)	(65)
Accounts payable and accrued expenses	357	(619)
Option premiums paid, net	(186)	(131)
Collateral received (posted), net	1,974	640
Income taxes	177	112
Pension and non-pension postretirement benefit contributions	(237)	(249)
Other assets and liabilities	(2,849)	(2,889)
Net cash flows provided by operating activities	974	1,363
Cash flows from investing activities
Capital expenditures	(1,086)	(1,212)
Proceeds from NDT fund sales	5,766	3,370
Investment in NDT funds	(5,900)	(3,438)
Collection of deferred purchase price	3,052	2,518
Proceeds from sales of assets and businesses	802	46
Other investing activities	5	5
Net cash flows provided by (used in) investing activities	2,639	1,289
Cash flows from financing activities
Changes in short-term borrowings	(340)	(280)
Proceeds from short-term borrowings with maturities greater than 90 days	880	500
Issuance of long-term debt	152	2,405
Retirement of long-term debt	(89)	(3,613)
Changes in Exelon/PHI intercompany money pool	(285)	0
Acquisition of CENG noncontrolling interest	(885)	0
Distributions to member	(1,373)	(1,406)
Contributions from member	64	64
Other financing activities	(45)	(48)
Net cash flows provided by (used in) financing activities	(1,921)	(2,378)
Increase (decrease) in cash, restricted cash, and cash equivalents	1,692	274
Cash, restricted cash, and cash equivalents at beginning of period	327	449
Cash, restricted cash, and cash equivalents at end of period	2,019	723
Supplemental Cash Flow Information
Increase (decrease) in capital expenditures not paid	(77)	(77)
Increase in deferred purchase price	2,933	3,275
Increase in PPE related to ARO update	550	775
Commonwealth Edison Co [Member]
Cash flows from operating activities
Net income (loss)	609	304
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization	893	841
Asset impairments	0	15
Deferred income taxes and amortization of investment tax credits	211	205
Other non-cash operating activities	95	354
Changes in assets and liabilities:
Accounts receivable	(72)	(104)
Change in Receivables From Payables To Affiliates, Net	(16)	(13)
Inventories	(6)	(2)
Accounts payable and accrued expenses	(36)	21
Collateral received (posted), net	68	3
Income taxes	(9)	(22)
Pension and non-pension postretirement benefit contributions	(176)	(145)
Other assets and liabilities	(376)	(380)
Net cash flows provided by operating activities	1,185	1,077
Cash flows from investing activities
Capital expenditures	(1,723)	(1,583)
Other investing activities	20	0
Net cash flows provided by (used in) investing activities	(1,703)	(1,583)
Cash flows from financing activities
Changes in short-term borrowings	(323)	11
Issuance of long-term debt	1,150	1,000
Retirement of long-term debt	(350)	(500)
Dividends paid on common stock	(380)	(374)
Contributions from parent	593	488
Other financing activities	(16)	(14)
Net cash flows provided by (used in) financing activities	674	611
Increase (decrease) in cash, restricted cash, and cash equivalents	156	105
Cash, restricted cash, and cash equivalents at beginning of period	405	403
Cash, restricted cash, and cash equivalents at end of period	561	508
Supplemental Cash Flow Information
Increase (decrease) in capital expenditures not paid	(118)	49
PECO Energy Co [Member]
Cash flows from operating activities
Net income (loss)	383	317
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization	259	259
Deferred income taxes and amortization of investment tax credits	19	(5)
Other non-cash operating activities	4	27
Changes in assets and liabilities:
Accounts receivable	47	(2)
Change in Receivables From Payables To Affiliates, Net	16	(7)
Inventories	(21)	(3)
Accounts payable and accrued expenses	(23)	32
Income taxes	55	48
Pension and non-pension postretirement benefit contributions	(15)	(18)
Other assets and liabilities	(87)	(13)
Net cash flows provided by operating activities	637	635
Cash flows from investing activities
Capital expenditures	(878)	(824)
Changes in Exelon/PHI intercompany money pool	0	68
Other investing activities	5	4
Net cash flows provided by (used in) investing activities	(873)	(752)
Cash flows from financing activities
Issuance of long-term debt	750	350
Retirement of long-term debt	(300)	0
Changes in Exelon/PHI intercompany money pool	(40)	0
Dividends paid on common stock	(254)	(255)
Contributions from parent	414	248
Other financing activities	(8)	(4)
Net cash flows provided by (used in) financing activities	562	339
Increase (decrease) in cash, restricted cash, and cash equivalents	326	222
Cash, restricted cash, and cash equivalents at beginning of period	26	27
Cash, restricted cash, and cash equivalents at end of period	352	249
Supplemental Cash Flow Information
Increase (decrease) in capital expenditures not paid	25	28
Baltimore Gas and Electric Company [Member]
Cash flows from operating activities
Net income (loss)	290	273
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization	434	405
Deferred income taxes and amortization of investment tax credits	7	35
Other non-cash operating activities	77	82
Changes in assets and liabilities:
Accounts receivable	92	(19)
Change in Receivables From Payables To Affiliates, Net	(13)	(27)
Inventories	(30)	2
Accounts payable and accrued expenses	14	53
Income taxes	3	46
Pension and non-pension postretirement benefit contributions	(76)	(74)
Other assets and liabilities	(129)	(50)
Net cash flows provided by operating activities	669	726
Cash flows from investing activities
Capital expenditures	(907)	(838)
Other investing activities	13	0
Net cash flows provided by (used in) investing activities	(894)	(838)
Cash flows from financing activities
Changes in short-term borrowings	0	(76)
Issuance of long-term debt	600	400
Retirement of long-term debt	(300)	0
Dividends paid on common stock	(219)	(186)
Contributions from parent	257	284
Other financing activities	(6)	(8)
Net cash flows provided by (used in) financing activities	332	414
Increase (decrease) in cash, restricted cash, and cash equivalents	107	302
Cash, restricted cash, and cash equivalents at beginning of period	145	25
Cash, restricted cash, and cash equivalents at end of period	252	327
Supplemental Cash Flow Information
Increase (decrease) in capital expenditures not paid	(70)	7
Pepco Holdings LLC [Member]
Cash flows from operating activities
Net income (loss)	535	418
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization	614	585
Deferred income taxes and amortization of investment tax credits	0	(99)
Other non-cash operating activities	(35)	115
Changes in assets and liabilities:
Accounts receivable	(112)	(121)
Change in Receivables From Payables To Affiliates, Net	(19)	(26)
Inventories	(13)	(2)
Accounts payable and accrued expenses	19	57
Income taxes	17	(14)
Pension and non-pension postretirement benefit contributions	(43)	(35)
Other assets and liabilities	(120)	(61)
Net cash flows provided by operating activities	843	817
Cash flows from investing activities
Capital expenditures	(1,299)	(1,072)
Other investing activities	(1)	3
Net cash flows provided by (used in) investing activities	(1,300)	(1,069)
Cash flows from financing activities
Changes in short-term borrowings	(81)	(208)
Issuance of long-term debt	750	601
Retirement of long-term debt	(255)	(119)
Changes in Exelon/PHI intercompany money pool	(5)	9
Distributions to member	(605)	(451)
Contributions from member	667	493
Other financing activities	(12)	(10)
Net cash flows provided by (used in) financing activities	459	315
Increase (decrease) in cash, restricted cash, and cash equivalents	2	63
Cash, restricted cash, and cash equivalents at beginning of period	160	181
Cash, restricted cash, and cash equivalents at end of period	162	244
Supplemental Cash Flow Information
Increase (decrease) in capital expenditures not paid	(74)	(5)
Potomac Electric Power Company [Member]
Cash flows from operating activities
Net income (loss)	264	227
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization	302	282
Deferred income taxes and amortization of investment tax credits	12	(36)
Other non-cash operating activities	(54)	6
Changes in assets and liabilities:
Accounts receivable	(57)	(61)
Change in Receivables From Payables To Affiliates, Net	(2)	(23)
Inventories	(6)	2
Accounts payable and accrued expenses	14	36
Income taxes	(10)	(11)
Pension and non-pension postretirement benefit contributions	(9)	(8)
Other assets and liabilities	(114)	15
Net cash flows provided by operating activities	340	429
Cash flows from investing activities
Capital expenditures	(641)	(512)
Changes in Exelon/PHI intercompany money pool	0	(117)
Other investing activities	(2)	(3)
Net cash flows provided by (used in) investing activities	(643)	(632)
Cash flows from financing activities
Changes in short-term borrowings	5	(82)
Issuance of long-term debt	275	300
Retirement of long-term debt	(1)	(2)
Dividends paid on common stock	(221)	(174)
Contributions from parent	244	262
Other financing activities	(4)	(6)
Net cash flows provided by (used in) financing activities	298	298
Increase (decrease) in cash, restricted cash, and cash equivalents	(5)	95
Cash, restricted cash, and cash equivalents at beginning of period	65	63
Cash, restricted cash, and cash equivalents at end of period	60	158
Supplemental Cash Flow Information
Increase (decrease) in capital expenditures not paid	(16)	(23)
Delmarva Power and Light Company [Member]
Cash flows from operating activities
Net income (loss)	135	91
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization	157	143
Deferred income taxes and amortization of investment tax credits	5	(20)
Other non-cash operating activities	(2)	47
Changes in assets and liabilities:
Accounts receivable	26	3
Change in Receivables From Payables To Affiliates, Net	(12)	(5)
Inventories	(5)	(3)
Accounts payable and accrued expenses	17	21
Income taxes	19	(12)
Pension and non-pension postretirement benefit contributions	(1)	(1)
Other assets and liabilities	(7)	(25)
Net cash flows provided by operating activities	332	239
Cash flows from investing activities
Capital expenditures	(320)	(278)
Other investing activities	1	(3)
Net cash flows provided by (used in) investing activities	(319)	(281)
Cash flows from financing activities
Changes in short-term borrowings	(124)	(56)
Issuance of long-term debt	125	178
Retirement of long-term debt	0	(79)
Dividends paid on common stock	(106)	(99)
Contributions from parent	120	112
Other financing activities	(4)	(1)
Net cash flows provided by (used in) financing activities	11	55
Increase (decrease) in cash, restricted cash, and cash equivalents	24	13
Cash, restricted cash, and cash equivalents at beginning of period	15	13
Cash, restricted cash, and cash equivalents at end of period	39	26
Supplemental Cash Flow Information
Increase (decrease) in capital expenditures not paid	(24)	8
Atlantic City Electric Company [Member]
Cash flows from operating activities
Net income (loss)	141	106
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization	133	134
Deferred income taxes and amortization of investment tax credits	(20)	(40)
Other non-cash operating activities	(8)	34
Changes in assets and liabilities:
Accounts receivable	(81)	(62)
Change in Receivables From Payables To Affiliates, Net	0	2
Inventories	(1)	0
Accounts payable and accrued expenses	(3)	16
Income taxes	10	4
Pension and non-pension postretirement benefit contributions	(3)	(3)
Other assets and liabilities	15	(53)
Net cash flows provided by operating activities	183	138
Cash flows from investing activities
Capital expenditures	(336)	(281)
Other investing activities	1	5
Net cash flows provided by (used in) investing activities	(335)	(276)
Cash flows from financing activities
Changes in short-term borrowings	38	(70)
Issuance of long-term debt	350	123
Retirement of long-term debt	(254)	(38)
Changes in Exelon/PHI intercompany money pool	0	117
Dividends paid on common stock	(280)	(111)
Contributions from parent	303	117
Other financing activities	(5)	(1)
Net cash flows provided by (used in) financing activities	152	137
Increase (decrease) in cash, restricted cash, and cash equivalents	0	(1)
Cash, restricted cash, and cash equivalents at beginning of period	30	28
Cash, restricted cash, and cash equivalents at end of period	30	27
Supplemental Cash Flow Information
Increase (decrease) in capital expenditures not paid	$ (34)	$ 9

Consolidated Balance Sheets (Unaudited) - USD ($)
shares in Millions, $ in Millions

Sep. 30, 2021

Dec. 31, 2020

$ 2,957

$ 663

473

438

3,530

3,597

(409)

(366)

3,121

3,231

1,616

1,469

(77)

(71)

Mark-to-market derivative assets, current

1,539

1,398

1,507

644

343

297

1,475

1,425

Renewable energy credits, current

1,258

1,228

492

633

958

1,665

1,609

14,877

12,562

30,049

26,727

82,852

82,584

8,628

8,759

15,404

14,464

435

440

Mark-to-market derivative assets, noncurrent

6,677

665

555

265

294

2,818

2,982

34,892

34,171

^[1]

132,621

129,317

2,667

2,031

3,375

1,819

3,694

3,562

1,949

2,078

Mark-to-market derivative liabilities, current

460

581

1,717

295

Renewable energy credit obligation

100

684

661

375

1,180

1,264

15,826

12,771

Long-term debt to financing trusts

35,269

35,093

390

Deferred income taxes and unamortized investment tax credits

13,816

13,035

12,907

12,300

Pension obligations

3,777

4,503

Spent nuclear fuel obligation

1,980

2,011

1,209

1,208

Mark-to-market derivative liabilities, noncurrent

9,448

9,485

721

473

Unamortized energy contract liabilities, noncurrent

169

238

2,850

2,942

46,877

46,195

^[1]

98,362

94,449

Common Stock, No Par Value

$ 0

Common stock, shares authorized

2,000

Common stock, shares outstanding

978

976

$ 20,271

$ 19,373

Treasury stock, shares

Treasury stock, at cost

$ (123)

Accumulated other comprehensive loss, net

16,926

16,735

(3,223)

(3,400)

33,851

32,585

Noncontrolling interests

408

2,283

Total equity

34,259

34,868

Variable Interest Entity, Primary Beneficiary [Member]

132,621

129,317

148

244

101

517

674

669

1,370

2,052

5,803

3,007

210

249

2,953

10,481

105

270

832

889

149

2,318

129

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

1,089

3,606

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

2,722

10,200

1,088

3,598

1,957

226

1,412

1,330

(84)

(32)

1,328

1,298

465

352

(4)

Mark-to-market derivative assets, current

461

352

1,505

644

184

153

240

233

Renewable energy credits, current

998

978

486

621

958

1,319

1,357

8,587

6,947

15,966

13,370

19,574

22,214

15,404

14,464

165

184

Mark-to-market derivative assets, noncurrent

664

555

1,702

1,558

265

293

Deferred income taxes

1,589

1,826

19,849

18,933

^[2]

48,010

48,094

1,380

840

1,216

197

1,612

1,253

691

788

Borrowings from Exelon/PHI intercompany money pool

154

107

285

Mark-to-market derivative liabilities, current

1,709

262

Renewable energy credit obligation

682

661

375

347

444

7,796

5,219

Long-term debt to affiliates

4,593

5,566

321

324

Deferred income taxes and unamortized investment tax credits

3,685

3,656

12,635

12,054

Spent nuclear fuel obligation

857

858

1,209

1,208

Payables to affiliates, noncurrent

3,143

3,017

Mark-to-market derivative liabilities, noncurrent

511

205

Unamortized energy contract liabilities, noncurrent

1,224

1,308

23,265

22,309

^[2]

35,975

33,418

Accumulated other comprehensive loss, net

1,185

2,805

(31)

(30)

Membership interest

10,480

9,624

Total members' equity

11,634

12,399

Noncontrolling interests

401

2,277

Total equity

12,035

14,676

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

48,010

48,094

148

244

101

513

669

660

1,362

2,052

5,803

3,007

210

249

2,935

10,463

244

832

889

149

2,318

129

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

1,079

3,580

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

2,704

10,182

Commonwealth Edison Co [Member]

1,078

3,572

241

276

279

685

656

(88)

(97)

597

559

252

239

(19)

(21)

233

218

Inventories, net

174

170

287

279

1,926

1,659

5,995

5,672

25,496

24,557

1,834

1,749

Receivables from affiliates, noncurrent

2,625

2,597

2,541

1,111

1,022

407

307

8,580

8,250

36,002

34,466

323

350

596

683

311

390

131

Mark-to-market derivative liabilities, current

197

289

165

143

1,502

2,393

Long-term debt to financing trusts

9,772

8,633

205

Deferred income taxes and unamortized investment tax credits

4,629

4,341

144

126

183

173

Mark-to-market derivative liabilities, noncurrent

6,604

6,403

209

268

603

595

12,372

11,906

23,851

23,137

Retained deficit unappropriated

1,588

Other paid-in capital

8,878

8,285

(1,639)

Retained earnings appropriated

3,324

3,095

12,151

11,329

36,002

34,466

PECO Energy Co [Member]

344

411

511

(101)

(116)

310

395

124

130

(7)

(8)

117

122

Prepaid utility taxes

978

662

3,921

3,843

10,841

10,181

901

776

Receivables from affiliates, noncurrent

546

475

386

375

1,914

1,688

13,733

12,531

350

300

487

479

168

129

Borrowings from Exelon/PHI intercompany money pool

102

121

1,246

1,208

Long-term debt to financing trusts

3,846

3,453

184

Deferred income taxes and unamortized investment tax credits

2,385

2,242

288

286

588

503

3,382

3,153

8,658

7,998

3,428

3,014

1,647

1,519

5,075

4,533

Baltimore Gas and Electric Company [Member]

13,733

12,531

225

144

351

487

(31)

(35)

320

452

149

117

(8)

(9)

141

108

185

168

1,004

948

4,212

4,034

10,374

9,872

468

481

289

270

819

830

12,197

11,650

250

300

291

346

204

205

110

1,007

1,143

3,710

3,364

Deferred income taxes and unamortized investment tax credits

1,656

1,521

177

189

989

1,109

107

104

2,955

2,946

7,672

7,453

2,575

2,318

1,950

1,879

4,525

4,197

12,197

11,650

111

671

611

(105)

(86)

566

525

300

260

(40)

(33)

260

227

207

198

434

440

1,690

1,599

1,995

1,811

16,163

15,377

1,848

1,933

146

140

4,005

357

365

Deferred income taxes

283

307

6,649

6,760

^[3]

24,502

23,736

287

368

405

347

479

539

300

299

Borrowings from Exelon/PHI intercompany money pool

104

106

122

137

154

141

2,015

2,154

7,077

6,659

Deferred income taxes and unamortized investment tax credits

2,635

2,439

Unamortized energy contract liabilities, noncurrent

1,237

1,438

168

235

589

622

4,769

4,879

^[3]

13,861

13,692

(138)

(68)

Membership interest

10,779

10,112

Total members' equity

10,641

10,044

Total equity

10,641

10,044

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

24,502

23,736

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

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

Potomac Electric Power Company [Member]

306

279

(41)

(32)

265

247

166

131

(17)

(13)

149

118

Inventories, net

117

111

215

214

818

770

3,831

3,697

7,919

7,456

548

570

120

115

280

284

1,011

1,038

9,748

9,264

313

218

226

149

164

Merger related obligation

Current portion of DC PLUG obligation

916

674

3,128

3,162

Deferred income taxes and unamortized investment tax credits

1,289

1,189

555

644

320

340

2,214

2,225

6,258

6,061

2,302

2,058

1,188

1,145

3,490

3,203

Delmarva Power and Light Company [Member]

9,748

9,264

135

176

(18)

(22)

117

154

(8)

(9)

Prepaid utility taxes

Renewable energy credits, current

365

368

1,608

1,533

4,485

4,314

219

222

158

162

445

458

5,295

5,140

146

107

126

414

535

1,725

1,595

Deferred income taxes and unamortized investment tax credits

761

715

446

493

1,330

1,334

3,469

3,464

1,209

1,089

617

587

1,826

1,676

Atlantic City Electric Company [Member]

5,295

5,140

230

156

(46)

(32)

184

124

(15)

(11)

Inventories, net

Prepaid utility taxes

376

326

1,390

1,303

3,649

3,475

428

395

507

485

^[4]

4,532

4,286

225

187

261

146

177

528

780

1,502

1,152

Deferred income taxes and unamortized investment tax credits

671

624

211

274

947

963

^[4]

2,977

2,895

1,574

1,271

(19)

120

1,555

1,391

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

4,532

4,286

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

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

Basis of Presentation and Significant Accounting Policies [Text Block]

$ 6

$ 21

[1]	Exelon’s consolidated assets include $2,722 million and $10,200 million at September 30, 2021 and December 31, 2020, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $1,088 million and $3,598 million at September 30, 2021 and December 31, 2020, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 17 — Variable Interest Entities for additional information.
[2]	Generation’s consolidated assets include $2,704 million and $10,182 million at September 30, 2021 and December 31, 2020, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $1,078 million and $3,572 million at September 30, 2021 and December 31, 2020, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 17 — Variable Interest Entities for additional information.
[3]	PHI’s consolidated total assets include $18 million at both September 30, 2021 and December 31, 2020 of PHI's consolidated VIE that can only be used to settle the liabilities of the VIE. PHI’s consolidated total liabilities include $10 million and $26 million at September 30, 2021 and December 31, 2020, respectively, of PHI's consolidated VIE for which the VIE creditors do not have recourse to PHI. See Note 17 — Variable Interest Entities for additional information.
[4]	ACE’s consolidated total assets include $14 million and $13 million at September 30, 2021 and December 31, 2020, respectively, of ACE's consolidated VIE that can only be used to settle the liabilities of the VIE. ACE’s consolidated total liabilities include $6 million and $21 million at September 30, 2021 and December 31, 2020, respectively, of ACE's consolidated VIE for which the VIE creditors do not have recourse to ACE. See Note 17 — Variable Interest Entities for additional information.

Consolidated Statements of Changes in Shareholders Equity (Unaudited) - USD ($) shares in Thousands, $ in Millions	Total	Correcting Adjustment [Member]	Common Stock [Member]	Common Stock [Member] Correcting Adjustment [Member]	Treasury Stock [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Noncontrolling Interest [Member]	Exelon Generation Co L L C [Member]	Exelon Generation Co L L C [Member] Retained Earnings [Member]	Exelon Generation Co L L C [Member] Accumulated Other Comprehensive Income (Loss) [Member]	Exelon Generation Co L L C [Member] Noncontrolling Interest [Member]	Exelon Generation Co L L C [Member] Membership Interest [Member]	Commonwealth Edison Co [Member]	Commonwealth Edison Co [Member] Common Stock [Member]	Commonwealth Edison Co [Member] Other Paid-in-Capital [Member]	Commonwealth Edison Co [Member] Retained Earnings, Unappropriated [Member]	Commonwealth Edison Co [Member] Retained Earnings, Appropriated	PECO Energy Co [Member]	PECO Energy Co [Member] Common Stock [Member]	PECO Energy Co [Member] Retained Earnings [Member]	Baltimore Gas and Electric Company [Member]	Baltimore Gas and Electric Company [Member] Common Stock [Member]	Baltimore Gas and Electric Company [Member] Retained Earnings [Member]	Pepco Holdings LLC [Member]	Pepco Holdings LLC [Member] Retained Earnings [Member]	Pepco Holdings LLC [Member] Membership Interest [Member]	Potomac Electric Power Company [Member]	Potomac Electric Power Company [Member] Common Stock [Member]	Potomac Electric Power Company [Member] Retained Earnings [Member]	Delmarva Power and Light Company [Member]	Delmarva Power and Light Company [Member] Common Stock [Member]	Delmarva Power and 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, 2019	974,416
Beginning balance at Dec. 31, 2019	$ 34,573		$ 19,274		$ (123)	$ 16,267	$ (3,194)	$ 2,349
Beginning Balance at Dec. 31, 2019									$ 15,830	$ 3,950	$ (32)	$ 2,346	$ 9,566												$ 9,608	$ (10)	$ 9,618
Beginning Balance at Dec. 31, 2019														$ 10,677	$ 1,588	$ 7,572	$ (1,639)	$ 3,156	$ 4,178	$ 2,766	$ 1,412	$ 3,683	$ 1,907	$ 1,776				$ 2,907	$ 1,796	$ 1,111	$ 1,580	$ 977	$ 603	$ 1,276	$ 1,154	$ 122
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	$ 376					582		(206)	(161)	45		(206)		168			168		140		140	181		181	108	108		52		52	45		45	13		13
Appropriation of retained earnings for future dividends														0			(168)	168
Long -Term Incentive Plan Activity (shares)	1,354
Long-Term Incentive Plan Activity		$ (4)		$ (4)
Employee stock purchase plan issuances (shares)	470
Employee stock purchase plan issuances	$ 31		31
Changes in equity of noncontrolling interests	(9)							(9)	(11)			(11)
Sale of noncontrolling interests	2		2						2				2
Common stock dividends	(374)					(374)								(125)				(125)	(85)		(85)	(62)		(62)				(28)		(28)	(52)		(52)	(23)		(23)
Distributions to member									(468)	(468)															(134)	(134)
Contributions from parent														125		125			231	231					144		144	137	137		6	6		1	1
Other comprehensive income (loss), net of income taxes	$ 21						21		(9)	0	(9)	0
Ending balance (in shares) at Mar. 31, 2020	976,240
Ending balance at Mar. 31, 2020	$ 34,616		19,303		(123)	16,475	(3,173)	2,134
Ending Balance at Mar. 31, 2020									15,183	3,527	(41)	2,129	9,568												9,726	(36)	9,762
Ending Balance at Mar. 31, 2020														10,845	1,588	7,697	(1,639)	3,199	4,464	2,997	1,467	3,802	1,907	1,895				3,068	1,933	1,135	1,579	983	596	1,267	1,155	112
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common Stock, Dividends, Per Share, Declared	$ 0.38
Beginning balance (in shares) at Dec. 31, 2019	974,416
Beginning balance at Dec. 31, 2019	$ 34,573		19,274		(123)	16,267	(3,194)	2,349
Beginning Balance at Dec. 31, 2019									15,830	3,950	(32)	2,346	9,566												9,608	(10)	9,618
Beginning Balance at Dec. 31, 2019														10,677	1,588	7,572	(1,639)	3,156	4,178	2,766	1,412	3,683	1,907	1,776				2,907	1,796	1,111	1,580	977	603	1,276	1,154	122
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	1,519								485					304					317			273			418			227			91			106
Acquisition of CENG noncontrolling interest	0								0
Other comprehensive income (loss), net of income taxes	$ 90						90		(4)
Ending balance (in shares) at Sep. 30, 2020	977,405
Ending balance at Sep. 30, 2020	$ 35,103		19,362		(123)	16,749	(3,104)	2,219
Ending Balance at Sep. 30, 2020									14,924	3,114	(36)	2,213	9,633												10,069	(43)	10,112
Ending Balance at Sep. 30, 2020														11,095	1,588	8,060	(1,700)	3,147	4,488	3,014	1,474	4,054	2,191	1,863				3,222	2,058	1,164	1,684	1,089	595	1,388	1,271	117
Beginning balance (in shares) at Mar. 31, 2020	976,240
Beginning balance at Mar. 31, 2020	$ 34,616		19,303		(123)	16,475	(3,173)	2,134
Beginning Balance at Mar. 31, 2020									15,183	3,527	(41)	2,129	9,568												9,726	(36)	9,762
Beginning Balance at Mar. 31, 2020														10,845	1,588	7,697	(1,639)	3,199	4,464	2,997	1,467	3,802	1,907	1,895				3,068	1,933	1,135	1,579	983	596	1,267	1,155	112
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	$ 574					521		53	529	476		53		(61)			(61)		39		39	39		39	94	94		57		57	19		19	18		18
Long -Term Incentive Plan Activity (shares)	148
Long-Term Incentive Plan Activity	$ 17		17
Employee stock purchase plan issuances (shares)		(51)
Employee stock purchase plan issuances	15		15
Changes in equity of noncontrolling interests	(19)							(19)	(19)			(19)
Sale of noncontrolling interests	1		1						1				1
Common stock dividends	(374)					(374)								(124)				(124)	(85)		(85)	(62)		(62)				(73)		(73)	(14)		(14)	(12)		(12)
Distributions to member									(469)	(469)															(134)	(134)
Contributions from parent														124		124						26	26		215		215				100	100		115	115
Other comprehensive income (loss), net of income taxes	$ 41						41		2	0	2	0
Ending balance (in shares) at Jun. 30, 2020	976,337
Ending balance at Jun. 30, 2020	$ 34,871		19,336		(123)	16,622	(3,132)	2,168
Ending Balance at Jun. 30, 2020									15,227	3,534	(39)	2,163	9,569												9,901	(76)	9,977
Ending Balance at Jun. 30, 2020														10,784	1,588	7,821	(1,700)	3,075	4,418	2,997	1,421	3,805	1,933	1,872				3,052	1,933	1,119	1,684	1,083	601	1,388	1,270	118
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common Stock, Dividends, Per Share, Declared	$ 0.38
Net income (loss)	$ 569					501		68	117	49		68		196			196		138		138	53		53	216	216		118		118	27		27	75		75
Appropriation of retained earnings for future dividends														0			(196)	196
Long -Term Incentive Plan Activity (shares)	68
Long-Term Incentive Plan Activity	$ 10		10
Employee stock purchase plan issuances (shares)	1,000
Employee stock purchase plan issuances	$ 16		16
Changes in equity of noncontrolling interests	(17)							(17)	(18)			(18)
Common stock dividends	(374)					(374)								(124)				(124)	(85)		(85)	(62)		(62)				(73)		(73)	(33)		(33)	(76)		(76)
Distributions to member									(469)	(469)															(183)	(183)
Contributions from parent									64				64	239		239			17	17		258	258		135		135	125	125		6	6		1	1
Other comprehensive income (loss), net of income taxes	$ 28						28	0	3	0	3	0
Ending balance (in shares) at Sep. 30, 2020	977,405
Ending balance at Sep. 30, 2020	$ 35,103		19,362		(123)	16,749	(3,104)	2,219
Ending Balance at Sep. 30, 2020									14,924	3,114	(36)	2,213	9,633												10,069	(43)	10,112
Ending Balance at Sep. 30, 2020														11,095	1,588	8,060	(1,700)	3,147	4,488	3,014	1,474	4,054	2,191	1,863				3,222	2,058	1,164	1,684	1,089	595	1,388	1,271	117
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common Stock, Dividends, Per Share, Declared	$ 0.38
Appropriation of retained earnings for future dividends														3,095
Beginning balance (in shares) at Dec. 31, 2020	977,466
Beginning balance at Dec. 31, 2020	$ 34,868		19,373		(123)	16,735	(3,400)	2,283
Beginning Balance at Dec. 31, 2020									14,676	2,805	(30)	2,277	9,624												10,044	(68)	10,112
Beginning Balance at Dec. 31, 2020	32,585													11,329	1,588	8,285	(1,639)	3,095	4,533	3,014	1,519	4,197	2,318	1,879				3,203	2,058	1,145	1,676	1,089	587	1,391	1,271	120
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	$ (264)					(289)		25	(769)	(793)		24		197			197		167		167	209		209	128	128		59		59	56		56	14		14
Appropriation of retained earnings for future dividends														0			(197)	197
Long -Term Incentive Plan Activity (shares)	640
Long-Term Incentive Plan Activity	$ 5		5
Employee stock purchase plan issuances (shares)	902
Employee stock purchase plan issuances	$ 34		34
Changes in equity of noncontrolling interests	(10)							(10)	(10)			(10)
Common stock dividends	(374)					(374)								(127)				(127)	(85)		(85)	(74)		(74)				(28)		(28)	(40)		(40)	(14)		(14)
Distributions to member									(458)	(458)															(81)	(81)
Contributions from parent														198		198									560		560	138	138		120	120		303	303
Other comprehensive income (loss), net of income taxes	$ 54						54		1	0	1	0
Ending balance (in shares) at Mar. 31, 2021	979,008
Ending balance at Mar. 31, 2021	$ 34,313		19,412		(123)	16,072	(3,346)	2,298
Ending Balance at Mar. 31, 2021									13,440	1,554	(29)	2,291	9,624												10,651	(21)	10,672
Ending Balance at Mar. 31, 2021														11,597	1,588	8,483	(1,639)	3,165	4,615	3,014	1,601	4,332	2,318	2,014				3,372	2,196	1,176	1,812	1,209	603	1,694	1,574	120
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common Stock, Dividends, Per Share, Declared	$ 0.38
Beginning balance (in shares) at Dec. 31, 2020	977,466
Beginning balance at Dec. 31, 2020	$ 34,868		19,373		(123)	16,735	(3,400)	2,283
Beginning Balance at Dec. 31, 2020									14,676	2,805	(30)	2,277	9,624												10,044	(68)	10,112
Beginning Balance at Dec. 31, 2020	32,585													11,329	1,588	8,285	(1,639)	3,095	4,533	3,014	1,519	4,197	2,318	1,879				3,203	2,058	1,145	1,676	1,089	587	1,391	1,271	120
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	1,441								(122)					609					383			290			535			264			135			141
Acquisition of CENG noncontrolling interest	885								885
Other comprehensive income (loss), net of income taxes	$ 177						177		(1)
Ending balance (in shares) at Sep. 30, 2021	980,150
Ending balance at Sep. 30, 2021	$ 34,259		20,271		(123)	16,926	(3,223)	408
Ending Balance at Sep. 30, 2021									12,035	1,185	(31)	401	10,480												10,641	(138)	10,779
Ending Balance at Sep. 30, 2021	$ 33,851													12,151	1,588	8,878	(1,639)	3,324	5,075	3,428	1,647	4,525	2,575	1,950				3,490	2,302	1,188	1,826	1,209	617	1,555	1,574	(19)
Beginning balance (in shares) at Mar. 31, 2021	979,008
Beginning balance at Mar. 31, 2021	$ 34,313		19,412		(123)	16,072	(3,346)	2,298
Beginning Balance at Mar. 31, 2021									13,440	1,554	(29)	2,291	9,624												10,651	(21)	10,672
Beginning Balance at Mar. 31, 2021														11,597	1,588	8,483	(1,639)	3,165	4,615	3,014	1,601	4,332	2,318	2,014				3,372	2,196	1,176	1,812	1,209	603	1,694	1,574	120
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	$ 476					401		75	13	(61)		74		192			192		104		104	45		45	141	141		75		75	30		30	37		37
Appropriation of retained earnings for future dividends														0			(192)	192
Long -Term Incentive Plan Activity (shares)	237
Long-Term Incentive Plan Activity	$ 24		24
Employee stock purchase plan issuances (shares)	420
Employee stock purchase plan issuances	$ 18		18
Changes in equity of noncontrolling interests	(13)							(13)	(12)			(12)
Common stock dividends	(375)					(375)								(126)				(126)	(84)		(84)	(72)		(72)				(95)		(95)	(23)		(23)	(215)		(215)
Distributions to member									(458)	(458)															(333)	(333)
Contributions from parent														197		197			395	395
Other comprehensive income (loss), net of income taxes	$ 57						57		2	0	2	0
Ending balance (in shares) at Jun. 30, 2021	979,665
Ending balance at Jun. 30, 2021	$ 34,500		19,454		(123)	16,098	(3,289)	2,360
Ending Balance at Jun. 30, 2021									12,985	1,035	(27)	2,353	9,624												10,459	(213)	10,672
Ending Balance at Jun. 30, 2021														11,860	1,588	8,680	(1,639)	3,231	5,030	3,409	1,621	4,305	2,318	1,987				3,352	2,196	1,156	1,819	1,209	610	1,516	1,574	(58)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common Stock, Dividends, Per Share, Declared	$ 0.38
Net income (loss)	$ 1,229					1,203		26	633	607		26		220			220		111		111	36		36	266	266		130		130	50		50	90		90
Appropriation of retained earnings for future dividends														0			(220)	220
Long -Term Incentive Plan Activity (shares)	94
Long-Term Incentive Plan Activity	$ 9		9
Employee stock purchase plan issuances (shares)	391
Employee stock purchase plan issuances	$ 18		18
Changes in equity of noncontrolling interests	(13)							(13)	(13)			(13)
Acquisition of CENG noncontrolling interest	(885)		1,080					(1,965)	(885)			(1,965)	1,080
Deferred Tax Liability Adjustment - Noncontrolling Interest	(290)		(290)						(288)				(288)
Common stock dividends	(375)					(375)								(127)				(127)	(85)		(85)	(73)		(73)				(98)		(98)	(43)		(43)	(51)		(51)
Distributions to member									(457)	(457)															(191)	(191)
Contributions from parent									64				64	198		198			19	19		257	257		107		107	106	106
Other comprehensive income (loss), net of income taxes	$ 66						66		(4)	0	(4)	0
Ending balance (in shares) at Sep. 30, 2021	980,150
Ending balance at Sep. 30, 2021	$ 34,259		$ 20,271		$ (123)	$ 16,926	$ (3,223)	$ 408
Ending Balance at Sep. 30, 2021									$ 12,035	$ 1,185	$ (31)	$ 401	$ 10,480												$ 10,641	$ (138)	$ 10,779
Ending Balance at Sep. 30, 2021	$ 33,851													12,151	$ 1,588	$ 8,878	$ (1,639)	$ 3,324	$ 5,075	$ 3,428	$ 1,647	$ 4,525	$ 2,575	$ 1,950				$ 3,490	$ 2,302	$ 1,188	$ 1,826	$ 1,209	$ 617	$ 1,555	$ 1,574	$ (19)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common Stock, Dividends, Per Share, Declared	$ 0.38
Appropriation of retained earnings for future dividends														$ 3,324

Significant Accounting Policies (All Registrants)

9 Months Ended

Sep. 30, 2021

Accounting Policies [Abstract]

Significant Accounting Policies (All Registrants)

Description of Business (All Registrants)

Exelon is a utility services holding company engaged in the generation, delivery and marketing of energy through Generation and the energy distribution and transmission businesses through ComEd, PECO, BGE, Pepco, DPL, and ACE.

Name of Registrant

Business

Service Territories

Exelon Generation
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 quarterly 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” in the consolidated financial statements and include intercompany eliminations unless otherwise disclosed.

The accompanying consolidated financial statements as of September 30, 2021 and for the three and nine months ended September 30, 2021 and 2020 are unaudited but, in the opinion of the management of each Registrant include all adjustments that are considered necessary for a fair statement of the Registrants’ respective financial statements in accordance with GAAP. All adjustments are of a normal, recurring nature,

except as otherwise disclosed. The December 31, 2020 Consolidated Balance Sheets were derived from audited financial statements. Financial results for interim periods are not necessarily indicative of results that may be expected for any other interim period or for the fiscal year ending December 31, 2021. These Combined Notes to Consolidated Financial Statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations.

Mergers, Acquisitions, and Dispositions (Exelon and Generation)

9 Months Ended

Sep. 30, 2021

Mergers, Acquisitions, and Dispositions [Abstract]

Mergers, Acquisitions, and Dispositions (Exelon and Generation)

CENG Put Option (Exelon and Generation)

Prior to August 6, 2021, Generation owned a 50.01% membership interest in CENG, a joint venture with EDF, which wholly owns the Calvert Cliffs and Ginna nuclear stations and Nine Mile Point Unit 1, in addition to an 82% undivided ownership interest in Nine Mile Point Unit 2. CENG is 100% consolidated in Exelon's and Generation's financial statements. See Note 17 — 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 terms of the Put Option Agreement, EDF had 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. The transaction required approval by FERC and the NYPSC, which approvals were received on July 30, 2020 and April 15, 2021, respectively. On August 6, 2021, Generation and EDF entered into a settlement agreement pursuant to which Generation purchased EDF’s equity interest in CENG for a net purchase price of $885 million, which includes, among other things, an adjustment for EDF’s share of the balance of the preferred distribution payable by CENG to Generation. The difference between the net purchase price and EDF’s Noncontrolling Interest as of August 6, 2021 was recorded in Common Stock in Exelon’s Consolidated Balance Sheet and Membership Interest in Generation’s Consolidated Balance Sheet. As a result of the transaction, Exelon and Generation recorded deferred tax liabilities of $290 million and $288 million, respectively, in Common Stock in Exelon’s Consolidated Balance Sheet and Membership Interest in Generation’s Consolidated Balance Sheet. See Note 10 — Income Taxes for additional information.

The following tables summarize the effects of the changes in Generation's ownership interest in CENG in Exelon's Shareholders' Equity and Generation's Member's Equity:


	Three Months Ended September 30, 2021		Nine Months Ended September 30, 2021
Net income attributable to Exelon's common shareholders	$	1,203	$	1,315
Pre-tax increase in Exelon's common stock for purchase of EDF's 49.99% equity interest(a)	1,080		1,080
Decrease in Exelon's common stock due to deferred tax liabilities resulting from purchase of EDF's 49.99% equity interest(a)	(290)		(290)
Change from net income attributable to common stock and transfers from noncontrolling interest	$	1,993	$	2,105

	Three Months Ended September 30, 2021		Nine Months Ended September 30, 2021
Net income (loss) attributable to Generation's membership interest	$	607	$	(247)
Pre-tax increase in Generation's membership interest for purchase of EDF's 49.99% equity interest(a)	1,080		1,080
Decrease in Generation's membership interest due to deferred tax liabilities resulting from purchase of EDF's 49.99% equity interest(a)	(288)		(288)
Change from net income (loss) attributable to membership interest and transfers from noncontrolling interest	$	1,399	$	545

_________

(a)Represents non-cash activity in Exelon’s and Generation’s consolidated financial statements.

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 MW of generation in operation or under construction across more than 600 sites across the United States. Generation will retain certain solar assets not included in this agreement, primarily Antelope Valley.

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

See Note 17 — Debt and Credit Agreements of the Exelon 2020 Form 10-K for additional information on the SolGen nonrecourse debt included as part of the transaction.

Agreement for the Sale of a Generation Biomass Facility (Exelon and Generation)

On April 28, 2021, Generation and ReGenerate Energy Holdings, LLC (“ReGenerate”) entered into a purchase agreement, under which ReGenerate agreed to purchase Generation’s interest in the Albany Green Energy biomass facility. As a result, in the second quarter of 2021, Exelon and Generation recorded a pre-tax impairment charge of $140 million in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. Completion of the transaction was subject to the satisfaction of various customary closing conditions which were satisfied in the second quarter of 2021. The sale was completed on June 30, 2021 for a net purchase price of $36 million.

Regulatory Matters (All Registrants)

9 Months Ended

Sep. 30, 2021

Regulated Operations [Abstract]

Regulatory Matters (All Registrants)

Regulatory Matters (All Registrants) As discussed in Note 3 — Regulatory Matters of the Exelon 2020 Form 10-K, the Registrants are involved in rate and regulatory proceedings at FERC and their state commissions. The following discusses developments in 2021 and updates to the 2020 Form 10-K.

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 2021.

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 16, 2020	Electric	$	(11)	$	(14)	8.38	%	December 9, 2020	January 1, 2021
PECO - Pennsylvania	September 30, 2020	Natural Gas	69		29		10.24	%	June 22, 2021	July 1, 2021
BGE - Maryland(b)	May 15, 2020 (amended September 11, 2020)	Electric	203		140		9.50	%	December 16, 2020	January 1, 2021
		Natural Gas	108		74		9.65	%
Pepco - District of Columbia(c)	May 30, 2019 (amended June 1, 2020)	Electric	136		109		9.275	%	June 8, 2021	July 1, 2021
Pepco - Maryland(d)	October 26, 2020 (amended March 31, 2021)	Electric	104		52		9.55	%	June 28, 2021	June 28, 2021
DPL - Delaware	March 6, 2020 (amended February 2, 2021)	Electric	23		14		9.60	%	September 15, 2021	October 6, 2020
ACE - New Jersey(e)	December 9, 2020 (amended February 26, 2021)	Electric	67		41		9.60	%	July 14, 2021	January 1, 2022

__________

(a)ComEd's 2021 approved revenue requirement 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.

(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, before offsets, in 2021, 2022, and 2023, respectively, and natural gas revenue requirement increases of $53 million, $11 million, and $10 million, before offsets, in 2021, 2022, and 2023, respectively. BGE proposed to use certain tax benefits to fully offset the increases in 2021 and 2022 and partially offset the increase in 2023. However, the MDPSC only utilized the tax benefits to fully offset the increases in 2021 such 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 customer rate increases in 2022 and 2023 and BGE cannot predict the outcome.

(c)Reflects a cumulative multi-year plan with 18-months remaining in 2021 through 2022. The DCPSC awarded Pepco electric incremental revenue requirement increases of $42 million and $67 million, before offsets, for the remainder of 2021 and 2022, respectively. However, the DCPSC utilized the acceleration of refunds for certain tax benefits along with other rate relief to partially offset the customer rate increases by $22 million and $40 million for the remainder of 2021 and 2022, respectively.

(d)Reflects a three-year cumulative multi-year plan for April 1, 2021 through March 31, 2024. The MDPSC awarded Pepco electric incremental revenue requirement increases of $21 million, $16 million, and $15 million, before offsets, for the 12-month periods ending March 31, 2022, 2023, and 2024, respectively. Pepco proposed to utilize certain tax benefits to fully offset the increase through 2023 and partially offset customer rate increases in 2024. However, the MDPSC only utilized the acceleration of refunds for certain tax benefits to fully offset the increases such that customer rates remain unchanged through March 31, 2022. The MDPSC has deferred decision on whether to use additional tax benefits to offset customer rate increases for periods after March 31, 2022 and Pepco cannot predict the outcome.

(e)Requested and approved increases are before New Jersey sales and use tax. The order allows ACE to retain approximately $11 million of certain tax benefits which resulted in a decrease to income tax expense in Exelon's, PHI's, and ACE's Consolidated Statements of Operations and Comprehensive Income in the third quarter of 2021.

Pending Distribution Base Rate Case Proceedings

Registrant/Jurisdiction

Filing Date

Service

Requested Revenue Requirement Increase

Requested ROE

Expected Approval Timing

ComEd - Illinois(a)

April 16, 2021

Electric

7.36

Fourth quarter of 2021

PECO - Pennsylvania(b)

March 30, 2021

Electric

246

10.95

Fourth quarter of 2021

DPL - Maryland

September 1, 2021

Electric

10.10

First quarter of 2022

__________

(a)ComEd's 2022 requested revenue requirement reflects an increase of $40 million for the initial year revenue requirement for 2022 and an increase of $11 million related to the annual reconciliation for 2020. The revenue requirement for 2022 provides for a weighted average debt and equity return on distribution rate base of 5.72%, inclusive of an allowed ROE of 7.36%, reflecting the average monthly yields for 30-year treasury bonds plus 580 basis points. The reconciliation revenue requirement for 2020 provides for a weighted average debt and equity return on distribution rate base of 5.69%, inclusive of an allowed ROE of 7.29%, reflecting the average monthly yields for 30-year treasury bonds plus 580 basis points less a performance metrics penalty of 7 basis points.

(b)The Joint Petition for Settlement was filed on September 15, 2021 and recommended for approval by the administrative law judge on October 6, 2021. PAPUC approval is expected in the fourth quarter of 2021.

Transmission Formula Rates

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 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 BGE, Pepco, DPL, and ACE 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 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, BGE, Pepco, DPL, and ACE also reconciles any differences between the actual costs and actual revenues for the calendar year (annual reconciliation).

For 2021, 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 Increase		Total Revenue Requirement Increase(b)		Allowed Return on Rate Base(c)		Allowed ROE(d)
ComEd	$	33	$	12	$	45	8.20	%	11.50	%
PECO	(2)		26		24		7.37	%	10.35	%
BGE	38		27		65		7.35	%	10.50	%
Pepco	(9)		21		12		7.68	%	10.50	%
DPL	19		33		52		7.20	%	10.50	%
ACE	27		24		51		7.45	%	10.50	%

__________

(a)All rates are effective June 1, 2021 - May 31, 2022, subject to review by interested parties pursuant to review protocols of each Utility Registrants' tariff.

(b)In 2020, ComEd, BGE, Pepco, DPL, and ACE's transmission revenue requirement included a one-time decrease in accordance with the April 24, 2020 settlement agreement related to excess deferred income taxes which now completed has resulted in an increase to the 2021 transmission revenue requirement. In 2020, PECO's transmission revenue requirement included a one-time decrease in accordance with the December 5, 2019 settlement agreement related to refunds which now completed has resulted in an increase to the 2021 transmission revenue requirement.

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

(d)As part of the FERC-approved settlements of ComEd’s 2007 and PECO's 2017 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

Clean Energy Law (Exelon and ComEd). On September 15, 2021, the Illinois Public Act 102-0662 was signed into law by the Governor of Illinois (“Clean Energy Law”). The Clean Energy Law includes, among other features, (1) procurement of carbon mitigation credits (CMCs) from qualifying nuclear-powered generating facilities, (2) a requirement to file a general rate case or a new four-year multi-year plan no later than January 20, 2023 to establish rates effective after ComEd’s existing performance-based distribution formula rate sunsets, (3) an extension of and certain adjustments to ComEd’s energy efficiency MWh savings goals, (4) revisions to the Illinois RPS requirements, including expanded charges for the procurement of RECs from wind and solar generation, (5) a requirement to accelerate amortization of ComEd’s unprotected excess deferred income taxes that ComEd was previously directed by the ICC to amortize using the average rate assumption method which equates to approximately 39.5 years, and (6) requirements that the ICC initiate and conduct various regulatory proceedings on subjects including ethics, spending, grid investments, and performance metrics. Regulatory or legal challenges regarding the validity or implementation of the Clean Energy Law are possible and Exelon, Generation, and ComEd cannot reasonably predict the outcome of any such challenges.

Carbon Mitigation Credit

The Clean Energy Law establishes decarbonization requirements for Illinois as well as programs to support the retention and development of emissions-free sources of electricity. Among other things, the Clean Energy Law authorizes the IPA to procure up to 54.5 million CMCs from qualifying nuclear plants for a five-year period beginning on June 1, 2022 through May 31, 2027. CMCs are credits for the carbon-free attributes of eligible nuclear power plants in PJM. The Byron, Dresden, and Braidwood nuclear plants located in Illinois will be eligible to participate in the CMC procurement process and, if awarded contracts, would be committed to operate through May 31, 2027. Selected generators will by December 3, 2021 contract directly with ComEd for the procurement of the CMCs based upon the number of MWhs produced annually by the eligible facilities, subject to specified caps and minimum performance requirements. The price to be paid for each CMC will be determined through a competitive bidding process that includes consumer-protection measures that cap the maximum acceptable bid amount and a formula that reduces CMC prices by an energy price index, the base residual auction capacity price in the ComEd zone of PJM, and the monetized value of any federal tax credit or other subsidy if applicable. The consumer protection measures contained in the new law will result in net payments to ComEd ratepayers if the energy index, the capacity price and applicable federal tax credits or subsidy exceed the maximum bid cap.

ComEd is required to purchase CMCs from eligible nuclear facilities and all its costs of doing so will be recovered through a new rider. That rider will provide for an annual reconciliation and true-up to actual costs incurred by ComEd to purchase CMCs, with any difference to be credited to or collected from ComEd’s retail customers in subsequent periods.

See Note 7 – Early Plant Retirements for the impacts of the provisions above on the Illinois nuclear plants and Generation’s consolidated financial statements. The provisions do not impact ComEd’s consolidated financial statements until 2022.

ComEd Electric Distribution Rates

The Clean Energy Law contains requirements associated with ComEd’s transition away from the performance-based electric distribution formula rate. The law authorizing that rate setting process sunsets at the end of 2022. The Clean Energy Law, and tariffs adopted under it, governs both the remaining reconciliations of rates set under that formula process and requires ComEd to file in 2023 its choice of either a general rate case or a four-year multi-year plan to set rates that take effect in 2024.

If ComEd elects to file a multi-year plan, that plan would set rates for 2024 – 2027, based on forecasted revenue requirements and an ICC determined rate of return on rate base, including the cost of common equity. Each year of the multi-year plan is subject to after the fact ICC review and reconciliation of the plan’s revenue requirement for that year with the actual costs that the ICC determines are prudently and reasonably incurred for that year.

That reconciliation is subject to adjustment for certain uncontrollable expenses and, unless the plan is modified, to a 5% cap on increases over the previously approved multi-year rate plan revenue requirement. ComEd would make its initial reconciliation filing in 2025, and the rate adjustments necessary to reconcile 2024 revenues to ComEd’s actual 2024 costs incurred would take effect in January 2026 after the ICC’s review. The ICC must also approve certain annual performance metrics, which can impose symmetrical performance adjustments in the total range of 20 to 60 basis points to ComEd’s rate of return on common equity based on the extent to which ComEd achieved the annual performance goals. ComEd will recover from retail customers, subject to certain exceptions, the costs it incurs pursuant to the Clean Energy Law either through its electric distribution rate or other recovery mechanisms.

The Clean Energy Law, among other things, also requires ComEd’s rates to include a decoupling mechanism to eliminate any impacts of weather or load from ComEd’s electric distribution rate revenues. The Clean Energy Law also requires the ICC to initiate a docket to accelerate and fully credit to customers unprotected property related TCJA excess deferred income taxes no later than December 31, 2025.

Energy Efficiency

The Clean Energy Law extends ComEd’s current cumulative annual energy efficiency MWh savings goals through 2040, adds expanded electrification measures to those goals, increases low-income commitments and adds a new performance adjustment to the energy efficiency formula rate. ComEd expects its annual spend to increase in 2022 through 2040 to achieve these energy efficiency MWh savings goals, which will be deferred as a separate regulatory asset that will be recovered through the energy efficiency formula rate over the weighted average useful life, as approved by the ICC, of the related energy efficiency measures.

Energy Efficiency Formula Rate (Exelon and ComEd). ComEd filed its annual energy efficiency formula rate update with the ICC on June 1, 2021. The filing establishes the revenue requirement used to set the rates that will take effect in January 2022 after the ICC’s review and approval. The requested revenue requirement update is based on a reconciliation of the 2020 actual costs plus projected 2022 expenditures.


Initial Revenue Requirement Increase		Annual Reconciliation Decrease		Total Revenue Requirement Increase		Requested Return on Rate Base(a)		Requested ROE
$	55	$	(1)	$	54	5.72	%	7.36	%

__________

(a)The requested revenue requirement increase provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 5.72% inclusive of an allowed ROE of 7.36%, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. For the 2020 reconciliation year, the requested revenue requirement provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 6.26% inclusive of an allowed ROE of 8.46%, which includes an upward performance adjustment that increased the ROE. The performance adjustment can either increase or decrease the ROE based upon the achievement of energy efficiency savings goals.

Maryland Regulatory Matters

Maryland Order Directing the Distribution of Energy Assistance Funds (Exelon, BGE, PHI, Pepco, and DPL). On June 15, 2021, the MDPSC issued an order authorizing the disbursal of funds to utilities in accordance with Maryland COVID-19 relief legislation. Under this order, BGE, Pepco, and DPL received funds of $50 million, $12 million, and $8 million, respectively, in July 2021. The funds have been used to reduce or eliminate certain qualifying past-due residential customer receivables.

New Jersey Regulatory Matters

Conservation Incentive Program (CIP) (Exelon, PHI, and ACE). On September 25, 2020, ACE filed an application with the NJBPU as was required seeking approval to implement a portfolio of energy efficiency programs pursuant to New Jersey’s clean energy legislation. The filing included a request to implement a CIP that would eliminate the favorable and unfavorable impacts of weather and customer usage patterns on distribution revenues for most customers. The CIP compares current distribution revenues by customer class to approved target revenues established in ACE’s most recent distribution base rate case. The CIP is calculated annually and recovery is subject to certain conditions, including an earnings test and ceilings on customer rate increases.

On April 27, 2021, the NJBPU approved the settlement filed by ACE and the third parties to the proceeding. The approved settlement addresses all material aspects of ACE’s filing, including ACE’s ability to implement the CIP prospectively effective July 1, 2021. As a result of this decoupling mechanism, operating revenues will no longer be impacted by abnormal weather or usage for most customers. Starting in third quarter of 2021, ACE will record alternative revenue program revenues for its best estimate of the distribution revenue impacts resulting from future changes in CIP rates that it believes are probable of approval by the NJBPU in accordance with this mechanism.

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 consisted 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.

On July 14, 2021, the NJBPU approved the settlement filed by ACE and the third parties to the proceeding. The approved settlement addresses all material aspects of ACE's smart energy network deployment plan, including cost recovery of the investment costs, incremental O&M expenses, and the unrecovered balance of existing infrastructure through future distribution rates.

Regulatory Assets and Liabilities

The Utility Registrants' regulatory assets and liabilities have not changed materially since December 31, 2020, unless noted below. See Note 3 — Regulatory Matters of the Exelon 2020 Form 10-K for additional information on the specific regulatory assets and liabilities.

ComEd. Regulatory assets increased $93 million primarily due to an increase of $47 million in the Electric Distribution Formula Rate Annual Reconciliations regulatory asset and $127 million in the Energy Efficiency Costs regulatory asset, partially offset by a decrease of $87 million in the renewable energy regulatory asset.

PECO. Regulatory assets increased $135 million primarily due to an increase of $123 million in the Deferred Income Taxes regulatory asset and $14 million in the Vacation Accrual regulatory asset. Regulatory liabilities increased by $66 million primarily due to an increase of $71 million in the Nuclear Decommissioning regulatory liability partially offset by a $18 million decrease in the Electric Energy and Natural Gas Costs regulatory liability.

BGE. Regulatory liabilities decreased $116 million primarily due to a decrease of $128 million in the Deferred Income Taxes regulatory liability offset by an increase of $12 million in Other regulatory liabilities.

Pepco. Regulatory liabilities decreased $108 million primarily due to a decrease of $89 million in the Deferred Income Taxes regulatory liability and $19 million in the Transmission Formula Rate regulatory liability.

DPL. Regulatory liabilities decreased $45 million primarily due to a decrease of $41 million in the Deferred Income Taxes regulatory liability.

ACE. Regulatory liabilities decreased $61 million primarily due to a decrease of $67 million in the Deferred Income Taxes regulatory liability partially offset by an increase of $14 million in the Stranded Costs regulatory liability.

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 the Utility Registrants' customers.


	Exelon		ComEd(a)		PECO		BGE(b)		PHI		Pepco(c)		DPL(c)		ACE
September 30, 2021	$	44	$	—	$	—	$	39	$	5	$	3	$	2	$	—

December 31, 2020	51		(1)		—		45		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)

Impacts of the February 2021 Extreme Cold Weather Event 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 outages as a result of extreme cold weather conditions. In addition, those weather conditions drove increased demand for service, dramatically increased wholesale power prices, and also increased gas prices in certain regions. In response to the high demand and significantly reduced total generation on the system, the PUCT directed ERCOT to use an administrative price cap of $9,000 per MWh during firm load shedding events.

The estimated impact to Exelon’s and Generation’s Net income for the nine months ended September 30, 2021 arising from these market and weather conditions was a reduction of approximately $880 million. The estimated impact to Exelon's and Generation's Net income for the three months ended September 30, 2021 was not material. The ultimate impact to Exelon’s and Generation’s consolidated financial statements for the full year 2021 may be affected by a number of factors, including the impacts of customer and counterparty credit losses, any state or federal solutions to address the financial challenges caused by the event, and related litigation and contract disputes.

During February and March 2021, various parties with differing interests, including generators and retail providers, filed requests with the PUCT to void the PUCT’s orders setting prices at $9,000 per MWh during firm load shedding events. Other requests were made for the PUCT to enforce its order and reduce prices for 33 hours between February 18 and February 19 after firm load shedding ceased, and to cap ancillary services at $9,000 per MWh. On March 2, 2021, a third party filed a notice of appeal in the Court of Appeals for the Third District of Texas challenging the validity of the PUCT’s actions. Generation intervened in that appeal and filed its initial brief on June 2, 2021. On April 19, 2021, Generation filed a declaratory action and request for judicial review of the PUCT’s orders setting prices at $9,000 per MWh in District Court of Travis County, Texas. Generation subsequently requested that the District Court of Travis County, Texas stay its proceeding pending action by the Court of Appeals in the third party proceeding. On May 17, 2021, Generation amended its petition for declaratory action and request for judicial review pending in the District Court of Travis County, Texas. Exelon and Generation cannot predict the outcome of these proceedings or the financial statement impact.

Due to these events, a number of ERCOT market participants experienced bankruptcies or defaulted on payments to ERCOT, resulting in approximately a $3.0 billion payment shortfall in collections, which is allocated to the remaining ERCOT market participants. As of September 30, 2021, Generation has recorded its estimated portion of this obligation of approximately $17 million on a discounted basis, which is to be paid over a term of 83 years. ERCOT rules historically have limited recovery of default from market participants to $2.5 million per month market-wide. In February 2021, the PUCT gave ERCOT discretion to disregard those rules, but ERCOT has declined to exercise that discretion thus far. On March 8, 2021, a third party filed a notice of appeal in the Court of Appeals for the Third District of Texas challenging the validity of the PUCT's order to ERCOT in February 2021. Generation intervened in that appeal and filed its initial brief on July 7, 2021. On May 7, 2021, Generation filed a declaratory action and request for judicial review of the PUCT's order in the District Court of Travis County, Texas. Generation subsequently requested that the District Court of Travis County, Texas stay its proceeding pending action by the Court of Appeals in the third party proceeding. Exelon and Generation cannot predict the outcome of these proceedings or the financial statement impact.

Additionally, several legislative proposals were introduced in the Texas legislature during February and March 2021 concerning the amount, timing and allocation of recovery of the $3.0 billion shortfall, as well as recovery of other costs associated with the PUCT's directive to set prices at $9,000 per MWh. Two of these proposals were enacted into law in June 2021 and establish financing mechanisms that ERCOT and certain market participants can utilize to fund amounts owed to ERCOT. Generation participated in proceedings before the PUCT addressing the proposed allocation of the $2.1 billion in securitized funds for reliability and ancillary service charges over $9,000/MWh. In September 2021, Generation entered into a settlement agreement and stipulation to resolve the allocation issues. The PUCT approved the settlement agreement and stipulation on October 13, 2021.

In addition, other legislative proposals were introduced in the Texas legislature during February and March 2021 addressing cold-weather preparation for power plants and natural gas production and transportation infrastructure and the market structure for reliability services. The Texas legislature addressed these proposals by enacting a bill with a broad set of market reforms that, among other things, directed the PUCT to establish weatherization standards for electric generators within six months of enactment and gave the PUCT authority to impose administrative penalties if the new proposed standards, once adopted, are not met. On October 21, 2021, the PUCT adopted rule change requiring generators by December 1, 2021 to complete a number of specified winter readiness preparations and to submit to ERCOT a report describing and certifying the completion of those preparations. The PUCT described these requirements as the first phase of its actions with respect to winter preparedness, to be followed by a second phase consisting of a year-round set of weather preparedness standards to be informed by a weather study that is being conducted by ERCOT.

The legislation also directs the PUCT to evaluate whether additional ancillary services are needed for reliability in the ERCOT power region to provide adequate incentives for dispatchable generation. Exelon and others have submitted various proposals to the PUCT with respect to a range of potential market reforms, including the implementation of additional ancillary service products as well as changes to the high system-wide offer cap and operating reserve demand curve, which remain pending. On September 23, 2021, the PUCT solicited comments regarding whether it should set ERCOT’s high system-wide offer cap at $4,500/MWh if the PUCT takes action to amend its rules with respect to that cap. Exelon and others submitted comments to the PUCT, which remain pending. The PUCT is expected to address potential changes to ERCOT’s market rules later in 2021.

In February 2021, more than 70 local distribution companies (LDCs) and natural gas pipelines in multiple states throughout the mid-continent region, where Generation serves natural gas customers, issued operational flow orders (OFOs), curtailments or other limitations on natural gas transportation or use to manage the operational integrity of the applicable LDC or pipeline system. When in effect, gas transportation or use above these limitations is subject to significant penalties according to the applicable LDCs’ and natural gas pipelines’ tariffs. Gas transportation and supply in many states became restricted due to wells freezing and pipeline compression disruption, while demand was increasing due to the extreme cold temperatures, resulting in extremely high natural gas prices. Due to the extraordinary circumstances, many LDCs and natural gas pipelines have either voluntarily waived or have sought applicable regulatory approvals to waive the tariff penalties associated with the extreme weather event. During March 2021, three natural gas pipelines filed individual petitions with FERC requesting approval to waive OFO penalties. Generation also filed motions in March 2021 to intervene and filed comments in support of these FERC waiver requests. On March 25, 2021, FERC issued an order on one of the petitions approving a pipeline’s request for a limited waiver of penalties for February 15, 2021. On April 23, 2021, Generation and several other entities filed a request at FERC for rehearing of this order which was denied on May 24, 2021. Generation and the other entities filed an appeal of the rehearing of the order with the U.S. Court of Appeals for the D.C. Circuit on July 21, 2021. Additionally, Generation and the other entities filed a complaint requesting that FERC expand the order to include additional days of the weather event in February, from February 16 through February 19, 2021. On October 21, 2021, FERC denied the complaint finding that a pipeline has the discretion whether to waive penalties under its tariff. Generation is evaluating whether to seek rehearing and appeal of the FERC order. During April 2021, FERC issued orders on the remaining petitions approving the requests to waive the penalties. During May 2021, an LDC filed a motion with the Kansas Corporation Commission (KCC) requesting the KCC to grant a waiver from the tariff and allow the LDC to reduce the amounts assessed by permitting the removal of a multiplier from the penalty calculation. On October 8, 2021, a settlement was filed with the KCC that, if approved, would resolve this matter. Exelon and Generation cannot predict the outcome of the pending FERC complaint proceeding, the KCC proceeding, or the determinations made by the LDCs and natural gas pipelines.

Illinois Regulatory Matters

Clean Energy Law. See Clean Energy Law above for additional information related to Generation. See Note 7 – Early Plant Retirements for additional information on Generation’s Illinois nuclear plants.

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. On March 19, 2021, a three-judge panel of the Superior Court of New Jersey Appellate Division unanimously affirmed the NJBPU’s April 2019 order awarding ZECs for the first eligibility period. On April 8, 2021, New Jersey Rate Counsel filed a notice asking the New Jersey Supreme Court to hear the appeal of the Superior Court’s order. On July 9, 2021, the New Jersey Supreme Court declined to hear the appeal. On October 1, 2020, PSEG and Generation filed applications seeking ZECs for the second eligibility period (June 2022 through May 2025). On April 27, 2021, the NJBPU approved the award of ZECs to Salem 1 and Salem 2 for the second eligibility period. On May 11, 2021, the New Jersey Rate Counsel appealed the April 27, 2021 decision to the Superior Court of New Jersey Appellate Division. Briefing on the appeal is expected to conclude in the fourth quarter of 2021 or first quarter of 2022. Exelon and Generation cannot predict the outcome of this proceeding.

New England Regulatory Matters

Mystic Units 8 and 9 and Everett Marine Terminal Cost of Service Agreement. 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 15, 2021, FERC issued an order establishing the ROE to be used in the cost of service agreement for Mystic 8 and 9 at 9.33%. On August 16, 2021, Exelon and several other parties filed requests for rehearing of certain aspects of the July 15, 2021 order. These requests were denied by operation of law; however, FERC indicated it would address the issues raised in the request in a future 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. In addition, several parties filed protests to a compliance filing by Generation on September 15, 2020, taking issue with how gross plant in-service was calculated, and Generation filed an answer to the protests on October 21, 2020. On December 21, 2020, FERC issued an order on rehearing of the three July 17, 2020 orders, clarifying several cost of service provisions. Several parties appealed the December 21, 2020 order to the U.S. Court of Appeals for the D.C. Circuit and that appeal was consolidated with appeals of orders issued December 20, 2018 and July 17, 2020 in the Mystic proceeding. Briefs in support of their petitions for review were filed by Exelon and several other parties on September 7, 2021. Briefing is expected to conclude in February 2022.

On February 25, 2021, Mystic made its filing to comply with the December 21, 2020 order. On April 26, 2021, FERC rejected Mystic’s language and directed another compliance filing relating to the claw back provision language, which only applies if Mystic 8 and 9 were to continue operation after the conclusion of the cost-of-service period. FERC’s April 26, 2021 order also accepted in part and rejected in part Mystic’s September 15, 2020 compliance filing. It directed a further compliance filing in 60 days consistent with the information provided

in Mystic’s October 21, 2020 answer to protests, which Mystic filed on June 2, 2021 and FERC accepted on July 29, 2021. On August 16, 2021, Mystic made a compliance filing, reflecting changes to the cost of service agreement to comply with the July 15, 2021 order on ROE.

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 April 15, 2021 FERC dismissed the complaint.

On February 16, 2021, Generation filed an unopposed motion to voluntarily dismiss an appeal filed with the U.S. Court of Appeals for the D.C. Circuit stemming from a June 2020 complaint filed with FERC against ISO-NE over failures to follow its tariff in evaluating Mystic for transmission security for the 2024 to 2025 Capacity Commitment Period, which was granted on February 18, 2021.

See Note 7 — Early Plant Retirements for additional information on the impacts of Generation’s August 2020 decision to retire Mystic Units 8 and 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 nuclear facilities in PJM and NYISO that are currently receiving state-supported compensation for carbon-free attributes, an expanded MOPR would require exclusion of such 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 expanded the breadth and scope of PJM’s MOPR, which became effective as of PJM’s capacity auction for the 2022-23 planning year. While FERC included some limited exemptions, no exemptions were available to state-supported nuclear resources.

FERC 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.

A number of parties, including Exelon, have filed petitions for review of FERC's orders in this proceeding, which remain pending before the Court of Appeals for the District of Columbia Circuit.

As a result, the MOPR applied in the capacity auction for the 2022-23 planning year to Generation's owned or jointly owned nuclear plants in those states receiving a benefit under the Illinois ZES and the New Jersey ZEC program. The MOPR prevented Quad Cities from clearing in that capacity auction.

At the direction of the PJM Board of Managers, PJM and its stakeholders developed further MOPR reforms to ensure that the capacity market rules respect and accommodate state resource preferences such as the ZEC programs. PJM filed related tariff revisions at FERC on July 30, 2021 and, on September 29, 2021, PJM's proposed MOPR reforms became effective by operation of law. Under the new tariff provisions, the MOPR will no longer apply to any of Generation’s owned or jointly owned nuclear plants. A request for rehearing of FERC’s

notice establishing the effective date for PJM’s proposed market reforms was filed on October 5, 2021 and remains pending.

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 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 an 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 had been working with MDE and other stakeholders to resolve water quality licensing issues, including: (1) water quality, (2) fish habitat, and (3) sediment.

On April 27, 2018, MDE issued its 401 Certification for Conowingo. 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.

On March 19, 2021, FERC issued a new 50-year license for Conowingo, effective March 1, 2021. FERC adopted the Proposed License Articles into the new license only making modifications it deemed necessary to allow FERC to enforce the Proposed License Articles. Consistent with the Offer of Settlement, FERC found that MDE waived its 401 Certification. On April 19, 2021, a few environmental groups filed with FERC a petition for rehearing requesting that FERC reconsider the issuance of the new Conowingo license, which was denied by operation of law on May 20, 2021. On June 17, 2021, the petitioners appealed FERC’s ruling to the United States Court of Appeals. On July 15, 2021, FERC issued an order addressing the arguments raised on rehearing, affirming the determinations of its March 19, 2021 order. Generation cannot predict the outcome of this proceeding.

Revenue from Contracts with Customers (All Registrants)

9 Months Ended

Sep. 30, 2021

Revenue from Contract with Customer [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.

See Note 4 — Revenue from Contracts with Customers of the Exelon 2020 Form 10-K for additional information regarding the primary sources of revenue for the Registrants.

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 in Other current assets and Customer accounts receivable, net, respectively, in 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 for the three and nine months ended September 30, 2021 and 2020. The Utility Registrants do not have any contract assets.



	Exelon		Generation
Balance as of December 31, 2020	$	144	$	144
Amounts reclassified to receivables	(16)		(16)
Revenues recognized	13		13
Amounts previously held-for-sale	12		12
Balance as of March 31, 2021	153		153
Amounts reclassified to receivables	(12)		(12)
Revenues recognized	9		9
Balance as of June 30, 2021	150		150
Amounts reclassified to receivables	(15)		(15)
Revenues recognized	14		14

Balance as of September 30, 2021	$	149	$	149


	Exelon		Generation
Balance as of December 31, 2019	$	174	$	174
Amounts reclassified to receivables	(19)		(19)
Revenues recognized	17		17

Balance as of March 31, 2020	172		172
Amounts reclassified to receivables	(26)		(26)
Revenues recognized	13		13
Balance as of June 30, 2020	159		159
Amounts reclassified to receivables	(18)		(18)
Revenues recognized	19		19
Balance as of September 30, 2020	$	160	$	160

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 in Other current liabilities and Other noncurrent liabilities in the Registrants' Consolidated Balance Sheets.

For Generation, these contract liabilities primarily relate to upfront consideration received or due for equipment service plans and the Illinois ZEC program that introduces a cap on the total consideration to be received by Generation.

For PHI, Pepco, DPL, and ACE these contract liabilities primarily relate to upfront consideration received in the third quarter of 2020 for a collaborative arrangement with an unrelated owner and manager of communication infrastructure. 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 for the three and nine months ended September 30, 2021 and 2020. As of September 30, 2021 and December 31, 2020, ComEd's, PECO's, and BGE's contract liabilities were immaterial.



	Exelon		Generation		PHI		Pepco		DPL		ACE
Balance as of December 31, 2020	$	151	$	84	$	118	$	94	$	12	$	12
Consideration received or due	20		31		—		—		—		—
Revenues recognized	(27)		(64)		(2)		(2)		—		—
Amounts previously held-for-sale	3		3		—		—		—		—
Balance as of March 31, 2021	147		54		116		92		12		12
Consideration received or due	17		39		—		—		—		—
Revenues recognized	(32)		(68)		(3)		(1)		(1)		(1)

Balance as of June 30, 2021	132		25		113		91		11		11
Consideration received or due	31		93		—		—		—		—
Revenues recognized	(26)		(65)		(2)		(2)		—		—
Balance as of September 30, 2021	$	137	$	53	$	111	$	89	$	11	$	11


	Exelon		Generation		PHI		Pepco		DPL		ACE
Balance as of December 31, 2019	$	33	$	71	$	—	$	—	$	—	$	—
Consideration received or due	20		55		—		—		—		—
Revenues recognized	(24)		(70)		—		—		—		—
Balance as of March 31, 2020	29		56		—		—		—		—
Consideration received or due	13		34		—		—		—		—
Revenues recognized	(22)		(63)		—		—		—		—
Balance as of June 30, 2020	20		27		—		—		—		—
Consideration received or due	154		94		124		98		13		13
Revenues recognized	(25)		(65)		(2)		(2)		—		—
Balance as of September 30, 2020	$	149	$	56	$	122	$	96	$	13	$	13

The following table reflects revenues recognized in the three and nine months ended September 30, 2021 and 2020, which were included in contract liabilities at December 31, 2020 and 2019, respectively:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Exelon	$	4	$	2	$	38	$	25
Generation	2		2		81		63
PHI	2		—		7		—
Pepco	2		—		5		—
DPL	—		—		1		—
ACE	—		—		1		—

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 September 30, 2021. 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	$	82	$	125	$	50	$	35	$	184	$	476
Generation	168		281		92		41		97		679
PHI	2		8		8		6		87		111
Pepco	2		6		6		5		70		89
DPL	—		1		1		—		9		11
ACE	—		1		1		1		8		11

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
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Reference 3: http://www.xbrl.org/2003/role/disclosureRef
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Segment Information (All Registrants)

Segment Information (All Registrants)

9 Months Ended

Sep. 30, 2021

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 the 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 Revenues Net of Purchased Power and Fuel Expense (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 three and nine months ended September 30, 2021 and 2020 is as follows:

Three Months Ended September 30, 2021 and 2020



	Generation		ComEd		PECO		BGE		PHI		Other(a)		Intersegment Eliminations		Exelon
Operating revenues(b):
2021
Competitive businesses electric revenues	$	4,330	$	—	$	—	$	—	$	—	$	—	$	(319)	$	4,011
Competitive businesses natural gas revenues	575		—		—		—		—		—		—		575
Competitive businesses other revenues	(499)		—		—		—		—		—		(3)		(502)
Rate-regulated electric revenues	—		1,789		762		677		1,444		—		(15)		4,657
Rate-regulated natural gas revenues	—		—		56		93		23		—		(3)		169
Shared service and other revenues	—		—		—		—		3		534		(537)		—
Total operating revenues	$	4,406	$	1,789	$	818	$	770	$	1,470	$	534	$	(877)	$	8,910
2020
Competitive businesses electric revenues	$	4,201	$	—	$	—	$	—	$	—	$	—	$	(326)	$	3,875
Competitive businesses natural gas revenues	323		—		—		—		—		—		—		323
Competitive businesses other revenues	135		—		—		—		—		—		(3)		132
Rate-regulated electric revenues	—		1,643		759		646		1,339		—		(22)		4,365
Rate-regulated natural gas revenues	—		—		54		85		23		—		(3)		159
Shared service and other revenues	—		—		—		—		6		484		(491)		(1)


Total operating revenues	$	4,659	$	1,643	$	813	$	731	$	1,368	$	484	$	(845)	$	8,853


	Generation		ComEd		PECO		BGE		PHI		Other(a)		Intersegment Eliminations		Exelon
Intersegment revenues(c):
2021	$	324	$	9	$	2	$	7	$	3	$	531	$	(876)	$	—
2020	331		15		3		6		6		485		(845)		1
Depreciation and amortization:
2021	$	866	$	304	$	86	$	142	$	210	$	16	$	—	$	1,624
2020	558		294		85		133		200		19		—		1,289
Operating expenses:
2021	$	3,465	$	1,428	$	677	$	709	$	1,155	$	541	$	(858)	$	7,117
2020	4,727		1,302		658		642		1,102		489		(833)		8,087
Interest expense, net:
2021	$	77	$	98	$	40	$	36	$	67	$	79	$	—	$	397
2020	80		95		39		34		67		89		—		404
Income (loss) before income taxes:
2021	$	814	$	276	$	108	$	32	$	264	$	(88)	$	—	$	1,406
2020	219		256		122		61		215		(87)		—		786
Income Taxes:
2021	$	177	$	56	$	(3)	$	(4)	$	(2)	$	(50)	$	—	$	174
2020	100		60		(16)		8		(1)		65		—		216
Net income (loss):
2021	$	633	$	220	$	111	$	36	$	266	$	(37)	$	—	$	1,229
2020	117		196		138		53		216		(151)		—		569
Capital Expenditures:
2021	$	367	$	561	$	301	$	287	$	410	$	4	$	—	$	1,930
2020	282		554		312		290		386		9		—		1,833

(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 18 — 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 19— Related Party Transactions for additional information on intersegment revenues.

PHI:



	Pepco		DPL		ACE		Other(a)		Intersegment Eliminations		PHI
Operating revenues(b):
2021
Rate-regulated electric revenues	$	660	$	337	$	451	$	—	$	(4)	$	1,444
Rate-regulated natural gas revenues	—		23		—		—		—		23
Shared service and other revenues	—		—		—		92		(89)		3
Total operating revenues	$	660	$	360	$	451	$	92	$	(93)	$	1,470
2020
Rate-regulated electric revenues	$	611	$	314	$	420	$	—	$	(6)	$	1,339
Rate-regulated natural gas revenues	—		23		—		—		—		23
Shared service and other revenues	—		—		—		91		(85)		6
Total operating revenues	$	611	$	337	$	420	$	91	$	(91)	$	1,368
Intersegment revenues(c):
2021	$	2	$	2	$	1	$	91	$	(93)	$	3
2020	3		3		1		90		(91)		6
Depreciation and amortization:
2021	$	104	$	53	$	46	$	7	$	—	$	210
2020	96		48		48		8		—		200
Operating expenses:
2021	$	501	$	295	$	359	$	93	$	(93)	$	1,155
2020	465		296		338		94		(91)		1,102
Interest expense, net:
2021	$	35	$	15	$	14	$	3	$	—	$	67
2020	35		15		15		2		—		67
Income (loss) before income taxes:
2021	$	136	$	53	$	79	$	(4)	$	—	$	264
2020	121		28		68		(2)		—		215
Income Taxes:
2021	$	6	$	3	$	(11)	$	—	$	—	$	(2)
2020	3		1		(7)		2		—		(1)
Net income (loss):
2021	$	130	$	50	$	90	$	(4)	$	—	$	266
2020	118		27		75		(4)		—		216
Capital Expenditures:
2021	$	202	$	109	$	97	$	2	$	—	$	410
2020	188		94		103		1		—		386

__________

(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.

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):


	Three Months Ended September 30, 2021
	Revenues from external customers(a)						Intersegment Revenues		Total Revenues
	Contracts with customers		Other(b)		Total
Mid-Atlantic	$	1,145	$	123	$	1,268	$	4	$	1,272
Midwest	1,084		(99)		985		—		985
New York	445		10		455		—		455
ERCOT	191		165		356		2		358
Other Power Regions	948		318		1,266		(6)		1,260
Total Competitive Businesses Electric Revenues	3,813		517		4,330		—		4,330
Competitive Businesses Natural Gas Revenues	266		309		575		—		575
Competitive Businesses Other Revenues(c)	95		(594)		(499)		—		(499)
Total Generation Consolidated Operating Revenues	$	4,174	$	232	$	4,406	$	—	$	4,406


	Three Months Ended September 30, 2020
	Revenues from external customers(a)						Intersegment revenues		Total Revenues
	Contracts with customers		Other(b)		Total
Mid-Atlantic	$	1,327	$	(20)	$	1,307	$	6	$	1,313
Midwest	974		68		1,042		1		1,043
New York	401		5		406		—		406
ERCOT	249		74		323		7		330
Other Power Regions	937		186		1,123		(14)		1,109
Total Competitive Businesses Electric Revenues	3,888		313		4,201		—		4,201
Competitive Businesses Natural Gas Revenues	169		154		323		—		323
Competitive Businesses Other Revenues(c)	85		50		135		—		135
Total Generation Consolidated Operating Revenues	$	4,142	$	517	$	4,659	$	—	$	4,659

__________

(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)Other represents activities not allocated to a region. See text above for a description of included activities. Includes unrealized mark-to-market losses of $635 million and gains of $37 million in 2021 and 2020, respectively, and elimination of intersegment revenues.

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


	Three Months Ended September 30, 2021						Three Months Ended September 30, 2020
	RNF from external customers(a)		Intersegment RNF		Total RNF		RNF from external customers(a)		Intersegment RNF		Total RNF
Mid-Atlantic	$	567	$	3	$	570	$	586	$	5	$	591
Midwest	655		—		655		748		2		750
New York	343		3		346		281		4		285
ERCOT	181		(2)		179		141		6		147
Other Power Regions	233		(22)		211		253		(28)		225
Total RNF for Reportable Segments	1,979		(18)		1,961		2,009		(11)		1,998
Other(b)	881		18		899		336		11		347
Total Generation RNF	$	2,860	$	—	$	2,860	$	2,345	$	—	$	2,345

__________

(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. includes:

•unrealized mark-to-market gains of $754 million and gains of $255 million in 2021 and 2020, respectively;

•accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 7 — Early Plant Retirements of $42 million and $24 million in 2021 and 2020 respectively; and

•the elimination of intersegment RNF.

Electric and Gas Revenue by Customer Class (Utility Registrants):


	Three Months Ended September 30, 2021
Revenues from contracts with customers	ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Rate-regulated electric revenues
Residential	$	978	$	509	$	383	$	782	$	309	$	198	$	275
Small commercial & industrial	433		113		73		150		36		53		61
Large commercial & industrial	148		67		128		320		244		27		49
Public authorities & electric railroads	11		7		7		15		8		4		3
Other(a)	245		61		104		172		53		56		63
Total rate-regulated electric revenues(b)	$	1,815	$	757	$	695	$	1,439	$	650	$	338	$	451
Rate-regulated natural gas revenues
Residential	$	—	$	36	$	57	$	10	$	—	$	10	$	—
Small commercial & industrial	—		13		10		5		—		5		—
Large commercial & industrial	—		—		22		2		—		2		—
Transportation	—		5		—		3		—		3		—
Other(c)	—		2		6		3		—		3		—
Total rate-regulated natural gas revenues(d)	$	—	$	56	$	95	$	23	$	—	$	23	$	—
Total rate-regulated revenues from contracts with customers	$	1,815	$	813	$	790	$	1,462	$	650	$	361	$	451

Other revenues
Revenues from alternative revenue programs	$	(32)	$	3	$	(24)	$	6	$	9	$	(2)	$	—
Other rate-regulated electric revenues(e)	6		2		3		2		1		1		—
Other rate-regulated natural gas revenues(e)	—		—		1		—		—		—		—

Total other revenues	$	(26)	$	5	$	(20)	$	8	$	10	$	(1)	$	—
Total rate-regulated revenues for reportable segments	$	1,789	$	818	$	770	$	1,470	$	660	$	360	$	451


	Three Months Ended September 30, 2020
Revenues from contracts with customers	ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Rate-regulated electric revenues
Residential	$	920	$	518	$	389	$	763	$	307	$	193	$	263
Small commercial & industrial	379		104		65		134		36		45		53
Large commercial & industrial	135		66		113		262		195		21		46
Public authorities & electric railroads	10		7		7		14		8		3		3
Other(a)	234		58		78		141		47		44		50
Total rate-regulated electric revenues(b)	$	1,678	$	753	$	652	$	1,314	$	593	$	306	$	415
Rate-regulated natural gas revenues
Residential	$	—	$	32	$	55	$	11	$	—	$	11	$	—
Small commercial & industrial	—		16		9		6		—		6		—
Large commercial & industrial	—		—		21		1		—		1		—
Transportation	—		6		—		3		—		3		—
Other(c)	—		1		3		2		—		2		—
Total rate-regulated natural gas revenues(d)	$	—	$	55	$	88	$	23	$	—	$	23	$	—
Total rate-regulated revenues from contracts with customers	$	1,678	$	808	$	740	$	1,337	$	593	$	329	$	415

Other revenues
Revenues from alternative revenue programs	$	(38)	$	5	$	(9)	$	31	$	18	$	8	$	5
Other rate-regulated electric revenues(e)	3		—		—		—		—		—		—
Other rate-regulated natural gas revenues(e)	—		—		—		—		—		—		—

Total other revenues	$	(35)	$	5	$	(9)	$	31	$	18	$	8	$	5
Total rate-regulated revenues for reportable segments	$	1,643	$	813	$	731	$	1,368	$	611	$	337	$	420

__________

(a)Includes revenues from transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue.

(b)Includes operating revenues from affiliates in 2021 and 2020 respectively of:

•$9 million, $15 million at ComEd

•$2 million, $3 million at PECO

•$4 million, $3 million at BGE

•$3 million, $6 million at PHI

•$2 million, $3 million at Pepco

•$2 million, $3 million at DPL

•$1 million, $1 million at ACE

(c)Includes revenues from off-system natural gas sales.

(d)Includes operating revenues from affiliates in 2021 and 2020 respectively of:

•less than $1 million at PECO both 2021 and 2020

•$3 million, $3 million at BGE

(e)Includes late payment charge revenues.

Nine Months Ended September 30, 2021 and 2020


	Generation		ComEd		PECO		BGE		PHI		Other(a)		Intersegment Eliminations		Exelon
Operating revenues(b):
2021
Competitive businesses electric revenues	$	12,264	$	—	$	—	$	—	$	—	$	—	$	(860)	$	11,404


	Generation		ComEd		PECO		BGE		PHI		Other(a)		Intersegment Eliminations		Exelon
Competitive businesses natural gas revenues	2,408		—		—		—		—		—		—		2,408
Competitive businesses other revenues	(555)		—		—		—		—		—		(9)		(564)
Rate-regulated electric revenues	—		4,840		2,033		1,866		3,726		—		(33)		12,432
Rate-regulated natural gas revenues	—		—		366		560		118		—		(9)		1,035
Shared service and other revenues	—		—		—		—		10		1,549		(1,559)		—
Total operating revenues	$	14,117	$	4,840	$	2,399	$	2,426	$	3,854	$	1,549	$	(2,470)	$	26,715
2020
Competitive businesses electric revenues	$	11,367	$	—	$	—	$	—	$	—	$	—	$	(920)	$	10,447
Competitive businesses natural gas revenues	1,348		—		—		—		—		—		(3)		1,345
Competitive businesses other revenues	557		—		—		—		—		—		(5)		552
Rate-regulated electric revenues	—		4,499		1,948		1,763		3,425		—		(50)		11,585
Rate-regulated natural gas revenues	—		—		358		521		116		—		(5)		990
Shared service and other revenues	—		—		—		—		13		1,440		(1,447)		6
Total operating revenues	$	13,272	$	4,499	$	2,306	$	2,284	$	3,554	$	1,440	$	(2,430)	$	24,925

Intersegment revenues(c):
2021	$	872	$	19	$	6	$	20	$	10	$	1,542	$	(2,469)	$	—
2020	932		31		7		16		13		1,435		(2,430)		4
Depreciation and amortization:
2021	$	2,735	$	893	$	259	$	434	$	614	$	52	$	1	$	4,988
2020	1,161		841		259		405		585		61		—		3,312
Operating expenses:
2021	$	14,605	$	3,833	$	1,908	$	2,080	$	3,167	$	1,572	$	(2,407)	$	24,758
2020	12,674		3,798		1,900		1,903		3,057		1,452		(2,397)		22,387
Interest expense, net:
2021	$	225	$	292	$	119	$	103	$	201	$	241	$	(1)	$	1,180
2020	277		287		108		99		201		269		—		1,241


	Generation		ComEd		PECO		BGE		PHI		Other(a)		Intersegment Eliminations		Exelon
Income (loss) before income taxes:
2021	$	(8)	$	750	$	392	$	266	$	538	$	(264)	$	1	$	1,675
2020	532		446		310		299		340		(262)		—		1,665
Income Taxes:
2021	$	108	$	141	$	9	$	(24)	$	3	$	(8)	$	—	$	229
2020	41		142		(7)		26		(77)		16		—		141
Net income (loss):
2021	$	(122)	$	609	$	383	$	290	$	535	$	(255)	$	1	$	1,441
2020	485		304		317		273		418		(278)		—		1,519
Capital Expenditures:
2021	$	1,086	$	1,723	$	878	$	907	$	1,299	$	77	$	—	$	5,970
2020	1,212		1,583		824		838		1,072		77		—		5,606
Total assets:
September 30, 2021	$	48,010	$	36,002	$	13,733	$	12,197	$	24,502	$	8,387	$	(10,210)	$	132,621
December 31, 2020	48,094		34,466		12,531		11,650		23,736		9,005		(10,165)		129,317

__________

(a)Other primarily includes Exelon’s corporate operations, shared service entities, and other financing and investment activities.

(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 19 — Related Party Transactions for additional information on intersegment revenues.

PHI:


	Pepco		DPL		ACE		Other(a)		Intersegment Eliminations		PHI
Operating revenues(b):
2021
Rate-regulated electric revenues	$	1,736	$	922	$	1,080	$	—	$	(12)	$	3,726
Rate-regulated natural gas revenues	—		118		—		—		—		118
Shared service and other revenues	—		—		—		281		(271)		10
Total operating revenues	$	1,736	$	1,040	$	1,080	$	281	$	(283)	$	3,854
2020
Rate-regulated electric revenues	$	1,650	$	838	$	952	$	—	$	(15)	$	3,425
Rate-regulated natural gas revenues	—		116		—		—		—		116
Shared service and other revenues	—		—		—		279		(266)		13
Total operating revenues	$	1,650	$	954	$	952	$	279	$	(281)	$	3,554
Intersegment revenues(c):
2021	$	4	$	6	$	2	$	281	$	(283)	$	10
2020	6		7		3		278		(281)		13
Depreciation and amortization:
2021	$	302	$	157	$	133	$	22	$	—	$	614
2020	282		143		134		26		—		585
Operating expenses:
2021	$	1,396	$	858	$	911	$	285	$	(283)	$	3,167
2020	1,364		843		847		284		(281)		3,057
Interest expense, net:
2021	$	104	$	47	$	43	$	7	$	—	$	201
2020	103		47		45		6		—		201
Income (loss) before income taxes:
2021	$	273	$	144	$	129	$	(8)	$	—	$	538
2020	211		71		67		(9)		—		340
Income Taxes:
2021	$	9	$	9	$	(12)	$	(3)	$	—	$	3
2020	(16)		(20)		(39)		(2)		—		(77)
Net income (loss):
2021	$	264	$	135	$	141	$	(5)	$	—	$	535
2020	227		91		106		(6)		—		418
Capital Expenditures:
2021	$	641	$	320	$	336	$	2	$	—	$	1,299
2020	512		278		281		1		—		1,072
Total assets:
September 30, 2021	$	9,748	$	5,295	$	4,532	$	4,977	$	(50)	$	24,502
December 31, 2020	9,264		5,140		4,286		5,079		(33)		23,736

__________

(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.

Competitive Business Revenues (Generation):



	Nine Months Ended September 30, 2021
	Revenues from external customers(a)						Intersegment Revenues		Total Revenues
	Contracts with customers		Other(b)		Total
Mid-Atlantic	$	3,377	$	134	$	3,511	$	16	$	3,527
Midwest	3,067		(123)		2,944		1		2,945
New York	1,204		(30)		1,174		(1)		1,173
ERCOT	724		155		879		11		890
Other Power Regions	3,043		713		3,756		(27)		3,729
Total Competitive Businesses Electric Revenues	11,415		849		12,264		—		12,264
Competitive Businesses Natural Gas Revenues	1,384		1,024		2,408		—		2,408
Competitive Businesses Other Revenues(c)	291		(846)		(555)		—		(555)
Total Generation Consolidated Operating Revenues	$	13,090	$	1,027	$	14,117	$	—	$	14,117



	Nine Months Ended September 30, 2020
	Revenues from external customers(a)						Intersegment revenues		Total Revenues
	Contracts with customers		Other(b)		Total
Mid-Atlantic	$	3,692	$	(152)	$	3,540	$	21	$	3,561
Midwest	2,773		240		3,013		(6)		3,007
New York	1,074		(12)		1,062		(1)		1,061
ERCOT	579		155		734		20		754
Other Power Regions	2,718		300		3,018		(34)		2,984
Total Competitive Businesses Electric Revenues	10,836		531		11,367		—		11,367
Competitive Businesses Natural Gas Revenues	881		467		1,348		—		1,348
Competitive Businesses Other Revenues(c)	268		289		557		—		557
Total Generation Consolidated Operating Revenues	$	11,985	$	1,287	$	13,272	$	—	$	13,272

__________

(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)Other represents activities not allocated to a region. See text above for a description of included activities. Includes unrealized mark-to-market losses of $958 million and gains of $238 million in 2021 and 2020, respectively, and elimination of intersegment revenues.

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



	Nine Months Ended September 30, 2021						Nine Months Ended September 30, 2020
	RNF from external customers(a)		Intersegment RNF		Total RNF		RNF from external customers(a)		Intersegment RNF		Total RNF
Mid-Atlantic	$	1,698	$	14	$	1,712	$	1,660	$	23	$	1,683
Midwest	2,014		1		2,015		2,180		(2)		2,178
New York	873		7		880		714		11		725
ERCOT	(775)		(147)		(922)		311		14		325
Other Power Regions	641		(77)		564		608		(70)		538
Total RNF for Reportable Segments	4,451		(202)		4,249		5,473		(24)		5,449
Other(b)	1,563		202		1,765		838		24		862
Total Generation RNF	$	6,014	$	—	$	6,014	$	6,311	$	—	$	6,311

__________

(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 $1,242 million and gains of $472 million in 2021 and 2020, respectively;

•accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 7 — Early Plant Retirements of $148 million and $24 million in 2021 and 2020 respectively; and

• the elimination of intersegment RNF.

Electric and Gas Revenue by Customer Class (Utility Registrants):



	Nine Months Ended September 30, 2021
Revenues from contracts with customers	ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Rate-regulated electric revenues
Residential	$	2,479	$	1,325	$	1,044	$	1,924	$	785	$	535	$	604
Small commercial & industrial	1,176		312		202		392		101		145		146
Large commercial & industrial	420		183		342		825		616		70		139
Public authorities & electric railroads	33		24		20		45		24		11		10
Other(a)	676		167		269		453		154		143		158
Total rate-regulated electric revenues(b)	$	4,784	$	2,011	$	1,877	$	3,639	$	1,680	$	904	$	1,057
Rate-regulated natural gas revenues
Residential	$	—	$	251	$	354	$	67	$	—	$	67	$	—
Small commercial & industrial	—		94		59		29		—		29		—
Large commercial & industrial	—		—		103		5		—		5		—
Transportation	—		17		—		11		—		11		—
Other(c)	—		4		41		6		—		6		—
Total rate-regulated natural gas revenues(d)	$	—	$	366	$	557	$	118	$	—	$	118	$	—
Total rate-regulated revenues from contracts with customers	$	4,784	$	2,377	$	2,434	$	3,757	$	1,680	$	1,022	$	1,057

Other revenues
Revenues from alternative revenue programs	$	32	$	20	$	(17)	$	94	$	54	$	17	$	23
Other rate-regulated electric revenues(e)	24		2		7		3		2		1		—
Other rate-regulated natural gas revenues(e)	—		—		2		—		—		—		—

Total other revenues	$	56	$	22	$	(8)	$	97	$	56	$	18	$	23
Total rate-regulated revenues for reportable segments	$	4,840	$	2,399	$	2,426	$	3,854	$	1,736	$	1,040	$	1,080



	Nine Months Ended September 30, 2020
Revenues from contracts with customers	ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Rate-regulated electric revenues
Residential	$	2,389	$	1,277	$	1,034	$	1,825	$	779	$	501	$	545
Small commercial & industrial	1,067		291		183		355		101		127		127
Large commercial & industrial	388		174		311		755		558		66		131
Public authorities & electric railroads	33		21		20		45		25		10		10
Other(a)	663		171		233		471		166		148		159
Total rate-regulated electric revenues(b)	$	4,540	$	1,934	$	1,781	$	3,451	$	1,629	$	852	$	972
Rate-regulated natural gas revenues
Residential	$	—	$	252	$	342	$	68	$	—	$	68	$	—
Small commercial & industrial	—		86		55		30		—		30		—
Large commercial & industrial	—		—		96		3		—		3		—
Transportation	—		18		—		10		—		10		—
Other(c)	—		3		16		5		—		5		—
Total rate-regulated natural gas revenues(d)	$	—	$	359	$	509	$	116	$	—	$	116	$	—
Total rate-regulated revenues from contracts with customers	$	4,540	$	2,293	$	2,290	$	3,567	$	1,629	$	968	$	972

Other revenues
Revenues from alternative revenue programs	$	(51)	$	10	$	(10)	$	(15)	$	20	$	(15)	$	(20)
Other rate-regulated electric revenues(e)	10		3		3		2		1		1		—
Other rate-regulated natural gas revenues(e)	—		—		1		—		—		—		—

Total other revenues	$	(41)	$	13	$	(6)	$	(13)	$	21	$	(14)	$	(20)
Total rate-regulated revenues for reportable segments	$	4,499	$	2,306	$	2,284	$	3,554	$	1,650	$	954	$	952

__________

(a)Includes revenues from transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue.

(b)Includes operating revenues from affiliates in 2021 and 2020 respectively of:

•$19 million, $31 million at ComEd

•$5 million, $6 million at PECO

•$10 million, $9 million at BGE

•$10 million, $13 million at PHI

•$4 million, $6 million at Pepco

•$6 million, $7 million at DPL

•$2 million, $3 million at ACE

(c)Includes revenues from off-system natural gas sales.

(d)Includes operating revenues from affiliates in 2021 and 2020 respectively of:

•$1 million, $1 million at PECO

•$10 million, $7 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.

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Accounts Receivable (All Registrants) [Text Block]

Accounts Receivable (All Registrants)

9 Months Ended

Sep. 30, 2021

Credit Loss [Abstract]

Accounts Receivable (All Registrants)

Allowance for Credit Losses on Accounts Receivable (All Registrants)

The following tables present the rollforward of Allowance for Credit Losses on Customer Accounts Receivable.


	Three Months Ended September 30, 2021
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance as of June 30, 2021	$	395	$	75	$	89	$	111	$	27	$	93	$	38	$	19	$	36
Plus: Current period provision for expected credit losses(a)	47		10		11		1		7		18		5		3		10
Less: Write-offs, net of recoveries(b)	33		1		12		11		3		6		2		4		—

Balance as of September 30, 2021	$	409	$	84	$	88	$	101	$	31	$	105	$	41	$	18	$	46

	Three Months Ended September 30, 2020
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance as of June 30, 2020	$	261	$	33	$	72	$	71	$	23	$	62	$	24	$	18	$	20
Plus: Current period provision for expected credit losses(c)	114		1		37		27		14		35		11		7		17
Less: Write-offs, net of recoveries(b)	17		1		4		2		2		8		—		3		5

Balance as of September 30, 2020	$	358	$	33	$	105	$	96	$	35	$	89	$	35	$	22	$	32


















	Nine Months Ended September 30, 2021
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance as of December 31, 2020	$	366	$	32	$	97	$	116	$	35	$	86	$	32	$	22	$	32
Plus: Current period provision for expected credit losses(d)	122		57		23		7		2		33		15		4		14
Less: Write-offs, net of recoveries(b)	79		5		32		22		6		14		6		8		—

Balance as of September 30, 2021	$	409	$	84	$	88	$	101	$	31	$	105	$	41	$	18	$	46

	Nine Months Ended September 30, 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(c)	222		13		62		56		28		63		24		14		25
Less: Write-offs, net of recoveries(b)	51		4		16		15		5		11		2		3		6
Less: Sale of customer accounts receivable(e)	56		56		—		—		—		—		—		—		—
Balance as of September 30, 2020	$	358	$	33	$	105	$	96	$	35	$	89	$	35	$	22	$	32

__________

(a)For ACE, the increase is primarily a result of increased aging of receivables and a slight decrease in the expected recovery rate.

(b)Recoveries were not material to the Registrants.

(c)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 reconnections of service to customers previously disconnected due to COVID-19.

(d)For Generation, primarily relates to the impacts of the February 2021 extreme cold weather event. See Note 3 — Regulatory Matters for additional information. For PHI, Pepco, and ACE, the increase is primarily a result of increased aging of receivables and a slight decrease in the expected recovery rate.

(e)See below for additional information on the sale of customer accounts receivable at Generation in the second quarter of 2020.

The following tables present the rollforward of Allowance for Credit Losses on Other Accounts Receivable.


	Three Months Ended September 30, 2021
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance as of June 30, 2021	$	72	$	1	$	18	$	7	$	8	$	38	$	16	$	9	$	13
Plus: Current period provision for expected credit losses	9		3		2		1		1		2		1		(1)		2
Less: Write-offs, net of recoveries(a)	4		—		1		1		1		—		—		—		—
Balance as of September 30, 2021	$	77	$	4	$	19	$	7	$	8	$	40	$	17	$	8	$	15

	Three Months Ended September 30, 2020
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance as of June 30, 2020	$	61	$	—	$	22	$	7	$	6	$	26	$	11	$	7	$	8
Plus: Current period provision for expected credit losses	15		—		5		1		3		6		2		1		3
Less: Write-offs, net of recoveries(a)	1		—		—		1		—		—		—		—		—
Balance as of September 30, 2020	$	75	$	—	$	27	$	7	$	9	$	32	$	13	$	8	$	11

	Nine Months Ended September 30, 2021
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance as of December 31, 2020	$	71	$	—	$	21	$	8	$	9	$	33	$	13	$	9	$	11
Plus: Current period provision for expected credit losses	15		4		—		2		2		7		4		(1)		4
Less: Write-offs, net of recoveries(a)	9		—		2		3		3		—		—		—		—
Balance as of September 30, 2021	$	77	$	4	$	19	$	7	$	8	$	40	$	17	$	8	$	15

	Nine Months Ended September 30, 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	36		—		9		3		7		17		6		4		7
Less: Write-offs, net of recoveries(a)	9		—		2		3		3		1		—		—		1
Balance as of September 30, 2020	$	75	$	—	$	27	$	7	$	9	$	32	$	13	$	8	$	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 September 30, 2021 and December 31, 2020.


	Unbilled customer revenues(a)
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
September 30, 2021	$	941	$	359	$	224	$	113	$	98	$	147	$	70	$	34	$	43
December 31, 2020	998		258		218		147		197		178		87		62		29

__________

(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 had a maximum funding limit of $750 million and was scheduled to expire on April 7, 2021, unless renewed by the mutual consent of the parties in accordance with its terms. The Facility was renewed on March 29, 2021. The Facility term was extended through March 29, 2024, unless further renewed by the mutual consent of the parties, and the maximum funding limit was increased to $900 million. 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 in Exelon’s and Generation’s Consolidated Balance Sheets.

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

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.

During the first quarter of 2021, Generation received additional cash of $250 million from the Purchasers for the remaining available funding in the Facility.

Additionally, during the first quarter of 2021, Generation received cash of approximately $150 million from the Purchasers in connection with the increased funding limit at the time of the Facility renewal.

During the second quarter of 2021, Generation returned cash of $50 million to the Purchasers due to the eligible receivables decreasing temporarily. Subsequently, in the second quarter, Generation received cash of $50 million from the Purchasers as a result of an increase in the eligible receivable balance. The $50 million cash outflow and inflow is included in the Collection of DPP line within Cash flows from investing activities in Exelon’s and Generation’s Consolidated Statements of Cash Flows.

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


	September 30, 2021		December 31, 2020
Derecognized receivables transferred at fair value	$	1,401	$	1,139
Cash proceeds received	900		500
DPP	501		639


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Loss on sale of receivables(a)	$	1	$	8	$	26	$	23

__________

(a)Reflected in Operating and maintenance expense in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.


	Nine Months Ended September 30,
	2021		2020
Proceeds from new transfers(a)	$	4,440	$	1,889
Cash collections received on DPP and reinvested in the Facility(b)	2,652		2,518
Cash collections reinvested in the Facility	7,092		4,407

__________

(a)Customer accounts receivable sold into the Facility were $7,373 million and $4,515 million for the nine months ended September 30, 2021 and September 30, 2020, respectively.

(b)Does not include the $400 million in cash proceeds received from the Purchasers in the first quarter of 2021.

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 Statements of Cash Flows. The collection and reinvestment of DPP is recognized in Net cash provided by investing activities in the Consolidated Statements of Cash Flows.

See Note 14 — Fair Value of Financial Assets and Liabilities and Note 17 — 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, Delaware, 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.


	Nine Months Ended September 30, 2021
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Total receivables purchased	$	2,945	$	—	$	810	$	795	$	531	$	826	$	504	$	166	$	156
Total receivables sold	100		117		—		—		—		—		—		—		—

Related party transactions:
Receivables purchased from Generation	—		—		—		—		17		—		—		—		—
Receivables sold to the Utility Registrants	—		17		—		—		—		—		—		—		—



	Nine Months Ended September 30, 2020
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Total receivables purchased	$	2,698	$	—	$	865	$	786	$	508	$	787	$	484	$	160	$	143
Total receivables sold	542		790		—		—		—		—		—		—		—

Related party transactions:
Receivables purchased from Generation	—		—		34		67		75		72		51		13		8
Receivables sold to the Utility Registrants	—		248		—		—		—		—		—		—		—

Early Plant Retirements (Exelon and Generation)

9 Months Ended

Sep. 30, 2021

Property, Plant and Equipment [Abstract]

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

On August 27, 2020, Generation announced that it intended to permanently cease generation operations at Byron in September 2021 and at Dresden in November 2021. Neither of these nuclear plants cleared in PJM’s capacity auction for the 2022-2023 planning year held in May 2021. Generation’s Braidwood and LaSalle nuclear plants in Illinois did clear in the capacity auction, but were also showing increased signs of economic distress.

On September 15, 2021, the Illinois Public Act 102-0662 was signed into law by the Governor of Illinois (“Clean Energy Law”). The Clean Energy Law is designed to achieve 100% carbon-free power by 2045 to enable the state’s transition to a clean energy economy. Among other things, the Clean Energy Law authorizes the IPA to procure up to 54.5 million CMCs from qualifying nuclear plants for a five-year period beginning on June 1, 2022 through May 31, 2027. CMCs are credits for the carbon-free attributes of eligible nuclear power plants in PJM. The Byron, Dresden, and Braidwood nuclear plants located in Illinois will be eligible to participate in the CMC procurement process and, if awarded contracts, would be committed to operate through May 31, 2027. See Note 3 — Regulatory Matters for additional information. Following enactment of the legislation, Generation announced on September 15, 2021, that it has reversed its previous decision to retire Byron and Dresden given the opportunity for additional revenue under the Clean Energy Law. In addition, Generation no longer considers the Braidwood or LaSalle nuclear plants to be at risk for premature retirement.

As a result of the decision to early retire Byron and Dresden, Exelon and Generation recognized certain one-time charges in the third and fourth quarters of 2020 related to materials and supplies inventory reserve adjustments, employee-related costs including severance benefit costs, and construction work-in-progress impairments, among other items. In addition, there were 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.

In the third quarter of 2021, Exelon and Generation reversed $81 million of severance benefit costs and $13 million of other one-time charges initially recorded in Operating and maintenance expense in the third and fourth quarters of 2020 associated with the early retirements. In addition, Generation updated the expected economic useful life for both facilities to 2044 and 2046 for Byron Units 1 and 2, respectively, and to 2029 and 2031 for Dresden Units 2 and 3, respectively, the end of the respective NRC operating license for each unit. Depreciation was therefore adjusted beginning September 15, 2021, to reflect these extended useful life estimates. See Note 8 — Nuclear Decommissioning for additional detail on changes to the nuclear decommissioning ARO balances resulting from the initial decision and subsequent reversal of the decision to early retire Byron and Dresden.

The total impact for the three and nine months ended September 30, 2021 and 2020 in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income resulting from the initial decision and subsequent reversal of the decision to early retire Byron and Dresden is summarized in the table below.


Income statement expense (pre-tax)	Three Months Ended September 30, 2021		Nine Months Ended September 30, 2021		Three and Nine Months Ended September 30, 2020
Depreciation and amortization
Accelerated depreciation(a)	$	574	$	1,805	$	254
Accelerated nuclear fuel amortization	42		148		14
Operating and maintenance
One-time charges	(94)		(94)		220
Other charges	4		8		34
Contractual offset(b)	(60)		(451)		(129)
Total	$	466	$	1,416	$	393

_________

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

(b)Reflects contractual offset for ARO accretion and ARC depreciation and excludes any changes in earnings in the NDT funds. Decommissioning-related impacts were not offset for the Byron units starting in the second quarter of 2021 due to the inability to recognize a regulatory asset at ComEd. With Generation’s September 15, 2021 reversal of the previous decision to retire Byron, Generation resumed contractual offset for Byron as of that date. Based on the regulatory agreement with the ICC, decommissioning-related activities are offset in Exelon's and Generation's Consolidated

Statements of Operations and Comprehensive Income as long as the net cumulative decommissioning-related activities result in a regulatory liability at ComEd. The offset resulted in an equal adjustment to the noncurrent payables to ComEd at Generation and an adjustment to the regulatory liabilities at ComEd. See Note 8 — Nuclear Decommissioning for additional information.

Generation remains committed to continued operations for its other nuclear plants receiving state-supported payments under the Illinois ZES (Clinton and Quad Cities), New Jersey ZEC program (Salem), and the New York CES (FitzPatrick, Ginna, and Nine Mile Point) assuming the continued effectiveness of such programs. To the extent such programs do not operate as expected over their full terms, each of these plants would be at heightened risk for early retirement, which could have a material impact on Exelon’s and Generation’s future financial statements. See Note 3 — Regulatory Matters for additional information on the New Jersey ZEC program and Note 3 — Regulatory Matters of the 2020 Form 10-K for additional information on the Illinois ZES and New York CES.

Exelon continues to work with stakeholders on state policy solutions to support continued operation of our nuclear fleet, while also advocating for broader market reforms at the regional and federal level. The absence of such solutions or reforms 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 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 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 $43 million in the third quarter of 2020 of one-time charges related to an expected long-term contract termination and materials and supplies reserve adjustments, among other items. In addition, there are 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 an immaterial amount of incremental Depreciation and amortization expense for the three months ended September 30, 2021 and $41 million for the nine months ended September 30, 2021. Exelon and Generation recorded incremental Depreciation and amortization expense of $6 million for the three and nine months ended September 30, 2020.

Nuclear Decommissioning (Exelon and Generation)

9 Months Ended

Sep. 30, 2021

Asset Retirement Obligation Disclosure [Abstract]

Nuclear Decommissioning (Exelon and Generation)

Nuclear Decommissioning Asset Retirement Obligations

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.

The financial statement impact for changes in the ARO, on an individual unit basis, due to the changes in and timing of estimated cash flows generally result in a corresponding change in the unit’s ARC in Property, plant, and equipment in 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 in 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 December 31, 2020 to September 30, 2021:


Nuclear decommissioning ARO at December 31, 2020(a)	$	11,922
Accretion expense	375
Net increase due to changes in, and timing of, estimated future cash flows	256
Costs incurred related to decommissioning plants	(57)
Nuclear decommissioning ARO at September 30, 2021(a)	$	12,496

_________

(a)Includes $74 million and $80 million as the current portion of the ARO at September 30, 2021 and December 31, 2020, which is included in Other current liabilities in Exelon’s and Generation’s Consolidated Balance Sheets.

During the nine months ended September 30, 2021, the net $256 million increase in the ARO for the changes in the amounts and timing of estimated decommissioning cash flows was driven by multiple adjustments. These adjustments primarily include:

•An increase of approximately $510 million for updated cost escalation rates, primarily for labor and energy, and a decrease in discount rates.

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

•A net decrease of approximately $110 million due to lower estimated costs to decommission Byron, Braidwood, Dresden, LaSalle, and Zion nuclear units resulting from the completion of updated cost studies.

The 2021 ARO updates resulted in a decrease of $51 million in Operating and maintenance expense for the three and nine months ended September 30, 2021 in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.

NDT Funds

Exelon and Generation had NDT funds totaling $15,602 million and $14,599 million at September 30, 2021 and December 31, 2020, respectively. The NDT funds also include $198 million and $134 million for the current portion of the NDT funds at September 30, 2021 and December 31, 2020, respectively, which are included in Other current assets in Exelon's and Generation's Consolidated Balance Sheets. See Note 18 — 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 in 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 in the balance sheet. For the purposes of making

this determination, the decommissioning obligation referred to is different from the calculation used in the NRC minimum funding obligation filings based on NRC guidelines.

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, decommissioning-related activities are offset in the Consolidated Statements of Operations and Comprehensive Income which 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. During the second and third quarter of 2021, a pre-tax charge of $53 million and $140 million, respectively, was recorded in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income for decommissioning-related activities that were not offset for the Byron units due to contractual offset being temporarily suspended. With Generation’s September 15, 2021 reversal of the previous decision to retire Byron and the corresponding adjustment to the ARO for Byron discussed previously, Generation resumed contractual offset for Byron as of that date.

As of September 30, 2021, decommissioning-related activities for all of the former ComEd units, except for Zion, are currently offset in 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 10 — Asset Retirement Obligations of the Exelon 2020 Form 10-K for additional information.

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.

Generation filed its biennial decommissioning funding status report with the NRC on February 24, 2021 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, 2020 for all units except for Byron Units 1 and 2. Generation filed an updated decommissioning funding status report for Byron Units 1 and 2 and Dresden Units 2 and 3 on September 28, 2021 based on their current license expiration dates consistent with Generation’s announcements regarding the continued operations of these units. This report demonstrated adequate decommissioning funding assurance as of December 31, 2020 for Byron Units 1 and 2 and Dresden Units 2 and 3.

Generation will file its next decommissioning funding status report with the NRC by March 31, 2022. This report will reflect the status of decommissioning funding assurance as of December 31, 2021 for shutdown units.

Asset Impairments (Exelon and Generation)	9 Months Ended
Asset Impairments (Exelon and Generation)	Sep. 30, 2021
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. New England Asset Group 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 in 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. In the second quarter of 2021, an overall decline in the asset group's portfolio value suggested that the carrying value of the New England asset group may be impaired. Generation completed a comprehensive review of the estimated undiscounted future cash flows of the New England asset group and concluded that the carrying value was not recoverable and that its fair value was less than its carrying value. As a result, a pre-tax impairment charge of $350 million was recorded in the second quarter of 2021 in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. Contracted Wind Project In the third quarter of 2021, significant long-term operational issues anticipated for a specific wind turbine technology suggested that the carrying value of a contracted wind asset, located in Maryland and part of the EGRP joint venture, may be impaired. Generation completed a comprehensive review of the estimated undiscounted future cash flows and concluded that the carrying value of this contracted wind project was not recoverable and that its fair value was less than its carrying value. As a result, in the third quarter of 2021, a pre-tax impairment charge of $45 million was recorded in Operating and maintenance expense, $21 million of which was offset in Net income attributable to noncontrolling interests in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

Income Taxes (All Registrants)

9 Months Ended

Sep. 30, 2021

Income Tax Disclosure [Abstract]

Income Taxes (All Registrants)

Rate Reconciliation

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


	Three Months Ended September 30, 2021

	Exelon(a)	Generation(a)	ComEd(a)	PECO(a)(b)	BGE(a)(b)	PHI(a)	Pepco(a)	DPL(a)	ACE(a)(b)
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	6.0	4.4	8.0	(4.1)	(13.0)	5.0	3.4	6.4	7.0
Qualified NDT fund income	0.5	0.9	—	—	—	—	—	—	—

Amortization of investment tax credit, including deferred taxes on basis difference	(0.4)	(0.7)	(0.1)	—	(0.1)	(0.1)	—	(0.2)	(0.2)
Plant basis differences	(1.7)	—	(0.8)	(16.2)	(1.4)	(1.3)	(2.0)	(0.6)	(0.6)
Production tax credits and other credits	(1.0)	(1.4)	(0.5)	—	(0.9)	(0.5)	(0.5)	(0.4)	(0.5)
Noncontrolling interests	(0.4)	(0.6)	—	—	—	—	—	—	—
Excess deferred tax amortization	(6.8)	—	(7.6)	(3.4)	(17.3)	(24.9)	(17.6)	(19.9)	(41.4)

Other(c)	(4.8)	(1.9)	0.3	(0.1)	(0.8)	—	0.1	(0.6)	0.8
Effective income tax rate	12.4%	21.7%	20.3%	(2.8)%	(12.5)%	(0.8)%	4.4%	5.7%	(13.9)%


	Three Months Ended September 30, 2020
	Exelon(a)	Generation(a)	ComEd(a)	PECO(a)(d)	BGE(a)(d)	PHI(a)(d)	Pepco(a)(d)	DPL(a)(d)	ACE(a)(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	12.3	(10.3)	8.1	(6.2)	5.1	5.5	4.6	6.6	6.9
Qualified NDT fund income	13.2	47.4	—	—	—	—	—	—	—

Amortization of investment tax credit, including deferred taxes on basis difference	(1.4)	(4.5)	(0.2)	—	(0.1)	(0.2)	(0.1)	(0.2)	(0.3)
Plant basis differences	(4.3)	—	(0.6)	(23.3)	(1.2)	(1.5)	(2.1)	(0.4)	(1.3)
Production tax credits and other credits	(3.0)	(9.2)	(0.4)	—	(0.8)	(0.5)	(0.5)	(0.5)	(0.4)
Noncontrolling interests	0.8	2.9	—	—	—	—	—	—	—
Excess deferred tax amortization	(10.1)	—	(5.6)	(3.8)	(10.6)	(24.9)	(20.0)	(23.6)	(36.8)
Tax Settlements	(0.2)	(0.7)	—	—	—	—	—	—	—
Other	(0.8)	(0.9)	1.1	(0.8)	(0.3)	0.1	(0.4)	0.7	0.6
Effective income tax rate	27.5%	45.7%	23.4%	(13.1)%	13.1%	(0.5)%	2.5%	3.6%	(10.3)%

__________

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

(b)For PECO, the income tax benefit is primarily due to plant basis differences attributable to tax repair deductions. For BGE,

the income tax benefit is primarily due to the Maryland multi-year plan which resulted in the acceleration of certain income tax benefits. For ACE, the income tax benefit is primarily due to a distribution rate case settlement which allows ACE to retain certain tax benefits.

(c)For Exelon, "Other" is primarily driven by the reversal of the consolidating income tax adjustment recorded at Exelon Corporate in the first quarter of 2021 that was required pursuant to GAAP interim reporting guidance.

(d)At PECO, the lower effective tax rate is primarily related to an increase in plant basis differences attributable to storm tax repair deductions. At BGE, PHI, Pepco, DPL and ACE, the lower effective tax rate is primarily attributable to accelerated amortization of transmission related deferred income tax regulatory liabilities as a result of regulatory settlements.


	Nine Months Ended September 30, 2021
	Exelon(a)	Generation(b)	ComEd(a)	PECO(a)(c)	BGE(a)(c)	PHI(a)	Pepco(a)	DPL(a)	ACE(a)(c)
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	3.0	90.2	7.6	(2.6)	(10.8)	4.6	2.5	6.5	7.3
Qualified NDT fund income	9.4	(1,932.6)	—	—	—	—	—	—	—

Amortization of investment tax credit, including deferred taxes on basis difference	(0.8)	130.6	(0.1)	—	(0.1)	(0.1)	—	(0.2)	(0.2)
Plant basis differences	(3.9)	—	(0.7)	(12.6)	(1.5)	(1.3)	(1.9)	(0.7)	(0.6)
Production tax credits and other credits	(2.6)	425.1	(0.5)	—	(0.9)	(0.5)	(0.5)	(0.4)	(0.5)
Noncontrolling interests	(0.7)	145.2	—	—	—	—	—	—	—
Excess deferred tax amortization	(13.9)	—	(7.2)	(3.3)	(16.0)	(22.8)	(17.4)	(19.7)	(36.3)

Other(d)	2.2	(229.5)	(1.3)	(0.2)	(0.7)	(0.3)	(0.4)	(0.2)	—
Effective income tax rate	13.7%	(1,350.0)%	18.8%	2.3%	(9.0)%	0.6%	3.3%	6.3%	(9.3)%


	Nine Months Ended September 30, 2020
	Exelon(a)	Generation(a)	ComEd(a)(e)	PECO(a)(e)	BGE(a)(e)	PHI(a)(e)	Pepco(a)(e)	DPL(a)(e)	ACE(a)(e)
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	9.3	—	12.7	(3.4)	5.5	5.0	4.2	6.5	6.8
Qualified NDT fund income	3.2	10.0	—	—	—	—	—	—	—
Deferred Prosecution Agreement payments	2.5	—	9.4	—	—	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(1.2)	(3.2)	(0.3)	—	(0.1)	(0.2)	(0.1)	(0.3)	(0.5)
Plant basis differences	(4.0)	—	(0.9)	(15.9)	(1.8)	(2.2)	(2.4)	(0.5)	(3.7)
Production tax credits and other credits	(2.6)	(7.0)	(0.4)	—	(0.4)	(0.3)	(0.3)	(0.2)	(0.4)
Noncontrolling interests	1.0	3.1	—	—	—	—	—	—	—
Excess deferred tax amortization	(15.8)	—	(11.8)	(3.5)	(15.0)	(45.3)	(29.2)	(53.6)	(81.4)
Tax Settlements(f)	(5.0)	(15.7)	—	—	—	—	—	—	—
Other	0.1	(0.5)	2.1	(0.5)	(0.5)	(0.6)	(0.8)	(1.1)	—
Effective income tax rate	8.5%	7.7%	31.8%	(2.3)%	8.7%	(22.6)%	(7.6)%	(28.2)%	(58.2)%

__________

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

(b)Generation recognized a loss before income taxes for the nine months ended September 30, 2021. As a result, a negative percentage represents an income tax expense for the period presented.

(c)For PECO, the lower effective tax rate is primarily related to an increase in plant basis differences attributable to tax repair deductions. For BGE, the income tax benefit is primarily due to the Maryland multi-year plan which resulted in the acceleration of certain income tax benefits. For ACE, the income tax benefit is primarily due to a distribution rate case settlement which allows ACE to retain certain tax benefits.

(d)For Exelon, "Other" is primarily driven by the consolidating income tax adjustment recorded at Exelon Corporate in the first quarter of 2021 that was required pursuant to GAAP interim reporting guidance. This incremental expense will reverse by year-end and will not have an impact on annual results.

(e)For ComEd, the higher effective tax rate is primarily related to the nondeductible Deferred Prosecution Agreement payments. For PECO, the income tax benefit is primarily related to an increase in plant basis differences attributable to storm tax repairs deductions. For BGE, PHI, Pepco, DPL, and ACE, the income tax benefit is primarily attributable to accelerated amortization of transmission related deferred income tax regulatory liabilities as a result of regulatory settlements.

(f)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.

Unrecognized Tax Benefits

PHI and ACE have the following unrecognized tax benefits as of September 30, 2021 and December 31, 2020. Exelon's, Generation's, ComEd's, PECO's, BGE's, Pepco's, and DPL's amounts are not material.


	PHI		ACE
September 30, 2021	$	56	$	16
December 31, 2020	52		15

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

As of September 30, 2021, 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.

Other Income Tax Matters

CENG Put Option (Exelon and Generation)

On August 6, 2021, Generation and EDF entered into a settlement agreement pursuant to which Generation purchased EDF’s equity interest in CENG. Exelon and Generation recorded deferred tax liabilities of $290 million and $288 million, respectively, against Common Stock in Exelon’s Consolidated Balance Sheet and Membership Interest in Generation’s Consolidated Balance Sheet. The deferred tax liabilities represent the tax effect on the difference between the net purchase price and EDF’s noncontrolling interest as of August 6, 2021. The deferred tax liabilities will reverse during the remaining operating lives and during decommissioning of the CENG nuclear plants. See Note 2 – Mergers, Acquisitions, and Dispositions for additional information.

Long-Term Marginal State Income Tax Rate (All Registrants)

In the third quarter of 2021 and 2020, Exelon updated its marginal state income tax rates for changes in state apportionment. The changes in marginal rates in the third quarter of 2021 resulted in an increase of $27 million to the deferred income tax liability at Exelon, and a corresponding adjustment to income tax expense, net of federal taxes. The changes in marginal rates in the third quarter of 2020 resulted in an increase of $66 million and a decrease of $26 million to the deferred income tax liability at Exelon and Generation, respectively. Exelon and Generation recorded a corresponding adjustment to income tax expense, net of federal taxes.

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 benefit 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 federal tax benefits from Exelon under the Tax Sharing Agreement.


	Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
September 30, 2021	$	64	$	1	$	19	$	—	$	17	$	16	$	—	$	—
September 30, 2020	64		14		17		—		17		8		6		1

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

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Retirement Benefits (All Registrants)

Retirement Benefits (All Registrants)

9 Months Ended

Sep. 30, 2021

Retirement Benefits [Abstract]

Defined Benefit Pension and OPEB

During the first quarter of 2021, Exelon received an updated valuation of its pension and OPEB to reflect actual census data as of January 1, 2021. This valuation resulted in an increase to the pension obligations of $33 million and a decrease to the OPEB obligations of $9 million. Additionally, accumulated other comprehensive loss

increased by $1 million (after-tax) and regulatory assets and liabilities increased by $21 million and $1 million, respectively.

The majority of the 2021 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 2.58%. The majority of the 2021 OPEB cost is calculated using an expected long-term rate of return on plan assets of 6.46% for funded plans and a discount rate of 2.51%.

A portion of the net periodic benefit cost for all plans is capitalized in the Consolidated Balance Sheets. The following table presents the components of Exelon's net periodic benefit costs, prior to capitalization, for the three and nine months ended September 30, 2021 and 2020.



	Pension Benefits				OPEB
	Three Months Ended September 30,				Three Months Ended September 30,
	2021		2020		2021		2020
Components of net periodic benefit cost:
Service cost	$	110	$	97	$	20	$	22
Interest cost	161		190		29		37
Expected return on assets	(335)		(317)		(40)		(41)
Amortization of:
Prior service cost (credit)	1		1		(8)		(30)
Actuarial loss	150		128		9		12
Settlement charges	12		8		—		—

Net periodic benefit cost	$	99	$	107	$	10	$	—



	Pension Benefits				OPEB
	Nine Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Components of net periodic benefit cost:
Service cost	$	330	$	290	$	60	$	67
Interest cost	481		569		86		114
Expected return on assets	(1,003)		(953)		(119)		(122)
Amortization of:
Prior service cost (credit)	3		3		(25)		(92)
Actuarial loss	449		384		27		36
Curtailment benefits	—		—		(1)		—
Settlement charges	16		14		—		—

Net periodic benefit cost	$	276	$	307	$	28	$	3

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.


	Three Months Ended September 30,				Nine Months Ended September 30,
Pension and OPEB Costs	2021		2020		2021		2020
Exelon	$	109	$	107	$	304	$	310
Generation	36		30		92		89
ComEd	32		29		97		85
PECO	2		1		5		4
BGE	16		16		47		47
PHI	12		17		36		52
Pepco	2		4		5		11
DPL	1		2		2		6
ACE	3		3		8		10

Defined Contribution Savings Plans

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 the matching contributions to the savings plans for the three and nine months ended September 30, 2021 and 2020, respectively.


	Three Months Ended September 30,				Nine Months Ended September 30,
Savings Plans Matching Contributions	2021		2020		2021		2020
Exelon	$	38	$	37	$	107	$	104
Generation	14		14		40		41
ComEd	9		9		27		25
PECO	2		3		8		8
BGE	4		4		8		8
PHI	5		3		12		9
Pepco	1		1		3		3
DPL	1		1		3		2
ACE	1		—		2		1

The entire disclosure for retirement benefits.

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Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Financial Instruments (All Registrants)

9 Months Ended

Sep. 30, 2021

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 derivatives settle and revenue or expense is recognized in earnings as the underlying physical commodity is sold or consumed.

Authoritative guidance about offsetting assets and liabilities requires the fair value of derivative instruments to be shown in the Combined Notes to Consolidated Financial Statements on a gross basis, even when the derivative instruments are subject to legally enforceable master netting agreements and qualify for net presentation in the Consolidated Balance Sheets. A master netting agreement is an agreement between two counterparties that may have derivative and non-derivative contracts with each other providing for the net settlement of all referenced contracts via one payment stream, which takes place as the contracts deliver, when collateral is requested or in the event of default. In the tables below, which present fair value balances, 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	Electricity	NPNS	Fixed price contracts for default supply requirements through full requirements contracts.
	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(b)	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 of the 2020 Form 10-K for additional information.

(b)The fair value of the DPL economic hedge is not material as of September 30, 2021 and December 31, 2020 and is not presented in the fair value tables below.

The following tables provide a summary of the derivative fair value balances recorded by Exelon, Generation, and ComEd as of September 30, 2021 and December 31, 2020:


	Exelon		Generation										ComEd
September 30, 2021	Total Derivatives		Economic Hedges		Proprietary Trading		Collateral(a)(b)		Netting(a)		Subtotal		Economic Hedges
Mark-to-market derivative assets (current assets)	$	1,505	$	19,631	$	63	$	(790)	$	(17,399)	$	1,505	$	—
Mark-to-market derivative assets (noncurrent assets)	661		3,612		5		(201)		(2,755)		661		—
Total mark-to-market derivative assets	2,166		23,243		68		(991)		(20,154)		2,166		—
Mark-to-market derivative liabilities (current liabilities)	(1,710)		(18,490)		(55)		(559)		17,399		(1,705)		(5)
Mark-to-market derivative liabilities (noncurrent liabilities)	(720)		(3,168)		(3)		(95)		2,755		(511)		(209)
Total mark-to-market derivative liabilities	(2,430)		(21,658)		(58)		(654)		20,154		(2,216)		(214)
Total mark-to-market derivative net (liabilities) assets	$	(264)	$	1,585	$	10	$	(1,645)	$	—	$	(50)	$	(214)


	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)

_________

(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. As of September 30, 2021, $1 million of cash collateral posted with external counterparties and an additional $71 million of cash collateral posted with affiliates, including $50 million with ComEd, and as of December 31, 2020, $15 million of cash collateral held with external counterparties, was not offset against derivative positions because such collateral was not associated with any energy-related derivatives, was associated with accrual positions, or had no positions to offset as of the balance sheet date.

(b)Includes $2,084 million held and $209 million posted of variation margin with the exchanges as of September 30, 2021 and December 31, 2020 respectively.

Economic Hedges (Commodity Price Risk)

Generation. For the three and nine months ended September 30, 2021 and 2020, 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.


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Income Statement Location	(Loss) Gain				(Loss) Gain
Operating revenues	$	(637)	$	39	$	(961)	$	238
Purchased power and fuel	1,392		209		2,209		224
Total Exelon and Generation	$	755	$	248	$	1,248	$	462

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 September 30, 2021, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York, and ERCOT reportable segments is 96%-99% for the remainder of 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 three and nine months ended September 30, 2021 and 2020,

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)

Generation utilizes interest rate swaps to manage its interest rate exposure and foreign currency derivatives to manage foreign exchange rate exposure associated with international commodity purchases in currencies other than U.S. dollars, both of which are treated as economic hedges. The notional amounts were $567 million and $665 million for Exelon and Generation as of September 30, 2021 and December 31, 2020, respectively.

The mark-to-market derivative assets and liabilities as of September 30, 2021 and December 31, 2020 and the mark-to-market gains and losses for the three and nine months ended September 30, 2021 and 2020 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 September 30, 2021. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties. The amounts in the tables below exclude credit risk exposure from individual retail counterparties, nuclear fuel procurement contracts, and exposure through RTOs, ISOs, NYMEX, ICE, NASDAQ, NGX, and Nodal commodity exchanges.


Rating as of September 30, 2021	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	$	701	$	254	$	447	—	$	—
Non-investment grade	23		2		21		—	—
No external ratings
Internally rated — investment grade	110		1		109		—	—
Internally rated — non-investment grade	309		48		261		—	—
Total	$	1,143	$	305	$	838	—	$	—


Net Credit Exposure by Type of Counterparty	As of September 30, 2021
Financial institutions	$	53
Investor-owned utilities, marketers, power producers	652
Energy cooperatives and municipalities	62
Other	71
Total	$	838

_________

(a)As of September 30, 2021, credit collateral held from counterparties where Generation had credit exposure included $188 million of cash and $117 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 September 30, 2021, the amount of cash collateral held with external counterparties by ComEd, BGE, and DPL was $56 million, $21 million, and $25 million, respectively, which is recorded in Other Current Liabilities in ComEd’s, BGE’s, and DPL’s Consolidated Balance Sheets. The amounts for PECO, Pepco, and ACE as of September 30, 2021 and for the Utility Registrants as of December 31, 2020 are not material. The amount for ComEd as of September 30, 2021 does not include cash collateral held from Generation, which is disclosed in the notes to the derivative fair value balances tables above.

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:


Credit-Risk Related Contingent Features	September 30, 2021		December 31, 2020
Gross fair value of derivative contracts containing this feature(a)	$	(5,289)	$	(834)
Offsetting fair value of in-the-money contracts under master netting arrangements(b)	2,735		537
Net fair value of derivative contracts containing this feature(c)	$	(2,554)	$	(297)

_________

(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 September 30, 2021 and December 31, 2020, 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.


	September 30, 2021		December 31, 2020
Cash collateral posted	$	299	$	511
Letters of credit posted	477		226
Cash collateral held	1,872		110
Letters of credit held	130		40
Additional collateral required in the event of a credit downgrade below investment grade	3,001		1,432

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 September 30, 2021, 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 September 30, 2021, they could have been required to post incremental collateral to their counterparties of $23 million, $46 million, and $11 million, respectively.

Debt and Credit Agreements (All Registrants)

9 Months Ended

Sep. 30, 2021

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 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 as of September 30, 2021 and December 31, 2020. PECO and BGE had no commercial paper borrowings as of September 30, 2021 and December 31, 2020.


	Outstanding Commercial Paper as of				Average Interest Rate on Commercial Paper Borrowings as of
Commercial Paper Issuer	September 30, 2021		December 31, 2020		September 30, 2021		December 31, 2020
Exelon(a)	$	287	$	1,031	0.19	%	0.25	%
Generation	—		340		—	%	0.27	%
ComEd	—		323		—	%	0.23	%


PHI(b)	287		368		0.19	%	0.24	%

Pepco	40		35		0.15	%	0.22	%
DPL	22		146		0.15	%	0.24	%
ACE	225		187		0.20	%	0.25	%

__________

(a)Exelon Corporate had no outstanding commercial paper borrowings as of September 30, 2021 and December 31, 2020.

(b)Represents the consolidated amounts of Pepco, DPL, and ACE.

See Note 17 — Debt and Credit Agreements of the Exelon 2020 Form 10-K for additional information on the Registrants' credit facilities.

Short-Term Loan Agreements

On March 23, 2017, Exelon Corporate entered into a term loan agreement for $500 million. The loan agreement was renewed on March 17, 2021 and will expire on March 16, 2022. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.65% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon's Consolidated Balance Sheets within Short-term borrowings.

On March 24, 2021, Exelon Corporate entered into a 9-month term loan agreement for $200 million. The loan agreement has an expiration of December 24, 2021. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.65% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon's Consolidated Balance Sheets within Short-term borrowings.

On March 31, 2021, Exelon Corporate entered into a 9-month and 364-day term loan agreement for $150 million each with variable interest rates of LIBOR plus 0.65% and expiration dates of December 31, 2021 and March 30, 2022, respectively. The loan agreements are 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 was renewed on March 17, 2021 and will expire on March 16, 2022. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.875% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon's and Generation's Consolidated Balance Sheets within Short-term borrowings.

On March 31, 2020, Generation entered into a term loan agreement for $300 million. The loan agreement was renewed on March 30, 2021 and will expire on March 29, 2022. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.70% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon's and Generation's Consolidated Balance Sheets within Short-term borrowings.

On August 6, 2021, Generation entered into a 364-day term loan agreement for $880 million with a variable interest rate of LIBOR plus 0.875% until March 31, 2022 and a rate of LIBOR plus 1% thereafter and all indebtedness thereunder is unsecured. The loan agreement has an expiration date of August 5, 2022 and is reflected in Short-term borrowings in Exelon's and Generation's Consolidated Balance Sheets.

On January 25, 2021, ComEd entered into two 90-day term loan agreements for $125 million each with variable interest rates of LIBOR plus 0.50% and LIBOR plus 0.75%, respectively. ComEd repaid the term loans on March 9, 2021.

Bilateral Credit Agreements

On January 11, 2013, Generation entered into a bilateral credit agreement for $100 million. The agreement was renewed on March 1, 2021 with a maturity date of March 1, 2023.

On February 21, 2019, Generation entered into a bilateral credit agreement for $100 million. The agreement was renewed on March 31, 2021 with a maturity date of March 31, 2022.

On January 5, 2016, Generation entered into a bilateral credit agreement for $150 million. The agreement was renewed on April 2, 2021 with a maturity date of April 5, 2023.

On October 26, 2012, Generation entered into a bilateral credit agreement for $200 million. The agreement had a maturity date of October 22, 2021, however, was terminated on August 27, 2021.

See Note 17 — Debt and Credit Agreements of the Exelon 2020 Form 10-K for additional information on Generation's bilateral credit agreements.

Credit Agreements

On July 15, 2021, each of the Registrants' respective syndicated revolving credit facilities had their maturity dates extended to May 26, 2024.

Long-Term Debt

Issuance of Long-Term Debt

During the nine months ended September 30, 2021, the following long-term debt was issued:

Company

Type

Interest Rate

Maturity

Amount

Use of Proceeds

Exelon

Long-Term Software License Agreements

3.62

December 1, 2025

Procurement of software licenses.

Generation

West Medway II
Nonrecourse Debt

LIBOR + 3%

(a)

March 31, 2026

150

Funding for general corporate purposes.

Generation

Energy Efficiency Project Financing(b)

2.53

November 30, 2021

Funding to install energy conservation measures for the Fort AP Hill project.

Generation

Energy Efficiency Project Financing(b)

4.24

November 30, 2021

Funding to install energy conservation measures for the Marine Corps. Logistics Project.

ComEd

First Mortgage Bonds, Series 130

3.13

March 15, 2051

700

Repay a portion of outstanding commercial paper obligations and two outstanding term loans, and to fund other general corporate purposes.

ComEd

First Mortgage Bonds, Series 131

2.75

September 1, 2051

450

Refinance existing indebtedness and for general corporate purposes.

PECO

First and Refunding Mortgage Bonds

3.05

March 15, 2051

375

Funding for general corporate purposes.

PECO

First and Refunding Mortgage Bonds

2.85

September 15, 2051

375

Refinance existing indebtedness and for general corporate purposes.

BGE

Senior Notes

2.25

June 15, 2031

600

Repay a portion of outstanding commercial paper obligations, repay existing indebtedness, and to fund other general corporate purposes.

Pepco

First Mortgage Bonds

2.32

March 30, 2031

150

Repay existing indebtedness and for general corporate purposes.

Pepco

First Mortgage Bonds

3.29

September 28, 2051

125

Repay existing indebtedness and for general corporate purposes.

DPL

First Mortgage Bonds

3.24

March 30, 2051

125

Repay existing indebtedness and for general corporate purposes.

ACE

First Mortgage Bonds

2.30

March 15, 2031

350

Refinance existing indebtedness, repay outstanding commercial paper obligations, and for general corporate purposes.

__________

(a)The nonrecourse debt has an average blended interest rate.

(b)For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt.

Debt Covenants

As of September 30, 2021, the Registrants are in compliance with debt covenants.

Nonrecourse Debt

Exelon and Generation have issued nonrecourse debt financing. 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.

West Medway II, LLC. On May 13, 2021, West Medway II, LLC (West Medway II), an indirect subsidiary of Generation, entered into a financing agreement for a $150 million nonrecourse senior secured term loan credit facility with a maturity date of March 31, 2026. The term loan bears interest at an average blended interest rate of

LIBOR plus 3%, paid quarterly. In addition to the financing, West Medway II, entered into interest rate swaps with an initial notional amount of $113 million at an interest rate of 0.61%, paid quarterly, to manage a portion of the interest rate exposure in connection with the financing. The net proceeds were distributed to Generation for general corporate purposes. Generation’s interests in West Medway II, were pledged as collateral for this financing. As of September 30, 2021, approximately $145 million was outstanding.

See Note 17 — Debt and Credit Agreements of the Exelon 2020 Form 10-K for additional information on nonrecourse debt and Note 12 — Derivative Financial Instruments for additional information on interest rate swaps.

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

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-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 50
-Paragraph 1I
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=123466505&loc=SL123495371-112611

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 50
-Paragraph 1B
-Subparagraph (i)
-URI http://asc.fasb.org/extlink&oid=123466505&loc=SL123495323-112611

Fair Value of Financial Assets and Liabilities (All Registrants)

Fair Value of Financial Assets and Liabilities (All Registrants)

9 Months Ended

Sep. 30, 2021

Fair Value Disclosures [Abstract]

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 September 30, 2021 and December 31, 2020. The Registrants have no financial liabilities classified as Level 1.

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


	September 30, 2021								December 31, 2020
	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	$	38,644	$	40,570	$	3,289	$	43,859	$	36,912	$	40,688	$	3,064	$	43,752
Generation	6,130		5,835		1,111		6,946		6,087		5,648		1,208		6,856
ComEd	9,772		11,344		—		11,344		8,983		11,117		—		11,117
PECO	4,196		4,738		50		4,788		3,753		4,553		50		4,603
BGE	3,960		4,416		—		4,416		3,664		4,366		—		4,366
PHI	7,482		6,030		2,128		8,158		7,006		6,099		1,806		7,905
Pepco	3,441		3,226		990		4,216		3,165		3,336		748		4,084
DPL	1,808		1,433		559		1,992		1,677		1,484		455		1,939
ACE	1,510		1,107		579		1,686		1,413		1,018		602		1,620
Long-Term Debt to Financing Trusts(a)
Exelon	$	390	$	—	$	479	$	479	$	390	$	—	$	467	$	467
ComEd	205		—		255		255		205		—		246		246
PECO	184		—		224		224		184		—		221		221
SNF Obligation
Exelon	$	1,209	$	1,021	$	—	$	1,021	$	1,208	$	909	$	—	$	909
Generation	1,209		1,021		—		1,021		1,208		909		—		909

__________

(a)Includes unamortized debt issuance costs which are not fair valued.

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 September 30, 2021 and December 31, 2020:

Exelon and Generation


	Exelon										Generation
As of September 30, 2021	Level 1		Level 2		Level 3		Not subject to leveling		Total		Level 1		Level 2		Level 3		Not subject to leveling		Total
Assets
Cash equivalents(a)	$	2,573	$	—	$	—	$	—	$	2,573	$	1,673	$	—	$	—	$	—	$	1,673
NDT fund investments
Cash equivalents(b)	647		135		—		—		782		647		135		—		—		782



Equities	4,373		1,717		1		1,559		7,650		4,373		1,717		1		1,559		7,650
Fixed income
Corporate debt(c)	—		1,155		287		—		1,442		—		1,155		287		—		1,442
U.S. Treasury and agencies	2,192		29		—		—		2,221		2,192		29		—		—		2,221
Foreign governments	—		54		—		—		54		—		54		—		—		54
State and municipal debt	—		29		—		—		29		—		29		—		—		29
Other	31		29		—		1,259		1,319		31		29		—		1,259		1,319
Fixed income subtotal	2,223		1,296		287		1,259		5,065		2,223		1,296		287		1,259		5,065
Private credit	—		—		187		592		779		—		—		187		592		779
Private equity	—		—		—		654		654		—		—		—		654		654
Real estate	—		—		—		802		802		—		—		—		802		802

NDT fund investments subtotal(d)(e)	7,243		3,148		475		4,866		15,732		7,243		3,148		475		4,866		15,732
Rabbi trust investments
Cash equivalents	65		—		—		—		65		4		—		—		—		4
Mutual funds	104		—		—		—		104		35		—		—		—		35
Fixed income	—		10		—		—		10		—		—		—		—		—
Life insurance contracts	—		99		34		—		133		—		33		—		—		33
Rabbi trust investments subtotal	169		109		34		—		312		39		33		—		—		72
Investments in equities(f)	137		—		—		—		137		137		—		—		—		137
Commodity derivative assets
Economic hedges	5,527		10,633		7,083		—		23,243		5,527		10,633		7,083		—		23,243
Proprietary trading	—		56		12		—		68		—		56		12		—		68
Effect of netting and allocation of collateral(g)(h)	(4,468)		(9,869)		(6,808)		—		(21,145)		(4,468)		(9,869)		(6,808)		—		(21,145)
Commodity derivative assets subtotal	1,059		820		287		—		2,166		1,059		820		287		—		2,166
DPP consideration	—		501		—		—		501		—		501		—		—		501


	Exelon										Generation
As of September 30, 2021	Level 1		Level 2		Level 3		Not subject to leveling		Total		Level 1		Level 2		Level 3		Not subject to leveling		Total
Total assets	11,181		4,578		796		4,866		21,421		10,151		4,502		762		4,866		20,281
Liabilities
Commodity derivative liabilities
Economic hedges	(4,126)		(9,192)		(8,554)		—		(21,872)		(4,126)		(9,192)		(8,340)		—		(21,658)
Proprietary trading	—		(32)		(26)		—		(58)		—		(32)		(26)		—		(58)
Effect of netting and allocation of collateral(g)(h)	4,123		9,159		6,218		—		19,500		4,123		9,159		6,218		—		19,500
Commodity derivative liabilities subtotal	(3)		(65)		(2,362)		—		(2,430)		(3)		(65)		(2,148)		—		(2,216)
Deferred compensation obligation	—		(149)		—		—		(149)		—		(44)		—		—		(44)
Total liabilities	(3)		(214)		(2,362)		—		(2,579)		(3)		(109)		(2,148)		—		(2,260)
Total net assets (liabilities)	$	11,178	$	4,364	$	(1,566)	$	4,866	$	18,842	$	10,148	$	4,393	$	(1,386)	$	4,866	$	18,021


	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


	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
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

__________

(a)Exelon excludes cash of $689 million and $409 million at September 30, 2021 and December 31, 2020, respectively, and restricted cash of $222 million and $59 million at September 30, 2021 and December 31, 2020, respectively, and includes long-term restricted cash of $54 million and $53 million at September 30, 2021 and December 31, 2020, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. Generation excludes cash of $292 million and $171 million at September 30, 2021 and December 31, 2020, respectively, and restricted cash of $54 million and $20 million at September 30, 2021 and December 31, 2020, respectively.

(b)Includes $109 million and $116 million of cash received from outstanding repurchase agreements at September 30, 2021 and December 31, 2020, 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 $(50) million and $(62) million as of September 30, 2021 and December 31, 2020, respectively, held in an investment vehicle primarily to hedge the equity option component of its convertible debt.

(d)Includes net derivative liabilities of less than $1 million and net derivative assets of $2 million, which have total notional amounts of $728 million and $1,043 million at September 30, 2021 and December 31, 2020, 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 $130 million and $181 million at September 30, 2021 and December 31, 2020, respectively, which include certain derivative assets that have notional amounts of $194 million and $104 million at September 30, 2021 and December 31, 2020, 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)Includes equity investments held by Generation which were previously designated as equity investments without readily determinable fair value but are now publicly traded and therefore have readily determinable fair values. The first investment became publicly traded in the fourth quarter of 2020. Generation records the fair value of these investments in Other current assets in Exelon's and Generation's Consolidated Balance Sheets based on the quoted market prices of the stocks as of the respective balance sheet date. There were no equity investments without readily determinable fair value that became publicly traded during the third quarter of 2021. For investments that became publicly traded during the first half of 2021, unrealized gains of $220 million were recorded in Other, net in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.

(g)Collateral (received) from counterparties, net of collateral paid to counterparties, totaled $(345) million, $(710) million, and $(590) million allocated to Level 1, Level 2, and Level 3 mark-to-market derivatives, respectively, as of September 30, 2021. Collateral (received)/posted 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.

(h)Includes $2,084 million held and $209 million posted of variation margin with the exchanges as of September 30, 2021 and December 31, 2020, respectively.

As of September 30, 2021, Exelon and Generation have outstanding commitments to invest in private credit, private equity, and real estate investments of approximately $359 million, $174 million, and $371 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 $44 million and $32 million as of September 30, 2021, respectively. 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. Changes in fair value, cumulative adjustments, and impairments were not material for the three and nine months ended September 30, 2021 and for the year ended December 31, 2020.

ComEd, PECO, and BGE


	ComEd								PECO								BGE
As of September 30, 2021	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)	$	309	$	—	$	—	$	309	$	247	$	—	$	—	$	247	$	169	$	—	$	—	$	169
Rabbi trust investments

Mutual funds	—		—		—		—		10		—		—		10		14		—		—		14
Life insurance contracts	—		—		—		—		—		15		—		15		—		—		—		—
Rabbi trust investments subtotal	—		—		—		—		10		15		—		25		14		—		—		14
Total assets	309		—		—		309		257		15		—		272		183		—		—		183
Liabilities
Deferred compensation obligation	—		(9)		—		(9)		—		(8)		—		(8)		—		(6)		—		(6)
Mark-to-market derivative liabilities(b)	—		—		(214)		(214)		—		—		—		—		—		—		—		—
Total liabilities	—		(9)		(214)		(223)		—		(8)		—		(8)		—		(6)		—		(6)
Total net assets (liabilities)	$	309	$	(9)	$	(214)	$	86	$	257	$	7	$	—	$	264	$	183	$	(6)	$	—	$	177


	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
Deferred compensation obligation	—		(8)		—		(8)		—		(9)		—		(9)		—		(5)		—		(5)
Mark-to-market derivative liabilities(b)	—		—		(301)		(301)		—		—		—		—		—		—		—		—
Total liabilities	—		(8)		(301)		(309)		—		(9)		—		(9)		—		(5)		—		(5)
Total net assets (liabilities)	$	285	$	(8)	$	(301)	$	(24)	$	17	$	4	$	—	$	21	$	130	$	(5)	$	—	$	125

__________

(a)ComEd excludes cash of $145 million and $83 million at September 30, 2021 and December 31, 2020, respectively, and restricted cash of $107 million and $37 million at September 30, 2021 and December 31, 2020, respectively, and includes long-term restricted cash of $44 million and $43 million at September 30, 2021 and December 31, 2020, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. PECO excludes cash of $105 million and $18 million at September 30, 2021 and December 31, 2020, respectively. BGE excludes cash of $56 million and $24 million at September 30, 2021 and December 31, 2020, respectively, and restricted cash of $27 million and $1 million at September 30, 2021 and December 31, 2020, respectively.

(b)The Level 3 balance consists of the current and noncurrent liability of $5 million and $209 million, respectively, at September 30, 2021 and $33 million and $268 million, respectively, at December 31, 2020 related to floating-to-fixed energy swap contracts with unaffiliated suppliers.

PHI, Pepco, DPL, and ACE



	As of September 30, 2021								As of December 31, 2020
PHI	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents(a)	$	100	$	—	$	—	$	100	$	86	$	—	$	—	$	86




Rabbi trust investments
Cash equivalents	59		—		—		59		55		—		—		55
Mutual funds	14		—		—		14		14		—		—		14
Fixed income	—		10		—		10		—		11		—		11
Life insurance contracts	—		27		34		61		—		26		34		60
Rabbi trust investments subtotal	73		37		34		144		69		37		34		140
Total assets	173		37		34		244		155		37		34		226
Liabilities
Deferred compensation obligation	—		(19)		—		(19)		—		(17)		—		(17)



Total liabilities	—		(19)		—		(19)		—		(17)		—		(17)
Total net assets	$	173	$	18	$	34	$	225	$	155	$	20	$	34	$	209


	Pepco								DPL								ACE
As of September 30, 2021	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)	$	36	$	—	$	—	$	36	$	26	$	—	$	—	$	26	$	14	$	—	$	—	$	14




Rabbi trust investments
Cash equivalents	58		—		—		58		—		—		—		—		—		—		—		—
Fixed income	—		—		—		—		—		—		—		—		—		—		—		—
Life insurance contracts	—		27		34		61		—		—		—		—		—		—		—		—
Rabbi trust investments subtotal	58		27		34		119		—		—		—		—		—		—		—		—
Total assets	94		27		34		155		26		—		—		26		14		—		—		14
Liabilities
Deferred compensation obligation	—		(2)		—		(2)		—		—		—		—		—		—		—		—



Total liabilities	—		(2)		—		(2)		—		—		—		—		—		—		—		—
Total net assets	$	94	$	25	$	34	$	153	$	26	$	—	$	—	$	26	$	14	$	—	$	—	$	14


	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

__________

(a)PHI excludes cash of $57 million and $74 million at September 30, 2021 and December 31, 2020, respectively, and restricted cash of $5 million and none at September 30, 2021 and December 31, 2020, respectively, and includes long-term restricted cash of $9 million and $10 million at September 30, 2021 and December 31, 2020, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. Pepco excludes cash of $19 million and $30 million at September 30, 2021 and December 31, 2020, respectively, and restricted cash of $5 million and none at September 30, 2021 and December 31, 2020, respectively. DPL excludes cash of $13 million and $15 million at September 30, 2021 and December 31, 2020, respectively. ACE excludes cash of $16 million and $17 million at September 30, 2021 and December 31, 2020, respectively, and includes long-term restricted cash of $9 million and $10 million at September 30, 2021 and December 31, 2020, 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 three and nine months ended September 30, 2021 and 2020:



	Exelon		Generation					ComEd		PHI and Pepco
Three Months Ended September 30, 2021	Total		NDT Fund Investments		Mark-to-Market Derivatives			Total Generation		Mark-to-Market Derivatives			Life Insurance Contracts		Eliminated in Consolidation
Balance as of June 30, 2021	$	(235)	$	461	$	(465)		$	(4)	$	(265)		$	34	$	—
Total realized / unrealized gains (losses)
Included in net income	(967)		3		(970)		(a)	(967)		—			—		—
Included in noncurrent payables to affiliates	—		11		—			11		—			—		(11)

Included in regulatory assets	62		—		—			—		51		(b)	—		11
Change in collateral	(413)		—		(413)			(413)		—			—		—
Purchases, sales, and settlements
Purchases	8		2		6			8		—			—		—
Sales	6		—		6			6		—			—		—

Settlements	(2)		(2)		—			(2)		—			—		—
Transfers into Level 3	2		—		2		(c)	2		—			—		—
Transfers out of Level 3	(27)		—		(27)		(c)	(27)		—			—		—
Balance at September 30, 2021	$	(1,566)	$	475	$	(1,861)		$	(1,386)	$	(214)		$	34	$	—
The amount of total (losses) gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2021	$	(1,001)	$	3	$	(1,004)		$	(1,001)	$	—		$	—	$	—


	Exelon		Generation					ComEd		PHI and Pepco
Nine months ended September 30, 2021	Total		NDT Fund Investments		Mark-to-Market Derivatives			Total Generation		Mark-to-Market Derivatives			Life Insurance Contracts		Eliminated in Consolidation
Balance as of December 31, 2020	$	660	$	497	$	430		$	927	$	(301)		$	34	$	—
Total realized / unrealized gains (losses)
Included in net income	(1,600)		4		(1,606)		(a)	(1,602)		—			2		—
Included in noncurrent payables to affiliates	—		18		—			18		—			—		(18)

Included in regulatory assets	105		—		—			—		87		(b)	—		18
Change in collateral	(751)		—		(751)			(751)		—			—		—
Purchases, sales, and settlements
Purchases	123		3		120			123		—			—		—
Sales	7		—		7			7		—			—		—

Settlements	(50)		(48)		—			(48)		—			(2)		—
Transfers into Level 3	4		1		3		(c)	4		—			—		—
Transfers out of Level 3	(64)		—		(64)		(c)	(64)		—			—		—
Balance as of September 30, 2021	$	(1,566)	$	475	$	(1,861)		$	(1,386)	$	(214)		$	34	$	—
The amount of total (losses) gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2021	$	(1,521)	$	4	$	(1,527)		$	(1,523)	$	—		$	2	$	—



	Exelon		Generation					ComEd		PHI and Pepco
Three Months Ended September 30, 2020	Total		NDT Fund Investments		Mark-to-Market Derivatives			Total Generation		Mark-to-Market Derivatives			Life Insurance Contracts		Eliminated in Consolidation
Balance as of June 30, 2020	$	883	$	499	$	659		$	1,158	$	(318)		$	43	$	—
Total realized / unrealized gains (losses)
Included in net income	(327)		3		(318)		(a)	(315)		—			(12)		—
Included in noncurrent payables to affiliates	—		18		—			18		—			—		(18)
Included in regulatory assets/liabilities	32		—		—			—		14		(b)	—		18
Change in collateral	(79)		—		(79)			(79)		—			—		—
Purchases, sales, and settlements
Purchases	66		1		65			66		—			—		—
Sales	(3)		—		(3)			(3)		—			—		—

Settlements	—		(3)		—			(3)		—			3		—

Transfers out of Level 3	9		—		9		(c)	9		—			—		—
Balance as of September 30, 2020	$	581	$	518	$	333		$	851	$	(304)		$	34	$	—
The amount of total (losses) gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2020	$	(222)	$	3	$	(213)		$	(210)	$	—		$	(12)	$	—


	Exelon		Generation					ComEd		PHI and Pepco
Nine Months Ended September 30, 2020	Total		NDT Fund Investments		Mark-to-Market Derivatives			Total Generation		Mark-to-Market Derivatives			Life Insurance Contracts		Eliminated in Consolidation
Balance as of December 31, 2019	$	1,068	$	511	$	817		$	1,328	$	(301)		$	41	$	—
Total realized / unrealized gains (losses)
Included in net income	(483)		1		(474)		(a)	(473)		—			(10)		—
Included in noncurrent payables to affiliates	—		17		—			17		—			—		(17)

Included in regulatory assets	14		—		—			—		(3)		(b)	—		17
Change in collateral	(120)		—		(120)			(120)		—			—		—
Purchases, sales, and settlements
Purchases	136		6		130			136		—			—		—
Sales	(27)		—		(27)			(27)		—			—		—

Settlements	(15)		(18)		—			(18)		—			3		—
Transfers into Level 3	(5)		1		(6)		(c)	(5)		—			—		—
Transfers out of Level 3	13		—		13		(c)	13		—			—		—
Balance as of September 30, 2020	$	581	$	518	$	333		$	851	$	(304)		$	34	$	—
The amount of total (losses) gains included in income attributed to the change in unrealized (losses) gains related to assets and liabilities as of September 30, 2020	$	(107)	$	1	$	(98)		$	(97)	$	—		$	(10)	$	—

__________

(a)Includes an addition of $34 million for realized losses and a reduction of $80 million for realized gains due to the settlement of derivative contracts for the three and nine months ended September 30, 2021. Includes a reduction of $105 million and $376 million for realized gains due to the settlement of derivative contracts for the three and nine months ended September 30, 2020.

(b)Includes $49 million of increases in fair value and an increase for realized losses due to settlements of $2 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended September 30, 2021. Includes $72 million of increases in fair value and an increase for realized losses due to settlements of $15 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the nine months ended September 30, 2021. Includes $9 million of increases in fair value and an increase for realized losses due to settlements of $5 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended September 30, 2020. Includes $26 million of decrease in fair value and an increase for realized losses due to settlements of $23 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the nine months ended September 30, 2020.

(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 three and nine months ended September 30, 2021 and 2020:




	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 three months ended September 30, 2021	$	(1,274)	$	304	$	—	$	3	$	(1,274)	$	304	$	3	$	—
Total (losses) gains included in net income for the nine months ended September 30, 2021	(1,944)		338		2		4		(1,944)		338		4		2
Total unrealized (losses) gains for the three months ended September 30, 2021	(1,361)		357		—		3		(1,361)		357		3		—
Total unrealized (losses) gains for the nine months ended September 30, 2021	(1,969)		443		2		4		(1,969)		443		4		2



	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 included in net income for the three months ended September 30, 2020	$	(305)	$	(13)	$	(12)	$	—	$	(305)	$	(13)	$	—	$	(12)
Total losses included in net income for the nine months ended September 30, 2020	(370)		(104)		(10)		—		(370)		(104)		—		(10)
Total unrealized (losses) gains for the three months ended September 30, 2020	(216)		3		(12)		3		(216)		3		3		(12)
Total unrealized gains (losses) for the nine months ended September 30, 2020	(50)		(48)		(10)		1		(50)		(48)		1		(10)

Valuation Techniques Used to Determine Fair Value

Exelon’s valuation techniques used to measure the fair value of the assets and liabilities shown in the tables below are in accordance with the policies discussed in Note 18 — Fair Value of Financial Assets and Liabilities of the Exelon 2020 Form 10-K.

Valuation Techniques Used to Determine Net asset Value (Exelon and Generation)

Certain NDT Fund Investments are not classified within the fair value hierarchy and are included under the heading “Not subject to leveling” in the table above. These investments are measured at fair value using NAV per share as a practical expedient and include commingled funds, mutual funds which are not publicly quoted, managed private credit funds, private equity and real estate funds.

For commingled funds and mutual funds, which are not publicly quoted, the fair value is primarily derived from the quoted prices in active markets on the underlying securities and can typically be redeemed monthly with 30 or less days of notice and without further restrictions. For managed private credit funds, the fair value is determined using a combination of valuation models including cost models, market models, and income models and typically cannot be redeemed until maturity of the term loan. Private equity and real estate investments include those in limited partnerships that invest in operating companies and real estate holding companies that are not publicly traded on a stock exchange, such as, leveraged buyouts, growth capital, venture capital, distressed investments, investments in natural resources, and direct investments in pools of real estate properties. These investments typically cannot be redeemed and are generally liquidated over a period of 8 to 10 years from the initial investment date, which is based on Exelon’s understanding of the investment funds. Private equity and real estate valuations are reported by the fund manager and are based on the valuation of the underlying investments, which include inputs such as cost, operating results, discounted future cash flows, market based comparable data, and independent appraisals from sources with professional qualifications. These valuation inputs are unobservable.

Mark-to-Market Derivatives (Exelon, Generation, and ComEd)

The table below discloses the significant inputs to the forward curve used to value mark-to-market derivatives.


Type of trade	Fair Value at September 30, 2021		Fair Value at December 31, 2020		Valuation Technique	Unobservable Input	2021 Range & Arithmetic Average				2020 Range & Arithmetic Average
Mark-to-market derivatives — Economic Hedges (Exelon and Generation)(a)(b)	$	(1,257)	$	245	Discounted Cash Flow	Forward power price	$9.77	-	$301	$55	$2.25	-	$163	$30
						Forward gas price	$1.76	-	$23.00	$4.16	$1.57	-	$7.88	$2.59
					Option Model	Volatility percentage	35%	-	197%	49%	11%	-	237%	32%

Mark-to-market derivatives — Proprietary trading (Exelon and Generation)(a)(b)	$	(14)	$	23	Discounted Cash Flow	Forward power price	$16	-	$156	$53	$10	-	$106	$27

Mark-to-market derivatives (Exelon and ComEd)	$	(214)	$	(301)	Discounted Cash Flow	Forward heat rate(c)	9x	-	10x	9.13x	8x	-	9x	8.85x
						Marketability reserve	3%	-	7%	4.77%	3%	-	8%	4.93%
						Renewable factor	95%	-	122%	100%	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 (received)/posted on level three positions of $(590) million and $162 million as of September 30, 2021 and December 31, 2020, 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)

9 Months Ended

Sep. 30, 2021

Commitments and Contingencies (All Registrants)

The following is an update to the current status of commitments and contingencies set forth in Note 19 — Commitments and Contingencies of the Exelon 2020 Form 10-K.

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 September 30, 2021:


Description	Exelon		PHI		Pepco		DPL		ACE
Total commitments	$	513	$	320	$	120	$	89	$	111
Remaining commitments(a)	74		62		51		7		4

__________

(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 September 30, 2021, approximately 33 MWs of new generation were developed and Exelon and Generation have incurred costs of $121 million. Approximately 30 MWs of the new generation developed was part of Generation's first quarter 2021 sale of a significant portion of its solar business. Refer to Note 2 — Mergers, Acquisitions, and Dispositions for additional information on the solar business. 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 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 September 30, 2021, representing commitments potentially triggered by future events were as follows:


			Expiration within
	Total		2021		2022		2023		2024		2025		2026 and beyond
Exelon
Letters of credit	$	2,241	$	268	$	1,860	$	113	$	—	$	—	$	—
Surety bonds(a)	971		403		566		—		2		—		—
Financing trust guarantees	378		—		—		—		—		—		378
Guaranteed lease residual values(b)	31		—		3		3		6		6		13
Total commercial commitments	$	3,621	$	671	$	2,429	$	116	$	8	$	6	$	391

Generation
Letters of credit	$	2,223	$	264	$	1,846	$	113	$	—	$	—	$	—
Surety bonds(a)	826		352		474		—		—		—		—
Total commercial commitments	$	3,049	$	616	$	2,320	$	113	$	—	$	—	$	—

ComEd
Letters of credit	$	7	$	2	$	5	$	—	$	—	$	—	$	—
Surety bonds(a)	17		5		10		—		2		—		—
Financing trust guarantees	200		—		—		—		—		—		200
Total commercial commitments	$	224	$	7	$	15	$	—	$	2	$	—	$	200

PECO
Letters of credit	$	1	$	—	$	1	$	—	$	—	$	—	$	—
Surety bonds(a)	2		—		2		—		—		—		—
Financing trust guarantees	178		—		—		—		—		—		178
Total commercial commitments	$	181	$	—	$	3	$	—	$	—	$	—	$	178

BGE
Letters of credit	$	2	$	—	$	2	$	—	$	—	$	—	$	—
Surety bonds(a)	3		2		1		—		—		—		—
Total commercial commitments	$	5	$	2	$	3	$	—	$	—	$	—	$	—

PHI

Surety bonds(a)	$	23	$	3	$	20	$	—	$	—	$	—	$	—
Guaranteed lease residual values(b)	31		—		3		3		6		6		13
Total commercial commitments	$	54	$	3	$	23	$	3	$	6	$	6	$	13

Pepco

Surety bonds(a)	$	14	$	—	$	14	$	—	$	—	$	—	$	—
Guaranteed lease residual values(b)	10		—		1		1		2		2		4
Total commercial commitments	$	24	$	—	$	15	$	1	$	2	$	2	$	4

DPL

Surety bonds(a)	$	5	$	2	$	3	$	—	$	—	$	—	$	—
Guaranteed lease residual values(b)	13		—		1		1		3		3		5
Total commercial commitments	$	18	$	2	$	4	$	1	$	3	$	3	$	5

ACE
Surety bonds(a)	$	4	$	1	$	3	$	—	$	—	$	—	$	—
Guaranteed lease residual values(b)	8		—		1		1		1		1		4
Total commercial commitments	$	12	$	1	$	4	$	1	$	1	$	1	$	4

__________

(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 $75 million guaranteed by Exelon and PHI, of which $25 million, $32 million, and $18 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.

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 2027.

•PECO has 6 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 September 30, 2021 and December 31, 2020, the Registrants had accrued the following undiscounted amounts for environmental liabilities in Other current liabilities and Other deferred credits and other liabilities in their respective Consolidated Balance Sheets:


	September 30, 2021				December 31, 2020
	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	$	474	$	310	$	483	$	314
Generation	119		—		121		—
ComEd	284		284		293		293
PECO	23		21		23		21
BGE	6		5		2		—
PHI	42		—		44		—
Pepco	40		—		42		—
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 Amendment (RODA) for the selection of a final remedy. The RODA modified the remedy previously selected by EPA in its 2008 Record of Decision (ROD). While the ROD required only that the radiological materials and other wastes at the site be capped, the 2018 RODA requires partial excavation of the radiological materials in addition to the previously selected capping remedy. The RODA 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 in late 2024. 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 $290 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 in 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 a 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 possess 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 in 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 and Feasibility Study (RI/FS). The purpose of this RI/FS is to define the nature and extent of any groundwater contamination from the West Lake Landfill site and evaluate remedial alternatives. Generation estimates the undiscounted cost for the groundwater RI/FS to be approximately $40 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 or the extent to which, if any, remediation activities may be required and therefore cannot estimate a reasonably possible range of loss for response costs beyond those associated with the RI/FS component. It is reasonably possible, however, that resolution of this matter could have a material, unfavorable impact in 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 February 28, 2022 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. At this time, the DOJ has stayed their request for a good faith offer while the parties review cost documentation associated with the cost claim. 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 March 16, 2022. 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 NPS 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 to 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 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.

On July 12, 2021, DOEE and NPS held a virtual meeting with the PRP's in response to a General Notice Letter sent by each agency inviting the PRP's to participate in discussions, which PEPCO attended.

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 September 30, 2021 and December 31, 2020, Exelon and Generation had recorded estimated liabilities of approximately $82 million and $89 million, respectively, in total for asbestos-related bodily injury claims. As of September 30, 2021, approximately $19 million of this amount related to 211 open claims presented to Generation, while the remaining $63 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 in Exelon’s and Generation’s financial statements. However, management cannot reasonably estimate a range of loss beyond the amounts recorded.

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, which was paid in November 2020. 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 were filed, and various demand letters were received related to the subject of the subpoenas, the conduct described in the DPA and the SEC's investigation, including:

•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, the Citizens Utility Board (CUB) filed a motion to intervene in these cases on October 22, 2020 which was granted on December 23, 2020. 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. However, the Potter plaintiffs voluntarily dismissed their complaint without prejudice on April 5, 2021. ComEd and Exelon moved to dismiss the consolidated class action complaint and CUB’s complaint on February 4, 2021 and briefing was completed on March 22, 2021. On March 25, 2021, the parties agreed, along with state court plaintiffs, discussed below, to jointly engage in mediation. The parties participated in a one-day mediation on June 7, 2021 but no settlement was reached. On September 9, 2021, the federal court granted Exelon’s and ComEd’s motion to dismiss and dismissed the plaintiffs’ and CUB’s federal law claim with prejudice. The federal court also dismissed the related state law claims made by the federal plaintiffs and CUB on jurisdictional grounds. Plaintiffs have appealed the ruling to the Seventh Circuit Court of Appeals. Plaintiffs' opening appeal brief is due January 14, 2022, Exelon's and ComEd's response brief is due February 14, 2022, and Plaintiffs' reply brief is due March 7, 2022. Plaintiffs also refiled their state law claims in state court and have moved to consolidate that action with the already pending consumer state court class action, discussed below. CUB also refiled its state law claims in state court.

•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. The cases were consolidated into a single action in October of 2020. In November 2020, CUB filed a motion to intervene in the 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 its 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 was completed on March 2, 2021. The parties agreed, on March 25, 2021, along with the federal court plaintiffs discussed above, to jointly engage in mediation. The parties participated in a one-day mediation on June 7, 2021 but no settlement was reached. Oral argument on the state court pending motion to dismiss was held on August 4, 2021. On September 27, 2021, the court set a tentative ruling date on the motion to dismiss for November 30, 2021. It is unclear at this time what impact the recent filings by the federal court plaintiffs and CUB will have on this action and the pending motion to dismiss.

•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. The court denied the motion in April 2021. On May 26, 2021, defendants moved the court to certify its order denying the motion to dismiss for interlocutory appeal. Briefing on the motion was completed in June 2021 and the motion remains pending. Litigation has proceeded and in May 2021, the parties each filed respective initial discovery disclosures. On June 9, 2021, defendants filed their answer and affirmative defenses to the complaint. The parties are currently engaged in discovery; however, on September 9, 2021, the U.S. government moved to intervene in this lawsuit and stay discovery relating to the U.S. government’s ongoing criminal proceedings until the parties to the litigation agree to an acceptable protective order. The court granted the U.S. government’s motion on September 23, 2021 and discovery remains stayed until further order of the court.

•Five shareholders sent letters to the Exelon Board of Directors between 2020 and 2021 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. In the first quarter of 2021, the Exelon Board of Directors appointed a Special Litigation Committee (“SLC”) consisting of disinterested and independent parties to investigate and address these shareholders’ allegations and make recommendations to the Exelon Board of Directors based on the outcome of the SLC’s investigation. In July 2021, one of the demand letter shareholders filed a derivative action against current and former Exelon and ComEd officers and directors, and against Exelon, as nominal defendant, asserting the same claims made in its demand letter. On October 12, 2021, the parties to the derivative action filed an agreed motion to stay that litigation for 120 days in order to allow the SLC to continue its investigation, which the court granted. The parties will confer in advance of the 120-day deadline to determine whether the stay should be extended.

•A separate shareholder demand seeking a review of certain Exelon books and records was received in August 2021. Exelon is in the process of responding to this demand.

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.

On August 12, 2021, the ICC commenced a proceeding, under its general regulatory authority, to investigate whether the conduct described in the DPA resulted in ComEd’s recovery, through rates, of costs that were not properly recoverable under law and, if so, what remedial action should be taken. The Staff Report cited by the ICC in its initiating order expressed “concerns” about whether ComEd improperly recovered DPA-related costs from customers. The Illinois Attorney General and CUB have intervened in the proceeding. Counsel for plaintiffs in the putative consumer class actions pending in Illinois Circuit Court have also sought to “partially” intervene, which request is pending. On October 14, 2021, as required by provisions of the Clean Energy Law, the ICC initiated a separate docket to investigate the rate treatment of costs associated with the DPA, including the fine paid by ComEd, and whether ComEd “collected, spent, allocated, transferred, remitted, or caused in any other way to be expended ratepayer funds that were not lawfully recoverable through rates, and which should accordingly be refunded to ratepayers ….” That proceeding must be completed within 330 days. On October 19, 2021, the ICC moved to consolidate these two proceedings because they address "similar issues and facts." That motion is pending. No schedule has been set for submission of testimony or for an evidentiary hearing in either docket. A status hearing is set in both matters for November 4, 2021. Exelon and ComEd cannot predict the outcome of these proceedings.

Impacts of the February 2021 Extreme Cold Weather Event and Texas-based Generating Assets Outages (Exelon and Generation). 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 outages as a result of extreme cold weather conditions. In addition, those weather conditions drove increased demand for service, dramatically increased wholesale power prices, and also increased gas prices in certain regions. See Note 3 — Regulatory Matters for additional information.

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

•On March 5, 2021, Generation, along with more than 160 power generators and transmission and distribution companies, was sued by approximately 160 individually named plaintiffs, purportedly on behalf of all Texans who allegedly suffered loss of life or sustained personal injury, property damage or other losses as a result of the weather events. The plaintiffs allege that the defendants failed to properly prepare for the cold weather and failed to properly conduct their operations, seeking compensatory as well as punitive damages. On April 26, 2021, another multi-plaintiff lawsuit was filed on behalf of approximately 90 plaintiffs against more than 300 defendants, including Generation, involving similar allegations of liability and claims of personal injury and property damage. Since March 2021, approximately 60 additional lawsuits, naming multiple defendants including Generation, were filed by individual or multiple plaintiffs in different Texas counties, all arising out of the February weather events. These additional lawsuits allege wrongful death, property damage, or other losses. Co-defendants in these lawsuits include ERCOT, transmission and distribution utilities and other generators. Generation disputes liability and denies that it is responsible for any of plaintiffs’ alleged claims and is vigorously contesting them. No loss contingencies have been reflected in Exelon’s and Generation’s consolidated

financial statements with respect to these matters, as such contingencies are neither probable nor reasonably estimable at this time.

•On March 22, 2021, an LDC filed a lawsuit in Missouri federal court against Generation for breach of contract and unjust enrichment, seeking damages of approximately $40 million. The plaintiff claims that Generation failed to deliver gas to its customers in February of 2021, causing the plaintiff to incur damages by forcing it to purchase gas for Generation’s customers and by Generation’s refusal to pay the resulting penalties. On March 26, 2021, Generation filed a complaint with the MPSC against the LDC to void the OFO penalties, or alternatively to grant a waiver or variance from the tariff requirements, to prohibit the LDC from billing or otherwise attempting to collect from Generation or any Missouri customer any portion of the penalties claimed by the LDC until the resolution of the complaint, and to prohibit the LDC from taking any retaliatory measure, including termination of service. On September 1, 2021, the MPSC consolidated Generation’s complaint with two other similar complaints from other companies. The evidentiary hearing for the three consolidated complaint cases is scheduled for March 2022. Based on the penalty provisions within the tariff that was in effect at the relevant time, Exelon and Generation have recorded a liability of approximately $40 million as of September 30, 2021.

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.

Changes in Accumulated Other Comprehensive Income (Exelon)

9 Months Ended

Sep. 30, 2021

Changes in Accumulated Other Comprehensive Income [Abstract]

Changes in Accumulated Other Comprehensive Income [Text Block]

Changes in Accumulated Other Comprehensive Income (Exelon)

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


Three Months Ended September 30, 2021	Losses on Cash Flow Hedges		Pension and Non-Pension Postretirement Benefit Plan Items(a)		Foreign Currency Items		Total
Beginning balance	$	(5)	$	(3,264)	$	(20)	$	(3,289)
OCI before reclassifications	—		14		(3)		11
Amounts reclassified from AOCI	—		55		—		55
Net current-period OCI	—		69		(3)		66
Ending balance	$	(5)	$	(3,195)	$	(23)	$	(3,223)


Three Months Ended September 30, 2020	Losses on Cash Flow Hedges		Pension and Non-Pension Postretirement Benefit Plan Items(a)		Foreign Currency Items		Total
Beginning balance	$	(3)	$	(3,096)	$	(33)	$	(3,132)
OCI before reclassifications	(1)		(13)		3		(11)
Amounts reclassified from AOCI	—		39		—		39
Net current-period OCI	(1)		26		3		28
Ending balance	$	(4)	$	(3,070)	$	(30)	$	(3,104)


Nine Months Ended September 30, 2021	Losses on Cash Flow Hedges		Pension and Non-Pension Postretirement Benefit Plan Items(a)		Foreign Currency Items		Total
Beginning balance	$	(5)	$	(3,372)	$	(23)	$	(3,400)
OCI before reclassifications	(1)		15		—		14
Amounts reclassified from AOCI	—		163		—		163
Net current-period OCI	(1)		178		—		177
Ending balance	$	(6)	$	(3,194)	$	(23)	$	(3,223)


Nine Months Ended September 30, 2020	Losses on Cash Flow Hedges		Pension and Non-Pension Postretirement Benefit Plan Items(a)		Foreign Currency Items		Total
Beginning balance	$	(2)	$	(3,165)	$	(27)	$	(3,194)
OCI before reclassifications	(2)		(17)		(3)		(22)
Amounts reclassified from AOCI	—		112		—		112
Net current-period OCI	(2)		95		(3)		90
Ending balance	$	(4)	$	(3,070)	$	(30)	$	(3,104)

______

(a)AOCI amounts are included in the computation of net periodic pension and OPEB cost. See Note 11 — Retirement Benefits for additional information. See Exelon's Statements of Operations and Comprehensive Income for individual components of AOCI.

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	$	1	$	4	$	3	$	12
Actuarial loss reclassified to periodic benefit cost	(19)		(16)		(57)		(50)
Pension and non-pension postretirement benefit plans valuation adjustment	(7)		3		(8)		6

Variable Interest Entities (Exelon, Generation, PHI and ACE)

9 Months Ended

Sep. 30, 2021

Variable Interest Entity [Abstract]

Variable Interest Entity Disclosure

Variable Interest Entities (Exelon, Generation, PHI, and ACE)

At September 30, 2021 and December 31, 2020, 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 September 30, 2021 and December 31, 2020. 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 footnote to the table below, are such that creditors, or beneficiaries, do not have recourse to the general credit of Exelon, Generation, PHI, and ACE.


	September 30, 2021								December 31, 2020
	Exelon		Generation		PHI(a)		ACE		Exelon		Generation		PHI(a)		ACE
Cash and cash equivalents	$	38	$	38	$	—	$	—	$	98	$	98	$	—	$	—
Restricted cash and cash equivalents	47		42		5		5		47		44		3		3
Accounts receivable
Customer	25		25		—		—		148		148		—		—
Other	7		7		—		—		36		36		—		—
Unamortized energy contract assets	21		21		—		—		22		22		—		—
Inventories, net

Materials and supplies	14		14		—		—		244		244		—		—
Assets held for sale(b)	—		—		—		—		101		101		—		—
Other current assets	517		513		4		—		674		669		5		—
Total current assets	669		660		9		5		1,370		1,362		8		3
Property, plant, and equipment, net	2,052		2,052		—		—		5,803		5,803		—		—
Nuclear decommissioning trust funds	—		—		—		—		3,007		3,007		—		—

Unamortized energy contract assets	210		210		—		—		249		249		—		—
Other noncurrent assets	22		13		9		9		52		42		10		10
Total noncurrent assets	2,284		2,275		9		9		9,111		9,101		10		10
Total assets(c)	$	2,953	$	2,935	$	18	$	14	$	10,481	$	10,463	$	18	$	13
Long-term debt due within one year	$	80	$	70	$	10	$	6	$	94	$	68	$	26	$	21
Accounts payable	11		11		—		—		81		81		—		—
Accrued expenses	14		14		—		—		70		70		—		—

Unamortized energy contract liabilities	—		—		—		—		4		4		—		—
Liabilities held for sale(b)	—		—		—		—		16		16		—		—
Other current liabilities	—		—		—		—		5		5		—		—
Total current liabilities	105		95		10		6		270		244		26		21
Long-term debt	832		832		—		—		889		889		—		—
Asset retirement obligations	149		149		—		—		2,318		2,318		—		—


Other noncurrent liabilities	3		3		—		—		129		129		—		—
Total noncurrent liabilities	984		984		—		—		3,336		3,336		—		—
Total liabilities(d)	$	1,089	$	1,079	$	10	$	6	$	3,606	$	3,580	$	26	$	21

_________

(a)Includes certain purchase accounting adjustments from the PHI merger not pushed down to ACE.

(b)In the fourth quarter of 2020, Generation entered into an agreement for the sale of a significant portion of Generation's solar business, and as a result of this transaction, Exelon and Generation reclassified the consolidated VIEs' solar assets and liabilities as held for sale. Completion of the transaction occurred in the first quarter of 2021. Refer to Note 2 — Mergers, Acquisitions, and Dispositions for additional information on the solar business.

(c)Exelon’s and Generation’s balances include unrestricted assets for current unamortized energy contract assets of $21 million and $22 million, non-current unamortized energy contract assets of $210 million and $249 million, assets held for sale of $0 million and $9 million, and other unrestricted assets of $0 million and $1 million as of September 30, 2021 and December 31, 2020, respectively.

(d)Exelon’s and Generation’s balances include liabilities with recourse of $1 million and $8 million as of September 30, 2021 and December 31, 2020, respectively.

As of September 30, 2021 and December 31, 2020, Exelon's and Generation's consolidated VIEs included the following:


Consolidated VIE or VIE groups:	Reason entity is a VIE:	Reason Generation is primary beneficiary:
CENG - A joint venture between Generation and EDF. Generation had a 50.01% equity ownership in CENG as of December 31, 2020 and acquired EDF's 49.99% equity interest on August 6,2021 resulting in CENG no longer being classified as a consolidated VIE beginning in the third quarter of 2021. 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 has a noncontrolling interest.	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 2019.	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. See 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.

On November 20, 2019, Generation received notice of EDF's intention to exercise the put option to sell its 49.99% equity interest in CENG to Generation and the put automatically exercised on January 19, 2020. On August 6, 2021, Generation and EDF entered into a settlement agreement pursuant to which Generation purchased EDF's equity interest in CENG and resulted in CENG no longer being classified as a consolidated VIE beginning in the third quarter of 2021. 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 of the Exelon 2020 Form 10-K for more details.

•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.

Prior to August 6, 2021, Generation and EDF shared in the $688 million of contingent payment obligations for the payment of contingent retrospective premium adjustments for the nuclear liability insurance. Following the execution of the settlement agreement, EDF no longer shares in the obligation.

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 ExGen Renewables IV non-recourse debt project financing structure. Refer to Note 17 — Debt and Credit Agreements of the Exelon 2020 Form 10-K for additional information on ExGen Renewables IV.

As of September 30, 2021 and December 31, 2020, 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 September 30, 2021 and December 31, 2020, 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:


	September 30, 2021						December 31, 2020
	Commercial Agreement VIEs		Equity Investment VIEs		Total		Commercial Agreement VIEs		Equity Investment VIEs		Total
Total assets(a)	$	781	$	370	$	1,151	$	777	$	401	$	1,178
Total liabilities(a)	80		209		289		61		223		284
Exelon's ownership interest in VIE(a)	—		143		143		—		157		157
Other ownership interests in VIE(a)	701		18		719		716		21		737

_________

(a)These items represent amounts in 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 September 30, 2021 and December 31, 2020.

As of September 30, 2021 and December 31, 2020, 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 2019.	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)

9 Months Ended

Sep. 30, 2021

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.


	Operating revenues
	Exelon		Generation		PHI		DPL
Three Months Ended September 30, 2021
Operating lease income	$	30	$	29	$	1	$	1
Variable lease income	71		71		—		—

Three Months Ended September 30, 2020
Operating lease income	$	30	$	28	$	1	$	1
Variable lease income	76		76		—		—

Nine Months Ended September 30, 2021
Operating lease income	$	47	$	44	$	3	$	3
Variable lease income	208		207		1		1

Nine Months Ended September 30, 2020
Operating lease income	$	48	$	43	$	3	$	3
Variable lease income	225		224		1		1


	Taxes other than income taxes
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Three Months Ended September 30, 2021
Utility taxes(a)	$	242	$	27	$	67	$	41	$	21	$	86	$	80	$	6	$	—
Property	165		66		13		5		46		34		23		10		1
Payroll	57		26		7		4		5		7		2		1		1

Three Months Ended September 30, 2020
Utility taxes(a)	$	237	$	26	$	66	$	41	$	21	$	83	$	77	$	5	$	1
Property	152		66		7		4		42		32		21		10		1
Payroll	59		29		7		4		4		6		2		1		1

Nine Months Ended September 30, 2021
Utility taxes(a)	$	665	$	73	$	188	$	107	$	66	$	231	$	212	$	17	$	2
Property	470		199		30		13		131		97		65		30		2
Payroll	180		83		20		12		14		21		5		4		2

Nine Months Ended September 30, 2020
Utility taxes(a)	$	651	$	75	$	181	$	102	$	65	$	228	$	210	$	16	$	2
Property	449		199		23		12		121		94		63		29		2
Payroll	183		88		21		12		13		21		6		4		3

__________

(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
Three Months Ended September 30, 2021
Decommissioning-related activities:
Net realized income on NDT funds(a)
Regulatory Agreement Units	$	263	$	263	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-Regulatory Agreement Units	102		102		—		—		—		—		—		—		—
Net unrealized losses on NDT funds
Regulatory Agreement Units	(195)		(195)		—		—		—		—		—		—		—
Non-Regulatory Agreement Units	(88)		(88)		—		—		—		—		—		—		—
Regulatory offset to NDT fund-related activities(b)	(38)		(38)		—		—		—		—		—		—		—
Decommissioning-related activities	44		44		—		—		—		—		—		—		—
AFUDC — Equity	36		—		10		7		7		12		9		2		1
Non-service net periodic benefit cost	19		—		—		—		—		—		—		—		—
Net unrealized losses from equity investments(c)	(179)		(179)		—		—		—		—		—		—		—

Three Months Ended September 30, 2020
Decommissioning-related activities:
Net realized income on NDT funds(a)
Regulatory Agreement Units	$	50	$	50	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-Regulatory Agreement Units	23		23		—		—		—		—		—		—		—
Net unrealized gains on NDT funds
Regulatory Agreement Units	398		398		—		—		—		—		—		—		—
Non-Regulatory Agreement Units	254		254		—		—		—		—		—		—		—
Regulatory offset to NDT fund-related activities(b)	(359)		(359)		—		—		—		—		—		—		—
Decommissioning-related activities	366		366		—		—		—		—		—		—		—
AFUDC — Equity	27		—		7		5		6		9		7		1		1
Non-service net periodic benefit cost	15		—		—		—		—		—		—		—		—


	Other, net
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Nine Months Ended September 30, 2021
Decommissioning-related activities:
Net realized income on NDT funds(a)
Regulatory Agreement Units	$	698	$	698	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-Regulatory Agreement Units	392		392		—		—		—		—		—		—		—
Net unrealized gains on NDT funds
Regulatory Agreement Units	84		84		—		—		—		—		—		—		—
Non-Regulatory Agreement Units	38		38		—		—		—		—		—		—		—
Regulatory offset to NDT fund-related activities(b)	(607)		(607)		—		—		—		—		—		—		—
Decommissioning-related activities	605		605		—		—		—		—		—		—		—

AFUDC — Equity	99		—		23		19		21		36		30		4		2
Non-service net periodic benefit cost	64		—		—		—		—		—		—		—		—
Net unrealized losses from equity investments(c)	(83)		(83)		—		—		—		—		—		—		—

Nine Months Ended September 30, 2020
Decommissioning-related activities:
Net realized income on NDT funds(a)
Regulatory Agreement Units	$	127	$	127	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-Regulatory Agreement Units	127		127		—		—		—		—		—		—		—
Net unrealized gains on NDT funds
Regulatory Agreement Units	111		111		—		—		—		—		—		—		—
Non-Regulatory Agreement Units	1		1		—		—		—		—		—		—		—
Regulatory offset to NDT fund-related activities(b)	(192)		(192)		—		—		—		—		—		—		—
Decommissioning-related activities	174		174		—		—		—		—		—		—		—


AFUDC — Equity	76		—		22		12		16		26		20		3		3
Non-service net periodic benefit cost	38		—		—		—		—		—		—		—		—

__________

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

(b)Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units except for decommissioning-related impacts that were not offset for the Byron units starting in the second quarter of 2021, including the elimination of income taxes related to all NDT fund activity for those units. With Generation's September 15, 2021 reversal of the previous decision to retire Byron, Generation resumed contractual offset for Byron as of that date. See Note 10 — Asset Retirement Obligations of the Exelon 2020 Form 10-K for additional information regarding the accounting for nuclear decommissioning and Note 8 — Nuclear Decommissioning for additional information on the contractual offset suspension for the Byron units.

(c)Net unrealized losses from equity investments that became publicly traded entities in the fourth quarter of 2020 and the first half of 2021.

Supplemental Cash Flow Information

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


	Depreciation, amortization, and accretion
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Nine Months Ended September 30, 2021
Property, plant, and equipment(a)	$	4,505	$	2,698	$	721	$	249	$	324	$	467	$	204	$	126	$	115
Amortization of regulatory assets(a)	439		—		172		10		110		147		98		31		18
Amortization of intangible assets, net(a)	44		37		—		—		—		—		—		—		—
Amortization of energy contract assets and liabilities(b)	23		23		—		—		—		—		—		—		—
Nuclear fuel(c)	810		810		—		—		—		—		—		—		—
ARO accretion(d)	383		383		—		—		—		—		—		—		—
Total depreciation, amortization, and accretion	$	6,204	$	3,951	$	893	$	259	$	434	$	614	$	302	$	157	$	133

Nine Months Ended September 30, 2020
Property, plant, and equipment(a)	$	2,831	$	1,121	$	689	$	238	$	293	$	436	$	191	$	116	$	104
Amortization of regulatory assets(a)	434		—		152		21		112		149		91		27		30
Amortization of intangible assets, net(a)	47		40		—		—		—		—		—		—		—
Amortization of energy contract assets and liabilities(b)	24		22		—		—		—		—		—		—		—
Nuclear fuel(c)	708		708		—		—		—		—		—		—		—
ARO accretion(d)	375		375		—		—		—		—		—		—		—
Total depreciation, amortization, and accretion	$	4,419	$	2,266	$	841	$	259	$	405	$	585	$	282	$	143	$	134

__________

(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.


	Other non-cash operating activities
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Nine Months Ended September 30, 2021
Pension and non-pension postretirement benefit costs	$	304	$	92	$	97	$	5	$	45	$	36	$	5	$	2	$	8
Allowance for credit losses	155		59		34		36		7		18		9		3		6
Other decommissioning-related activity(a)	(810)		(810)		—		—		—		—		—		—		—
Energy-related options(b)	45		45		—		—		—		—		—		—		—
True-up adjustments to decoupling mechanisms and formula rates(c)	(129)		—		(32)		(20)		17		(94)		(54)		(17)		(23)
Severance costs	(67)		(75)		1		—		—		1		—		—		—

Long-term incentive plan	94		—		—		—		—		—		—		—		—


Amortization of operating ROU asset	146		98		2		—		22		21		5		7		3


AFUDC — Equity	(99)		—		(23)		(19)		(21)		(36)		(30)		(4)		(2)

Nine Months Ended September 30, 2020
Pension and non-pension postretirement benefit costs	$	310	$	89	$	85	$	4	$	46	$	52	$	11	$	6	$	10
Allowance for credit losses	130		16		23		38		12		41		24		15		2
Other decommissioning-related activity(a)	(301)		(301)		—		—		—		—		—		—		—
Energy-related options(b)	79		79		—		—		—		—		—		—		—
True-up adjustments to decoupling mechanisms and formula rates(c)	66		—		51		(10)		10		15		(20)		15		20
Severance costs	96		88		1		—		—		—		—		—		—
Provision for excess and obsolete inventory	119		118		1		1		—		(1)		—		(1)		—
Long-term incentive plan	(8)		—		—		—		—		—		—		—		—


Amortization of operating ROU asset	185		135		1		—		23		21		5		6		2
Deferred Prosecution Agreement payments(d)	200		—		200		—		—		—		—		—		—

AFUDC — Equity	(76)		—		(22)		(12)		(16)		(26)		(20)		(3)		(3)

__________

(a)Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units except for decommissioning-related impacts that were not offset for the Byron units starting in the second quarter of 2021, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income, and income taxes related to all NDT fund activity for these units. With Generation's September 15, 2021 reversal of the previous decision to retire Byron, Generation resumed contractual offset for Byron as of that date. See Note 10 — Asset Retirement Obligations of the Exelon 2020 Form 10-K for additional information regarding the accounting for nuclear decommissioning and Note 8 — Nuclear Decommissioning for additional information on the contractual offset suspension for the Byron units.

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

(c)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, DPL, and ACE, reflects the change in regulatory assets and liabilities associated with their decoupling mechanisms and transmission formula rates. For PECO, reflects the change in regulatory assets and liabilities associated with its transmission formula rates. See Note 3 — Regulatory Matters for additional information.

(d)See Note 15 — Commitments and Contingencies for additional information related to the Deferred Prosecution Agreement.

The following tables provide a reconciliation of cash, cash equivalents, and restricted cash 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
September 30, 2021
Cash and cash equivalents	$	2,957	$	1,957	$	241	$	344	$	225	$	82	$	19	$	13	$	16
Restricted cash and cash equivalents	473		62		276		8		27		71		41		26		5
Restricted cash included in other long-term assets	54		—		44		—		—		9		—		—		9
Total cash, restricted cash, and cash equivalents	$	3,484	$	2,019	$	561	$	352	$	252	$	162	$	60	$	39	$	30

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

September 30, 2020
Cash and cash equivalents	$	1,858	$	623	$	76	$	242	$	326	$	196	$	125	$	26	$	13
Restricted cash and cash equivalents	485		100		305		7		1		38		33		—		4
Restricted cash included in other long-term assets	137		—		127		—		—		10		—		—		10
Total cash, restricted cash, and cash equivalents	$	2,480	$	723	$	508	$	249	$	327	$	244	$	158	$	26	$	27

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

For additional information on restricted cash see Note 1 — Significant Accounting Policies of the Exelon 2020 Form 10-K.

Supplemental Balance Sheet Information

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


	Accrued expenses
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
September 30, 2021
Compensation-related accruals(a)	$	894	$	318	$	148	$	66	$	72	$	108	$	34	$	21	$	16
Taxes accrued	508		222		80		61		90		98		67		16		7
Interest accrued	415		77		65		36		39		75		37		20		15

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

__________

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

Related Party Transactions (All Registrants)

9 Months Ended

Sep. 30, 2021

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:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Operating revenues from affiliates:
ComEd(a)(b)	$	96	$	71	$	249	$	241
PECO(c)	59		68		142		146
BGE(d)	65		84		195		252
PHI	99		105		276		288
Pepco(e)	69		80		199		219
DPL(f)	25		21		63		60
ACE(g)	5		4		14		9
Other	5		3		10		5
Total operating revenues from affiliates (Generation)	$	324	$	331	$	872	$	932

__________

(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 the three and nine months ended September 30, 2021, respectively, ComEd’s Purchased power from Generation of $94 million and $256 million is recorded as Operating revenues from ComEd of $96 million and $249 million and as Purchased power and fuel from ComEd of $2 million and $(7) million at Generation. For the three and nine months ended September 30, 2020, respectively, ComEd’s Purchased power from Generation of $71 million and $252 million is recorded as Operating revenues from ComEd of $71 million and $241 million and as Purchased power and fuel from ComEd of less than $1 million and $11 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.

Service Company Costs for Corporate Support

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
	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020		2021		2020		2021		2020
Exelon
BSC									$	149	$	148	$	431	$	390
PHISCO									18		15		54		45
Generation
BSC	$	145	$	133	$	424	$	406	43		13		76		37
ComEd
BSC	71		65		214		204		47		49		148		133
PECO
BSC	41		34		120		107		12		20		57		53
BGE
BSC	45		38		133		120		20		30		62		88
PHI
BSC	40		36		116		107		27		36		88		79
PHISCO	—		—		—		—		18		15		54		45
Pepco
BSC	23		20		68		61		11		14		36		29
PHISCO	26		28		84		90		7		7		22		20
DPL
BSC	14		13		43		38		10		12		29		26
PHISCO	24		24		73		73		6		4		17		13
ACE
BSC	14		11		37		32		7		10		22		22
PHISCO	21		21		64		65		5		4		15		12

Current Receivables from/Payables to affiliates

The following tables present current receivables from affiliates and current payables to affiliates:

September 30, 2021


				Receivables from affiliates:
	Payables to affiliates:			Generation			ComEd			PECO			BGE			Pepco			DPL			ACE			BSC			PHISCO			Other			Total
Generation					$	36		$	9		$	—		$	—		$	—		$	—		$	86		$	—		$	23		$	154
ComEd		$	103	(a)				—			—			—			—			—			49			—			6			158
PECO		24			3						1			—			—			—			25			—			7			60
BGE		15			—			—						—			—			—			32			—			2			49
PHI		—			—			—			—			—			—			—			2			—			10			12
Pepco		22			—			—			—						1			—			15			13			—			51
DPL		4			—			—			—			—						—			9			11			—			24
ACE		7			—			—			—			—			—						9			9			1			26
Other		9			2			—			1			—			—			1			2			—						15
Total		$	184		$	41		$	9		$	2		$	—		$	1		$	1		$	229		$	33		$	49		$	549

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

__________

(a)As of September 30, 2021 and December 31, 2020, Generation had a contract liability with ComEd for $27 million and $50 million, respectively, that was included in Other current liabilities on Generation’s Consolidated Balance Sheets. As of September 30, 2021 and December 31, 2020, ComEd had a Current Payable to Generation of $76 million and $28 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 of the Exelon 2020 Form 10-K 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:


	September 30, 2021		December 31, 2020
ComEd	$	2,597	$	2,541
PECO	546		475

Long-term debt to financing trusts

The following table presents Long-term debt to financing trusts:


	September 30, 2021						December 31, 2020
	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.

Planned Separation	9 Months Ended
Planned Separation	Sep. 30, 2021
Discontinued Operations and Disposal Groups [Abstract]
Planned Separation	Planned SeparationOn 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 FERC, NRC, and NYPSC and receipt of a private letter ruling from the IRS and tax opinion from Exelon’s tax advisors. On February 25, 2021, Exelon and Generation filed applications with FERC, NYPSC, and NRC seeking approvals for the separation of Generation. On March 25, 2021, Exelon filed a request for a private letter ruling with the IRS to confirm the tax-free treatment of the planned separation, which was received on September 23, 2021. On August 24, 2021, Exelon and Generation received approval from FERC for the planned separation. Exelon and Generation expect a decision from the NRC in the fourth quarter of 2021 and have requested a decision from the NYPSC before the end of 2021. Exelon and Generation cannot predict if the remaining applications will be approved as filed. There can be no assurance that any separation transaction will ultimately occur or, if one does occur, of its terms or timing.

Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2021

Accounting Policies [Abstract]

Description of Business and Basis of Presentation (All Registrants) [Policy Text Block]

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)

Revenue [Policy Text Block]

Mergers, Acquisitions, and Dispositions (Tables)

9 Months Ended

Sep. 30, 2021

Mergers, Acquisitions, and Dispositions [Abstract]

Schedule of Changes in Ownership Interest [Table Text Block]

The following tables summarize the effects of the changes in Generation's ownership interest in CENG in Exelon's Shareholders' Equity and Generation's Member's Equity:


	Three Months Ended September 30, 2021		Nine Months Ended September 30, 2021
Net income attributable to Exelon's common shareholders	$	1,203	$	1,315
Pre-tax increase in Exelon's common stock for purchase of EDF's 49.99% equity interest(a)	1,080		1,080
Decrease in Exelon's common stock due to deferred tax liabilities resulting from purchase of EDF's 49.99% equity interest(a)	(290)		(290)
Change from net income attributable to common stock and transfers from noncontrolling interest	$	1,993	$	2,105

	Three Months Ended September 30, 2021		Nine Months Ended September 30, 2021
Net income (loss) attributable to Generation's membership interest	$	607	$	(247)
Pre-tax increase in Generation's membership interest for purchase of EDF's 49.99% equity interest(a)	1,080		1,080
Decrease in Generation's membership interest due to deferred tax liabilities resulting from purchase of EDF's 49.99% equity interest(a)	(288)		(288)
Change from net income (loss) attributable to membership interest and transfers from noncontrolling interest	$	1,399	$	545

_________

(a)Represents non-cash activity in Exelon’s and Generation’s consolidated financial statements.

Regulatory Matters (Tables)

9 Months Ended

Sep. 30, 2021

Regulated Operations [Abstract]

Public Utilities Distribution Rate Cases [Table Text Block]

The following tables show the completed and pending distribution base rate case proceedings in 2021.

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 16, 2020	Electric	$	(11)	$	(14)	8.38	%	December 9, 2020	January 1, 2021
PECO - Pennsylvania	September 30, 2020	Natural Gas	69		29		10.24	%	June 22, 2021	July 1, 2021
BGE - Maryland(b)	May 15, 2020 (amended September 11, 2020)	Electric	203		140		9.50	%	December 16, 2020	January 1, 2021
		Natural Gas	108		74		9.65	%
Pepco - District of Columbia(c)	May 30, 2019 (amended June 1, 2020)	Electric	136		109		9.275	%	June 8, 2021	July 1, 2021
Pepco - Maryland(d)	October 26, 2020 (amended March 31, 2021)	Electric	104		52		9.55	%	June 28, 2021	June 28, 2021
DPL - Delaware	March 6, 2020 (amended February 2, 2021)	Electric	23		14		9.60	%	September 15, 2021	October 6, 2020
ACE - New Jersey(e)	December 9, 2020 (amended February 26, 2021)	Electric	67		41		9.60	%	July 14, 2021	January 1, 2022

__________

Pending Distribution Base Rate Case Proceedings

Registrant/Jurisdiction

Filing Date

Service

Requested Revenue Requirement Increase

Requested ROE

Expected Approval Timing

ComEd - Illinois(a)

April 16, 2021

Electric

7.36

Fourth quarter of 2021

PECO - Pennsylvania(b)

March 30, 2021

Electric

246

10.95

Fourth quarter of 2021

DPL - Maryland

September 1, 2021

Electric

10.10

First quarter of 2022

__________

Public Utilities Transmission Rate Filings [Table Text Block]

For 2021, 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 Increase		Total Revenue Requirement Increase(b)		Allowed Return on Rate Base(c)		Allowed ROE(d)
ComEd	$	33	$	12	$	45	8.20	%	11.50	%
PECO	(2)		26		24		7.37	%	10.35	%
BGE	38		27		65		7.35	%	10.50	%
Pepco	(9)		21		12		7.68	%	10.50	%
DPL	19		33		52		7.20	%	10.50	%
ACE	27		24		51		7.45	%	10.50	%

__________

(a)All rates are effective June 1, 2021 - May 31, 2022, subject to review by interested parties pursuant to review protocols of each Utility Registrants' tariff.

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

Public Utilities Energy Efficiency Revenue [Table Text Block]


Initial Revenue Requirement Increase		Annual Reconciliation Decrease		Total Revenue Requirement Increase		Requested Return on Rate Base(a)		Requested ROE
$	55	$	(1)	$	54	5.72	%	7.36	%

__________

Public Utilities General Disclosures [Table Text Block]


	Exelon		ComEd(a)		PECO		BGE(b)		PHI		Pepco(c)		DPL(c)		ACE
September 30, 2021	$	44	$	—	$	—	$	39	$	5	$	3	$	2	$	—

December 31, 2020	51		(1)		—		45		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.

Revenue from Contracts with Customers (Tables)

9 Months Ended

Sep. 30, 2021

Contracts with Customers [Line Items]

Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Table Text Block]


	2021		2022		2023		2024		2025 and thereafter		Total
Exelon	$	82	$	125	$	50	$	35	$	184	$	476
Generation	168		281		92		41		97		679
PHI	2		8		8		6		87		111
Pepco	2		6		6		5		70		89
DPL	—		1		1		—		9		11
ACE	—		1		1		1		8		11

Contract Assets [Member]

Contracts with Customers [Line Items]

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



	Exelon		Generation
Balance as of December 31, 2020	$	144	$	144
Amounts reclassified to receivables	(16)		(16)
Revenues recognized	13		13
Amounts previously held-for-sale	12		12
Balance as of March 31, 2021	153		153
Amounts reclassified to receivables	(12)		(12)
Revenues recognized	9		9
Balance as of June 30, 2021	150		150
Amounts reclassified to receivables	(15)		(15)
Revenues recognized	14		14

Balance as of September 30, 2021	$	149	$	149


	Exelon		Generation
Balance as of December 31, 2019	$	174	$	174
Amounts reclassified to receivables	(19)		(19)
Revenues recognized	17		17

Balance as of March 31, 2020	172		172
Amounts reclassified to receivables	(26)		(26)
Revenues recognized	13		13
Balance as of June 30, 2020	159		159
Amounts reclassified to receivables	(18)		(18)
Revenues recognized	19		19
Balance as of September 30, 2020	$	160	$	160

Contract Liabilities [Member]

Contracts with Customers [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, 2020	$	151	$	84	$	118	$	94	$	12	$	12
Consideration received or due	20		31		—		—		—		—
Revenues recognized	(27)		(64)		(2)		(2)		—		—
Amounts previously held-for-sale	3		3		—		—		—		—
Balance as of March 31, 2021	147		54		116		92		12		12
Consideration received or due	17		39		—		—		—		—
Revenues recognized	(32)		(68)		(3)		(1)		(1)		(1)

Balance as of June 30, 2021	132		25		113		91		11		11
Consideration received or due	31		93		—		—		—		—
Revenues recognized	(26)		(65)		(2)		(2)		—		—
Balance as of September 30, 2021	$	137	$	53	$	111	$	89	$	11	$	11


	Exelon		Generation		PHI		Pepco		DPL		ACE
Balance as of December 31, 2019	$	33	$	71	$	—	$	—	$	—	$	—
Consideration received or due	20		55		—		—		—		—
Revenues recognized	(24)		(70)		—		—		—		—
Balance as of March 31, 2020	29		56		—		—		—		—
Consideration received or due	13		34		—		—		—		—
Revenues recognized	(22)		(63)		—		—		—		—
Balance as of June 30, 2020	20		27		—		—		—		—
Consideration received or due	154		94		124		98		13		13
Revenues recognized	(25)		(65)		(2)		(2)		—		—
Balance as of September 30, 2020	$	149	$	56	$	122	$	96	$	13	$	13


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Exelon	$	4	$	2	$	38	$	25
Generation	2		2		81		63
PHI	2		—		7		—
Pepco	2		—		5		—
DPL	—		—		1		—
ACE	—		—		1		—

Segment Information (Tables)

9 Months Ended

Sep. 30, 2021

Segment Tables [Line Items]

Analysis and reconciliation of reportable segment information

Three Months Ended September 30, 2021 and 2020



	Generation		ComEd		PECO		BGE		PHI		Other(a)		Intersegment Eliminations		Exelon
Operating revenues(b):
2021
Competitive businesses electric revenues	$	4,330	$	—	$	—	$	—	$	—	$	—	$	(319)	$	4,011
Competitive businesses natural gas revenues	575		—		—		—		—		—		—		575
Competitive businesses other revenues	(499)		—		—		—		—		—		(3)		(502)
Rate-regulated electric revenues	—		1,789		762		677		1,444		—		(15)		4,657
Rate-regulated natural gas revenues	—		—		56		93		23		—		(3)		169
Shared service and other revenues	—		—		—		—		3		534		(537)		—
Total operating revenues	$	4,406	$	1,789	$	818	$	770	$	1,470	$	534	$	(877)	$	8,910
2020
Competitive businesses electric revenues	$	4,201	$	—	$	—	$	—	$	—	$	—	$	(326)	$	3,875
Competitive businesses natural gas revenues	323		—		—		—		—		—		—		323
Competitive businesses other revenues	135		—		—		—		—		—		(3)		132
Rate-regulated electric revenues	—		1,643		759		646		1,339		—		(22)		4,365
Rate-regulated natural gas revenues	—		—		54		85		23		—		(3)		159
Shared service and other revenues	—		—		—		—		6		484		(491)		(1)


Total operating revenues	$	4,659	$	1,643	$	813	$	731	$	1,368	$	484	$	(845)	$	8,853


	Generation		ComEd		PECO		BGE		PHI		Other(a)		Intersegment Eliminations		Exelon
Intersegment revenues(c):
2021	$	324	$	9	$	2	$	7	$	3	$	531	$	(876)	$	—
2020	331		15		3		6		6		485		(845)		1
Depreciation and amortization:
2021	$	866	$	304	$	86	$	142	$	210	$	16	$	—	$	1,624
2020	558		294		85		133		200		19		—		1,289
Operating expenses:
2021	$	3,465	$	1,428	$	677	$	709	$	1,155	$	541	$	(858)	$	7,117
2020	4,727		1,302		658		642		1,102		489		(833)		8,087
Interest expense, net:
2021	$	77	$	98	$	40	$	36	$	67	$	79	$	—	$	397
2020	80		95		39		34		67		89		—		404
Income (loss) before income taxes:
2021	$	814	$	276	$	108	$	32	$	264	$	(88)	$	—	$	1,406
2020	219		256		122		61		215		(87)		—		786
Income Taxes:
2021	$	177	$	56	$	(3)	$	(4)	$	(2)	$	(50)	$	—	$	174
2020	100		60		(16)		8		(1)		65		—		216
Net income (loss):
2021	$	633	$	220	$	111	$	36	$	266	$	(37)	$	—	$	1,229
2020	117		196		138		53		216		(151)		—		569
Capital Expenditures:
2021	$	367	$	561	$	301	$	287	$	410	$	4	$	—	$	1,930
2020	282		554		312		290		386		9		—		1,833

(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):
2021
Rate-regulated electric revenues	$	660	$	337	$	451	$	—	$	(4)	$	1,444
Rate-regulated natural gas revenues	—		23		—		—		—		23
Shared service and other revenues	—		—		—		92		(89)		3
Total operating revenues	$	660	$	360	$	451	$	92	$	(93)	$	1,470
2020
Rate-regulated electric revenues	$	611	$	314	$	420	$	—	$	(6)	$	1,339
Rate-regulated natural gas revenues	—		23		—		—		—		23
Shared service and other revenues	—		—		—		91		(85)		6
Total operating revenues	$	611	$	337	$	420	$	91	$	(91)	$	1,368
Intersegment revenues(c):
2021	$	2	$	2	$	1	$	91	$	(93)	$	3
2020	3		3		1		90		(91)		6
Depreciation and amortization:
2021	$	104	$	53	$	46	$	7	$	—	$	210
2020	96		48		48		8		—		200
Operating expenses:
2021	$	501	$	295	$	359	$	93	$	(93)	$	1,155
2020	465		296		338		94		(91)		1,102
Interest expense, net:
2021	$	35	$	15	$	14	$	3	$	—	$	67
2020	35		15		15		2		—		67
Income (loss) before income taxes:
2021	$	136	$	53	$	79	$	(4)	$	—	$	264
2020	121		28		68		(2)		—		215
Income Taxes:
2021	$	6	$	3	$	(11)	$	—	$	—	$	(2)
2020	3		1		(7)		2		—		(1)
Net income (loss):
2021	$	130	$	50	$	90	$	(4)	$	—	$	266
2020	118		27		75		(4)		—		216
Capital Expenditures:
2021	$	202	$	109	$	97	$	2	$	—	$	410
2020	188		94		103		1		—		386

__________

(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):


	Three Months Ended September 30, 2021
	Revenues from external customers(a)						Intersegment Revenues		Total Revenues
	Contracts with customers		Other(b)		Total
Mid-Atlantic	$	1,145	$	123	$	1,268	$	4	$	1,272
Midwest	1,084		(99)		985		—		985
New York	445		10		455		—		455
ERCOT	191		165		356		2		358
Other Power Regions	948		318		1,266		(6)		1,260
Total Competitive Businesses Electric Revenues	3,813		517		4,330		—		4,330
Competitive Businesses Natural Gas Revenues	266		309		575		—		575
Competitive Businesses Other Revenues(c)	95		(594)		(499)		—		(499)
Total Generation Consolidated Operating Revenues	$	4,174	$	232	$	4,406	$	—	$	4,406


	Three Months Ended September 30, 2020
	Revenues from external customers(a)						Intersegment revenues		Total Revenues
	Contracts with customers		Other(b)		Total
Mid-Atlantic	$	1,327	$	(20)	$	1,307	$	6	$	1,313
Midwest	974		68		1,042		1		1,043
New York	401		5		406		—		406
ERCOT	249		74		323		7		330
Other Power Regions	937		186		1,123		(14)		1,109
Total Competitive Businesses Electric Revenues	3,888		313		4,201		—		4,201
Competitive Businesses Natural Gas Revenues	169		154		323		—		323
Competitive Businesses Other Revenues(c)	85		50		135		—		135
Total Generation Consolidated Operating Revenues	$	4,142	$	517	$	4,659	$	—	$	4,659

__________

(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):


	Three Months Ended September 30, 2021						Three Months Ended September 30, 2020
	RNF from external customers(a)		Intersegment RNF		Total RNF		RNF from external customers(a)		Intersegment RNF		Total RNF
Mid-Atlantic	$	567	$	3	$	570	$	586	$	5	$	591
Midwest	655		—		655		748		2		750
New York	343		3		346		281		4		285
ERCOT	181		(2)		179		141		6		147
Other Power Regions	233		(22)		211		253		(28)		225
Total RNF for Reportable Segments	1,979		(18)		1,961		2,009		(11)		1,998
Other(b)	881		18		899		336		11		347
Total Generation RNF	$	2,860	$	—	$	2,860	$	2,345	$	—	$	2,345

__________

(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. includes:

•unrealized mark-to-market gains of $754 million and gains of $255 million in 2021 and 2020, respectively;

•the elimination of intersegment RNF.

Schedule of Revenue by Major Customers by Reporting Segments [Table Text Block]

Electric and Gas Revenue by Customer Class (Utility Registrants):


	Three Months Ended September 30, 2021
Revenues from contracts with customers	ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Rate-regulated electric revenues
Residential	$	978	$	509	$	383	$	782	$	309	$	198	$	275
Small commercial & industrial	433		113		73		150		36		53		61
Large commercial & industrial	148		67		128		320		244		27		49
Public authorities & electric railroads	11		7		7		15		8		4		3
Other(a)	245		61		104		172		53		56		63
Total rate-regulated electric revenues(b)	$	1,815	$	757	$	695	$	1,439	$	650	$	338	$	451
Rate-regulated natural gas revenues
Residential	$	—	$	36	$	57	$	10	$	—	$	10	$	—
Small commercial & industrial	—		13		10		5		—		5		—
Large commercial & industrial	—		—		22		2		—		2		—
Transportation	—		5		—		3		—		3		—
Other(c)	—		2		6		3		—		3		—
Total rate-regulated natural gas revenues(d)	$	—	$	56	$	95	$	23	$	—	$	23	$	—
Total rate-regulated revenues from contracts with customers	$	1,815	$	813	$	790	$	1,462	$	650	$	361	$	451

Other revenues
Revenues from alternative revenue programs	$	(32)	$	3	$	(24)	$	6	$	9	$	(2)	$	—
Other rate-regulated electric revenues(e)	6		2		3		2		1		1		—
Other rate-regulated natural gas revenues(e)	—		—		1		—		—		—		—

Total other revenues	$	(26)	$	5	$	(20)	$	8	$	10	$	(1)	$	—
Total rate-regulated revenues for reportable segments	$	1,789	$	818	$	770	$	1,470	$	660	$	360	$	451


	Three Months Ended September 30, 2020
Revenues from contracts with customers	ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Rate-regulated electric revenues
Residential	$	920	$	518	$	389	$	763	$	307	$	193	$	263
Small commercial & industrial	379		104		65		134		36		45		53
Large commercial & industrial	135		66		113		262		195		21		46
Public authorities & electric railroads	10		7		7		14		8		3		3
Other(a)	234		58		78		141		47		44		50
Total rate-regulated electric revenues(b)	$	1,678	$	753	$	652	$	1,314	$	593	$	306	$	415
Rate-regulated natural gas revenues
Residential	$	—	$	32	$	55	$	11	$	—	$	11	$	—
Small commercial & industrial	—		16		9		6		—		6		—
Large commercial & industrial	—		—		21		1		—		1		—
Transportation	—		6		—		3		—		3		—
Other(c)	—		1		3		2		—		2		—
Total rate-regulated natural gas revenues(d)	$	—	$	55	$	88	$	23	$	—	$	23	$	—
Total rate-regulated revenues from contracts with customers	$	1,678	$	808	$	740	$	1,337	$	593	$	329	$	415

Other revenues
Revenues from alternative revenue programs	$	(38)	$	5	$	(9)	$	31	$	18	$	8	$	5
Other rate-regulated electric revenues(e)	3		—		—		—		—		—		—
Other rate-regulated natural gas revenues(e)	—		—		—		—		—		—		—

Total other revenues	$	(35)	$	5	$	(9)	$	31	$	18	$	8	$	5
Total rate-regulated revenues for reportable segments	$	1,643	$	813	$	731	$	1,368	$	611	$	337	$	420

__________

(a)Includes revenues from transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue.

(b)Includes operating revenues from affiliates in 2021 and 2020 respectively of:

•$9 million, $15 million at ComEd

•$2 million, $3 million at PECO

•$4 million, $3 million at BGE

•$3 million, $6 million at PHI

•$2 million, $3 million at Pepco

•$2 million, $3 million at DPL

•$1 million, $1 million at ACE

(c)Includes revenues from off-system natural gas sales.

(d)Includes operating revenues from affiliates in 2021 and 2020 respectively of:

•less than $1 million at PECO both 2021 and 2020

•$3 million, $3 million at BGE

(e)Includes late payment charge revenues.

Year to Date [Member]

Segment Tables [Line Items]

Analysis and reconciliation of reportable segment information

Nine Months Ended September 30, 2021 and 2020


	Generation		ComEd		PECO		BGE		PHI		Other(a)		Intersegment Eliminations		Exelon
Operating revenues(b):
2021
Competitive businesses electric revenues	$	12,264	$	—	$	—	$	—	$	—	$	—	$	(860)	$	11,404


	Generation		ComEd		PECO		BGE		PHI		Other(a)		Intersegment Eliminations		Exelon
Competitive businesses natural gas revenues	2,408		—		—		—		—		—		—		2,408
Competitive businesses other revenues	(555)		—		—		—		—		—		(9)		(564)
Rate-regulated electric revenues	—		4,840		2,033		1,866		3,726		—		(33)		12,432
Rate-regulated natural gas revenues	—		—		366		560		118		—		(9)		1,035
Shared service and other revenues	—		—		—		—		10		1,549		(1,559)		—
Total operating revenues	$	14,117	$	4,840	$	2,399	$	2,426	$	3,854	$	1,549	$	(2,470)	$	26,715
2020
Competitive businesses electric revenues	$	11,367	$	—	$	—	$	—	$	—	$	—	$	(920)	$	10,447
Competitive businesses natural gas revenues	1,348		—		—		—		—		—		(3)		1,345
Competitive businesses other revenues	557		—		—		—		—		—		(5)		552
Rate-regulated electric revenues	—		4,499		1,948		1,763		3,425		—		(50)		11,585
Rate-regulated natural gas revenues	—		—		358		521		116		—		(5)		990
Shared service and other revenues	—		—		—		—		13		1,440		(1,447)		6
Total operating revenues	$	13,272	$	4,499	$	2,306	$	2,284	$	3,554	$	1,440	$	(2,430)	$	24,925

Intersegment revenues(c):
2021	$	872	$	19	$	6	$	20	$	10	$	1,542	$	(2,469)	$	—
2020	932		31		7		16		13		1,435		(2,430)		4
Depreciation and amortization:
2021	$	2,735	$	893	$	259	$	434	$	614	$	52	$	1	$	4,988
2020	1,161		841		259		405		585		61		—		3,312
Operating expenses:
2021	$	14,605	$	3,833	$	1,908	$	2,080	$	3,167	$	1,572	$	(2,407)	$	24,758
2020	12,674		3,798		1,900		1,903		3,057		1,452		(2,397)		22,387
Interest expense, net:
2021	$	225	$	292	$	119	$	103	$	201	$	241	$	(1)	$	1,180
2020	277		287		108		99		201		269		—		1,241


	Generation		ComEd		PECO		BGE		PHI		Other(a)		Intersegment Eliminations		Exelon
Income (loss) before income taxes:
2021	$	(8)	$	750	$	392	$	266	$	538	$	(264)	$	1	$	1,675
2020	532		446		310		299		340		(262)		—		1,665
Income Taxes:
2021	$	108	$	141	$	9	$	(24)	$	3	$	(8)	$	—	$	229
2020	41		142		(7)		26		(77)		16		—		141
Net income (loss):
2021	$	(122)	$	609	$	383	$	290	$	535	$	(255)	$	1	$	1,441
2020	485		304		317		273		418		(278)		—		1,519
Capital Expenditures:
2021	$	1,086	$	1,723	$	878	$	907	$	1,299	$	77	$	—	$	5,970
2020	1,212		1,583		824		838		1,072		77		—		5,606
Total assets:
September 30, 2021	$	48,010	$	36,002	$	13,733	$	12,197	$	24,502	$	8,387	$	(10,210)	$	132,621
December 31, 2020	48,094		34,466		12,531		11,650		23,736		9,005		(10,165)		129,317

__________

(a)Other primarily includes Exelon’s corporate operations, shared service entities, and other financing and investment activities.

(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 19 — Related Party Transactions for additional information on intersegment revenues.

PHI:


	Pepco		DPL		ACE		Other(a)		Intersegment Eliminations		PHI
Operating revenues(b):
2021
Rate-regulated electric revenues	$	1,736	$	922	$	1,080	$	—	$	(12)	$	3,726
Rate-regulated natural gas revenues	—		118		—		—		—		118
Shared service and other revenues	—		—		—		281		(271)		10
Total operating revenues	$	1,736	$	1,040	$	1,080	$	281	$	(283)	$	3,854
2020
Rate-regulated electric revenues	$	1,650	$	838	$	952	$	—	$	(15)	$	3,425
Rate-regulated natural gas revenues	—		116		—		—		—		116
Shared service and other revenues	—		—		—		279		(266)		13
Total operating revenues	$	1,650	$	954	$	952	$	279	$	(281)	$	3,554
Intersegment revenues(c):
2021	$	4	$	6	$	2	$	281	$	(283)	$	10
2020	6		7		3		278		(281)		13
Depreciation and amortization:
2021	$	302	$	157	$	133	$	22	$	—	$	614
2020	282		143		134		26		—		585
Operating expenses:
2021	$	1,396	$	858	$	911	$	285	$	(283)	$	3,167
2020	1,364		843		847		284		(281)		3,057
Interest expense, net:
2021	$	104	$	47	$	43	$	7	$	—	$	201
2020	103		47		45		6		—		201
Income (loss) before income taxes:
2021	$	273	$	144	$	129	$	(8)	$	—	$	538
2020	211		71		67		(9)		—		340
Income Taxes:
2021	$	9	$	9	$	(12)	$	(3)	$	—	$	3
2020	(16)		(20)		(39)		(2)		—		(77)
Net income (loss):
2021	$	264	$	135	$	141	$	(5)	$	—	$	535
2020	227		91		106		(6)		—		418
Capital Expenditures:
2021	$	641	$	320	$	336	$	2	$	—	$	1,299
2020	512		278		281		1		—		1,072
Total assets:
September 30, 2021	$	9,748	$	5,295	$	4,532	$	4,977	$	(50)	$	24,502
December 31, 2020	9,264		5,140		4,286		5,079		(33)		23,736

__________

(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):



	Nine Months Ended September 30, 2021
	Revenues from external customers(a)						Intersegment Revenues		Total Revenues
	Contracts with customers		Other(b)		Total
Mid-Atlantic	$	3,377	$	134	$	3,511	$	16	$	3,527
Midwest	3,067		(123)		2,944		1		2,945
New York	1,204		(30)		1,174		(1)		1,173
ERCOT	724		155		879		11		890
Other Power Regions	3,043		713		3,756		(27)		3,729
Total Competitive Businesses Electric Revenues	11,415		849		12,264		—		12,264
Competitive Businesses Natural Gas Revenues	1,384		1,024		2,408		—		2,408
Competitive Businesses Other Revenues(c)	291		(846)		(555)		—		(555)
Total Generation Consolidated Operating Revenues	$	13,090	$	1,027	$	14,117	$	—	$	14,117



	Nine Months Ended September 30, 2020
	Revenues from external customers(a)						Intersegment revenues		Total Revenues
	Contracts with customers		Other(b)		Total
Mid-Atlantic	$	3,692	$	(152)	$	3,540	$	21	$	3,561
Midwest	2,773		240		3,013		(6)		3,007
New York	1,074		(12)		1,062		(1)		1,061
ERCOT	579		155		734		20		754
Other Power Regions	2,718		300		3,018		(34)		2,984
Total Competitive Businesses Electric Revenues	10,836		531		11,367		—		11,367
Competitive Businesses Natural Gas Revenues	881		467		1,348		—		1,348
Competitive Businesses Other Revenues(c)	268		289		557		—		557
Total Generation Consolidated Operating Revenues	$	11,985	$	1,287	$	13,272	$	—	$	13,272

__________

(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):



	Nine Months Ended September 30, 2021						Nine Months Ended September 30, 2020
	RNF from external customers(a)		Intersegment RNF		Total RNF		RNF from external customers(a)		Intersegment RNF		Total RNF
Mid-Atlantic	$	1,698	$	14	$	1,712	$	1,660	$	23	$	1,683
Midwest	2,014		1		2,015		2,180		(2)		2,178
New York	873		7		880		714		11		725
ERCOT	(775)		(147)		(922)		311		14		325
Other Power Regions	641		(77)		564		608		(70)		538
Total RNF for Reportable Segments	4,451		(202)		4,249		5,473		(24)		5,449
Other(b)	1,563		202		1,765		838		24		862
Total Generation RNF	$	6,014	$	—	$	6,014	$	6,311	$	—	$	6,311

__________

(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 $1,242 million and gains of $472 million in 2021 and 2020, respectively;

• the elimination of intersegment RNF.

Schedule of Revenue by Major Customers by Reporting Segments [Table Text Block]

Electric and Gas Revenue by Customer Class (Utility Registrants):



	Nine Months Ended September 30, 2021
Revenues from contracts with customers	ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Rate-regulated electric revenues
Residential	$	2,479	$	1,325	$	1,044	$	1,924	$	785	$	535	$	604
Small commercial & industrial	1,176		312		202		392		101		145		146
Large commercial & industrial	420		183		342		825		616		70		139
Public authorities & electric railroads	33		24		20		45		24		11		10
Other(a)	676		167		269		453		154		143		158
Total rate-regulated electric revenues(b)	$	4,784	$	2,011	$	1,877	$	3,639	$	1,680	$	904	$	1,057
Rate-regulated natural gas revenues
Residential	$	—	$	251	$	354	$	67	$	—	$	67	$	—
Small commercial & industrial	—		94		59		29		—		29		—
Large commercial & industrial	—		—		103		5		—		5		—
Transportation	—		17		—		11		—		11		—
Other(c)	—		4		41		6		—		6		—
Total rate-regulated natural gas revenues(d)	$	—	$	366	$	557	$	118	$	—	$	118	$	—
Total rate-regulated revenues from contracts with customers	$	4,784	$	2,377	$	2,434	$	3,757	$	1,680	$	1,022	$	1,057

Other revenues
Revenues from alternative revenue programs	$	32	$	20	$	(17)	$	94	$	54	$	17	$	23
Other rate-regulated electric revenues(e)	24		2		7		3		2		1		—
Other rate-regulated natural gas revenues(e)	—		—		2		—		—		—		—

Total other revenues	$	56	$	22	$	(8)	$	97	$	56	$	18	$	23
Total rate-regulated revenues for reportable segments	$	4,840	$	2,399	$	2,426	$	3,854	$	1,736	$	1,040	$	1,080



	Nine Months Ended September 30, 2020
Revenues from contracts with customers	ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Rate-regulated electric revenues
Residential	$	2,389	$	1,277	$	1,034	$	1,825	$	779	$	501	$	545
Small commercial & industrial	1,067		291		183		355		101		127		127
Large commercial & industrial	388		174		311		755		558		66		131
Public authorities & electric railroads	33		21		20		45		25		10		10
Other(a)	663		171		233		471		166		148		159
Total rate-regulated electric revenues(b)	$	4,540	$	1,934	$	1,781	$	3,451	$	1,629	$	852	$	972
Rate-regulated natural gas revenues
Residential	$	—	$	252	$	342	$	68	$	—	$	68	$	—
Small commercial & industrial	—		86		55		30		—		30		—
Large commercial & industrial	—		—		96		3		—		3		—
Transportation	—		18		—		10		—		10		—
Other(c)	—		3		16		5		—		5		—
Total rate-regulated natural gas revenues(d)	$	—	$	359	$	509	$	116	$	—	$	116	$	—
Total rate-regulated revenues from contracts with customers	$	4,540	$	2,293	$	2,290	$	3,567	$	1,629	$	968	$	972

Other revenues
Revenues from alternative revenue programs	$	(51)	$	10	$	(10)	$	(15)	$	20	$	(15)	$	(20)
Other rate-regulated electric revenues(e)	10		3		3		2		1		1		—
Other rate-regulated natural gas revenues(e)	—		—		1		—		—		—		—

Total other revenues	$	(41)	$	13	$	(6)	$	(13)	$	21	$	(14)	$	(20)
Total rate-regulated revenues for reportable segments	$	4,499	$	2,306	$	2,284	$	3,554	$	1,650	$	954	$	952

__________

(a)Includes revenues from transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue.

(b)Includes operating revenues from affiliates in 2021 and 2020 respectively of:

•$19 million, $31 million at ComEd

•$5 million, $6 million at PECO

•$10 million, $9 million at BGE

•$10 million, $13 million at PHI

•$4 million, $6 million at Pepco

•$6 million, $7 million at DPL

•$2 million, $3 million at ACE

(c)Includes revenues from off-system natural gas sales.

(d)Includes operating revenues from affiliates in 2021 and 2020 respectively of:

•$1 million, $1 million at PECO

•$10 million, $7 million at BGE

(e)Includes late payment charge revenues.

Accounts Receivable (Tables)

9 Months Ended

Sep. 30, 2021

Accounts, Notes, Loans and Financing Receivable, Gross, Allowance, and Net [Abstract]

Allowance for credit loss rollforward

The following tables present the rollforward of Allowance for Credit Losses on Customer Accounts Receivable.


	Three Months Ended September 30, 2021
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance as of June 30, 2021	$	395	$	75	$	89	$	111	$	27	$	93	$	38	$	19	$	36
Plus: Current period provision for expected credit losses(a)	47		10		11		1		7		18		5		3		10
Less: Write-offs, net of recoveries(b)	33		1		12		11		3		6		2		4		—

Balance as of September 30, 2021	$	409	$	84	$	88	$	101	$	31	$	105	$	41	$	18	$	46

	Three Months Ended September 30, 2020
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance as of June 30, 2020	$	261	$	33	$	72	$	71	$	23	$	62	$	24	$	18	$	20
Plus: Current period provision for expected credit losses(c)	114		1		37		27		14		35		11		7		17
Less: Write-offs, net of recoveries(b)	17		1		4		2		2		8		—		3		5

Balance as of September 30, 2020	$	358	$	33	$	105	$	96	$	35	$	89	$	35	$	22	$	32


















	Nine Months Ended September 30, 2021
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance as of December 31, 2020	$	366	$	32	$	97	$	116	$	35	$	86	$	32	$	22	$	32
Plus: Current period provision for expected credit losses(d)	122		57		23		7		2		33		15		4		14
Less: Write-offs, net of recoveries(b)	79		5		32		22		6		14		6		8		—

Balance as of September 30, 2021	$	409	$	84	$	88	$	101	$	31	$	105	$	41	$	18	$	46

	Nine Months Ended September 30, 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(c)	222		13		62		56		28		63		24		14		25
Less: Write-offs, net of recoveries(b)	51		4		16		15		5		11		2		3		6
Less: Sale of customer accounts receivable(e)	56		56		—		—		—		—		—		—		—
Balance as of September 30, 2020	$	358	$	33	$	105	$	96	$	35	$	89	$	35	$	22	$	32

__________

(a)For ACE, the increase is primarily a result of increased aging of receivables and a slight decrease in the expected recovery rate.

(b)Recoveries were not material to the Registrants.

(e)See below for additional information on the sale of customer accounts receivable at Generation in the second quarter of 2020.

The following tables present the rollforward of Allowance for Credit Losses on Other Accounts Receivable.


	Three Months Ended September 30, 2021
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance as of June 30, 2021	$	72	$	1	$	18	$	7	$	8	$	38	$	16	$	9	$	13
Plus: Current period provision for expected credit losses	9		3		2		1		1		2		1		(1)		2
Less: Write-offs, net of recoveries(a)	4		—		1		1		1		—		—		—		—
Balance as of September 30, 2021	$	77	$	4	$	19	$	7	$	8	$	40	$	17	$	8	$	15

	Three Months Ended September 30, 2020
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance as of June 30, 2020	$	61	$	—	$	22	$	7	$	6	$	26	$	11	$	7	$	8
Plus: Current period provision for expected credit losses	15		—		5		1		3		6		2		1		3
Less: Write-offs, net of recoveries(a)	1		—		—		1		—		—		—		—		—
Balance as of September 30, 2020	$	75	$	—	$	27	$	7	$	9	$	32	$	13	$	8	$	11

	Nine Months Ended September 30, 2021
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance as of December 31, 2020	$	71	$	—	$	21	$	8	$	9	$	33	$	13	$	9	$	11
Plus: Current period provision for expected credit losses	15		4		—		2		2		7		4		(1)		4
Less: Write-offs, net of recoveries(a)	9		—		2		3		3		—		—		—		—
Balance as of September 30, 2021	$	77	$	4	$	19	$	7	$	8	$	40	$	17	$	8	$	15

	Nine Months Ended September 30, 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	36		—		9		3		7		17		6		4		7
Less: Write-offs, net of recoveries(a)	9		—		2		3		3		1		—		—		1
Balance as of September 30, 2020	$	75	$	—	$	27	$	7	$	9	$	32	$	13	$	8	$	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 September 30, 2021 and December 31, 2020.


	Unbilled customer revenues(a)
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
September 30, 2021	$	941	$	359	$	224	$	113	$	98	$	147	$	70	$	34	$	43
December 31, 2020	998		258		218		147		197		178		87		62		29

__________

(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:


	September 30, 2021		December 31, 2020
Derecognized receivables transferred at fair value	$	1,401	$	1,139
Cash proceeds received	900		500
DPP	501		639


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Loss on sale of receivables(a)	$	1	$	8	$	26	$	23

__________

(a)Reflected in Operating and maintenance expense in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.


	Nine Months Ended September 30,
	2021		2020
Proceeds from new transfers(a)	$	4,440	$	1,889
Cash collections received on DPP and reinvested in the Facility(b)	2,652		2,518
Cash collections reinvested in the Facility	7,092		4,407

__________

(a)Customer accounts receivable sold into the Facility were $7,373 million and $4,515 million for the nine months ended September 30, 2021 and September 30, 2020, respectively.

(b)Does not include the $400 million in cash proceeds received from the Purchasers in the first quarter of 2021.


	Nine Months Ended September 30, 2021
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Total receivables purchased	$	2,945	$	—	$	810	$	795	$	531	$	826	$	504	$	166	$	156
Total receivables sold	100		117		—		—		—		—		—		—		—

Related party transactions:
Receivables purchased from Generation	—		—		—		—		17		—		—		—		—
Receivables sold to the Utility Registrants	—		17		—		—		—		—		—		—		—



	Nine Months Ended September 30, 2020
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Total receivables purchased	$	2,698	$	—	$	865	$	786	$	508	$	787	$	484	$	160	$	143
Total receivables sold	542		790		—		—		—		—		—		—		—

Related party transactions:
Receivables purchased from Generation	—		—		34		67		75		72		51		13		8
Receivables sold to the Utility Registrants	—		248		—		—		—		—		—		—		—

Early Plant Retirements (Tables)

9 Months Ended

Sep. 30, 2021

Property, Plant and Equipment [Abstract]

Restructuring and Related Costs [Table Text Block]


Income statement expense (pre-tax)	Three Months Ended September 30, 2021		Nine Months Ended September 30, 2021		Three and Nine Months Ended September 30, 2020
Depreciation and amortization
Accelerated depreciation(a)	$	574	$	1,805	$	254
Accelerated nuclear fuel amortization	42		148		14
Operating and maintenance
One-time charges	(94)		(94)		220
Other charges	4		8		34
Contractual offset(b)	(60)		(451)		(129)
Total	$	466	$	1,416	$	393

_________

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

Nuclear Decommissioning (Tables)

9 Months Ended

Sep. 30, 2021

Schedule Of Nuclear Decommissioning [Line Items]

Schedule of Change in Asset Retirement Obligation [Table Text Block]

The following table provides a rollforward of the nuclear decommissioning ARO reflected in Exelon’s and Generation’s Consolidated Balance Sheets from December 31, 2020 to September 30, 2021:


Nuclear decommissioning ARO at December 31, 2020(a)	$	11,922
Accretion expense	375
Net increase due to changes in, and timing of, estimated future cash flows	256
Costs incurred related to decommissioning plants	(57)
Nuclear decommissioning ARO at September 30, 2021(a)	$	12,496

_________

Income Taxes (Tables)

9 Months Ended

Sep. 30, 2021

Income Tax Disclosure [Abstract]

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]

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


	Three Months Ended September 30, 2021

	Exelon(a)	Generation(a)	ComEd(a)	PECO(a)(b)	BGE(a)(b)	PHI(a)	Pepco(a)	DPL(a)	ACE(a)(b)
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	6.0	4.4	8.0	(4.1)	(13.0)	5.0	3.4	6.4	7.0
Qualified NDT fund income	0.5	0.9	—	—	—	—	—	—	—

Amortization of investment tax credit, including deferred taxes on basis difference	(0.4)	(0.7)	(0.1)	—	(0.1)	(0.1)	—	(0.2)	(0.2)
Plant basis differences	(1.7)	—	(0.8)	(16.2)	(1.4)	(1.3)	(2.0)	(0.6)	(0.6)
Production tax credits and other credits	(1.0)	(1.4)	(0.5)	—	(0.9)	(0.5)	(0.5)	(0.4)	(0.5)
Noncontrolling interests	(0.4)	(0.6)	—	—	—	—	—	—	—
Excess deferred tax amortization	(6.8)	—	(7.6)	(3.4)	(17.3)	(24.9)	(17.6)	(19.9)	(41.4)

Other(c)	(4.8)	(1.9)	0.3	(0.1)	(0.8)	—	0.1	(0.6)	0.8
Effective income tax rate	12.4%	21.7%	20.3%	(2.8)%	(12.5)%	(0.8)%	4.4%	5.7%	(13.9)%


	Three Months Ended September 30, 2020
	Exelon(a)	Generation(a)	ComEd(a)	PECO(a)(d)	BGE(a)(d)	PHI(a)(d)	Pepco(a)(d)	DPL(a)(d)	ACE(a)(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	12.3	(10.3)	8.1	(6.2)	5.1	5.5	4.6	6.6	6.9
Qualified NDT fund income	13.2	47.4	—	—	—	—	—	—	—

Amortization of investment tax credit, including deferred taxes on basis difference	(1.4)	(4.5)	(0.2)	—	(0.1)	(0.2)	(0.1)	(0.2)	(0.3)
Plant basis differences	(4.3)	—	(0.6)	(23.3)	(1.2)	(1.5)	(2.1)	(0.4)	(1.3)
Production tax credits and other credits	(3.0)	(9.2)	(0.4)	—	(0.8)	(0.5)	(0.5)	(0.5)	(0.4)
Noncontrolling interests	0.8	2.9	—	—	—	—	—	—	—
Excess deferred tax amortization	(10.1)	—	(5.6)	(3.8)	(10.6)	(24.9)	(20.0)	(23.6)	(36.8)
Tax Settlements	(0.2)	(0.7)	—	—	—	—	—	—	—
Other	(0.8)	(0.9)	1.1	(0.8)	(0.3)	0.1	(0.4)	0.7	0.6
Effective income tax rate	27.5%	45.7%	23.4%	(13.1)%	13.1%	(0.5)%	2.5%	3.6%	(10.3)%

__________

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

(b)For PECO, the income tax benefit is primarily due to plant basis differences attributable to tax repair deductions. For BGE,


	Nine Months Ended September 30, 2021
	Exelon(a)	Generation(b)	ComEd(a)	PECO(a)(c)	BGE(a)(c)	PHI(a)	Pepco(a)	DPL(a)	ACE(a)(c)
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	3.0	90.2	7.6	(2.6)	(10.8)	4.6	2.5	6.5	7.3
Qualified NDT fund income	9.4	(1,932.6)	—	—	—	—	—	—	—

Amortization of investment tax credit, including deferred taxes on basis difference	(0.8)	130.6	(0.1)	—	(0.1)	(0.1)	—	(0.2)	(0.2)
Plant basis differences	(3.9)	—	(0.7)	(12.6)	(1.5)	(1.3)	(1.9)	(0.7)	(0.6)
Production tax credits and other credits	(2.6)	425.1	(0.5)	—	(0.9)	(0.5)	(0.5)	(0.4)	(0.5)
Noncontrolling interests	(0.7)	145.2	—	—	—	—	—	—	—
Excess deferred tax amortization	(13.9)	—	(7.2)	(3.3)	(16.0)	(22.8)	(17.4)	(19.7)	(36.3)

Other(d)	2.2	(229.5)	(1.3)	(0.2)	(0.7)	(0.3)	(0.4)	(0.2)	—
Effective income tax rate	13.7%	(1,350.0)%	18.8%	2.3%	(9.0)%	0.6%	3.3%	6.3%	(9.3)%


	Nine Months Ended September 30, 2020
	Exelon(a)	Generation(a)	ComEd(a)(e)	PECO(a)(e)	BGE(a)(e)	PHI(a)(e)	Pepco(a)(e)	DPL(a)(e)	ACE(a)(e)
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	9.3	—	12.7	(3.4)	5.5	5.0	4.2	6.5	6.8
Qualified NDT fund income	3.2	10.0	—	—	—	—	—	—	—
Deferred Prosecution Agreement payments	2.5	—	9.4	—	—	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(1.2)	(3.2)	(0.3)	—	(0.1)	(0.2)	(0.1)	(0.3)	(0.5)
Plant basis differences	(4.0)	—	(0.9)	(15.9)	(1.8)	(2.2)	(2.4)	(0.5)	(3.7)
Production tax credits and other credits	(2.6)	(7.0)	(0.4)	—	(0.4)	(0.3)	(0.3)	(0.2)	(0.4)
Noncontrolling interests	1.0	3.1	—	—	—	—	—	—	—
Excess deferred tax amortization	(15.8)	—	(11.8)	(3.5)	(15.0)	(45.3)	(29.2)	(53.6)	(81.4)
Tax Settlements(f)	(5.0)	(15.7)	—	—	—	—	—	—	—
Other	0.1	(0.5)	2.1	(0.5)	(0.5)	(0.6)	(0.8)	(1.1)	—
Effective income tax rate	8.5%	7.7%	31.8%	(2.3)%	8.7%	(22.6)%	(7.6)%	(28.2)%	(58.2)%

__________

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

(b)Generation recognized a loss before income taxes for the nine months ended September 30, 2021. As a result, a negative percentage represents an income tax expense for the period presented.

Schedule of Unrecognized Tax Benefits Roll Forward [Table Text Block]

PHI and ACE have the following unrecognized tax benefits as of September 30, 2021 and December 31, 2020. Exelon's, Generation's, ComEd's, PECO's, BGE's, Pepco's, and DPL's amounts are not material.


	PHI		ACE
September 30, 2021	$	56	$	16
December 31, 2020	52		15

Allocation of Tax Benefits

The following table presents the allocation of federal tax benefits from Exelon under the Tax Sharing Agreement.


	Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
September 30, 2021	$	64	$	1	$	19	$	—	$	17	$	16	$	—	$	—
September 30, 2020	64		14		17		—		17		8		6		1

Retirement Benefits (Tables)

9 Months Ended

Sep. 30, 2021

Retirement Benefits [Abstract]

Calculation of Net Periodic Benefit Costs



	Pension Benefits				OPEB
	Three Months Ended September 30,				Three Months Ended September 30,
	2021		2020		2021		2020
Components of net periodic benefit cost:
Service cost	$	110	$	97	$	20	$	22
Interest cost	161		190		29		37
Expected return on assets	(335)		(317)		(40)		(41)
Amortization of:
Prior service cost (credit)	1		1		(8)		(30)
Actuarial loss	150		128		9		12
Settlement charges	12		8		—		—

Net periodic benefit cost	$	99	$	107	$	10	$	—



	Pension Benefits				OPEB
	Nine Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Components of net periodic benefit cost:
Service cost	$	330	$	290	$	60	$	67
Interest cost	481		569		86		114
Expected return on assets	(1,003)		(953)		(119)		(122)
Amortization of:
Prior service cost (credit)	3		3		(25)		(92)
Actuarial loss	449		384		27		36
Curtailment benefits	—		—		(1)		—
Settlement charges	16		14		—		—

Net periodic benefit cost	$	276	$	307	$	28	$	3

Allocated Portion of Pension and Postretirement Benefit Costs


	Three Months Ended September 30,				Nine Months Ended September 30,
Pension and OPEB Costs	2021		2020		2021		2020
Exelon	$	109	$	107	$	304	$	310
Generation	36		30		92		89
ComEd	32		29		97		85
PECO	2		1		5		4
BGE	16		16		47		47
PHI	12		17		36		52
Pepco	2		4		5		11
DPL	1		2		2		6
ACE	3		3		8		10

Defined Contribution Savings Plans


	Three Months Ended September 30,				Nine Months Ended September 30,
Savings Plans Matching Contributions	2021		2020		2021		2020
Exelon	$	38	$	37	$	107	$	104
Generation	14		14		40		41
ComEd	9		9		27		25
PECO	2		3		8		8
BGE	4		4		8		8
PHI	5		3		12		9
Pepco	1		1		3		3
DPL	1		1		3		2
ACE	1		—		2		1

Derivative Financial Instruments (Tables)

9 Months Ended

Sep. 30, 2021

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Summary of the derivative fair value

The following tables provide a summary of the derivative fair value balances recorded by Exelon, Generation, and ComEd as of September 30, 2021 and December 31, 2020:


	Exelon		Generation										ComEd
September 30, 2021	Total Derivatives		Economic Hedges		Proprietary Trading		Collateral(a)(b)		Netting(a)		Subtotal		Economic Hedges
Mark-to-market derivative assets (current assets)	$	1,505	$	19,631	$	63	$	(790)	$	(17,399)	$	1,505	$	—
Mark-to-market derivative assets (noncurrent assets)	661		3,612		5		(201)		(2,755)		661		—
Total mark-to-market derivative assets	2,166		23,243		68		(991)		(20,154)		2,166		—
Mark-to-market derivative liabilities (current liabilities)	(1,710)		(18,490)		(55)		(559)		17,399		(1,705)		(5)
Mark-to-market derivative liabilities (noncurrent liabilities)	(720)		(3,168)		(3)		(95)		2,755		(511)		(209)
Total mark-to-market derivative liabilities	(2,430)		(21,658)		(58)		(654)		20,154		(2,216)		(214)
Total mark-to-market derivative net (liabilities) assets	$	(264)	$	1,585	$	10	$	(1,645)	$	—	$	(50)	$	(214)


	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)

_________

(b)Includes $2,084 million held and $209 million posted of variation margin with the exchanges as of September 30, 2021 and December 31, 2020 respectively.

Economic Hedges (Commodity Price Risk)

For the three and nine months ended September 30, 2021 and 2020, 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.


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Income Statement Location	(Loss) Gain				(Loss) Gain
Operating revenues	$	(637)	$	39	$	(961)	$	238
Purchased power and fuel	1,392		209		2,209		224
Total Exelon and Generation	$	755	$	248	$	1,248	$	462

Disclosure of Credit Derivatives [Table Text Block]


Rating as of September 30, 2021	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	$	701	$	254	$	447	—	$	—
Non-investment grade	23		2		21		—	—
No external ratings
Internally rated — investment grade	110		1		109		—	—
Internally rated — non-investment grade	309		48		261		—	—
Total	$	1,143	$	305	$	838	—	$	—


Net Credit Exposure by Type of Counterparty	As of September 30, 2021
Financial institutions	$	53
Investor-owned utilities, marketers, power producers	652
Energy cooperatives and municipalities	62
Other	71
Total	$	838

_________

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


Credit-Risk Related Contingent Features	September 30, 2021		December 31, 2020
Gross fair value of derivative contracts containing this feature(a)	$	(5,289)	$	(834)
Offsetting fair value of in-the-money contracts under master netting arrangements(b)	2,735		537
Net fair value of derivative contracts containing this feature(c)	$	(2,554)	$	(297)

_________

(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]


	September 30, 2021		December 31, 2020
Cash collateral posted	$	299	$	511
Letters of credit posted	477		226
Cash collateral held	1,872		110
Letters of credit held	130		40
Additional collateral required in the event of a credit downgrade below investment grade	3,001		1,432

Line of Credit Facility [Line Items]

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)

9 Months Ended

Sep. 30, 2021

Schedule of Commercial Paper Borrowings [Table Text Block]


	Outstanding Commercial Paper as of				Average Interest Rate on Commercial Paper Borrowings as of
Commercial Paper Issuer	September 30, 2021		December 31, 2020		September 30, 2021		December 31, 2020
Exelon(a)	$	287	$	1,031	0.19	%	0.25	%
Generation	—		340		—	%	0.27	%
ComEd	—		323		—	%	0.23	%


PHI(b)	287		368		0.19	%	0.24	%

Pepco	40		35		0.15	%	0.22	%
DPL	22		146		0.15	%	0.24	%
ACE	225		187		0.20	%	0.25	%

__________

(a)Exelon Corporate had no outstanding commercial paper borrowings as of September 30, 2021 and December 31, 2020.

(b)Represents the consolidated amounts of Pepco, DPL, and ACE.

Schedule of Long-term Debt Instruments [Table Text Block]

During the nine months ended September 30, 2021, the following long-term debt was issued:

Company

Type

Interest Rate

Maturity

Amount

Use of Proceeds

Exelon

Long-Term Software License Agreements

3.62

December 1, 2025

Procurement of software licenses.

Generation

West Medway II
Nonrecourse Debt

LIBOR + 3%

(a)

March 31, 2026

150

Funding for general corporate purposes.

Generation

Energy Efficiency Project Financing(b)

2.53

November 30, 2021

Funding to install energy conservation measures for the Fort AP Hill project.

Generation

Energy Efficiency Project Financing(b)

4.24

November 30, 2021

Funding to install energy conservation measures for the Marine Corps. Logistics Project.

ComEd

First Mortgage Bonds, Series 130

3.13

March 15, 2051

700

Repay a portion of outstanding commercial paper obligations and two outstanding term loans, and to fund other general corporate purposes.

ComEd

First Mortgage Bonds, Series 131

2.75

September 1, 2051

450

Refinance existing indebtedness and for general corporate purposes.

PECO

First and Refunding Mortgage Bonds

3.05

March 15, 2051

375

Funding for general corporate purposes.

PECO

First and Refunding Mortgage Bonds

2.85

September 15, 2051

375

Refinance existing indebtedness and for general corporate purposes.

BGE

Senior Notes

2.25

June 15, 2031

600

Repay a portion of outstanding commercial paper obligations, repay existing indebtedness, and to fund other general corporate purposes.

Pepco

First Mortgage Bonds

2.32

March 30, 2031

150

Repay existing indebtedness and for general corporate purposes.

Pepco

First Mortgage Bonds

3.29

September 28, 2051

125

Repay existing indebtedness and for general corporate purposes.

DPL

First Mortgage Bonds

3.24

March 30, 2051

125

Repay existing indebtedness and for general corporate purposes.

ACE

First Mortgage Bonds

2.30

March 15, 2031

350

Refinance existing indebtedness, repay outstanding commercial paper obligations, and for general corporate purposes.

__________

(a)The nonrecourse debt has an average blended interest rate.

(b)For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt.

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

Fair Value of Financial Liabilities Recorded at Amortized Cost

Fair Value of Financial Assets and Liabilities (Tables)

9 Months Ended

Sep. 30, 2021

Fair Value Disclosures [Abstract]


	September 30, 2021								December 31, 2020
	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	$	38,644	$	40,570	$	3,289	$	43,859	$	36,912	$	40,688	$	3,064	$	43,752
Generation	6,130		5,835		1,111		6,946		6,087		5,648		1,208		6,856
ComEd	9,772		11,344		—		11,344		8,983		11,117		—		11,117
PECO	4,196		4,738		50		4,788		3,753		4,553		50		4,603
BGE	3,960		4,416		—		4,416		3,664		4,366		—		4,366
PHI	7,482		6,030		2,128		8,158		7,006		6,099		1,806		7,905
Pepco	3,441		3,226		990		4,216		3,165		3,336		748		4,084
DPL	1,808		1,433		559		1,992		1,677		1,484		455		1,939
ACE	1,510		1,107		579		1,686		1,413		1,018		602		1,620
Long-Term Debt to Financing Trusts(a)
Exelon	$	390	$	—	$	479	$	479	$	390	$	—	$	467	$	467
ComEd	205		—		255		255		205		—		246		246
PECO	184		—		224		224		184		—		221		221
SNF Obligation
Exelon	$	1,209	$	1,021	$	—	$	1,021	$	1,208	$	909	$	—	$	909
Generation	1,209		1,021		—		1,021		1,208		909		—		909

__________

(a)Includes unamortized debt issuance costs which are not fair valued.

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]

Recurring Fair Value Measurements

Exelon and Generation


	Exelon										Generation
As of September 30, 2021	Level 1		Level 2		Level 3		Not subject to leveling		Total		Level 1		Level 2		Level 3		Not subject to leveling		Total
Assets
Cash equivalents(a)	$	2,573	$	—	$	—	$	—	$	2,573	$	1,673	$	—	$	—	$	—	$	1,673
NDT fund investments
Cash equivalents(b)	647		135		—		—		782		647		135		—		—		782



Equities	4,373		1,717		1		1,559		7,650		4,373		1,717		1		1,559		7,650
Fixed income
Corporate debt(c)	—		1,155		287		—		1,442		—		1,155		287		—		1,442
U.S. Treasury and agencies	2,192		29		—		—		2,221		2,192		29		—		—		2,221
Foreign governments	—		54		—		—		54		—		54		—		—		54
State and municipal debt	—		29		—		—		29		—		29		—		—		29
Other	31		29		—		1,259		1,319		31		29		—		1,259		1,319
Fixed income subtotal	2,223		1,296		287		1,259		5,065		2,223		1,296		287		1,259		5,065
Private credit	—		—		187		592		779		—		—		187		592		779
Private equity	—		—		—		654		654		—		—		—		654		654
Real estate	—		—		—		802		802		—		—		—		802		802

NDT fund investments subtotal(d)(e)	7,243		3,148		475		4,866		15,732		7,243		3,148		475		4,866		15,732
Rabbi trust investments
Cash equivalents	65		—		—		—		65		4		—		—		—		4
Mutual funds	104		—		—		—		104		35		—		—		—		35
Fixed income	—		10		—		—		10		—		—		—		—		—
Life insurance contracts	—		99		34		—		133		—		33		—		—		33
Rabbi trust investments subtotal	169		109		34		—		312		39		33		—		—		72
Investments in equities(f)	137		—		—		—		137		137		—		—		—		137
Commodity derivative assets
Economic hedges	5,527		10,633		7,083		—		23,243		5,527		10,633		7,083		—		23,243
Proprietary trading	—		56		12		—		68		—		56		12		—		68
Effect of netting and allocation of collateral(g)(h)	(4,468)		(9,869)		(6,808)		—		(21,145)		(4,468)		(9,869)		(6,808)		—		(21,145)
Commodity derivative assets subtotal	1,059		820		287		—		2,166		1,059		820		287		—		2,166
DPP consideration	—		501		—		—		501		—		501		—		—		501


	Exelon										Generation
As of September 30, 2021	Level 1		Level 2		Level 3		Not subject to leveling		Total		Level 1		Level 2		Level 3		Not subject to leveling		Total
Total assets	11,181		4,578		796		4,866		21,421		10,151		4,502		762		4,866		20,281
Liabilities
Commodity derivative liabilities
Economic hedges	(4,126)		(9,192)		(8,554)		—		(21,872)		(4,126)		(9,192)		(8,340)		—		(21,658)
Proprietary trading	—		(32)		(26)		—		(58)		—		(32)		(26)		—		(58)
Effect of netting and allocation of collateral(g)(h)	4,123		9,159		6,218		—		19,500		4,123		9,159		6,218		—		19,500
Commodity derivative liabilities subtotal	(3)		(65)		(2,362)		—		(2,430)		(3)		(65)		(2,148)		—		(2,216)
Deferred compensation obligation	—		(149)		—		—		(149)		—		(44)		—		—		(44)
Total liabilities	(3)		(214)		(2,362)		—		(2,579)		(3)		(109)		(2,148)		—		(2,260)
Total net assets (liabilities)	$	11,178	$	4,364	$	(1,566)	$	4,866	$	18,842	$	10,148	$	4,393	$	(1,386)	$	4,866	$	18,021


	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


	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
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

__________

(h)Includes $2,084 million held and $209 million posted of variation margin with the exchanges as of September 30, 2021 and December 31, 2020, respectively.

ComEd, PECO, and BGE


	ComEd								PECO								BGE
As of September 30, 2021	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)	$	309	$	—	$	—	$	309	$	247	$	—	$	—	$	247	$	169	$	—	$	—	$	169
Rabbi trust investments

Mutual funds	—		—		—		—		10		—		—		10		14		—		—		14
Life insurance contracts	—		—		—		—		—		15		—		15		—		—		—		—
Rabbi trust investments subtotal	—		—		—		—		10		15		—		25		14		—		—		14
Total assets	309		—		—		309		257		15		—		272		183		—		—		183
Liabilities
Deferred compensation obligation	—		(9)		—		(9)		—		(8)		—		(8)		—		(6)		—		(6)
Mark-to-market derivative liabilities(b)	—		—		(214)		(214)		—		—		—		—		—		—		—		—
Total liabilities	—		(9)		(214)		(223)		—		(8)		—		(8)		—		(6)		—		(6)
Total net assets (liabilities)	$	309	$	(9)	$	(214)	$	86	$	257	$	7	$	—	$	264	$	183	$	(6)	$	—	$	177


	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
Deferred compensation obligation	—		(8)		—		(8)		—		(9)		—		(9)		—		(5)		—		(5)
Mark-to-market derivative liabilities(b)	—		—		(301)		(301)		—		—		—		—		—		—		—		—
Total liabilities	—		(8)		(301)		(309)		—		(9)		—		(9)		—		(5)		—		(5)
Total net assets (liabilities)	$	285	$	(8)	$	(301)	$	(24)	$	17	$	4	$	—	$	21	$	130	$	(5)	$	—	$	125

__________

PHI, Pepco, DPL, and ACE



	As of September 30, 2021								As of December 31, 2020
PHI	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents(a)	$	100	$	—	$	—	$	100	$	86	$	—	$	—	$	86




Rabbi trust investments
Cash equivalents	59		—		—		59		55		—		—		55
Mutual funds	14		—		—		14		14		—		—		14
Fixed income	—		10		—		10		—		11		—		11
Life insurance contracts	—		27		34		61		—		26		34		60
Rabbi trust investments subtotal	73		37		34		144		69		37		34		140
Total assets	173		37		34		244		155		37		34		226
Liabilities
Deferred compensation obligation	—		(19)		—		(19)		—		(17)		—		(17)



Total liabilities	—		(19)		—		(19)		—		(17)		—		(17)
Total net assets	$	173	$	18	$	34	$	225	$	155	$	20	$	34	$	209


	Pepco								DPL								ACE
As of September 30, 2021	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)	$	36	$	—	$	—	$	36	$	26	$	—	$	—	$	26	$	14	$	—	$	—	$	14




Rabbi trust investments
Cash equivalents	58		—		—		58		—		—		—		—		—		—		—		—
Fixed income	—		—		—		—		—		—		—		—		—		—		—		—
Life insurance contracts	—		27		34		61		—		—		—		—		—		—		—		—
Rabbi trust investments subtotal	58		27		34		119		—		—		—		—		—		—		—		—
Total assets	94		27		34		155		26		—		—		26		14		—		—		14
Liabilities
Deferred compensation obligation	—		(2)		—		(2)		—		—		—		—		—		—		—		—



Total liabilities	—		(2)		—		(2)		—		—		—		—		—		—		—		—
Total net assets	$	94	$	25	$	34	$	153	$	26	$	—	$	—	$	26	$	14	$	—	$	—	$	14


	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

__________

Fair Value Reconciliation of Level 3 Assets and Liabilities Measured at Fair Value on a Recurring Basis

Reconciliation of Level 3 Assets and Liabilities



	Exelon		Generation					ComEd		PHI and Pepco
Three Months Ended September 30, 2021	Total		NDT Fund Investments		Mark-to-Market Derivatives			Total Generation		Mark-to-Market Derivatives			Life Insurance Contracts		Eliminated in Consolidation
Balance as of June 30, 2021	$	(235)	$	461	$	(465)		$	(4)	$	(265)		$	34	$	—
Total realized / unrealized gains (losses)
Included in net income	(967)		3		(970)		(a)	(967)		—			—		—
Included in noncurrent payables to affiliates	—		11		—			11		—			—		(11)

Included in regulatory assets	62		—		—			—		51		(b)	—		11
Change in collateral	(413)		—		(413)			(413)		—			—		—
Purchases, sales, and settlements
Purchases	8		2		6			8		—			—		—
Sales	6		—		6			6		—			—		—

Settlements	(2)		(2)		—			(2)		—			—		—
Transfers into Level 3	2		—		2		(c)	2		—			—		—
Transfers out of Level 3	(27)		—		(27)		(c)	(27)		—			—		—
Balance at September 30, 2021	$	(1,566)	$	475	$	(1,861)		$	(1,386)	$	(214)		$	34	$	—
The amount of total (losses) gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2021	$	(1,001)	$	3	$	(1,004)		$	(1,001)	$	—		$	—	$	—


	Exelon		Generation					ComEd		PHI and Pepco
Nine months ended September 30, 2021	Total		NDT Fund Investments		Mark-to-Market Derivatives			Total Generation		Mark-to-Market Derivatives			Life Insurance Contracts		Eliminated in Consolidation
Balance as of December 31, 2020	$	660	$	497	$	430		$	927	$	(301)		$	34	$	—
Total realized / unrealized gains (losses)
Included in net income	(1,600)		4		(1,606)		(a)	(1,602)		—			2		—
Included in noncurrent payables to affiliates	—		18		—			18		—			—		(18)

Included in regulatory assets	105		—		—			—		87		(b)	—		18
Change in collateral	(751)		—		(751)			(751)		—			—		—
Purchases, sales, and settlements
Purchases	123		3		120			123		—			—		—
Sales	7		—		7			7		—			—		—

Settlements	(50)		(48)		—			(48)		—			(2)		—
Transfers into Level 3	4		1		3		(c)	4		—			—		—
Transfers out of Level 3	(64)		—		(64)		(c)	(64)		—			—		—
Balance as of September 30, 2021	$	(1,566)	$	475	$	(1,861)		$	(1,386)	$	(214)		$	34	$	—
The amount of total (losses) gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2021	$	(1,521)	$	4	$	(1,527)		$	(1,523)	$	—		$	2	$	—



	Exelon		Generation					ComEd		PHI and Pepco
Three Months Ended September 30, 2020	Total		NDT Fund Investments		Mark-to-Market Derivatives			Total Generation		Mark-to-Market Derivatives			Life Insurance Contracts		Eliminated in Consolidation
Balance as of June 30, 2020	$	883	$	499	$	659		$	1,158	$	(318)		$	43	$	—
Total realized / unrealized gains (losses)
Included in net income	(327)		3		(318)		(a)	(315)		—			(12)		—
Included in noncurrent payables to affiliates	—		18		—			18		—			—		(18)
Included in regulatory assets/liabilities	32		—		—			—		14		(b)	—		18
Change in collateral	(79)		—		(79)			(79)		—			—		—
Purchases, sales, and settlements
Purchases	66		1		65			66		—			—		—
Sales	(3)		—		(3)			(3)		—			—		—

Settlements	—		(3)		—			(3)		—			3		—

Transfers out of Level 3	9		—		9		(c)	9		—			—		—
Balance as of September 30, 2020	$	581	$	518	$	333		$	851	$	(304)		$	34	$	—
The amount of total (losses) gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2020	$	(222)	$	3	$	(213)		$	(210)	$	—		$	(12)	$	—


	Exelon		Generation					ComEd		PHI and Pepco
Nine Months Ended September 30, 2020	Total		NDT Fund Investments		Mark-to-Market Derivatives			Total Generation		Mark-to-Market Derivatives			Life Insurance Contracts		Eliminated in Consolidation
Balance as of December 31, 2019	$	1,068	$	511	$	817		$	1,328	$	(301)		$	41	$	—
Total realized / unrealized gains (losses)
Included in net income	(483)		1		(474)		(a)	(473)		—			(10)		—
Included in noncurrent payables to affiliates	—		17		—			17		—			—		(17)

Included in regulatory assets	14		—		—			—		(3)		(b)	—		17
Change in collateral	(120)		—		(120)			(120)		—			—		—
Purchases, sales, and settlements
Purchases	136		6		130			136		—			—		—
Sales	(27)		—		(27)			(27)		—			—		—

Settlements	(15)		(18)		—			(18)		—			3		—
Transfers into Level 3	(5)		1		(6)		(c)	(5)		—			—		—
Transfers out of Level 3	13		—		13		(c)	13		—			—		—
Balance as of September 30, 2020	$	581	$	518	$	333		$	851	$	(304)		$	34	$	—
The amount of total (losses) gains included in income attributed to the change in unrealized (losses) gains related to assets and liabilities as of September 30, 2020	$	(107)	$	1	$	(98)		$	(97)	$	—		$	(10)	$	—

__________

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 three months ended September 30, 2021	$	(1,274)	$	304	$	—	$	3	$	(1,274)	$	304	$	3	$	—
Total (losses) gains included in net income for the nine months ended September 30, 2021	(1,944)		338		2		4		(1,944)		338		4		2
Total unrealized (losses) gains for the three months ended September 30, 2021	(1,361)		357		—		3		(1,361)		357		3		—
Total unrealized (losses) gains for the nine months ended September 30, 2021	(1,969)		443		2		4		(1,969)		443		4		2



	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 included in net income for the three months ended September 30, 2020	$	(305)	$	(13)	$	(12)	$	—	$	(305)	$	(13)	$	—	$	(12)
Total losses included in net income for the nine months ended September 30, 2020	(370)		(104)		(10)		—		(370)		(104)		—		(10)
Total unrealized (losses) gains for the three months ended September 30, 2020	(216)		3		(12)		3		(216)		3		3		(12)
Total unrealized gains (losses) for the nine months ended September 30, 2020	(50)		(48)		(10)		1		(50)		(48)		1		(10)

Fair Value Reconciliation of Level 3 Assets and Liabilities Measured at Fair Value on a Recurring Basis, Valuation Technique

Mark-to-Market Derivatives (Exelon, Generation, and ComEd)

The table below discloses the significant inputs to the forward curve used to value mark-to-market derivatives.


Type of trade	Fair Value at September 30, 2021		Fair Value at December 31, 2020		Valuation Technique	Unobservable Input	2021 Range & Arithmetic Average				2020 Range & Arithmetic Average
Mark-to-market derivatives — Economic Hedges (Exelon and Generation)(a)(b)	$	(1,257)	$	245	Discounted Cash Flow	Forward power price	$9.77	-	$301	$55	$2.25	-	$163	$30
						Forward gas price	$1.76	-	$23.00	$4.16	$1.57	-	$7.88	$2.59
					Option Model	Volatility percentage	35%	-	197%	49%	11%	-	237%	32%

Mark-to-market derivatives — Proprietary trading (Exelon and Generation)(a)(b)	$	(14)	$	23	Discounted Cash Flow	Forward power price	$16	-	$156	$53	$10	-	$106	$27

Mark-to-market derivatives (Exelon and ComEd)	$	(214)	$	(301)	Discounted Cash Flow	Forward heat rate(c)	9x	-	10x	9.13x	8x	-	9x	8.85x
						Marketability reserve	3%	-	7%	4.77%	3%	-	8%	4.93%
						Renewable factor	95%	-	122%	100%	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 (received)/posted on level three positions of $(590) million and $162 million as of September 30, 2021 and December 31, 2020, respectively.

Commitments and Contingencies (Tables)

9 Months Ended

Sep. 30, 2021

Commitments and Contingencies Disclosure [Abstract]

PHI Merger 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 September 30, 2021:


Description	Exelon		PHI		Pepco		DPL		ACE
Total commitments	$	513	$	320	$	120	$	89	$	111
Remaining commitments(a)	74		62		51		7		4

__________

(a)Remaining commitments extend through 2026 and include rate credits, energy efficiency programs and delivery system modernization.

Commercial Commitments

The Registrants’ commercial commitments as of September 30, 2021, representing commitments potentially triggered by future events were as follows:


			Expiration within
	Total		2021		2022		2023		2024		2025		2026 and beyond
Exelon
Letters of credit	$	2,241	$	268	$	1,860	$	113	$	—	$	—	$	—
Surety bonds(a)	971		403		566		—		2		—		—
Financing trust guarantees	378		—		—		—		—		—		378
Guaranteed lease residual values(b)	31		—		3		3		6		6		13
Total commercial commitments	$	3,621	$	671	$	2,429	$	116	$	8	$	6	$	391

Generation
Letters of credit	$	2,223	$	264	$	1,846	$	113	$	—	$	—	$	—
Surety bonds(a)	826		352		474		—		—		—		—
Total commercial commitments	$	3,049	$	616	$	2,320	$	113	$	—	$	—	$	—

ComEd
Letters of credit	$	7	$	2	$	5	$	—	$	—	$	—	$	—
Surety bonds(a)	17		5		10		—		2		—		—
Financing trust guarantees	200		—		—		—		—		—		200
Total commercial commitments	$	224	$	7	$	15	$	—	$	2	$	—	$	200

PECO
Letters of credit	$	1	$	—	$	1	$	—	$	—	$	—	$	—
Surety bonds(a)	2		—		2		—		—		—		—
Financing trust guarantees	178		—		—		—		—		—		178
Total commercial commitments	$	181	$	—	$	3	$	—	$	—	$	—	$	178

BGE
Letters of credit	$	2	$	—	$	2	$	—	$	—	$	—	$	—
Surety bonds(a)	3		2		1		—		—		—		—
Total commercial commitments	$	5	$	2	$	3	$	—	$	—	$	—	$	—

PHI

Surety bonds(a)	$	23	$	3	$	20	$	—	$	—	$	—	$	—
Guaranteed lease residual values(b)	31		—		3		3		6		6		13
Total commercial commitments	$	54	$	3	$	23	$	3	$	6	$	6	$	13

Pepco

Surety bonds(a)	$	14	$	—	$	14	$	—	$	—	$	—	$	—
Guaranteed lease residual values(b)	10		—		1		1		2		2		4
Total commercial commitments	$	24	$	—	$	15	$	1	$	2	$	2	$	4

DPL

Surety bonds(a)	$	5	$	2	$	3	$	—	$	—	$	—	$	—
Guaranteed lease residual values(b)	13		—		1		1		3		3		5
Total commercial commitments	$	18	$	2	$	4	$	1	$	3	$	3	$	5

ACE
Surety bonds(a)	$	4	$	1	$	3	$	—	$	—	$	—	$	—
Guaranteed lease residual values(b)	8		—		1		1		1		1		4
Total commercial commitments	$	12	$	1	$	4	$	1	$	1	$	1	$	4

__________

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

Accrued environmental liabilities


	September 30, 2021				December 31, 2020
	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	$	474	$	310	$	483	$	314
Generation	119		—		121		—
ComEd	284		284		293		293
PECO	23		21		23		21
BGE	6		5		2		—
PHI	42		—		44		—
Pepco	40		—		42		—
DPL	1		—		1		—
ACE	1		—		1		—

Changes in Accumulated Other Comprehensive Income (Tables)

9 Months Ended

Sep. 30, 2021

Changes in Accumulated Other Comprehensive Income [Abstract]

Schedule of Changes in Accumulated Other Comprehensive Income (Loss)

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


Three Months Ended September 30, 2021	Losses on Cash Flow Hedges		Pension and Non-Pension Postretirement Benefit Plan Items(a)		Foreign Currency Items		Total
Beginning balance	$	(5)	$	(3,264)	$	(20)	$	(3,289)
OCI before reclassifications	—		14		(3)		11
Amounts reclassified from AOCI	—		55		—		55
Net current-period OCI	—		69		(3)		66
Ending balance	$	(5)	$	(3,195)	$	(23)	$	(3,223)


Three Months Ended September 30, 2020	Losses on Cash Flow Hedges		Pension and Non-Pension Postretirement Benefit Plan Items(a)		Foreign Currency Items		Total
Beginning balance	$	(3)	$	(3,096)	$	(33)	$	(3,132)
OCI before reclassifications	(1)		(13)		3		(11)
Amounts reclassified from AOCI	—		39		—		39
Net current-period OCI	(1)		26		3		28
Ending balance	$	(4)	$	(3,070)	$	(30)	$	(3,104)


Nine Months Ended September 30, 2021	Losses on Cash Flow Hedges		Pension and Non-Pension Postretirement Benefit Plan Items(a)		Foreign Currency Items		Total
Beginning balance	$	(5)	$	(3,372)	$	(23)	$	(3,400)
OCI before reclassifications	(1)		15		—		14
Amounts reclassified from AOCI	—		163		—		163
Net current-period OCI	(1)		178		—		177
Ending balance	$	(6)	$	(3,194)	$	(23)	$	(3,223)


Nine Months Ended September 30, 2020	Losses on Cash Flow Hedges		Pension and Non-Pension Postretirement Benefit Plan Items(a)		Foreign Currency Items		Total
Beginning balance	$	(2)	$	(3,165)	$	(27)	$	(3,194)
OCI before reclassifications	(2)		(17)		(3)		(22)
Amounts reclassified from AOCI	—		112		—		112
Net current-period OCI	(2)		95		(3)		90
Ending balance	$	(4)	$	(3,070)	$	(30)	$	(3,104)

______

Schedule Of Other Comprehensive Income (Loss) Tax

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	$	1	$	4	$	3	$	12
Actuarial loss reclassified to periodic benefit cost	(19)		(16)		(57)		(50)
Pension and non-pension postretirement benefit plans valuation adjustment	(7)		3		(8)		6

Variable Interest Entities (Tables)

9 Months Ended

Sep. 30, 2021

Variable Interest Entity [Abstract]

VIE - Assets and Liabilities of VIEs which Creditors or Beneficiaries have no Recourse

Consolidated VIEs


	September 30, 2021								December 31, 2020
	Exelon		Generation		PHI(a)		ACE		Exelon		Generation		PHI(a)		ACE
Cash and cash equivalents	$	38	$	38	$	—	$	—	$	98	$	98	$	—	$	—
Restricted cash and cash equivalents	47		42		5		5		47		44		3		3
Accounts receivable
Customer	25		25		—		—		148		148		—		—
Other	7		7		—		—		36		36		—		—
Unamortized energy contract assets	21		21		—		—		22		22		—		—
Inventories, net

Materials and supplies	14		14		—		—		244		244		—		—
Assets held for sale(b)	—		—		—		—		101		101		—		—
Other current assets	517		513		4		—		674		669		5		—
Total current assets	669		660		9		5		1,370		1,362		8		3
Property, plant, and equipment, net	2,052		2,052		—		—		5,803		5,803		—		—
Nuclear decommissioning trust funds	—		—		—		—		3,007		3,007		—		—

Unamortized energy contract assets	210		210		—		—		249		249		—		—
Other noncurrent assets	22		13		9		9		52		42		10		10
Total noncurrent assets	2,284		2,275		9		9		9,111		9,101		10		10
Total assets(c)	$	2,953	$	2,935	$	18	$	14	$	10,481	$	10,463	$	18	$	13
Long-term debt due within one year	$	80	$	70	$	10	$	6	$	94	$	68	$	26	$	21
Accounts payable	11		11		—		—		81		81		—		—
Accrued expenses	14		14		—		—		70		70		—		—

Unamortized energy contract liabilities	—		—		—		—		4		4		—		—
Liabilities held for sale(b)	—		—		—		—		16		16		—		—
Other current liabilities	—		—		—		—		5		5		—		—
Total current liabilities	105		95		10		6		270		244		26		21
Long-term debt	832		832		—		—		889		889		—		—
Asset retirement obligations	149		149		—		—		2,318		2,318		—		—


Other noncurrent liabilities	3		3		—		—		129		129		—		—
Total noncurrent liabilities	984		984		—		—		3,336		3,336		—		—
Total liabilities(d)	$	1,089	$	1,079	$	10	$	6	$	3,606	$	3,580	$	26	$	21

_________

(a)Includes certain purchase accounting adjustments from the PHI merger not pushed down to ACE.

(d)Exelon’s and Generation’s balances include liabilities with recourse of $1 million and $8 million as of September 30, 2021 and December 31, 2020, respectively.

VIE - Summary of Unconsolidated VIEs

The following table presents summary information about Exelon's and Generation’s significant unconsolidated VIE entities:


	September 30, 2021						December 31, 2020
	Commercial Agreement VIEs		Equity Investment VIEs		Total		Commercial Agreement VIEs		Equity Investment VIEs		Total
Total assets(a)	$	781	$	370	$	1,151	$	777	$	401	$	1,178
Total liabilities(a)	80		209		289		61		223		284
Exelon's ownership interest in VIE(a)	—		143		143		—		157		157
Other ownership interests in VIE(a)	701		18		719		716		21		737

_________

Supplemental Financial Information (Tables)

9 Months Ended

Sep. 30, 2021

Supplemental Financial Information [Abstract]

Components of Operating Lease Income

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


	Operating revenues
	Exelon		Generation		PHI		DPL
Three Months Ended September 30, 2021
Operating lease income	$	30	$	29	$	1	$	1
Variable lease income	71		71		—		—

Three Months Ended September 30, 2020
Operating lease income	$	30	$	28	$	1	$	1
Variable lease income	76		76		—		—

Nine Months Ended September 30, 2021
Operating lease income	$	47	$	44	$	3	$	3
Variable lease income	208		207		1		1

Nine Months Ended September 30, 2020
Operating lease income	$	48	$	43	$	3	$	3
Variable lease income	225		224		1		1

Taxes Other Than Income Taxes


	Taxes other than income taxes
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Three Months Ended September 30, 2021
Utility taxes(a)	$	242	$	27	$	67	$	41	$	21	$	86	$	80	$	6	$	—
Property	165		66		13		5		46		34		23		10		1
Payroll	57		26		7		4		5		7		2		1		1

Three Months Ended September 30, 2020
Utility taxes(a)	$	237	$	26	$	66	$	41	$	21	$	83	$	77	$	5	$	1
Property	152		66		7		4		42		32		21		10		1
Payroll	59		29		7		4		4		6		2		1		1

Nine Months Ended September 30, 2021
Utility taxes(a)	$	665	$	73	$	188	$	107	$	66	$	231	$	212	$	17	$	2
Property	470		199		30		13		131		97		65		30		2
Payroll	180		83		20		12		14		21		5		4		2

Nine Months Ended September 30, 2020
Utility taxes(a)	$	651	$	75	$	181	$	102	$	65	$	228	$	210	$	16	$	2
Property	449		199		23		12		121		94		63		29		2
Payroll	183		88		21		12		13		21		6		4		3

__________

Schedule of Other Nonoperating Income, by Component


	Other, Net
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Three Months Ended September 30, 2021
Decommissioning-related activities:
Net realized income on NDT funds(a)
Regulatory Agreement Units	$	263	$	263	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-Regulatory Agreement Units	102		102		—		—		—		—		—		—		—
Net unrealized losses on NDT funds
Regulatory Agreement Units	(195)		(195)		—		—		—		—		—		—		—
Non-Regulatory Agreement Units	(88)		(88)		—		—		—		—		—		—		—
Regulatory offset to NDT fund-related activities(b)	(38)		(38)		—		—		—		—		—		—		—
Decommissioning-related activities	44		44		—		—		—		—		—		—		—
AFUDC — Equity	36		—		10		7		7		12		9		2		1
Non-service net periodic benefit cost	19		—		—		—		—		—		—		—		—
Net unrealized losses from equity investments(c)	(179)		(179)		—		—		—		—		—		—		—

Three Months Ended September 30, 2020
Decommissioning-related activities:
Net realized income on NDT funds(a)
Regulatory Agreement Units	$	50	$	50	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-Regulatory Agreement Units	23		23		—		—		—		—		—		—		—
Net unrealized gains on NDT funds
Regulatory Agreement Units	398		398		—		—		—		—		—		—		—
Non-Regulatory Agreement Units	254		254		—		—		—		—		—		—		—
Regulatory offset to NDT fund-related activities(b)	(359)		(359)		—		—		—		—		—		—		—
Decommissioning-related activities	366		366		—		—		—		—		—		—		—
AFUDC — Equity	27		—		7		5		6		9		7		1		1
Non-service net periodic benefit cost	15		—		—		—		—		—		—		—		—


	Other, net
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Nine Months Ended September 30, 2021
Decommissioning-related activities:
Net realized income on NDT funds(a)
Regulatory Agreement Units	$	698	$	698	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-Regulatory Agreement Units	392		392		—		—		—		—		—		—		—
Net unrealized gains on NDT funds
Regulatory Agreement Units	84		84		—		—		—		—		—		—		—
Non-Regulatory Agreement Units	38		38		—		—		—		—		—		—		—
Regulatory offset to NDT fund-related activities(b)	(607)		(607)		—		—		—		—		—		—		—
Decommissioning-related activities	605		605		—		—		—		—		—		—		—

AFUDC — Equity	99		—		23		19		21		36		30		4		2
Non-service net periodic benefit cost	64		—		—		—		—		—		—		—		—
Net unrealized losses from equity investments(c)	(83)		(83)		—		—		—		—		—		—		—

Nine Months Ended September 30, 2020
Decommissioning-related activities:
Net realized income on NDT funds(a)
Regulatory Agreement Units	$	127	$	127	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-Regulatory Agreement Units	127		127		—		—		—		—		—		—		—
Net unrealized gains on NDT funds
Regulatory Agreement Units	111		111		—		—		—		—		—		—		—
Non-Regulatory Agreement Units	1		1		—		—		—		—		—		—		—
Regulatory offset to NDT fund-related activities(b)	(192)		(192)		—		—		—		—		—		—		—
Decommissioning-related activities	174		174		—		—		—		—		—		—		—


AFUDC — Equity	76		—		22		12		16		26		20		3		3
Non-service net periodic benefit cost	38		—		—		—		—		—		—		—		—

__________

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

(c)Net unrealized losses from equity investments that became publicly traded entities in the fourth quarter of 2020 and the first half of 2021.

Cash Flow Supplemental Disclosures

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


	Depreciation, amortization, and accretion
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Nine Months Ended September 30, 2021
Property, plant, and equipment(a)	$	4,505	$	2,698	$	721	$	249	$	324	$	467	$	204	$	126	$	115
Amortization of regulatory assets(a)	439		—		172		10		110		147		98		31		18
Amortization of intangible assets, net(a)	44		37		—		—		—		—		—		—		—
Amortization of energy contract assets and liabilities(b)	23		23		—		—		—		—		—		—		—
Nuclear fuel(c)	810		810		—		—		—		—		—		—		—
ARO accretion(d)	383		383		—		—		—		—		—		—		—
Total depreciation, amortization, and accretion	$	6,204	$	3,951	$	893	$	259	$	434	$	614	$	302	$	157	$	133

Nine Months Ended September 30, 2020
Property, plant, and equipment(a)	$	2,831	$	1,121	$	689	$	238	$	293	$	436	$	191	$	116	$	104
Amortization of regulatory assets(a)	434		—		152		21		112		149		91		27		30
Amortization of intangible assets, net(a)	47		40		—		—		—		—		—		—		—
Amortization of energy contract assets and liabilities(b)	24		22		—		—		—		—		—		—		—
Nuclear fuel(c)	708		708		—		—		—		—		—		—		—
ARO accretion(d)	375		375		—		—		—		—		—		—		—
Total depreciation, amortization, and accretion	$	4,419	$	2,266	$	841	$	259	$	405	$	585	$	282	$	143	$	134

__________

(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.


	Other non-cash operating activities
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Nine Months Ended September 30, 2021
Pension and non-pension postretirement benefit costs	$	304	$	92	$	97	$	5	$	45	$	36	$	5	$	2	$	8
Allowance for credit losses	155		59		34		36		7		18		9		3		6
Other decommissioning-related activity(a)	(810)		(810)		—		—		—		—		—		—		—
Energy-related options(b)	45		45		—		—		—		—		—		—		—
True-up adjustments to decoupling mechanisms and formula rates(c)	(129)		—		(32)		(20)		17		(94)		(54)		(17)		(23)
Severance costs	(67)		(75)		1		—		—		1		—		—		—

Long-term incentive plan	94		—		—		—		—		—		—		—		—


Amortization of operating ROU asset	146		98		2		—		22		21		5		7		3


AFUDC — Equity	(99)		—		(23)		(19)		(21)		(36)		(30)		(4)		(2)

Nine Months Ended September 30, 2020
Pension and non-pension postretirement benefit costs	$	310	$	89	$	85	$	4	$	46	$	52	$	11	$	6	$	10
Allowance for credit losses	130		16		23		38		12		41		24		15		2
Other decommissioning-related activity(a)	(301)		(301)		—		—		—		—		—		—		—
Energy-related options(b)	79		79		—		—		—		—		—		—		—
True-up adjustments to decoupling mechanisms and formula rates(c)	66		—		51		(10)		10		15		(20)		15		20
Severance costs	96		88		1		—		—		—		—		—		—
Provision for excess and obsolete inventory	119		118		1		1		—		(1)		—		(1)		—
Long-term incentive plan	(8)		—		—		—		—		—		—		—		—


Amortization of operating ROU asset	185		135		1		—		23		21		5		6		2
Deferred Prosecution Agreement payments(d)	200		—		200		—		—		—		—		—		—

AFUDC — Equity	(76)		—		(22)		(12)		(16)		(26)		(20)		(3)		(3)

__________

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

(d)See Note 15 — Commitments and Contingencies for additional information related to the Deferred Prosecution Agreement.


	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
September 30, 2021
Cash and cash equivalents	$	2,957	$	1,957	$	241	$	344	$	225	$	82	$	19	$	13	$	16
Restricted cash and cash equivalents	473		62		276		8		27		71		41		26		5
Restricted cash included in other long-term assets	54		—		44		—		—		9		—		—		9
Total cash, restricted cash, and cash equivalents	$	3,484	$	2,019	$	561	$	352	$	252	$	162	$	60	$	39	$	30

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

September 30, 2020
Cash and cash equivalents	$	1,858	$	623	$	76	$	242	$	326	$	196	$	125	$	26	$	13
Restricted cash and cash equivalents	485		100		305		7		1		38		33		—		4
Restricted cash included in other long-term assets	137		—		127		—		—		10		—		—		10
Total cash, restricted cash, and cash equivalents	$	2,480	$	723	$	508	$	249	$	327	$	244	$	158	$	26	$	27

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

For additional information on restricted cash see Note 1 — Significant Accounting Policies of the Exelon 2020 Form 10-K.

Supplemental Balance Sheet Disclosures

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


	Accrued expenses
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
September 30, 2021
Compensation-related accruals(a)	$	894	$	318	$	148	$	66	$	72	$	108	$	34	$	21	$	16
Taxes accrued	508		222		80		61		90		98		67		16		7
Interest accrued	415		77		65		36		39		75		37		20		15

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

__________

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

Related Party Transactions (Tables)

9 Months Ended

Sep. 30, 2021

Operating Revenues and Purchased Power and Fuel


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Operating revenues from affiliates:
ComEd(a)(b)	$	96	$	71	$	249	$	241
PECO(c)	59		68		142		146
BGE(d)	65		84		195		252
PHI	99		105		276		288
Pepco(e)	69		80		199		219
DPL(f)	25		21		63		60
ACE(g)	5		4		14		9
Other	5		3		10		5
Total operating revenues from affiliates (Generation)	$	324	$	331	$	872	$	932

__________

(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.

BSC and PHISCO Service Companies

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


	Operating and maintenance from affiliates								Capitalized costs
	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020		2021		2020		2021		2020
Exelon
BSC									$	149	$	148	$	431	$	390
PHISCO									18		15		54		45
Generation
BSC	$	145	$	133	$	424	$	406	43		13		76		37
ComEd
BSC	71		65		214		204		47		49		148		133
PECO
BSC	41		34		120		107		12		20		57		53
BGE
BSC	45		38		133		120		20		30		62		88
PHI
BSC	40		36		116		107		27		36		88		79
PHISCO	—		—		—		—		18		15		54		45
Pepco
BSC	23		20		68		61		11		14		36		29
PHISCO	26		28		84		90		7		7		22		20
DPL
BSC	14		13		43		38		10		12		29		26
PHISCO	24		24		73		73		6		4		17		13
ACE
BSC	14		11		37		32		7		10		22		22
PHISCO	21		21		64		65		5		4		15		12

Current Receivables From/Payables To Affiliates

The following tables present current receivables from affiliates and current payables to affiliates:

September 30, 2021


				Receivables from affiliates:
	Payables to affiliates:			Generation			ComEd			PECO			BGE			Pepco			DPL			ACE			BSC			PHISCO			Other			Total
Generation					$	36		$	9		$	—		$	—		$	—		$	—		$	86		$	—		$	23		$	154
ComEd		$	103	(a)				—			—			—			—			—			49			—			6			158
PECO		24			3						1			—			—			—			25			—			7			60
BGE		15			—			—						—			—			—			32			—			2			49
PHI		—			—			—			—			—			—			—			2			—			10			12
Pepco		22			—			—			—						1			—			15			13			—			51
DPL		4			—			—			—			—						—			9			11			—			24
ACE		7			—			—			—			—			—						9			9			1			26
Other		9			2			—			1			—			—			1			2			—						15
Total		$	184		$	41		$	9		$	2		$	—		$	1		$	1		$	229		$	33		$	49		$	549

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

__________

Noncurrent Receivables from/Payables to affiliates

The following table presents noncurrent receivables from affiliates at ComEd and PECO which are recorded as noncurrent payables to affiliates at Generation:


	September 30, 2021		December 31, 2020
ComEd	$	2,597	$	2,541
PECO	546		475

Long Term Debt to Financing Trusts

The following table presents Long-term debt to financing trusts:


	September 30, 2021						December 31, 2020
	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

Mergers, Acquisitions, and Dispositions - Narrative (Details) $ in Millions			3 Months Ended			9 Months Ended
	Aug. 06, 2021 USD ($)	Apr. 01, 2014 USD ($)	Sep. 30, 2021 USD ($)	Jun. 30, 2021 USD ($)	Mar. 31, 2021 USD ($) MW	Sep. 30, 2021 USD ($)	Sep. 30, 2020 USD ($)	Dec. 31, 2020
Business Acquisitions
Acquisition of CENG noncontrolling interest			$ (885)			$ 885	$ 0
Deferred Tax Liability Adjustment - Noncontrolling Interest			$ (290)
Business Dispositions
Gain (Loss) on Sale of Assets and Asset Impairment Charges						$ 147	16
CENG [Member]
Business Acquisitions
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners	49.99%		49.99%			49.99%		49.99%
Solar Business
Business Dispositions
Capacity Of Facility Of Company Owned Solar Distribution Generation Facilities \| MW					360
Disposal Group, Including Discontinued Operation, Consideration					$ 810
Proceeds from Divestiture of Businesses					675
Disposal Group, Including Discontinued Operation, Liabilities, Noncurrent					125
Gain (Loss) on Sale of Assets and Asset Impairment Charges					$ 68
Albany Green Energy biomass facility
Business Dispositions
Disposal Group, Including Discontinued Operation, Consideration				$ 36
Impairment of Long-Lived Assets to be Disposed of				140
Exelon Generation Co L L C [Member]
Business Acquisitions
Acquisition of CENG noncontrolling interest			$ (885)			$ 885	0
Deferred Tax Liability Adjustment - Noncontrolling Interest			$ (288)
Business Dispositions
Gain (Loss) on Sale of Assets and Asset Impairment Charges						$ 144	$ 12
Exelon Generation Co L L C [Member] \| CENG [Member]
Business Acquisitions
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners	49.99%		49.99%			49.99%		49.99%
Exelon Generation Co L L C [Member] \| Solar Business
Business Dispositions
Capacity Of Facility Of Company Owned Solar Distribution Generation Facilities \| MW					360
Disposal Group, Including Discontinued Operation, Consideration					$ 810
Proceeds from Divestiture of Businesses					675
Disposal Group, Including Discontinued Operation, Liabilities, Noncurrent					125
Gain (Loss) on Sale of Assets and Asset Impairment Charges					$ 68
Exelon Generation Co L L C [Member] \| Albany Green Energy biomass facility
Business Dispositions
Disposal Group, Including Discontinued Operation, Consideration				36
Impairment of Long-Lived Assets to be Disposed of				$ 140
CENG [Member]
Business Acquisitions
Equity Method Investment, Ownership Percentage	50.01%		50.01%			50.01%		50.01%
Payments of Capital Distribution		$ 400
Due from Affiliates		400
CENG Preferred Distribution Return						8.50%
Acquisition of CENG noncontrolling interest	$ 885		$ 1,080			$ 1,080
Deferred Tax Liability Adjustment - Noncontrolling Interest			$ (290)			$ (290)
CENG [Member] \| Nine Mile Point
Business Acquisitions
Equity Method Investment, Ownership Percentage			82.00%			82.00%
CENG [Member] \| Exelon Generation Co L L C [Member]
Business Acquisitions
Equity Method Investment, Ownership Percentage	50.01%		50.01%			50.01%		50.01%
Payments of Capital Distribution		400
Due from Affiliates		$ 400
CENG Preferred Distribution Return						8.50%
Acquisition of CENG noncontrolling interest	$ 885		$ 1,080			$ 1,080
Deferred Tax Liability Adjustment - Noncontrolling Interest			$ (288)			$ (288)
CENG [Member] \| Exelon Generation Co L L C [Member] \| Nine Mile Point
Business Acquisitions
Equity Method Investment, Ownership Percentage			82.00%			82.00%

Mergers, Acquisitions, and Dispositions - Changes in Ownership Equity (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
	Aug. 06, 2021	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020	Dec. 31, 2020
Schedule of Changes in Ownership Interest [Line Items]
Net Income (Loss) Available to Common Stockholders, Basic		$ 1,203	$ 501	$ 1,315	$ 1,604
Acquisition of CENG noncontrolling interest		(885)		885	0
Deferred Tax Liability Adjustment - Noncontrolling Interest		(290)
Change from net income (loss) attributable to ownership interest and transfers from Noncontrolling Interest		$ 1,993		$ 2,105
CENG [Member]
Schedule of Changes in Ownership Interest [Line Items]
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners	49.99%	49.99%		49.99%		49.99%
Exelon Generation Co L L C [Member]
Schedule of Changes in Ownership Interest [Line Items]
Acquisition of CENG noncontrolling interest		$ (885)		$ 885	0
Deferred Tax Liability Adjustment - Noncontrolling Interest		(288)
Change from net income (loss) attributable to ownership interest and transfers from Noncontrolling Interest		1,399		545
Net Income (Loss) Attributable to Parent		$ 607	$ 49	$ (247)	$ 570
Exelon Generation Co L L C [Member] \| CENG [Member]
Schedule of Changes in Ownership Interest [Line Items]
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners	49.99%	49.99%		49.99%		49.99%
CENG [Member]
Schedule of Changes in Ownership Interest [Line Items]
Acquisition of CENG noncontrolling interest	$ 885	$ 1,080		$ 1,080
Deferred Tax Liability Adjustment - Noncontrolling Interest		(290)		(290)
CENG [Member] \| Exelon Generation Co L L C [Member]
Schedule of Changes in Ownership Interest [Line Items]
Acquisition of CENG noncontrolling interest	$ 885	1,080		1,080
Deferred Tax Liability Adjustment - Noncontrolling Interest		$ (288)		$ (288)

Regulatory Matters - Narrative (Details)				9 Months Ended
Regulatory Matters - Narrative (Details)	Sep. 23, 2021 USD ($)	Jul. 15, 2021	Feb. 15, 2021 USD ($)	Sep. 30, 2021 USD ($)	Jul. 09, 2021 USD ($)	Jul. 02, 2021 USD ($)	Aug. 26, 2020 USD ($)
Texas-based generating assets
Regulatory Matters Additional Narrative Information [Line Items]
Operating and maintenance				$ 880,000,000
Market Payment Shortfall in Collections				17,000,000
Exelon Generation Co L L C [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Public Utilities, Approved Return on Equity, Percentage		9.33%
Exelon Generation Co L L C [Member] \| ERCOT
Regulatory Matters Additional Narrative Information [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount			$ 9,000
Market Payment Shortfall in Collections				3,000,000,000
Market-wide Limit Recovery of Default				2,500,000
Securitized Funds Allocation				2,100,000,000
System-Wide Offer Cap	$ 4,500
Exelon Generation Co L L C [Member] \| Texas-based generating assets
Regulatory Matters Additional Narrative Information [Line Items]
Operating and maintenance				880,000,000
Market Payment Shortfall in Collections				$ 17,000,000
Commonwealth Edison Co [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Carbon mitigation credit				54,500,000
Maximum increase of revenue requirement				5.00%
Increase (Decrease) in Regulatory Assets				$ 93,000,000
Commonwealth Edison Co [Member] \| Minimum [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Basis points for ComEd's Electric Distribution rates				20
Commonwealth Edison Co [Member] \| Maximum [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Basis points for ComEd's Electric Distribution rates				60
Commonwealth Edison Co [Member] \| Electric Distribution Formula Rate Annual Reconciliations [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Increase (Decrease) in Regulatory Assets				$ 47,000,000
Commonwealth Edison Co [Member] \| Energy Efficiency Costs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Increase (Decrease) in Regulatory Assets				127,000,000
Commonwealth Edison Co [Member] \| Renewable energy swaps
Regulatory Matters Additional Narrative Information [Line Items]
Increase (Decrease) in Regulatory Assets				(87,000,000)
PECO Energy Co [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Increase (Decrease) in Regulatory Assets				135,000,000
Increase (Decrease) in Regulatory Liabilities				66,000,000
PECO Energy Co [Member] \| Nuclear Decommissioning [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Increase (Decrease) in Regulatory Liabilities				71,000,000
PECO Energy Co [Member] \| Electric Energy and Natural Gas Cost [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Increase (Decrease) in Regulatory Liabilities				(18,000,000)
PECO Energy Co [Member] \| Deferred Income Tax Charge [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Increase (Decrease) in Regulatory Assets				123,000,000
PECO Energy Co [Member] \| Vacation Accrual
Regulatory Matters Additional Narrative Information [Line Items]
Increase (Decrease) in Regulatory Assets				14,000,000
Baltimore Gas and Electric Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Maryland Relief Act Funds						$ 50,000,000
Increase (Decrease) in Regulatory Liabilities				(116,000,000)
Baltimore Gas and Electric Company [Member] \| Deferred Income Tax Charge [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Increase (Decrease) in Regulatory Liabilities				(128,000,000)
Baltimore Gas and Electric Company [Member] \| Other [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Increase (Decrease) in Regulatory Liabilities				12,000,000
Potomac Electric Power Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Maryland Relief Act Funds						$ 12,000,000
Increase (Decrease) in Regulatory Liabilities				(108,000,000)
Potomac Electric Power Company [Member] \| Deferred Income Tax Charge [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Increase (Decrease) in Regulatory Liabilities				(89,000,000)
Potomac Electric Power Company [Member] \| Electric Transmission Formula Rate Annual Reconciliations [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Increase (Decrease) in Regulatory Liabilities				(19,000,000)
Delmarva Power and Light Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Maryland Relief Act Funds					$ 8,000,000
Increase (Decrease) in Regulatory Liabilities				(45,000,000)
Delmarva Power and Light Company [Member] \| Deferred Income Tax Charge [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Increase (Decrease) in Regulatory Liabilities				(41,000,000)
Atlantic City Electric Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Proposed Capital Expenditure							$ 220,000,000
Increase (Decrease) in Regulatory Liabilities				(61,000,000)
Atlantic City Electric Company [Member] \| Deferred Income Tax Charge [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Increase (Decrease) in Regulatory Liabilities				(67,000,000)
Atlantic City Electric Company [Member] \| Stranded Costs
Regulatory Matters Additional Narrative Information [Line Items]
Increase (Decrease) in Regulatory Liabilities				$ 14,000,000

Regulatory Matters - Schedule of Completed Rate Cases (Details) - USD ($) $ in Millions	Sep. 15, 2021	Jul. 14, 2021	Jun. 28, 2021	Jun. 22, 2021	Jun. 08, 2021	Mar. 31, 2021	Feb. 26, 2021	Feb. 02, 2021	Dec. 16, 2020	Dec. 09, 2020	Sep. 30, 2020	Sep. 11, 2020	Jun. 01, 2020	Apr. 16, 2020
Commonwealth Edison Co [Member] \| Illinois 2020 Electric Distribution Base Rate Case [Member]
Regulatory Matters Completed Rate Cases [Line Items]
Requested Revenue Requirement Increase (Decrease)														$ (11)
Approved Revenue Requirement Increase (Decrease)										$ (14)
Approved Return on Equity, Percentage										8.38%
Public Utilities Requested Rate Increase (Decrease), Prior Year Annual Reconciliation										$ (64)
Public Utilities, Approved Equity Capital Structure, Percentage										6.28%
Basis points for ComEd's Revenue Requirement										580
Commonwealth Edison Co [Member] \| Illinois 2020 Electric Distribution Base Rate Case [Member] \| 2021
Regulatory Matters Completed Rate Cases [Line Items]
Approved Revenue Requirement Increase (Decrease)										$ 50
PECO Energy Co [Member] \| Pennsylvania 2020 Natural Gas Distribution Base Rate Case
Regulatory Matters Completed Rate Cases [Line Items]
Requested Revenue Requirement Increase (Decrease)											$ 69
Approved Revenue Requirement Increase (Decrease)				$ 29
Approved Return on Equity, Percentage				10.24%
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												$ 203
Approved Revenue Requirement Increase (Decrease)									$ 140
Approved Return on Equity, Percentage									9.50%
Baltimore Gas and Electric Company [Member] \| Maryland 2020 Electric Distribution Base Rate Case [Member] \| 2021
Regulatory Matters Completed Rate Cases [Line Items]
Approved Revenue Requirement Increase (Decrease)									$ 59
Baltimore Gas and Electric Company [Member] \| Maryland 2020 Electric Distribution Base Rate Case [Member] \| 2022
Regulatory Matters Completed Rate Cases [Line Items]
Approved Revenue Requirement Increase (Decrease)									39
Baltimore Gas and Electric Company [Member] \| Maryland 2020 Electric Distribution Base Rate Case [Member] \| 2023
Regulatory Matters Completed Rate Cases [Line Items]
Approved Revenue Requirement Increase (Decrease)									42
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												$ 108
Approved Revenue Requirement Increase (Decrease)									$ 74
Approved Return on Equity, Percentage									9.65%
Baltimore Gas and Electric Company [Member] \| Maryland 2020 Gas Distribution Base Rate Case [Member] \| 2021
Regulatory Matters Completed Rate Cases [Line Items]
Approved Revenue Requirement Increase (Decrease)									$ 53
Baltimore Gas and Electric Company [Member] \| Maryland 2020 Gas Distribution Base Rate Case [Member] \| 2022
Regulatory Matters Completed Rate Cases [Line Items]
Approved Revenue Requirement Increase (Decrease)									11
Baltimore Gas and Electric Company [Member] \| Maryland 2020 Gas Distribution Base Rate Case [Member] \| 2023
Regulatory Matters Completed Rate Cases [Line Items]
Approved Revenue Requirement Increase (Decrease)									$ 10
Potomac Electric Power 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						$ 104
Approved Revenue Requirement Increase (Decrease)			$ 52
Approved Return on Equity, Percentage			9.55%
Potomac Electric Power Company [Member] \| Maryland 2020 Electric Distribution Base Rate Case [Member] \| March 31, 2022
Regulatory Matters Completed Rate Cases [Line Items]
Approved Revenue Requirement Increase (Decrease)			$ 21
Potomac Electric Power Company [Member] \| Maryland 2020 Electric Distribution Base Rate Case [Member] \| March 31, 2023
Regulatory Matters Completed Rate Cases [Line Items]
Approved Revenue Requirement Increase (Decrease)			16
Potomac Electric Power Company [Member] \| Maryland 2020 Electric Distribution Base Rate Case [Member] \| March 31, 2024
Regulatory Matters Completed Rate Cases [Line Items]
Approved Revenue Requirement Increase (Decrease)			$ 15
Potomac Electric Power Company [Member] \| District of Columbia 2019 Electric Distribution Base Rate Case [Member]
Regulatory Matters Completed Rate Cases [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount													$ 136
Approved Revenue Requirement Increase (Decrease)					$ 109
Approved Return on Equity, Percentage					9.275%
Potomac Electric Power Company [Member] \| District of Columbia 2019 Electric Distribution Base Rate Case [Member] \| 2021
Regulatory Matters Completed Rate Cases [Line Items]
Approved Revenue Requirement Increase (Decrease)					$ 42
Potomac Electric Power Company [Member] \| District of Columbia 2019 Electric Distribution Base Rate Case [Member] \| 2021 \| Offsets
Regulatory Matters Completed Rate Cases [Line Items]
Approved Revenue Requirement Increase (Decrease)					(22)
Potomac Electric Power Company [Member] \| District of Columbia 2019 Electric Distribution Base Rate Case [Member] \| 2022
Regulatory Matters Completed Rate Cases [Line Items]
Approved Revenue Requirement Increase (Decrease)					67
Potomac Electric Power Company [Member] \| District of Columbia 2019 Electric Distribution Base Rate Case [Member] \| 2022 \| Offsets
Regulatory Matters Completed Rate Cases [Line Items]
Approved Revenue Requirement Increase (Decrease)					$ (40)
Delmarva Power and Light Company [Member] \| Delaware 2020 Electric Distribution Base Rate Case [Member]
Regulatory Matters Completed Rate Cases [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount								$ 23
Approved Revenue Requirement Increase (Decrease)	$ 14
Approved Return on Equity, Percentage	9.60%
Atlantic City Electric Company [Member] \| New Jersey 2020 Electric Distribution Base Rate Case
Regulatory Matters Completed Rate Cases [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount							$ 67
Approved Revenue Requirement Increase (Decrease)		$ 41
Approved Return on Equity, Percentage		9.60%
Atlantic City Electric Company [Member] \| New Jersey 2020 Electric Distribution Base Rate Case \| Tax Benefits
Regulatory Matters Completed Rate Cases [Line Items]
Approved Revenue Requirement Increase (Decrease)		$ 11

Regulatory Matters - Schedule of Pending Rate Cases (Details) - USD ($) $ in Millions	Sep. 01, 2021	Apr. 16, 2021	Mar. 30, 2021
Commonwealth Edison Co [Member] \| Illinois 2021 Electric Distribution Base Rate Case
Regulatory Matters Pending Rate Cases [Line Items]
Requested Revenue Requirement Increase (Decrease)		$ 51
Requested Return on Equity, Percentage		7.36%
Public Utilities, Requested Rate Increase (Decrease), Initial Revenue Requirement, Amount		$ 40
Public Utilities Requested Rate Increase (Decrease), Prior Year Annual Reconciliation		$ 11
Requested Return on Distribution Rate Base, Percentage		5.72%
Basis points for ComEd's Revenue Requirement		580
Commonwealth Edison Co [Member] \| Illinois 2021 Electric Distribution Base Rate Case 2020 Reconciliation
Regulatory Matters Pending Rate Cases [Line Items]
Requested Return on Equity, Percentage		7.29%
Requested Return on Distribution Rate Base, Percentage		5.69%
Basis points for ComEd's Revenue Requirement		580
Commonwealth Edison Co [Member] \| Illinois 2021 Electric Distribution Base Rate Case 2020 Reconciliation \| Performance Metrics Penalty
Regulatory Matters Pending Rate Cases [Line Items]
Basis points for ComEd's Revenue Requirement		7
PECO Energy Co [Member] \| Pennsylvania 2021 Electric Distribution Base Rate Case
Regulatory Matters Pending Rate Cases [Line Items]
Requested Revenue Requirement Increase (Decrease)			$ 246
Requested Return on Equity, Percentage			10.95%
Delmarva Power and Light Company [Member] \| Maryland 2021 Electric Distribution Base Rate Case
Regulatory Matters Pending Rate Cases [Line Items]
Requested Revenue Requirement Increase (Decrease)	$ 29
Requested Return on Equity, Percentage	10.10%

Regulatory Matters - Annual Electric Transmission Fillings (Details) - 2021 Transmission Formula Rate Annual Update [Domain] - USD ($) $ in Millions	May 28, 2021	May 14, 2021	May 10, 2021	Apr. 16, 2021
Commonwealth Edison Co [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount				$ 33
Annual Reconciliation Increase				12
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount				$ 45
Public Utilities, Approved Equity Capital Structure, Percentage				8.20%
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%
PECO Energy Co [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount	$ (2)
Annual Reconciliation Increase	26
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount	$ 24
Public Utilities, Approved Equity Capital Structure, Percentage	7.37%
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%
Baltimore Gas and Electric Company [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount			$ 38
Annual Reconciliation Increase			27
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount			$ 65
Public Utilities, Approved Equity Capital Structure, Percentage			7.35%
Public Utilities, Approved Return on Equity, Percentage			10.50%
Potomac Electric Power Company [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount		$ (9)
Annual Reconciliation Increase		21
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount		$ 12
Public Utilities, Approved Equity Capital Structure, Percentage		7.68%
Public Utilities, Approved Return on Equity, Percentage		10.50%
Delmarva Power and Light Company [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount		$ 19
Annual Reconciliation Increase		33
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount		$ 52
Public Utilities, Approved Equity Capital Structure, Percentage		7.20%
Public Utilities, Approved Return on Equity, Percentage		10.50%
Atlantic City Electric Company [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount		$ 27
Annual Reconciliation Increase		24
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount		$ 51
Public Utilities, Approved Equity Capital Structure, Percentage		7.45%
Public Utilities, Approved Return on Equity, Percentage		10.50%

Regulatory Matters - Energy Efficiency Formula Rate (Details) - Commonwealth Edison Co [Member] - ComEd 2020 Energy Efficiency Formula Rate [Domain] - USD ($) $ in Millions		12 Months Ended
	Jun. 01, 2021	Dec. 31, 2020
Schedule of Energy Efficiency Formula Rate Updates [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount	$ 55
Revenue	(1)
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount	$ 54
Public Utilities, Requested Equity Capital Structure, Percentage	5.72%
Requested Return on Equity, Percentage	7.36%
Basis points for ComEd's Revenue Requirement	580
Public Utilities, Approved Equity Capital Structure, Percentage		6.26%
Public Utilities, Approved Return on Equity, Percentage		8.46%

Regulatory Matters - Capitalized Ratemaking Amount Not Recognized (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Public Utility, Property, Plant and Equipment [Line Items]
Public Utilities, Amount of Allowance for Earnings on Equity Capitalized for Rate Making Purposes	$ 44	$ 51
Commonwealth Edison Co [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Public Utilities, Amount of Allowance for Earnings on Equity Capitalized for Rate Making Purposes	0	(1)
PECO Energy Co [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Public Utilities, Amount of Allowance for Earnings on Equity Capitalized for Rate Making Purposes	0	0
Baltimore Gas and Electric Company [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Public Utilities, Amount of Allowance for Earnings on Equity Capitalized for Rate Making Purposes	39	45
Pepco Holdings LLC [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Public Utilities, Amount of Allowance for Earnings on Equity Capitalized for Rate Making Purposes	5	7
Potomac Electric Power Company [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Public Utilities, Amount of Allowance for Earnings on Equity Capitalized for Rate Making Purposes	3	4
Delmarva Power and Light Company [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Public Utilities, Amount of Allowance for Earnings on Equity Capitalized for Rate Making Purposes	2	3
Atlantic City Electric Company [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Public Utilities, Amount of Allowance for Earnings on Equity Capitalized for Rate Making Purposes	$ 0	$ 0

Revenue from Contracts with Customers - Change in Contract with Customer, Asset and Liability (Details) - USD ($) $ in Millions	3 Months Ended						9 Months Ended
	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Sep. 30, 2021	Sep. 30, 2020
Contract Asset [Roll Forward]
Beginning Balance - Contract Assets	$ 150	$ 153	$ 144	$ 159	$ 172	$ 174	$ 144	$ 174
Consideration (received) due, contract assets	(15)	(12)	(16)	(18)	(26)	(19)
Revenues recognized, contract assets	14	9	13	19	13	17
Contract with Customer, Asset, Increase (Decrease) for Contract Acquired in Business Combination			12
Ending Balance - Contract Assets	149	150	153	160	159	172	149	160
Contract Liabilities [Roll Forward]
Beginning Balance - Contract Liabilities	132	147	151	20	29	33	151	33
Consideration received (due), contract liabilities	31	17	20	154	13	20
Revenues recognized, contract liabilities	(26)	(32)	(27)	(25)	(22)	(24)
Contract with Customer, Liability, Increase (Decrease) for Contract Acquired in Business Combination			3
Ending Balance - Contract Liabilities	137	132	147	149	20	29	137	149
Contract with Customer, Performance Obligation Satisfied in Previous Period	4			2			38	25
Exelon Generation Co L L C [Member]
Contract Asset [Roll Forward]
Beginning Balance - Contract Assets	150	153	144	159	172	174	144	174
Consideration (received) due, contract assets	(15)	(12)	(16)	(18)	(26)	(19)
Revenues recognized, contract assets	14	9	13	19	13	17
Contract with Customer, Asset, Increase (Decrease) for Contract Acquired in Business Combination			12
Ending Balance - Contract Assets	149	150	153	160	159	172	149	160
Contract Liabilities [Roll Forward]
Beginning Balance - Contract Liabilities	25	54	84	27	56	71	84	71
Consideration received (due), contract liabilities	93	39	31	94	34	55
Revenues recognized, contract liabilities	(65)	(68)	(64)	(65)	(63)	(70)
Contract with Customer, Liability, Increase (Decrease) for Contract Acquired in Business Combination			3
Ending Balance - Contract Liabilities	53	25	54	56	27	56	53	56
Contract with Customer, Performance Obligation Satisfied in Previous Period	2			2			81	63
Pepco Holdings LLC [Member]
Contract Liabilities [Roll Forward]
Beginning Balance - Contract Liabilities	113	116	118	0	0	0	118	0
Consideration received (due), contract liabilities	0	0	0	124	0	0
Revenues recognized, contract liabilities	(2)	(3)	(2)	(2)	0	0
Contract with Customer, Liability, Increase (Decrease) for Contract Acquired in Business Combination			0
Ending Balance - Contract Liabilities	111	113	116	122	0	0	111	122
Contract with Customer, Performance Obligation Satisfied in Previous Period	2			0			7	0
Potomac Electric Power Company [Member]
Contract Liabilities [Roll Forward]
Beginning Balance - Contract Liabilities	91	92	94	0	0	0	94	0
Consideration received (due), contract liabilities	0	0	0	98	0	0
Revenues recognized, contract liabilities	(2)	(1)	(2)	(2)	0	0
Contract with Customer, Liability, Increase (Decrease) for Contract Acquired in Business Combination			0
Ending Balance - Contract Liabilities	89	91	92	96	0	0	89	96
Contract with Customer, Performance Obligation Satisfied in Previous Period	2			0			5	0
Delmarva Power and Light Company [Member]
Contract Liabilities [Roll Forward]
Beginning Balance - Contract Liabilities	11	12	12	0	0	0	12	0
Consideration received (due), contract liabilities	0	0	0	13	0	0
Revenues recognized, contract liabilities	0	(1)	0	0	0	0
Contract with Customer, Liability, Increase (Decrease) for Contract Acquired in Business Combination			0
Ending Balance - Contract Liabilities	11	11	12	13	0	0	11	13
Contract with Customer, Performance Obligation Satisfied in Previous Period	0			0			1	0
Atlantic City Electric Company [Member]
Contract Liabilities [Roll Forward]
Beginning Balance - Contract Liabilities	11	12	12	0	0	0	12	0
Consideration received (due), contract liabilities	0	0	0	13	0	0
Revenues recognized, contract liabilities	0	(1)	0	0	0	0
Contract with Customer, Liability, Increase (Decrease) for Contract Acquired in Business Combination			0
Ending Balance - Contract Liabilities	11	$ 11	$ 12	13	$ 0	$ 0	11	13
Contract with Customer, Performance Obligation Satisfied in Previous Period	$ 0			$ 0			$ 1	$ 0

Segment Information - Narrative (Details)	9 Months Ended
Segment Information - Narrative (Details)	Sep. 30, 2021 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

3 Months Ended

9 Months Ended

Sep. 30, 2021

Jun. 30, 2021

Mar. 31, 2021

Sep. 30, 2020

Jun. 30, 2020

Mar. 31, 2020

Sep. 30, 2021

Sep. 30, 2020

Dec. 31, 2020

$ 8,910

$ 8,853

$ 26,715

$ 24,925

1,624

1,289

4,988

3,312

7,117

8,087

24,758

22,387

397

404

1,180

1,241

1,406

786

1,675

1,665

174

216

229

141

1,229

$ 476

$ (264)

569

$ 574

$ 376

1,441

1,519

1,930

1,833

5,970

5,606

^[1]

132,621

$ 129,317

4,406

4,659

14,117

13,272

324

331

872

932

814

219

(8)

532

177

100

108

633

(769)

117

529

(161)

(122)

485

1,086

1,212

^[2]

48,010

48,094

1,470

1,368

3,854

3,554

264

215

538

340

(2)

(1)

(77)

266

$ 141

$ 128

216

$ 94

$ 108

535

418

1,299

1,072

Commonwealth Edison Co Affiliate [Member] | Exelon Generation Co L L C [Member]

^[3]

24,502

23,736

PECO Energy Co Affiliate [Member] | Exelon Generation Co L L C [Member]

249

241

Baltimore Gas And Electric Company Affiliate [Member] | Exelon Generation Co L L C [Member]

142

146

Intersegment Eliminations [Member]

195

252

(877)

(845)

(2,470)

(2,430)

(876)

(845)

(2,469)

(2,430)

(858)

(833)

(2,407)

(2,397)

(1)

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

(10,210)

(10,165)

(93)

(91)

(283)

(281)

(93)

(91)

(283)

(281)

(93)

(91)

(283)

(281)

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

(50)

(33)

4,406

4,659

14,117

13,272

866

558

2,735

1,161

3,465

4,727

14,605

12,674

225

277

814

219

(8)

532

177

100

108

633

117

(122)

485

367

282

1,086

1,212

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

48,010

48,094

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

324

331

872

932

1,789

1,643

4,840

4,499

304

294

893

841

1,428

1,302

3,833

3,798

292

287

276

256

750

446

141

142

220

196

609

304

561

554

1,723

1,583

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

36,002

34,466

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

818

813

2,399

2,306

259

677

658

1,908

1,900

119

108

108

122

392

310

(3)

(16)

(7)

111

138

383

317

301

312

878

824

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

13,733

12,531

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

770

731

2,426

2,284

142

133

434

405

709

642

2,080

1,903

103

266

299

(4)

(24)

290

273

287

290

907

838

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

12,197

11,650

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

1,470

1,368

3,854

3,554

210

200

614

585

1,155

1,102

3,167

3,057

201

264

215

538

340

(2)

(1)

(77)

266

216

535

418

410

386

1,299

1,072

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

24,502

23,736

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

660

611

1,736

1,650

104

302

282

501

465

1,396

1,364

104

103

136

121

273

211

(16)

130

118

264

227

202

188

641

512

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

9,748

9,264

Delmarva Power and Light Company [Member] | Operating Segment [Member]

360

337

1,040

954

157

143

295

296

858

843

144

(20)

135

109

320

278

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

5,295

5,140

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

451

420

1,080

952

133

134

359

338

911

847

129

(11)

(7)

(12)

(39)

141

106

103

336

281

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

4,532

4,286

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

534

484

1,549

1,440

541

489

1,572

1,452

241

269

(88)

(87)

(264)

(262)

(50)

(8)

(37)

(151)

(255)

(278)

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

8,387

9,005

281

279

285

284

(4)

(2)

(8)

(9)

(3)

(2)

(4)

(5)

(6)

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

4,977

$ 5,079

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

531

485

1,542

1,435

Competitive businesses electric revenues [Member]

281

278

Revenue from Contract with Customer, Including Assessed Tax

4,011

3,875

11,404

10,447

Competitive businesses electric revenues [Member] | Intersegment Eliminations [Member]

Revenue from Contract with Customer, Including Assessed Tax

(319)

(326)

(860)

(920)

Competitive businesses electric revenues [Member] | Exelon Generation Co L L C [Member] | Operating Segment [Member]

Revenue from Contract with Customer, Including Assessed Tax

4,330

4,201

12,264

11,367

Competitive businesses electric revenues [Member] | Commonwealth Edison Co [Member] | Operating Segment [Member]

Revenue from Contract with Customer, Including Assessed Tax

Competitive businesses electric revenues [Member] | PECO Energy Co [Member] | Operating Segment [Member]

Revenue from Contract with Customer, Including Assessed Tax

Competitive businesses electric revenues [Member] | Baltimore Gas and Electric Company [Member] | Operating Segment [Member]

Revenue from Contract with Customer, Including Assessed Tax

Competitive businesses electric revenues [Member] | Pepco Holdings LLC [Member] | Operating Segment [Member]

Revenue from Contract with Customer, Including Assessed Tax

Competitive businesses electric revenues [Member] | Corporate and Other [Member] | Corporate, Non-Segment [Member]

Revenue from Contract with Customer, Including Assessed Tax

Competitive businesses natural gas revenues Member]

Revenue from Contract with Customer, Including Assessed Tax

575

323

2,408

1,345

Competitive businesses natural gas revenues Member] | Intersegment Eliminations [Member]

Revenue from Contract with Customer, Including Assessed Tax

(3)

Competitive businesses natural gas revenues Member] | Exelon Generation Co L L C [Member] | Operating Segment [Member]

Revenue from Contract with Customer, Including Assessed Tax

575

323

2,408

1,348

Competitive businesses natural gas revenues Member] | Commonwealth Edison Co [Member] | Operating Segment [Member]

Revenue from Contract with Customer, Including Assessed Tax

Competitive businesses natural gas revenues Member] | PECO Energy Co [Member] | Operating Segment [Member]

Revenue from Contract with Customer, Including Assessed Tax

Competitive businesses natural gas revenues Member] | Baltimore Gas and Electric Company [Member] | Operating Segment [Member]

Revenue from Contract with Customer, Including Assessed Tax

Competitive businesses natural gas revenues Member] | Pepco Holdings LLC [Member] | Operating Segment [Member]

Revenue from Contract with Customer, Including Assessed Tax

Competitive businesses natural gas revenues Member] | Corporate and Other [Member] | Corporate, Non-Segment [Member]

Revenue from Contract with Customer, Including Assessed Tax

Competitive businesses other revenues [Member]

Competitive businesses other revenues [Member] | Intersegment Eliminations [Member]

(502)

132

(564)

552

Competitive businesses other revenues [Member] | Exelon Generation Co L L C [Member] | Operating Segment [Member]

(3)

(9)

(5)

Competitive businesses other revenues [Member] | Commonwealth Edison Co [Member] | Operating Segment [Member]

(499)

135

(555)

557

Competitive businesses other revenues [Member] | PECO Energy Co [Member] | Operating Segment [Member]

Competitive businesses other revenues [Member] | Baltimore Gas and Electric Company [Member] | Operating Segment [Member]

Competitive businesses other revenues [Member] | Pepco Holdings LLC [Member] | Operating Segment [Member]

Competitive businesses other revenues [Member] | Corporate and Other [Member] | Corporate, Non-Segment [Member]

Rate-regulated electric revenues [Member]

Revenue from Contract with Customer, Including Assessed Tax

4,657

4,365

12,432

11,585

Rate-regulated electric revenues [Member] | Pepco Holdings LLC [Member]

Revenue from Contract with Customer, Including Assessed Tax

1,438

1,308

3,632

3,440

Rate-regulated electric revenues [Member] | Intersegment Eliminations [Member]

Revenue from Contract with Customer, Including Assessed Tax

(15)

(22)

(33)

(50)

Rate-regulated electric revenues [Member] | Intersegment Eliminations [Member] | Pepco Holdings LLC [Member]

Revenue from Contract with Customer, Including Assessed Tax

(4)

(6)

(12)

(15)

Rate-regulated electric revenues [Member] | Exelon Generation Co L L C [Member] | Operating Segment [Member]

Revenue from Contract with Customer, Including Assessed Tax

Rate-regulated electric revenues [Member] | Commonwealth Edison Co [Member] | Operating Segment [Member]

Revenue from Contract with Customer, Including Assessed Tax

1,789

1,643

4,840

4,499

Rate-regulated electric revenues [Member] | PECO Energy Co [Member] | Operating Segment [Member]

Revenue from Contract with Customer, Including Assessed Tax

762

759

2,033

1,948

Rate-regulated electric revenues [Member] | Baltimore Gas and Electric Company [Member] | Operating Segment [Member]

Revenue from Contract with Customer, Including Assessed Tax

677

646

1,866

1,763

Rate-regulated electric revenues [Member] | Pepco Holdings LLC [Member] | Operating Segment [Member]

Revenue from Contract with Customer, Including Assessed Tax

1,444

1,339

3,726

3,425

Rate-regulated electric revenues [Member] | Potomac Electric Power Company [Member] | Operating Segment [Member]

Revenue from Contract with Customer, Including Assessed Tax

660

611

1,736

1,650

Rate-regulated electric revenues [Member] | Delmarva Power and Light Company [Member] | Operating Segment [Member]

Revenue from Contract with Customer, Including Assessed Tax

337

314

922

838

Rate-regulated electric revenues [Member] | Atlantic City Electric Company [Member] | Operating Segment [Member]

Revenue from Contract with Customer, Including Assessed Tax

451

420

1,080

952

Rate-regulated electric revenues [Member] | Corporate and Other [Member] | Corporate, Non-Segment [Member]

Revenue from Contract with Customer, Including Assessed Tax

Rate-regulated electric revenues [Member] | Corporate and Other [Member] | Corporate, Non-Segment [Member] | Pepco Holdings LLC [Member]

Revenue from Contract with Customer, Including Assessed Tax

Rate-regulated natural gas revenues [Member]

Revenue from Contract with Customer, Including Assessed Tax

169

159

1,035

990

Rate-regulated natural gas revenues [Member] | Pepco Holdings LLC [Member]

Revenue from Contract with Customer, Including Assessed Tax

118

116

Rate-regulated natural gas revenues [Member] | Intersegment Eliminations [Member]

Revenue from Contract with Customer, Including Assessed Tax

(3)

(9)

(5)

Rate-regulated natural gas revenues [Member] | Intersegment Eliminations [Member] | Pepco Holdings LLC [Member]

Revenue from Contract with Customer, Including Assessed Tax

Rate-regulated natural gas revenues [Member] | Exelon Generation Co L L C [Member] | Operating Segment [Member]

Revenue from Contract with Customer, Including Assessed Tax

Rate-regulated natural gas revenues [Member] | Commonwealth Edison Co [Member] | Operating Segment [Member]

Revenue from Contract with Customer, Including Assessed Tax

Rate-regulated natural gas revenues [Member] | PECO Energy Co [Member] | Operating Segment [Member]

Revenue from Contract with Customer, Including Assessed Tax

366

358

Rate-regulated natural gas revenues [Member] | Baltimore Gas and Electric Company [Member] | Operating Segment [Member]

Revenue from Contract with Customer, Including Assessed Tax

560

521

Rate-regulated natural gas revenues [Member] | Pepco Holdings LLC [Member] | Operating Segment [Member]

Revenue from Contract with Customer, Including Assessed Tax

118

116

Rate-regulated natural gas revenues [Member] | Potomac Electric Power Company [Member] | Operating Segment [Member]

Revenue from Contract with Customer, Including Assessed Tax

Rate-regulated natural gas revenues [Member] | Delmarva Power and Light Company [Member] | Operating Segment [Member]

Revenue from Contract with Customer, Including Assessed Tax

118

116

Rate-regulated natural gas revenues [Member] | Atlantic City Electric Company [Member] | Operating Segment [Member]

Revenue from Contract with Customer, Including Assessed Tax

Rate-regulated natural gas revenues [Member] | Corporate and Other [Member] | Corporate, Non-Segment [Member]

Revenue from Contract with Customer, Including Assessed Tax

Rate-regulated natural gas revenues [Member] | Corporate and Other [Member] | Corporate, Non-Segment [Member] | Pepco Holdings LLC [Member]

Revenue from Contract with Customer, Including Assessed Tax

Shared service and other revenues [Member]

Revenue from Contract with Customer, Including Assessed Tax

(1)

Shared service and other revenues [Member] | Intersegment Eliminations [Member]

Revenue from Contract with Customer, Including Assessed Tax

(537)

(491)

(1,559)

(1,447)

Shared service and other revenues [Member] | Intersegment Eliminations [Member] | Pepco Holdings LLC [Member]

Revenue from Contract with Customer, Including Assessed Tax

(89)

(85)

(271)

(266)

Shared service and other revenues [Member] | Exelon Generation Co L L C [Member] | Operating Segment [Member]

Revenue from Contract with Customer, Including Assessed Tax

Shared service and other revenues [Member] | Commonwealth Edison Co [Member] | Operating Segment [Member]

Revenue from Contract with Customer, Including Assessed Tax

Shared service and other revenues [Member] | PECO Energy Co [Member] | Operating Segment [Member]

Revenue from Contract with Customer, Including Assessed Tax

Shared service and other revenues [Member] | Baltimore Gas and Electric Company [Member] | Operating Segment [Member]

Revenue from Contract with Customer, Including Assessed Tax

Shared service and other revenues [Member] | Pepco Holdings LLC [Member] | Operating Segment [Member]

Revenue from Contract with Customer, Including Assessed Tax

Shared service and other revenues [Member] | Potomac Electric Power Company [Member] | Operating Segment [Member]

Revenue from Contract with Customer, Including Assessed Tax

Shared service and other revenues [Member] | Delmarva Power and Light Company [Member] | Operating Segment [Member]

Revenue from Contract with Customer, Including Assessed Tax

Shared service and other revenues [Member] | Atlantic City Electric Company [Member] | Operating Segment [Member]

Revenue from Contract with Customer, Including Assessed Tax

Shared service and other revenues [Member] | Corporate and Other [Member] | Corporate, Non-Segment [Member]

Revenue from Contract with Customer, Including Assessed Tax

534

484

1,549

1,440

Shared service and other revenues [Member] | Corporate and Other [Member] | Corporate, Non-Segment [Member] | Pepco Holdings LLC [Member]

Revenue from Contract with Customer, Including Assessed Tax

$ 92

$ 91

$ 281

$ 279

[1]	Exelon’s consolidated assets include $2,722 million and $10,200 million at September 30, 2021 and December 31, 2020, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $1,088 million and $3,598 million at September 30, 2021 and December 31, 2020, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 17 — Variable Interest Entities for additional information.
[2]	Generation’s consolidated assets include $2,704 million and $10,182 million at September 30, 2021 and December 31, 2020, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $1,078 million and $3,572 million at September 30, 2021 and December 31, 2020, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 17 — Variable Interest Entities for additional information.
[3]	PHI’s consolidated total assets include $18 million at both September 30, 2021 and December 31, 2020 of PHI's consolidated VIE that can only be used to settle the liabilities of the VIE. PHI’s consolidated total liabilities include $10 million and $26 million at September 30, 2021 and December 31, 2020, respectively, of PHI's consolidated VIE for which the VIE creditors do not have recourse to PHI. See Note 17 — Variable Interest Entities for additional information.

Segment Information - Generation Total Revenues (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Segment Reporting Information [Line Items]
Revenues	$ 8,910	$ 8,853	$ 26,715	$ 24,925
Revenue from Related Parties	0	1	0	4
Generation Mid Atlantic [Member]
Segment Reporting Information [Line Items]
Revenues	1,272	1,313	3,527	3,561
Generation Midwest [Member]
Segment Reporting Information [Line Items]
Revenues	985	1,043	2,945	3,007
Generation New York [Member]
Segment Reporting Information [Line Items]
Revenues	455	406	1,173	1,061
Generation ERCOT [Member]
Segment Reporting Information [Line Items]
Revenues	358	330	890	754
Generation Other Regions [Member]
Segment Reporting Information [Line Items]
Revenues	1,260	1,109	3,729	2,984
Generation Reportable Segments Total [Member]
Segment Reporting Information [Line Items]
Revenues	4,330	4,201	12,264	11,367
Generation Natural Gas [Member]
Segment Reporting Information [Line Items]
Revenues	575	323	2,408	1,348
Generation All Other Segments [Member]
Segment Reporting Information [Line Items]
Revenues	(499)	135	(555)	557
Unrealized Gain (Loss) on Securities	(635)	37	(958)	238
Generation Total Consolidated Group [Member]
Segment Reporting Information [Line Items]
Revenues	4,406	4,659	14,117	13,272
Operating Segment [Member] \| Generation Mid Atlantic [Member]
Segment Reporting Information [Line Items]
Revenues	1,268	1,307	3,511	3,540
Operating Segment [Member] \| Generation Midwest [Member]
Segment Reporting Information [Line Items]
Revenues	985	1,042	2,944	3,013
Operating Segment [Member] \| Generation New York [Member]
Segment Reporting Information [Line Items]
Revenues	455	406	1,174	1,062
Operating Segment [Member] \| Generation ERCOT [Member]
Segment Reporting Information [Line Items]
Revenues	356	323	879	734
Operating Segment [Member] \| Generation Other Regions [Member]
Segment Reporting Information [Line Items]
Revenues	1,266	1,123	3,756	3,018
Operating Segment [Member] \| Generation Reportable Segments Total [Member]
Segment Reporting Information [Line Items]
Revenues	4,330	4,201	12,264	11,367
Operating Segment [Member] \| Generation Natural Gas [Member]
Segment Reporting Information [Line Items]
Revenues	575	323	2,408	1,348
Operating Segment [Member] \| Generation All Other Segments [Member]
Segment Reporting Information [Line Items]
Unrealized Gain (Loss) on Securities	754	255	1,242	472
Operating Segment [Member] \| Generation Total Consolidated Group [Member]
Segment Reporting Information [Line Items]
Revenues	4,406	4,659	14,117	13,272
Corporate, Non-Segment [Member] \| Generation All Other Segments [Member]
Segment Reporting Information [Line Items]
Revenues	(499)	135	(555)	557
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	(877)	(845)	(2,470)	(2,430)
Revenue from Related Parties	(876)	(845)	(2,469)	(2,430)
Intersegment Eliminations [Member] \| Generation Mid Atlantic [Member]
Segment Reporting Information [Line Items]
Revenue from Related Parties	4	6	16	21
Intersegment Eliminations [Member] \| Generation Midwest [Member]
Segment Reporting Information [Line Items]
Revenue from Related Parties	0	1	1	(6)
Intersegment Eliminations [Member] \| Generation New York [Member]
Segment Reporting Information [Line Items]
Revenue from Related Parties	0	0	(1)	(1)
Intersegment Eliminations [Member] \| Generation ERCOT [Member]
Segment Reporting Information [Line Items]
Revenue from Related Parties	2	7	11	20
Intersegment Eliminations [Member] \| Generation Other Regions [Member]
Segment Reporting Information [Line Items]
Revenue from Related Parties	(6)	(14)	(27)	(34)
Intersegment Eliminations [Member] \| Generation Reportable Segments Total [Member]
Segment Reporting Information [Line Items]
Revenue from Related Parties	0	0	0	0
Intersegment Eliminations [Member] \| Generation Natural Gas [Member]
Segment Reporting Information [Line Items]
Revenue from Related Parties	0	0	0	0
Intersegment Eliminations [Member] \| Generation All Other Segments [Member]
Segment Reporting Information [Line Items]
Revenue from Related Parties	0	0	0	0
Intersegment Eliminations [Member] \| Generation Total Consolidated Group [Member]
Segment Reporting Information [Line Items]
Revenue from Related Parties	0	0	0	0
Revenue from Contract with Customer [Member] \| Operating Segment [Member] \| Generation Mid Atlantic [Member]
Segment Reporting Information [Line Items]
Revenues	1,145	1,327	3,377	3,692
Revenue from Contract with Customer [Member] \| Operating Segment [Member] \| Generation Midwest [Member]
Segment Reporting Information [Line Items]
Revenues	1,084	974	3,067	2,773
Revenue from Contract with Customer [Member] \| Operating Segment [Member] \| Generation New York [Member]
Segment Reporting Information [Line Items]
Revenues	445	401	1,204	1,074
Revenue from Contract with Customer [Member] \| Operating Segment [Member] \| Generation ERCOT [Member]
Segment Reporting Information [Line Items]
Revenues	191	249	724	579
Revenue from Contract with Customer [Member] \| Operating Segment [Member] \| Generation Other Regions [Member]
Segment Reporting Information [Line Items]
Revenues	948	937	3,043	2,718
Revenue from Contract with Customer [Member] \| Operating Segment [Member] \| Generation Reportable Segments Total [Member]
Segment Reporting Information [Line Items]
Revenues	3,813	3,888	11,415	10,836
Revenue from Contract with Customer [Member] \| Operating Segment [Member] \| Generation Natural Gas [Member]
Segment Reporting Information [Line Items]
Revenues	266	169	1,384	881
Revenue from Contract with Customer [Member] \| Operating Segment [Member] \| Generation Total Consolidated Group [Member]
Segment Reporting Information [Line Items]
Revenues	4,174	4,142	13,090	11,985
Revenue from Contract with Customer [Member] \| Corporate, Non-Segment [Member] \| Generation All Other Segments [Member]
Segment Reporting Information [Line Items]
Revenues	95	85	291	268
Other [Member] \| Operating Segment [Member] \| Generation Mid Atlantic [Member]
Segment Reporting Information [Line Items]
Revenues	123	(20)	134	(152)
Other [Member] \| Operating Segment [Member] \| Generation Midwest [Member]
Segment Reporting Information [Line Items]
Revenues	(99)	68	(123)	240
Other [Member] \| Operating Segment [Member] \| Generation New York [Member]
Segment Reporting Information [Line Items]
Revenues	10	5	(30)	(12)
Other [Member] \| Operating Segment [Member] \| Generation ERCOT [Member]
Segment Reporting Information [Line Items]
Revenues	165	74	155	155
Other [Member] \| Operating Segment [Member] \| Generation Other Regions [Member]
Segment Reporting Information [Line Items]
Revenues	318	186	713	300
Other [Member] \| Operating Segment [Member] \| Generation Reportable Segments Total [Member]
Segment Reporting Information [Line Items]
Revenues	517	313	849	531
Other [Member] \| Operating Segment [Member] \| Generation Natural Gas [Member]
Segment Reporting Information [Line Items]
Revenues	309	154	1,024	467
Other [Member] \| Operating Segment [Member] \| Generation Total Consolidated Group [Member]
Segment Reporting Information [Line Items]
Revenues	232	517	1,027	1,287
Other [Member] \| Corporate, Non-Segment [Member] \| Generation All Other Segments [Member]
Segment Reporting Information [Line Items]
Revenues	$ (594)	$ 50	$ (846)	$ 289

Segment Information - Generation Total Revenues Net of Purchased Power and Fuel Expense (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Generation Mid Atlantic [Member]
Segment Reporting Information [Line Items]
Revenue Net of Purchase Power And Fuel	$ 570	$ 591	$ 1,712	$ 1,683
Generation Midwest [Member]
Segment Reporting Information [Line Items]
Revenue Net of Purchase Power And Fuel	655	750	2,015	2,178
Generation New York [Member]
Segment Reporting Information [Line Items]
Revenue Net of Purchase Power And Fuel	346	285	880	725
Generation ERCOT [Member]
Segment Reporting Information [Line Items]
Revenue Net of Purchase Power And Fuel	179	147	(922)	325
Generation Other Regions [Member]
Segment Reporting Information [Line Items]
Revenue Net of Purchase Power And Fuel	211	225	564	538
Generation Reportable Segments Total [Member]
Segment Reporting Information [Line Items]
Revenue Net of Purchase Power And Fuel	1,961	1,998	4,249	5,449
Generation All Other Segments [Member]
Segment Reporting Information [Line Items]
Revenue Net of Purchase Power And Fuel	899	347	1,765	862
Unrealized Gain (Loss) on Securities	(635)	37	(958)	238
Generation Total Consolidated Group [Member]
Segment Reporting Information [Line Items]
Revenue Net of Purchase Power And Fuel	2,860	2,345	6,014	6,311
Operating Segment [Member] \| Generation Mid Atlantic [Member]
Segment Reporting Information [Line Items]
RNF from external customers	567	586	1,698	1,660
Operating Segment [Member] \| Generation Midwest [Member]
Segment Reporting Information [Line Items]
RNF from external customers	655	748	2,014	2,180
Operating Segment [Member] \| Generation New York [Member]
Segment Reporting Information [Line Items]
RNF from external customers	343	281	873	714
Operating Segment [Member] \| Generation ERCOT [Member]
Segment Reporting Information [Line Items]
RNF from external customers	181	141	(775)	311
Operating Segment [Member] \| Generation Other Regions [Member]
Segment Reporting Information [Line Items]
RNF from external customers	233	253	641	608
Operating Segment [Member] \| Generation Reportable Segments Total [Member]
Segment Reporting Information [Line Items]
RNF from external customers	1,979	2,009	4,451	5,473
Operating Segment [Member] \| Generation All Other Segments [Member]
Segment Reporting Information [Line Items]
RNF from external customers	881	336	1,563	838
Unrealized Gain (Loss) on Securities	754	255	1,242	472
Accelerated nuclear fuel amortization	42	24	148	24
Operating Segment [Member] \| Generation Total Consolidated Group [Member]
Segment Reporting Information [Line Items]
RNF from external customers	2,860	2,345	6,014	6,311
Intersegment Eliminations [Member] \| Generation Mid Atlantic [Member]
Segment Reporting Information [Line Items]
Intersegment Revenue Net Of Purchase Power And Fuel	3	5	14	23
Intersegment Eliminations [Member] \| Generation Midwest [Member]
Segment Reporting Information [Line Items]
Intersegment Revenue Net Of Purchase Power And Fuel	0	2	1	(2)
Intersegment Eliminations [Member] \| Generation New York [Member]
Segment Reporting Information [Line Items]
Intersegment Revenue Net Of Purchase Power And Fuel	3	4	7	11
Intersegment Eliminations [Member] \| Generation ERCOT [Member]
Segment Reporting Information [Line Items]
Intersegment Revenue Net Of Purchase Power And Fuel	(2)	6	(147)	14
Intersegment Eliminations [Member] \| Generation Other Regions [Member]
Segment Reporting Information [Line Items]
Intersegment Revenue Net Of Purchase Power And Fuel	(22)	(28)	(77)	(70)
Intersegment Eliminations [Member] \| Generation Reportable Segments Total [Member]
Segment Reporting Information [Line Items]
Intersegment Revenue Net Of Purchase Power And Fuel	(18)	(11)	(202)	(24)
Intersegment Eliminations [Member] \| Generation All Other Segments [Member]
Segment Reporting Information [Line Items]
Intersegment Revenue Net Of Purchase Power And Fuel	18	11	202	24
Intersegment Eliminations [Member] \| Generation Total Consolidated Group [Member]
Segment Reporting Information [Line Items]
Intersegment Revenue Net Of Purchase Power And Fuel	$ 0	$ 0	$ 0	$ 0

Accounts Receivable - Narrative (Details) - Sale of accounts receivable [Member] - USD ($) $ in Millions	Sep. 30, 2021	Jun. 24, 2021	May 24, 2021	Mar. 31, 2021	Feb. 17, 2021	Dec. 31, 2020	Apr. 08, 2020
Accounts, Notes, Loans and Financing Receivable [Line Items]
Derecognized receivables transferred at fair value	$ 1,401					$ 1,139	$ 1,200
Cash proceeds received	900	$ 50			$ 250	500	500
DPP consideration	501					639	650
Cash outflows returned			$ (50)
April 7, 2021
Accounts, Notes, Loans and Financing Receivable [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	750
March 29, 2024
Accounts, Notes, Loans and Financing Receivable [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	900
Cash proceeds received				$ 150
Exelon Generation Co L L C [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Derecognized receivables transferred at fair value	1,401					1,139	1,200
Cash proceeds received	900	$ 50			$ 250	500	500
DPP consideration	501					$ 639	$ 650
Cash outflows returned			$ (50)
Exelon Generation Co L L C [Member] \| April 7, 2021
Accounts, Notes, Loans and Financing Receivable [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	750
Exelon Generation Co L L C [Member] \| March 29, 2024
Accounts, Notes, Loans and Financing Receivable [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 900
Cash proceeds received				$ 150

Accounts Receivable - Allowance for Credit Losses Rollforward (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Accounts, Notes, Loans and Financing Receivable [Line Items]
Current period provision for expected credit losses			$ (155)	$ (130)
Exelon Generation Co L L C [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Current period provision for expected credit losses			(59)	(16)
Commonwealth Edison Co [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Current period provision for expected credit losses			(34)	(23)
PECO Energy Co [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Current period provision for expected credit losses			(36)	(38)
Baltimore Gas and Electric Company [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Current period provision for expected credit losses			(7)	(12)
Pepco Holdings LLC [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Current period provision for expected credit losses			(18)	(41)
Potomac Electric Power Company [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Current period provision for expected credit losses			(9)	(24)
Delmarva Power and Light Company [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Current period provision for expected credit losses			(3)	(15)
Atlantic City Electric Company [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Current period provision for expected credit losses			(6)	(2)
Customer accounts receivable
Accounts, Notes, Loans and Financing Receivable [Line Items]
Beginning balance	$ 395	$ 261	366	243
Current period provision for expected credit losses	47	114	122	222
Writeoffs, net of recoveries	33	17	79	51
Allowance change due to sale of customer accounts				56
Ending balance	409	358	409	358
Customer accounts receivable \| Exelon Generation Co L L C [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Beginning balance	75	33	32	80
Current period provision for expected credit losses	10	1	57	13
Writeoffs, net of recoveries	1	1	5	4
Allowance change due to sale of customer accounts				56
Ending balance	84	33	84	33
Customer accounts receivable \| Commonwealth Edison Co [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Beginning balance	89	72	97	59
Current period provision for expected credit losses	11	37	23	62
Writeoffs, net of recoveries	12	4	32	16
Ending balance	88	105	88	105
Customer accounts receivable \| PECO Energy Co [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Beginning balance	111	71	116	55
Current period provision for expected credit losses	1	27	7	56
Writeoffs, net of recoveries	11	2	22	15
Ending balance	101	96	101	96
Customer accounts receivable \| Baltimore Gas and Electric Company [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Beginning balance	27	23	35	12
Current period provision for expected credit losses	7	14	2	28
Writeoffs, net of recoveries	3	2	6	5
Ending balance	31	35	31	35
Customer accounts receivable \| Pepco Holdings LLC [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Beginning balance	93	62	86	37
Current period provision for expected credit losses	18	35	33	63
Writeoffs, net of recoveries	6	8	14	11
Ending balance	105	89	105	89
Customer accounts receivable \| Potomac Electric Power Company [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Beginning balance	38	24	32	13
Current period provision for expected credit losses	5	11	15	24
Writeoffs, net of recoveries	2	0	6	2
Ending balance	41	35	41	35
Customer accounts receivable \| Delmarva Power and Light Company [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Beginning balance	19	18	22	11
Current period provision for expected credit losses	3	7	4	14
Writeoffs, net of recoveries	4	3	8	3
Ending balance	18	22	18	22
Customer accounts receivable \| Atlantic City Electric Company [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Beginning balance	36	20	32	13
Current period provision for expected credit losses	10	17	14	25
Writeoffs, net of recoveries	0	5	0	6
Ending balance	46	32	46	32
Other receivables
Accounts, Notes, Loans and Financing Receivable [Line Items]
Beginning balance	72	61	71	48
Current period provision for expected credit losses	9	15	15	36
Writeoffs, net of recoveries	4	1	9	9
Ending balance	77	75	77	75
Other receivables \| Exelon Generation Co L L C [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Beginning balance	1	0	0	0
Current period provision for expected credit losses	3	0	4	0
Writeoffs, net of recoveries	0	0	0	0
Ending balance	4	0	4	0
Other receivables \| Commonwealth Edison Co [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Beginning balance	18	22	21	20
Current period provision for expected credit losses	2	5	0	9
Writeoffs, net of recoveries	1	0	2	2
Ending balance	19	27	19	27
Other receivables \| PECO Energy Co [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Beginning balance	7	7	8	7
Current period provision for expected credit losses	1	1	2	3
Writeoffs, net of recoveries	1	1	3	3
Ending balance	7	7	7	7
Other receivables \| Baltimore Gas and Electric Company [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Beginning balance	8	6	9	5
Current period provision for expected credit losses	1	3	2	7
Writeoffs, net of recoveries	1	0	3	3
Ending balance	8	9	8	9
Other receivables \| Pepco Holdings LLC [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Beginning balance	38	26	33	16
Current period provision for expected credit losses	2	6	7	17
Writeoffs, net of recoveries	0	0	0	1
Ending balance	40	32	40	32
Other receivables \| Potomac Electric Power Company [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Beginning balance	16	11	13	7
Current period provision for expected credit losses	1	2	4	6
Writeoffs, net of recoveries	0	0	0	0
Ending balance	17	13	17	13
Other receivables \| Delmarva Power and Light Company [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Beginning balance	9	7	9	4
Current period provision for expected credit losses	(1)	1	(1)	4
Writeoffs, net of recoveries	0	0	0	0
Ending balance	8	8	8	8
Other receivables \| Atlantic City Electric Company [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Beginning balance	13	8	11	5
Current period provision for expected credit losses	2	3	4	7
Writeoffs, net of recoveries	0	0	0	1
Ending balance	$ 15	$ 11	$ 15	$ 11

Accounts Receivable - Unbilled Customer Revenue (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Accounts, Notes, Loans and Financing Receivable [Line Items]
Unbilled customer revenue	$ 941	$ 998
Exelon Generation Co L L C [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Unbilled customer revenue	359	258
Commonwealth Edison Co [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Unbilled customer revenue	224	218
PECO Energy Co [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Unbilled customer revenue	113	147
Baltimore Gas and Electric Company [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Unbilled customer revenue	98	197
Pepco Holdings LLC [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Unbilled customer revenue	147	178
Potomac Electric Power Company [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Unbilled customer revenue	70	87
Delmarva Power and Light Company [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Unbilled customer revenue	34	62
Atlantic City Electric Company [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Unbilled customer revenue	$ 43	$ 29

Accounts Receivable - Purchases and Sales of Accounts Receivable (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020	Jun. 24, 2021	Feb. 17, 2021	Dec. 31, 2020	Apr. 08, 2020
Accounts, Notes, Loans and Financing Receivable [Line Items]
Loss on sale receivables	$ 1	$ 8	$ 26	$ 23
Proceeds from new transfers			4,440	1,889
Cash collections received on deferred purchase price and reinvested in the Facility			2,652	2,518
Cash collections reinvested in the Facility			7,092	4,407
Accounts Receivable, Purchase			2,945	2,698
Accounts Receivable, Sale			100	542
Exelon Generation Co L L C [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Loss on sale receivables	1	$ 8	26	23
Proceeds from new transfers			4,440	1,889
Cash collections received on deferred purchase price and reinvested in the Facility			2,652	2,518
Cash collections reinvested in the Facility			7,092	4,407
Accounts Receivable, Purchase			0	0
Accounts Receivable, Sale			117	790
Commonwealth Edison Co [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Purchase			810	865
Accounts Receivable, Sale			0	0
PECO Energy Co [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Purchase			795	786
Accounts Receivable, Sale			0	0
Baltimore Gas and Electric Company [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Purchase			531	508
Accounts Receivable, Sale			0	0
Pepco Holdings LLC [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Purchase			826	787
Accounts Receivable, Sale			0	0
Potomac Electric Power Company [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Purchase			504	484
Accounts Receivable, Sale			0	0
Delmarva Power and Light Company [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Purchase			166	160
Accounts Receivable, Sale			0	0
Atlantic City Electric Company [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Purchase			156	143
Accounts Receivable, Sale			0	0
Exelon Generation Co LLC Affiliate [Member] \| Commonwealth Edison Co [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Related Parties, Purchase			0	34
Exelon Generation Co LLC Affiliate [Member] \| PECO Energy Co [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Related Parties, Purchase			0	67
Exelon Generation Co LLC Affiliate [Member] \| Baltimore Gas and Electric Company [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Related Parties, Purchase			17	75
Exelon Generation Co LLC Affiliate [Member] \| Pepco Holdings LLC [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Related Parties, Purchase			0	72
Exelon Generation Co LLC Affiliate [Member] \| Potomac Electric Power Company [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Related Parties, Purchase			0	51
Exelon Generation Co LLC Affiliate [Member] \| Delmarva Power and Light Company [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Related Parties, Purchase			0	13
Exelon Generation Co LLC Affiliate [Member] \| Atlantic City Electric Company [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Related Parties, Purchase			0	8
Exelon Utility Registrants Affiliates [Member] \| Exelon Generation Co L L C [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Related Parties, Sale			17	248
Sale of accounts receivable [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Derecognized receivables transferred at fair value	1,401		1,401				$ 1,139	$ 1,200
Cash proceeds received	900		900		$ 50	$ 250	500	500
DPP consideration	501		501				639	650
Transfer of Financial Assets Accounted for as Sales, Additional Transfers			7,373	4,515
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	1,401		1,401				1,139	1,200
Cash proceeds received	900		900		$ 50	$ 250	500	500
DPP consideration	501		501				$ 639	$ 650
Transfer of Financial Assets Accounted for as Sales, Additional Transfers			7,373	$ 4,515
Sale of Accounts Receivable_Three Months Ended Q1 2021
Accounts, Notes, Loans and Financing Receivable [Line Items]
Cash proceeds received	400		400
Sale of Accounts Receivable_Three Months Ended Q1 2021 \| Exelon Generation Co L L C [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Cash proceeds received	$ 400		$ 400

Early Plant Retirements - Narrative (Details) $ in Millions	3 Months Ended		9 Months Ended
Early Plant Retirements - Narrative (Details) $ in Millions	Sep. 30, 2021 USD ($)	Sep. 30, 2020 USD ($)	Sep. 30, 2021 USD ($)	Sep. 30, 2020 USD ($)
Property, Plant and Equipment [Line Items]
Operating Expenses	$ 7,117	$ 8,087	$ 24,758	$ 22,387
Cost, Depreciation and Amortization	1,624	1,289	4,988	3,312
Generation New England [Member]
Property, Plant and Equipment [Line Items]
Operating Expenses			43
Cost, Depreciation and Amortization			41	6
Byron Dresden
Property, Plant and Equipment [Line Items]
Asset Retirement Obligation, Revision of Estimate	(13)
Facility Closing [Member] \| Midwest Asset Group [Member]
Property, Plant and Equipment [Line Items]
Severance Costs	(81)
Facility Closing [Member] \| Byron Dresden
Property, Plant and Equipment [Line Items]
Asset Retirement Obligation, Revision of Estimate	(4)	(34)	(8)	(34)
Exelon Generation Co L L C [Member]
Property, Plant and Equipment [Line Items]
Cost, Depreciation and Amortization	866	558	2,735	1,161
Exelon Generation Co L L C [Member] \| Generation New England [Member]
Property, Plant and Equipment [Line Items]
Operating Expenses			43
Cost, Depreciation and Amortization			41	6
Exelon Generation Co L L C [Member] \| Byron Dresden
Property, Plant and Equipment [Line Items]
Asset Retirement Obligation, Revision of Estimate	(13)
Exelon Generation Co L L C [Member] \| Facility Closing [Member] \| Midwest Asset Group [Member]
Property, Plant and Equipment [Line Items]
Severance Costs	(81)
Exelon Generation Co L L C [Member] \| Facility Closing [Member] \| Byron Dresden
Property, Plant and Equipment [Line Items]
Asset Retirement Obligation, Revision of Estimate	$ (4)	(34)	$ (8)	(34)
Commonwealth Edison Co [Member]
Property, Plant and Equipment [Line Items]
Carbon mitigation credit	54,500,000		54,500,000
Cost, Depreciation and Amortization	$ 304	$ 294	$ 893	$ 841

Early Plant Retirements - Pretax Expense (Details) - Byron Dresden - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Asset Retirement Obligation, Revision of Estimate	$ (13)
Facility Closing [Member]
Accelerated depreciation	574	$ 254	$ 1,805	$ 254
Accelerated nuclear fuel amortization	42	14	148	14
Operating and maintenance	(94)	220	(94)	220
Asset Retirement Obligation, Revision of Estimate	(4)	(34)	(8)	(34)
Asset Retirement Obligation Contractual Offset	(60)	(129)	(451)	(129)
Restructuring and Related Cost, Incurred Cost	466	393	1,416	393
Exelon Generation Co L L C [Member]
Asset Retirement Obligation, Revision of Estimate	(13)
Exelon Generation Co L L C [Member] \| Facility Closing [Member]
Accelerated depreciation	574	254	1,805	254
Accelerated nuclear fuel amortization	42	14	148	14
Operating and maintenance	(94)	220	(94)	220
Asset Retirement Obligation, Revision of Estimate	(4)	(34)	(8)	(34)
Asset Retirement Obligation Contractual Offset	(60)	(129)	(451)	(129)
Restructuring and Related Cost, Incurred Cost	$ 466	$ 393	$ 1,416	$ 393

Nuclear Decommissioning - Narrative (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Jun. 30, 2021	Sep. 30, 2021	Sep. 30, 2020	Dec. 31, 2020
Nuclear Decommissioning Additional Narrative Information [Line Items]
Nuclear decommissioning trust funds	$ 15,404		$ 15,404		$ 14,464
Increase in PPE related to ARO update			574	$ 775
Nuclear Decommissioning [Member]
Nuclear Decommissioning Additional Narrative Information [Line Items]
Net increase (decrease) due to changes in, and timing of, estimated future cash flows			256
Increase (Decrease) in ARO Due to Reversal of Early Retirement			(170)
Increase (Decrease) in ARO for Impacts of Revised Decommissioning Cost Estimates			(110)
Increase (Decrease) in ARO Due to Updated Cost Escalation Rates and Discount Rates			510
Nuclear Decommissioning [Member] \| Operating Expense [Member]
Nuclear Decommissioning Additional Narrative Information [Line Items]
Asset Retirement Obligation, Revision of Estimate			(51)
Nuclear Decommissioning Byron
Nuclear Decommissioning Additional Narrative Information [Line Items]
Decommissioning Related Activities Not Contractually Offset	140	$ 53
Exelon Generation Co L L C [Member]
Nuclear Decommissioning Additional Narrative Information [Line Items]
Nuclear decommissioning trust funds	15,404		15,404		14,464
Increase in PPE related to ARO update			550	$ 775
Exelon Generation Co L L C [Member] \| Nuclear Decommissioning [Member]
Nuclear Decommissioning Additional Narrative Information [Line Items]
Net increase (decrease) due to changes in, and timing of, estimated future cash flows			256
Increase (Decrease) in ARO Due to Reversal of Early Retirement			(170)
Increase (Decrease) in ARO for Impacts of Revised Decommissioning Cost Estimates			(110)
Increase (Decrease) in ARO Due to Updated Cost Escalation Rates and Discount Rates			510
Exelon Generation Co L L C [Member] \| Nuclear Decommissioning [Member] \| Operating Expense [Member]
Nuclear Decommissioning Additional Narrative Information [Line Items]
Asset Retirement Obligation, Revision of Estimate			(51)
Exelon Generation Co L L C [Member] \| Nuclear Decommissioning Byron
Nuclear Decommissioning Additional Narrative Information [Line Items]
Decommissioning Related Activities Not Contractually Offset	140	$ 53
Assets, Total [Member]
Nuclear Decommissioning Additional Narrative Information [Line Items]
Nuclear decommissioning trust funds	15,602		15,602		14,599
Assets, Total [Member] \| Exelon Generation Co L L C [Member]
Nuclear Decommissioning Additional Narrative Information [Line Items]
Nuclear decommissioning trust funds	15,602		15,602		14,599
Other Current Assets [Member]
Nuclear Decommissioning Additional Narrative Information [Line Items]
Nuclear decommissioning trust funds	198		198		134
Other Current Assets [Member] \| Exelon Generation Co L L C [Member]
Nuclear Decommissioning Additional Narrative Information [Line Items]
Nuclear decommissioning trust funds	$ 198		$ 198		$ 134

Nuclear Decommissioning - Rollforward of Nuclear Decommissioning ARO (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Dec. 31, 2020
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Accretion expense	$ 383	$ 375
Exelon Generation Co L L C [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Accretion expense	383	$ 375
Nuclear Decommissioning [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
ARO beginning balance	11,922
Accretion expense	375
Net increase (decrease) due to changes in, and timing of, estimated future cash flows	256
Costs incurred related to decommissioning plants	(57)
ARO ending balance	12,496
Current portion of ARO	74		$ 80
Nuclear Decommissioning [Member] \| Exelon Generation Co L L C [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
ARO beginning balance	11,922
Accretion expense	375
Net increase (decrease) due to changes in, and timing of, estimated future cash flows	256
Costs incurred related to decommissioning plants	(57)
ARO ending balance	12,496
Current portion of ARO	$ 74		$ 80

Asset Impairments - Narrative (Details) - USD ($) $ in Millions	3 Months Ended			9 Months Ended
	Sep. 30, 2021	Jun. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Property, Plant and Equipment [Line Items]
Impairment of Long-Lived Assets Held-for-use				$ 541	$ 567
Net income (loss) attributable to noncontrolling interests	$ 26		$ 68	126	(85)
Exelon Generation Co L L C [Member]
Property, Plant and Equipment [Line Items]
Impairment of Long-Lived Assets Held-for-use				537	552
Net income (loss) attributable to noncontrolling interests	26		68	125	$ (85)
Generation New England [Member]
Property, Plant and Equipment [Line Items]
Impairment of Long-Lived Assets Held-for-use		$ 350	500
Generation New England [Member] \| Exelon Generation Co L L C [Member]
Property, Plant and Equipment [Line Items]
Impairment of Long-Lived Assets Held-for-use		$ 350	$ 500
Midwest Asset Group [Member]
Property, Plant and Equipment [Line Items]
Impairment of Long-Lived Assets Held-for-use				0
Midwest Asset Group [Member] \| Exelon Generation Co L L C [Member]
Property, Plant and Equipment [Line Items]
Impairment of Long-Lived Assets Held-for-use				$ 0
Contracted Wind Project
Property, Plant and Equipment [Line Items]
Impairment of Long-Lived Assets Held-for-use	45
Net income (loss) attributable to noncontrolling interests	21
Contracted Wind Project \| Exelon Generation Co L L C [Member]
Property, Plant and Equipment [Line Items]
Impairment of Long-Lived Assets Held-for-use	45
Net income (loss) attributable to noncontrolling interests	$ 21

Income Taxes - Narrative (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
Income Taxes - Narrative (Details) - USD ($) $ in Millions	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Income Tax Additional Narrative Information [Line Items]
Deferred Tax Liability Adjustment - Noncontrolling Interest	$ (290)
Income taxes	174	$ 216	$ 229	$ 141
CENG [Member]
Income Tax Additional Narrative Information [Line Items]
Deferred Tax Liability Adjustment - Noncontrolling Interest	290
Exelon Generation Co L L C [Member]
Income Tax Additional Narrative Information [Line Items]
Deferred Tax Liability Adjustment - Noncontrolling Interest	(288)
Income taxes	177	100	108	41
Exelon Generation Co L L C [Member] \| CENG [Member]
Income Tax Additional Narrative Information [Line Items]
Deferred Tax Liability Adjustment - Noncontrolling Interest	288
Atlantic City Electric Company [Member]
Income Tax Additional Narrative Information [Line Items]
Income taxes	(11)	$ (7)	(12)	(39)
State and Local Jurisdiction [Member]
Income Tax Additional Narrative Information [Line Items]
Increase (Decrease) in Deferred Income Taxes			27	66
Income taxes			27
State and Local Jurisdiction [Member] \| Exelon Generation Co L L C [Member]
Income Tax Additional Narrative Information [Line Items]
Increase (Decrease) in Deferred Income Taxes				$ (26)
State and Local Jurisdiction [Member] \| Atlantic City Electric Company [Member]
Income Tax Additional Narrative Information [Line Items]
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecorded Benefit	$ 14		$ 14

Amount of current income tax expense (benefit) and deferred income tax expense (benefit) pertaining to continuing operations.

+ References + Details

Income Taxes - Reconciliation to Effective Tax Rate (Details) - USD ($) $ in Millions	3 Months Ended			9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Mar. 31, 2020	Sep. 30, 2021	Sep. 30, 2020
Effective Income Tax Rate Reconciliation, Percent [Abstract]
U.S. Federal statutory rate	21.00%	21.00%		21.00%	21.00%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	6.00%	12.30%		3.00%	9.30%
Qualified nuclear decommissioning trust fund income	0.50%	13.20%		9.40%	3.20%
Effective Income Tax Rate Reconciliation, Deferred Prosecution Agreement payments					2.50%
Amortization of investment tax credit, including deferred taxes on basis difference	(0.40%)	(1.40%)		(0.80%)	(1.20%)
Plant basis differences	(1.70%)	(4.30%)		(3.90%)	(4.00%)
Production tax credits and other credits	(1.00%)	(3.00%)		(2.60%)	(2.60%)
Noncontrolling interests	(0.40%)	0.80%		(0.70%)	1.00%
Excess deferred tax amortization	(6.80%)	(10.10%)		(13.90%)	(15.80%)
Tax Settlements		(0.20%)			(5.00%)
Other	(4.80%)	(0.80%)		2.20%	0.10%
Effective income tax rate	12.40%	27.50%		13.70%	8.50%
Decrease in Unrecognized Tax Benefits is Reasonably Possible			$ 411
Tax Adjustments, Settlements, and Unusual Provisions			76
Income Tax Expense (Benefit)	$ (174)	$ (216)		$ (229)	$ (141)
Internal Revenue Service (IRS) [Member]
Increase (decrease) due to:
Income Tax Expense (Benefit)			67
Exelon Generation Co L L C [Member]
Effective Income Tax Rate Reconciliation, Percent [Abstract]
U.S. Federal statutory rate	21.00%	21.00%		21.00%	21.00%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	4.40%	(10.30%)		90.20%	0.00%
Qualified nuclear decommissioning trust fund income	0.90%	47.40%		(1932.60%)	10.00%
Effective Income Tax Rate Reconciliation, Deferred Prosecution Agreement payments					0.00%
Amortization of investment tax credit, including deferred taxes on basis difference	(0.70%)	(4.50%)		130.60%	(3.20%)
Plant basis differences	0.00%	0.00%		0.00%	0.00%
Production tax credits and other credits	(1.40%)	(9.20%)		425.10%	(7.00%)
Noncontrolling interests	(0.60%)	2.90%		145.20%	3.10%
Excess deferred tax amortization	0.00%	0.00%		0.00%	0.00%
Tax Settlements		(0.70%)			(15.70%)
Other	(1.90%)	(0.90%)		(229.50%)	(0.50%)
Effective income tax rate	21.70%	45.70%		(1350.00%)	7.70%
Decrease in Unrecognized Tax Benefits is Reasonably Possible			411
Tax Adjustments, Settlements, and Unusual Provisions			73
Income Tax Expense (Benefit)	$ (177)	$ (100)		$ (108)	$ (41)
Exelon Generation Co L L C [Member] \| Internal Revenue Service (IRS) [Member]
Increase (decrease) due to:
Income Tax Expense (Benefit)			$ 67
Commonwealth Edison Co [Member]
Effective Income Tax Rate Reconciliation, Percent [Abstract]
U.S. Federal statutory rate	21.00%	21.00%		21.00%	21.00%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	8.00%	8.10%		7.60%	12.70%
Qualified nuclear decommissioning trust fund income	0.00%	0.00%		0.00%	0.00%
Effective Income Tax Rate Reconciliation, Deferred Prosecution Agreement payments					9.40%
Amortization of investment tax credit, including deferred taxes on basis difference	(0.10%)	(0.20%)		(0.10%)	(0.30%)
Plant basis differences	(0.80%)	(0.60%)		(0.70%)	(0.90%)
Production tax credits and other credits	(0.50%)	(0.40%)		(0.50%)	(0.40%)
Noncontrolling interests	0.00%	0.00%		0.00%	0.00%
Excess deferred tax amortization	(7.60%)	(5.60%)		(7.20%)	(11.80%)
Tax Settlements		0.00%			0.00%
Other	0.30%	1.10%		(1.30%)	2.10%
Effective income tax rate	20.30%	23.40%		18.80%	31.80%
Income Tax Expense (Benefit)	$ (56)	$ (60)		$ (141)	$ (142)
PECO Energy Co [Member]
Effective Income Tax Rate Reconciliation, Percent [Abstract]
U.S. Federal statutory rate	21.00%	21.00%		21.00%	21.00%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	(4.10%)	(6.20%)		(2.60%)	(3.40%)
Qualified nuclear decommissioning trust fund income	0.00%	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%		0.00%	0.00%
Plant basis differences	(16.20%)	(23.30%)		(12.60%)	(15.90%)
Production tax credits and other credits	0.00%	0.00%		0.00%	0.00%
Noncontrolling interests	0.00%	0.00%		0.00%	0.00%
Excess deferred tax amortization	(3.40%)	(3.80%)		(3.30%)	(3.50%)
Tax Settlements		0.00%			0.00%
Other	(0.10%)	(0.80%)		(0.20%)	(0.50%)
Effective income tax rate	(2.80%)	(13.10%)		2.30%	(2.30%)
Income Tax Expense (Benefit)	$ 3	$ 16		$ (9)	$ 7
Baltimore Gas and Electric Company [Member]
Effective Income Tax Rate Reconciliation, Percent [Abstract]
U.S. Federal statutory rate	21.00%	21.00%		21.00%	21.00%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	(13.00%)	5.10%		(10.80%)	5.50%
Qualified nuclear decommissioning trust fund income	0.00%	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%)	(0.10%)
Plant basis differences	(1.40%)	(1.20%)		(1.50%)	(1.80%)
Production tax credits and other credits	(0.90%)	(0.80%)		(0.90%)	(0.40%)
Noncontrolling interests	0.00%	0.00%		0.00%	0.00%
Excess deferred tax amortization	(17.30%)	(10.60%)		(16.00%)	(15.00%)
Tax Settlements		0.00%			0.00%
Other	(0.80%)	(0.30%)		(0.70%)	(0.50%)
Effective income tax rate	(12.50%)	13.10%		(9.00%)	8.70%
Income Tax Expense (Benefit)	$ 4	$ (8)		$ 24	$ (26)
Pepco Holdings LLC [Member]
Effective Income Tax Rate Reconciliation, Percent [Abstract]
U.S. Federal statutory rate	21.00%	21.00%		21.00%	21.00%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	5.00%	5.50%		4.60%	5.00%
Qualified nuclear decommissioning trust fund income	0.00%	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%)	(0.20%)		(0.10%)	(0.20%)
Plant basis differences	(1.30%)	(1.50%)		(1.30%)	(2.20%)
Production tax credits and other credits	(0.50%)	(0.50%)		(0.50%)	(0.30%)
Noncontrolling interests	0.00%	0.00%		0.00%	0.00%
Excess deferred tax amortization	(24.90%)	(24.90%)		(22.80%)	(45.30%)
Tax Settlements		0.00%			0.00%
Other	0.00%	0.10%		(0.30%)	(0.60%)
Effective income tax rate	(0.80%)	(0.50%)		0.60%	(22.60%)
Income Tax Expense (Benefit)	$ 2	$ 1		$ (3)	$ 77
Potomac Electric Power Company [Member]
Effective Income Tax Rate Reconciliation, Percent [Abstract]
U.S. Federal statutory rate	21.00%	21.00%		21.00%	21.00%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	3.40%	4.60%		2.50%	4.20%
Qualified nuclear decommissioning trust fund income	0.00%	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%	(0.10%)		0.00%	(0.10%)
Plant basis differences	(2.00%)	(2.10%)		(1.90%)	(2.40%)
Production tax credits and other credits	(0.50%)	(0.50%)		(0.50%)	(0.30%)
Noncontrolling interests	0.00%	0.00%		0.00%	0.00%
Excess deferred tax amortization	(17.60%)	(20.00%)		(17.40%)	(29.20%)
Tax Settlements		0.00%			0.00%
Other	0.10%	(0.40%)		(0.40%)	(0.80%)
Effective income tax rate	4.40%	2.50%		3.30%	(7.60%)
Income Tax Expense (Benefit)	$ (6)	$ (3)		$ (9)	$ 16
Delmarva Power and Light Company [Member]
Effective Income Tax Rate Reconciliation, Percent [Abstract]
U.S. Federal statutory rate	21.00%	21.00%		21.00%	21.00%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	6.40%	6.60%		6.50%	6.50%
Qualified nuclear decommissioning trust fund income	0.00%	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%)	(0.30%)
Plant basis differences	(0.60%)	(0.40%)		(0.70%)	(0.50%)
Production tax credits and other credits	(0.40%)	(0.50%)		(0.40%)	(0.20%)
Noncontrolling interests	0.00%	0.00%		0.00%	0.00%
Excess deferred tax amortization	(19.90%)	(23.60%)		(19.70%)	(53.60%)
Tax Settlements		0.00%			0.00%
Other	(0.60%)	0.70%		(0.20%)	(1.10%)
Effective income tax rate	5.70%	3.60%		6.30%	(28.20%)
Income Tax Expense (Benefit)	$ (3)	$ (1)		$ (9)	$ 20
Atlantic City Electric Company [Member]
Effective Income Tax Rate Reconciliation, Percent [Abstract]
U.S. Federal statutory rate	21.00%	21.00%		21.00%	21.00%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	7.00%	6.90%		7.30%	6.80%
Qualified nuclear decommissioning trust fund income	0.00%	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%)	(0.30%)		(0.20%)	(0.50%)
Plant basis differences	(0.60%)	(1.30%)		(0.60%)	(3.70%)
Production tax credits and other credits	(0.50%)	(0.40%)		(0.50%)	(0.40%)
Noncontrolling interests	0.00%	0.00%		0.00%	0.00%
Excess deferred tax amortization	(41.40%)	(36.80%)		(36.30%)	(81.40%)
Tax Settlements		0.00%			0.00%
Other	0.80%	0.60%		0.00%	0.00%
Effective income tax rate	(13.90%)	(10.30%)		(9.30%)	(58.20%)
Income Tax Expense (Benefit)	$ 11	$ 7		$ 12	$ 39

Income Taxes - Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Pepco Holdings LLC [Member]
Income Tax Contingency [Line Items]
Unrecognized Tax Benefits	$ 56	$ 52
Atlantic City Electric Company [Member]
Income Tax Contingency [Line Items]
Unrecognized Tax Benefits	$ 16	$ 15

Income Taxes - Allocation of Tax Benefits (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Exelon Generation Co L L C [Member]
Allocation of Tax Benefits [Line Items]
Allocation Of Federal Tax Benefit Under Tax Sharing Agreement	$ 64	$ 64
Commonwealth Edison Co [Member]
Allocation of Tax Benefits [Line Items]
Allocation Of Federal Tax Benefit Under Tax Sharing Agreement	1	14
PECO Energy Co [Member]
Allocation of Tax Benefits [Line Items]
Allocation Of Federal Tax Benefit Under Tax Sharing Agreement	19	17
Baltimore Gas and Electric Company [Member]
Allocation of Tax Benefits [Line Items]
Allocation Of Federal Tax Benefit Under Tax Sharing Agreement	0	0
Pepco Holdings LLC [Member]
Allocation of Tax Benefits [Line Items]
Allocation Of Federal Tax Benefit Under Tax Sharing Agreement	17	17
Potomac Electric Power Company [Member]
Allocation of Tax Benefits [Line Items]
Allocation Of Federal Tax Benefit Under Tax Sharing Agreement	16	8
Delmarva Power and Light Company [Member]
Allocation of Tax Benefits [Line Items]
Allocation Of Federal Tax Benefit Under Tax Sharing Agreement	0	6
Atlantic City Electric Company [Member]
Allocation of Tax Benefits [Line Items]
Allocation Of Federal Tax Benefit Under Tax Sharing Agreement	$ 0	$ 1

Retirement Benefits - Narrative (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Mar. 31, 2021	Sep. 30, 2021
Defined Benefit Plan Disclosure [Line Items]
Increase (Decrease) in Obligation, Pension Benefits	$ 33
Increase (Decrease) in Obligation, Other Postretirement Benefits	(9)
Accumulated Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss), after Tax	1
Defined Benefit Plan Amounts Recognized In Regulatory Assets Before Tax	21
Defined Benefit Plan Amounts Recognized In Regulatory Liabilities Before Tax	$ 1
Pension Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected return on assets		7.00%
Discount rate		2.58%
Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected return on assets		6.46%
Discount rate		2.51%

Retirement Benefits - Calculation of Net Periodic Benefit Cost (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Amortization of:
Net periodic benefit cost	$ 19	$ 15	$ 64	$ 38
Pension Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	110	97	330	290
Interest cost	161	190	481	569
Expected return on assets	(335)	(317)	(1,003)	(953)
Amortization of:
Prior service cost (credit)	1	1	3	3
Actuarial loss	150	128	449	384
Curtailment benefits			0	0
Settlement charges	12	8	16	14
Net periodic benefit cost	99	107	276	307
Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	20	22	60	67
Interest cost	29	37	86	114
Expected return on assets	(40)	(41)	(119)	(122)
Amortization of:
Prior service cost (credit)	(8)	(30)	(25)	(92)
Actuarial loss	9	12	27	36
Curtailment benefits			(1)	0
Settlement charges	0	0	0	0
Net periodic benefit cost	$ 10	$ 0	$ 28	$ 3

Retirement Benefits - Defined Contribution Savings Plans (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Defined Benefit Plan Disclosure [Line Items]
Savings Plans Matching Contributions	$ 38	$ 37	$ 107	$ 104
Exelon Generation Co L L C [Member]
Defined Benefit Plan Disclosure [Line Items]
Savings Plans Matching Contributions	14	14	40	41
Commonwealth Edison Co [Member]
Defined Benefit Plan Disclosure [Line Items]
Savings Plans Matching Contributions	9	9	27	25
PECO Energy Co [Member]
Defined Benefit Plan Disclosure [Line Items]
Savings Plans Matching Contributions	2	3	8	8
Baltimore Gas and Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Savings Plans Matching Contributions	4	4	8	8
Pepco Holdings LLC [Member]
Defined Benefit Plan Disclosure [Line Items]
Savings Plans Matching Contributions	5	3	12	9
Potomac Electric Power Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Savings Plans Matching Contributions	1	1	3	3
Delmarva Power and Light Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Savings Plans Matching Contributions	1	1	3	2
Atlantic City Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Savings Plans Matching Contributions	$ 1	$ 0	$ 2	$ 1

Derivative Financial Instruments - Narrative (Details) MWh in Millions, $ in Millions	1 Months Ended	9 Months Ended
	Jun. 30, 2012 MWh	Sep. 30, 2021 USD ($)	Dec. 31, 2020 USD ($)
Derivative [Line Items]
Incremental Collateral For Loss Of Investment Grade Credit Rating		$ 3,001	$ 1,432
Other		1,180	1,264
Exelon Generation Co L L C [Member]
Derivative [Line Items]
Incremental Collateral For Loss Of Investment Grade Credit Rating		3,001	1,432
Other		347	444
Commonwealth Edison Co [Member]
Derivative [Line Items]
Long-term Purchase Commitment, Minimum Energy Volume Required \| MWh	1.3
Other		165	143
PECO Energy Co [Member]
Derivative [Line Items]
Incremental Collateral For Loss Of Investment Grade Credit Rating		23
Other		31	30
Baltimore Gas and Electric Company [Member]
Derivative [Line Items]
Incremental Collateral For Loss Of Investment Grade Credit Rating		46
Other		81	91
Delmarva Power and Light Company [Member]
Derivative [Line Items]
Incremental Collateral For Loss Of Investment Grade Credit Rating		11
Other		$ 41	20
Minimum [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Expected Generation Hedged In Next Twelve Months		96.00%
Maximum [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Expected Generation Hedged In Next Twelve Months		99.00%
Commodity Contract [Member] \| Commonwealth Edison Co [Member] \| External Counterparties \| Collateral [Member]
Derivative [Line Items]
Other		$ 56
Commodity Contract [Member] \| Baltimore Gas and Electric Company [Member] \| External Counterparties \| Collateral [Member]
Derivative [Line Items]
Other		21
Commodity Contract [Member] \| Delmarva Power and Light Company [Member] \| External Counterparties \| Collateral [Member]
Derivative [Line Items]
Other		25
Not Designated as Hedging Instrument, Economic Hedge [Member]
Derivative [Line Items]
Derivative, Notional Amount		567	665
Not Designated as Hedging Instrument, Economic Hedge [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Derivative, Notional Amount		$ 567	$ 665

Derivative Financial Instruments - Summary of Derivative Fair Value Balances (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Derivative [Line Items]
Mark-to-market derivative assets, current	$ 1,507	$ 644
Derivative Asset, Noncurrent	665	555
Mark-to-market derivative liabilities, current	(1,717)	(295)
Mark-to-market derivative liabilities, noncurrent	(721)	(473)
Margin Deposit Assets	(2,084)	(209)
Commodity Contract [Member]
Derivative [Line Items]
Mark-to-market derivative assets, current	1,505	639
Derivative Asset, Noncurrent	661	554
Total mark-to-market derivative assets	2,166	1,193
Mark-to-market derivative liabilities, current	(1,710)	(293)
Mark-to-market derivative liabilities, noncurrent	(720)	(472)
Total mark-to-market derivative liabilities	(2,430)	(765)
Total mark-to-market derivative net assets (liabilities)	(264)	428
Exelon Generation Co L L C [Member]
Derivative [Line Items]
Mark-to-market derivative assets, current	1,505	644
Derivative Asset, Noncurrent	664	555
Mark-to-market derivative liabilities, current	(1,709)	(262)
Mark-to-market derivative liabilities, noncurrent	(511)	(205)
Margin Deposit Assets	(2,084)	(209)
Exelon Generation Co L L C [Member] \| Commodity Contract [Member]
Derivative [Line Items]
Mark-to-market derivative assets, current	1,505	639
Derivative Asset, Noncurrent	661	554
Total mark-to-market derivative assets	2,166	1,193
Mark-to-market derivative liabilities, current	(1,705)	(260)
Mark-to-market derivative liabilities, noncurrent	(511)	(204)
Total mark-to-market derivative liabilities	(2,216)	(464)
Total mark-to-market derivative net assets (liabilities)	(50)	729
Commonwealth Edison Co [Member]
Derivative [Line Items]
Mark-to-market derivative liabilities, current	(5)	(33)
Mark-to-market derivative liabilities, noncurrent	(209)	(268)
Collateral [Member] \| Commodity Contract [Member] \| External Counterparties
Derivative [Line Items]
Cash Collateral Posted	1
Cash Collateral Held		(15)
Collateral [Member] \| Commodity Contract [Member] \| Affiliates
Derivative [Line Items]
Cash Collateral Posted	71
Collateral [Member] \| Exelon Generation Co L L C [Member] \| Commodity Contract [Member]
Derivative [Line Items]
Mark-to-market derivative assets, current	(790)	103
Derivative Asset, Noncurrent	(201)	64
Total mark-to-market derivative assets	(991)	167
Mark-to-market derivative liabilities, current	(559)	131
Mark-to-market derivative liabilities, noncurrent	(95)	118
Total mark-to-market derivative liabilities	(654)	249
Total mark-to-market derivative net assets (liabilities)	(1,645)	416
Collateral [Member] \| Exelon Generation Co L L C [Member] \| Commodity Contract [Member] \| External Counterparties
Derivative [Line Items]
Cash Collateral Posted	1
Cash Collateral Held		(15)
Collateral [Member] \| Exelon Generation Co L L C [Member] \| Commodity Contract [Member] \| Affiliates
Derivative [Line Items]
Cash Collateral Posted	71
Collateral [Member] \| Exelon Generation Co L L C [Member] \| Commodity Contract [Member] \| Commonwealth Edison Co [Member]
Derivative [Line Items]
Cash Collateral Posted	50
Netting [Member] \| Exelon Generation Co L L C [Member] \| Commodity Contract [Member]
Derivative [Line Items]
Mark-to-market derivative assets, current	(17,399)	(2,261)
Derivative Asset, Noncurrent	(2,755)	(1,015)
Total mark-to-market derivative assets	(20,154)	(3,276)
Mark-to-market derivative liabilities, current	17,399	2,261
Mark-to-market derivative liabilities, noncurrent	2,755	1,015
Total mark-to-market derivative liabilities	20,154	3,276
Total mark-to-market derivative net assets (liabilities)	0	0
Not Designated as Hedging Instrument, Economic Hedge [Member] \| Exelon Generation Co L L C [Member] \| Commodity Contract [Member]
Derivative [Line Items]
Mark-to-market derivative assets, current	19,631	2,757
Derivative Asset, Noncurrent	3,612	1,501
Total mark-to-market derivative assets	23,243	4,258
Mark-to-market derivative liabilities, current	(18,490)	(2,629)
Mark-to-market derivative liabilities, noncurrent	(3,168)	(1,335)
Total mark-to-market derivative liabilities	(21,658)	(3,964)
Total mark-to-market derivative net assets (liabilities)	1,585	294
Not Designated as Hedging Instrument, Economic Hedge [Member] \| Commonwealth Edison Co [Member] \| Commodity Contract [Member]
Derivative [Line Items]
Mark-to-market derivative assets, current	0	0
Derivative Asset, Noncurrent	0	0
Total mark-to-market derivative assets	0	0
Mark-to-market derivative liabilities, current	(5)	(33)
Mark-to-market derivative liabilities, noncurrent	(209)	(268)
Total mark-to-market derivative liabilities	(214)	(301)
Total mark-to-market derivative net assets (liabilities)	(214)	(301)
Not Designated as Hedging Instrument, Trading [Member] \| Exelon Generation Co L L C [Member] \| Commodity Contract [Member]
Derivative [Line Items]
Mark-to-market derivative assets, current	63	40
Derivative Asset, Noncurrent	5	4
Total mark-to-market derivative assets	68	44
Mark-to-market derivative liabilities, current	(55)	(23)
Mark-to-market derivative liabilities, noncurrent	(3)	(2)
Total mark-to-market derivative liabilities	(58)	(25)
Total mark-to-market derivative net assets (liabilities)	$ 10	$ 19

Derivative Financial Instruments - Summary of Economic Hedges (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives			$ 1,244	$ 448
Exelon Generation Co L L C [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives			1,244	448
Not Designated as Hedging Instrument, Economic Hedge [Member] \| Commodity Contract [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	$ 755	$ 248	1,248	462
Not Designated as Hedging Instrument, Economic Hedge [Member] \| Commodity Contract [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	755	248	1,248	462
Not Designated as Hedging Instrument, Economic Hedge [Member] \| Commodity Contract [Member] \| Operating revenues [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	(637)	39	(961)	238
Not Designated as Hedging Instrument, Economic Hedge [Member] \| Commodity Contract [Member] \| Operating revenues [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	(637)	39	(961)	238
Not Designated as Hedging Instrument, Economic Hedge [Member] \| Commodity Contract [Member] \| Purchased power and fuel [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	1,392	209	2,209	224
Not Designated as Hedging Instrument, Economic Hedge [Member] \| Commodity Contract [Member] \| Purchased power and fuel [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	$ 1,392	$ 209	$ 2,209	$ 224

Derivative Financial Instruments - Summary of Credit Risk Exposure (Details) - Exelon Generation Co L L C [Member] $ in Millions	9 Months Ended
	Sep. 30, 2021 USD ($)
Derivative [Line Items]
Cash Collateral Held	$ 188
Letters Of Credit Held	117
Total Exposure Before Credit Collateral [Member]
Derivative [Line Items]
Concentration Risk, Credit Risk, Financial Instrument, Maximum Exposure	1,143
Total Exposure Before Credit Collateral [Member] \| Internal Investment Grade
Derivative [Line Items]
Concentration Risk, Credit Risk, Financial Instrument, Maximum Exposure	110
Total Exposure Before Credit Collateral [Member] \| Internal Noninvestment Grade
Derivative [Line Items]
Concentration Risk, Credit Risk, Financial Instrument, Maximum Exposure	309
Total Exposure Before Credit Collateral [Member] \| External Credit Rating, Investment Grade
Derivative [Line Items]
Concentration Risk, Credit Risk, Financial Instrument, Maximum Exposure	701
Total Exposure Before Credit Collateral [Member] \| External Credit Rating, Non Investment Grade
Derivative [Line Items]
Concentration Risk, Credit Risk, Financial Instrument, Maximum Exposure	23
Credit Collateral [Member]
Derivative [Line Items]
Concentration Risk, Credit Risk, Financial Instrument, Maximum Exposure	305
Credit Collateral [Member] \| Internal Investment Grade
Derivative [Line Items]
Concentration Risk, Credit Risk, Financial Instrument, Maximum Exposure	1
Credit Collateral [Member] \| Internal Noninvestment Grade
Derivative [Line Items]
Concentration Risk, Credit Risk, Financial Instrument, Maximum Exposure	48
Credit Collateral [Member] \| External Credit Rating, Investment Grade
Derivative [Line Items]
Concentration Risk, Credit Risk, Financial Instrument, Maximum Exposure	254
Credit Collateral [Member] \| External Credit Rating, Non Investment Grade
Derivative [Line Items]
Concentration Risk, Credit Risk, Financial Instrument, Maximum Exposure	2
Net Exposure [Member]
Derivative [Line Items]
Concentration Risk, Credit Risk, Financial Instrument, Maximum Exposure	838
Net Exposure [Member] \| Financial institutions [Member]
Derivative [Line Items]
Concentration Risk, Credit Risk, Financial Instrument, Maximum Exposure	53
Net Exposure [Member] \| Investor-owned utilities, marketers, power producers [Member]
Derivative [Line Items]
Concentration Risk, Credit Risk, Financial Instrument, Maximum Exposure	652
Net Exposure [Member] \| Energy cooperatives and municipalities [Member]
Derivative [Line Items]
Concentration Risk, Credit Risk, Financial Instrument, Maximum Exposure	62
Net Exposure [Member] \| Other [Member]
Derivative [Line Items]
Concentration Risk, Credit Risk, Financial Instrument, Maximum Exposure	71
Net Exposure [Member] \| Internal Investment Grade
Derivative [Line Items]
Concentration Risk, Credit Risk, Financial Instrument, Maximum Exposure	109
Net Exposure [Member] \| Internal Noninvestment Grade
Derivative [Line Items]
Concentration Risk, Credit Risk, Financial Instrument, Maximum Exposure	261
Net Exposure [Member] \| External Credit Rating, Investment Grade
Derivative [Line Items]
Concentration Risk, Credit Risk, Financial Instrument, Maximum Exposure	447
Net Exposure [Member] \| External Credit Rating, Non Investment Grade
Derivative [Line Items]
Concentration Risk, Credit Risk, Financial Instrument, Maximum Exposure	$ 21
Number Of Counterparties Greater Than Ten Percent Of Net Exposure [Member]
Derivative [Line Items]
Number of Counterparties	0
Number Of Counterparties Greater Than Ten Percent Of Net Exposure [Member] \| External Credit Rating, Investment Grade
Derivative [Line Items]
Number of Counterparties	0
Net Exposure Of Counterparties Greater Than Ten Percent Of Net Exposure [Member]
Derivative [Line Items]
Concentration Risk, Credit Risk, Financial Instrument, Maximum Exposure	$ 0
Net Exposure Of Counterparties Greater Than Ten Percent Of Net Exposure [Member] \| External Credit Rating, Investment Grade
Derivative [Line Items]
Concentration Risk, Credit Risk, Financial Instrument, Maximum Exposure	$ 0

Derivative Financial Instruments - Summary of Credit Risk Related Contingent Features (Details) - Exelon Generation Co L L C [Member] - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Liability	$ (5,289)	$ (834)
Offsetting Fair Value of In-the-Money Contracts Under Master Netting Agreements	2,735	537
Derivative liabilities, fair value	$ (2,554)	$ (297)

Derivative Financial Instruments Derivative Financial Instruments - Summary of Cash Collateral and Letters of Credit (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Collateral, Right to Reclaim Cash	$ 299	$ 511
Derivative, Collateral, Right to Reclaim Securities	477	226
Derivative, Collateral, Obligation to Return Cash	1,872	110
Derivative, Collateral, Obligation to Return Securities	130	40
Incremental Collateral For Loss Of Investment Grade Credit Rating	3,001	1,432
Exelon Generation Co L L C [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Collateral, Right to Reclaim Cash	299	511
Derivative, Collateral, Right to Reclaim Securities	477	226
Derivative, Collateral, Obligation to Return Cash	1,872	110
Derivative, Collateral, Obligation to Return Securities	130	40
Incremental Collateral For Loss Of Investment Grade Credit Rating	$ 3,001	$ 1,432

Debt and Credit Agreements - Narrative (Details) $ in Millions	9 Months Ended
	Sep. 30, 2021 USD ($)
ShortTermDebt03232017 \| Corporate [Member]
Debt Instrument [Line Items]
Short-term Bank Loans and Notes Payable	$ 500
ShortTermDebt03242021 \| Corporate [Member]
Debt Instrument [Line Items]
Short-term Bank Loans and Notes Payable	200
ShortTermDebt03312021.1 \| Corporate [Member]
Debt Instrument [Line Items]
Short-term Bank Loans and Notes Payable	150
ShortTermDebt03312021.2 \| Corporate [Member]
Debt Instrument [Line Items]
Short-term Bank Loans and Notes Payable	150
ShortTermDebt03192020 \| Exelon Generation Co L L C [Member]
Debt Instrument [Line Items]
Short-term Bank Loans and Notes Payable	200
ShortTermDebt300 \| Exelon Generation Co L L C [Member]
Debt Instrument [Line Items]
Short-term Bank Loans and Notes Payable	300
ShortTermDebt08062021 \| Exelon Generation Co L L C [Member]
Debt Instrument [Line Items]
Short-term Bank Loans and Notes Payable	880
ShortTermDebt01252021.1 \| Commonwealth Edison Co [Member]
Debt Instrument [Line Items]
Short-term Bank Loans and Notes Payable	125
ShortTermDebt01252021.2 \| Commonwealth Edison Co [Member]
Debt Instrument [Line Items]
Short-term Bank Loans and Notes Payable	125
ExGenBilatJan2013 \| Exelon Generation Co L L C [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	100
ExGenBilatFeb2019 \| Exelon Generation Co L L C [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	100
ExGenBilatJan2016 \| Exelon Generation Co L L C [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	150
ExGenBilatOct2012 \| Exelon Generation Co L L C [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Increase (Decrease), Net	200
WestMedMarch2026 \| Non-Recourse Debt [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	150
Non-Recourse Debt	145
WestMedMarch2026 \| Non-Recourse Debt [Member] \| Interest Rate Swap [Member]
Debt Instrument [Line Items]
Derivative, Notional Amount	$ 113
Derivative, Fixed Interest Rate	0.61%
WestMedMarch2026 \| Exelon Generation Co L L C [Member] \| Non-Recourse Debt [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate Terms	LIBOR + 3
Debt Instrument, Face Amount	$ 150
Non-Recourse Debt	145
WestMedMarch2026 \| Exelon Generation Co L L C [Member] \| Non-Recourse Debt [Member] \| Interest Rate Swap [Member]
Debt Instrument [Line Items]
Derivative, Notional Amount	$ 113
Derivative, Fixed Interest Rate	0.61%
London Interbank Offered Rate (LIBOR) [Member] \| ShortTermDebt03232017 \| Corporate [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate Terms	LIBOR plus 0.65
London Interbank Offered Rate (LIBOR) [Member] \| ShortTermDebt03242021 \| Corporate [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate Terms	LIBOR plus 0.65
London Interbank Offered Rate (LIBOR) [Member] \| ShortTermDebt03312021.1 \| Corporate [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate Terms	LIBOR plus 0.65
London Interbank Offered Rate (LIBOR) [Member] \| ShortTermDebt03312021.2 \| Corporate [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate Terms	LIBOR plus 0.65
London Interbank Offered Rate (LIBOR) [Member] \| ShortTermDebt03192020 \| Exelon Generation Co L L C [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate Terms	LIBOR plus 0.875
London Interbank Offered Rate (LIBOR) [Member] \| ShortTermDebt300 \| Exelon Generation Co L L C [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate Terms	LIBOR plus 0.70
London Interbank Offered Rate (LIBOR) [Member] \| ShortTermDebt08062021 \| Exelon Generation Co L L C [Member] \| Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate Terms	LIBOR plus 0.875
London Interbank Offered Rate (LIBOR) [Member] \| ShortTermDebt08062021 \| Exelon Generation Co L L C [Member] \| Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate Terms	LIBOR plus 1
London Interbank Offered Rate (LIBOR) [Member] \| ShortTermDebt01252021.1 \| Commonwealth Edison Co [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate Terms	LIBOR plus 0.50
London Interbank Offered Rate (LIBOR) [Member] \| ShortTermDebt01252021.2 \| Commonwealth Edison Co [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate Terms	LIBOR plus 0.75
London Interbank Offered Rate (LIBOR) [Member] \| WestMedMarch2026 \| Non-Recourse Debt [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate Terms	LIBOR plus 3
London Interbank Offered Rate (LIBOR) [Member] \| WestMedMarch2026 \| Exelon Generation Co L L C [Member] \| Non-Recourse Debt [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate Terms	LIBOR plus 3

Debt and Credit Agreements - Commercial Paper Borrowings (Details) - Commercial Paper [Member] - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Short-term Debt [Line Items]
Commercial Paper	$ 287	$ 1,031
Short-term Debt, Weighted Average Interest Rate, at Point in Time	0.19%	0.25%
Corporate [Member]
Short-term Debt [Line Items]
Commercial Paper	$ 0	$ 0
Exelon Generation Co L L C [Member]
Short-term Debt [Line Items]
Commercial Paper	$ 0	$ 340
Short-term Debt, Weighted Average Interest Rate, at Point in Time	0.00%	0.27%
Commonwealth Edison Co [Member]
Short-term Debt [Line Items]
Commercial Paper	$ 0	$ 323
Short-term Debt, Weighted Average Interest Rate, at Point in Time	0.00%	0.23%
PECO Energy Co [Member]
Short-term Debt [Line Items]
Commercial Paper	$ 0	$ 0
Baltimore Gas and Electric Company [Member]
Short-term Debt [Line Items]
Commercial Paper	0	0
Pepco Holdings LLC [Member]
Short-term Debt [Line Items]
Commercial Paper	$ 287	$ 368
Short-term Debt, Weighted Average Interest Rate, at Point in Time	0.19%	0.24%
Potomac Electric Power Company [Member]
Short-term Debt [Line Items]
Commercial Paper	$ 40	$ 35
Short-term Debt, Weighted Average Interest Rate, at Point in Time	0.15%	0.22%
Delmarva Power and Light Company [Member]
Short-term Debt [Line Items]
Commercial Paper	$ 22	$ 146
Short-term Debt, Weighted Average Interest Rate, at Point in Time	0.15%	0.24%
Atlantic City Electric Company [Member]
Short-term Debt [Line Items]
Commercial Paper	$ 225	$ 187
Short-term Debt, Weighted Average Interest Rate, at Point in Time	0.20%	0.25%

Debt and Credit Agreements - Issuance of Long-Term Debt (Details) $ in Millions	9 Months Ended
	Sep. 30, 2021 USD ($)
WestMedMarch2026 \| Non-Recourse Debt [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 150
Corporate [Member] \| SoftAgree362Dec2025 \| Notes Payable to Banks [Member]
Debt Instrument [Line Items]
Interest Rate	3.62%
Debt Instrument, Face Amount	$ 4
Exelon Generation Co L L C [Member] \| WestMedMarch2026 \| Non-Recourse Debt [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate Terms	LIBOR + 3
Debt Instrument, Face Amount	$ 150
Exelon Generation Co L L C [Member] \| EEPF253April2021 \| Notes Payable, Other Payables[Member]
Debt Instrument [Line Items]
Interest Rate	2.53%
Debt Instrument, Face Amount	$ 1
Exelon Generation Co L L C [Member] \| EEPF4242021 \| Notes Payable, Other Payables[Member]
Debt Instrument [Line Items]
Interest Rate	4.24%
Debt Instrument, Face Amount	$ 1
Commonwealth Edison Co [Member] \| FMB313Mar2051 \| First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Interest Rate	3.13%
Debt Instrument, Face Amount	$ 700
Commonwealth Edison Co [Member] \| FMB300March2050 [Member] \| First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Interest Rate	2.75%
Debt Instrument, Face Amount	$ 450
PECO Energy Co [Member] \| FMB305Mar2051 \| First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Interest Rate	3.05%
Debt Instrument, Face Amount	$ 375
PECO Energy Co [Member] \| FMB285Sep2051 \| First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Interest Rate	2.85%
Debt Instrument, Face Amount	$ 375
Baltimore Gas and Electric Company [Member] \| SN225June2031
Debt Instrument [Line Items]
Interest Rate	2.25%
Debt Instrument, Face Amount	$ 600
Potomac Electric Power Company [Member] \| FMB232Mar2031 \| First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Interest Rate	2.32%
Debt Instrument, Face Amount	$ 150
Potomac Electric Power Company [Member] \| FMB329Sep2051 \| First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Interest Rate	3.29%
Debt Instrument, Face Amount	$ 125
Delmarva Power and Light Company [Member] \| FMB324Mar2051 \| First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Interest Rate	3.24%
Debt Instrument, Face Amount	$ 125
Atlantic City Electric Company [Member] \| FMB230Mar2031 \| First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Interest Rate	2.30%
Debt Instrument, Face Amount	$ 350

Fair Value of Financial Assets and Liabilities - Narrative (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity Securities without Readily Determinable Fair Value, Amount	$ 44	$ 73
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	32	$ 55
Middle Market Lending [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	359
Middle Market Lending [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	359
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	174
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	174
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	371
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	$ 371

Fair Value of Financial Assets and Liabilities - Fair Value Assets Liabilities Measured On Recurring Basis Unobservable Input Reconciliation (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Fair Value, Inputs, Level 3 [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Beginning Balance	$ (235)	$ 883	$ 660	$ 1,068
Total realized / unrealized gains (losses)
Included in net income	(967)	(327)	(1,600)	(483)
Included in noncurrent payables to affiliates	0	0	0	0
Included in regulatory assets	62	32	105	14
Change in collateral	(413)	(79)	(751)	(120)
Purchases, sales, issuances and settlements
Purchases	8	66	123	136
Sales	6	(3)	7	(27)
Settlements	(2)	0	(50)	(15)
Transfers into Level 3	2		4	(5)
Transfers out of Level 3	(27)	9	(64)	13
Ending Balance	(1,566)	581	(1,566)	581
Fair Value, Asset, Recurring Basis, Still Held, Unrealized Gain (Loss)	(1,001)	(222)	(1,521)	(107)
Fair Value, Inputs, Level 3 [Member] \| Consolidation, Eliminations [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Beginning Balance	0	0	0	0
Total realized / unrealized gains (losses)
Included in net income	0	0	0	0
Included in noncurrent payables to affiliates	(11)	(18)	(18)	(17)
Included in regulatory assets	11	18	18	17
Change in collateral	0	0	0	0
Purchases, sales, issuances and settlements
Purchases	0	0	0	0
Sales	0	0	0	0
Settlements	0	0	0	0
Transfers into Level 3	0		0	0
Transfers out of Level 3	0	0	0	0
Ending Balance	0	0	0	0
Fair Value, Asset, Recurring Basis, Still Held, Unrealized Gain (Loss)	0	0	0	0
Exelon Generation Co L L C [Member]
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Gain (Loss) Included in Earnings	34	(105)	(80)	(376)
Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 3 [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Beginning Balance	(4)	1,158	927	1,328
Total realized / unrealized gains (losses)
Included in net income	(967)	(315)	(1,602)	(473)
Included in noncurrent payables to affiliates	11	18	18	17
Included in regulatory assets	0	0	0	0
Change in collateral	(413)	(79)	(751)	(120)
Purchases, sales, issuances and settlements
Purchases	8	66	123	136
Sales	6	(3)	7	(27)
Settlements	(2)	(3)	(48)	(18)
Transfers into Level 3	2		4	(5)
Transfers out of Level 3	(27)	9	(64)	13
Ending Balance	(1,386)	851	(1,386)	851
Fair Value, Asset, Recurring Basis, Still Held, Unrealized Gain (Loss)	(1,001)	(210)	(1,523)	(97)
Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 3 [Member] \| Nuclear Decommissioning Trust Fund Investments [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Beginning Balance	461	499	497	511
Total realized / unrealized gains (losses)
Included in net income	3	3	4	1
Included in noncurrent payables to affiliates	11	18	18	17
Included in regulatory assets	0	0	0	0
Change in collateral	0	0	0	0
Purchases, sales, issuances and settlements
Purchases	2	1	3	6
Sales	0	0	0	0
Settlements	(2)	(3)	(48)	(18)
Transfers into Level 3	0		1	1
Transfers out of Level 3	0	0	0	0
Ending Balance	475	518	475	518
Fair Value, Asset, Recurring Basis, Still Held, Unrealized Gain (Loss)	3	3	4	1
Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 3 [Member] \| Derivative [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Beginning Balance	(465)	659	430	817
Total realized / unrealized gains (losses)
Included in net income	(970)	(318)	(1,606)	(474)
Included in noncurrent payables to affiliates	0	0	0	0
Included in regulatory assets	0	0	0	0
Change in collateral	(413)	(79)	(751)	(120)
Purchases, sales, issuances and settlements
Purchases	6	65	120	130
Sales	6	(3)	7	(27)
Settlements	0	0	0	0
Transfers into Level 3	2		3	(6)
Transfers out of Level 3	(27)	9	(64)	13
Ending Balance	(1,861)	333	(1,861)	333
Fair Value, Asset, Recurring Basis, Still Held, Unrealized Gain (Loss)	(1,004)	(213)	(1,527)	(98)
Commonwealth Edison Co [Member] \| Derivative [Member] \| Interest Rate Swap [Member]
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]
Realized Investment Gains (Losses)	2	5	15	23
Commonwealth Edison Co [Member] \| Fair Value, Inputs, Level 3 [Member] \| Derivative [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Beginning Balance	(265)	(318)	(301)	(301)
Total realized / unrealized gains (losses)
Included in net income	0	0	0	0
Included in noncurrent payables to affiliates	0	0	0	0
Included in regulatory assets	51	14	87	(3)
Change in collateral	0	0	0	0
Purchases, sales, issuances and settlements
Purchases	0	0	0	0
Sales	0	0	0	0
Settlements	0	0	0	0
Transfers into Level 3	0		0	0
Transfers out of Level 3	0	0	0	0
Ending Balance	(214)	(304)	(214)	(304)
Fair Value, Asset, Recurring Basis, Still Held, Unrealized Gain (Loss)	0	0	0	0
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Period Increase (Decrease)	(49)	(9)	(72)	26
Pepco Holdings LLC [Member] \| Fair Value, Inputs, Level 3 [Member] \| 6311 Life Insurance [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Beginning Balance	34	43	34	41
Total realized / unrealized gains (losses)
Included in net income	0	(12)	2	(10)
Included in noncurrent payables to affiliates	0	0	0	0
Included in regulatory assets	0	0	0	0
Change in collateral	0	0	0	0
Purchases, sales, issuances and settlements
Purchases	0	0	0	0
Sales	0	0	0	0
Settlements	0	3	(2)	3
Transfers into Level 3	0		0	0
Transfers out of Level 3	0	0	0	0
Ending Balance	34	34	34	34
Fair Value, Asset, Recurring Basis, Still Held, Unrealized Gain (Loss)	0	(12)	2	(10)
Potomac Electric Power Company [Member] \| Fair Value, Inputs, Level 3 [Member] \| 6311 Life Insurance [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Beginning Balance	34	43	34	41
Total realized / unrealized gains (losses)
Included in net income	0	(12)	2	(10)
Included in noncurrent payables to affiliates	0	0	0	0
Included in regulatory assets	0	0	0	0
Change in collateral	0	0	0	0
Purchases, sales, issuances and settlements
Purchases	0	0	0	0
Sales	0	0	0	0
Settlements	0	3	(2)	3
Transfers into Level 3	0		0	0
Transfers out of Level 3	0	0	0	0
Ending Balance	34	34	34	34
Fair Value, Asset, Recurring Basis, Still Held, Unrealized Gain (Loss)	$ 0	$ (12)	$ 2	$ (10)

Fair Value of Financial Assets and Liabilities - Fair Value Inputs Assets Quantitative Information (Details)	9 Months Ended	12 Months Ended
	Sep. 30, 2021 USD ($)	Dec. 31, 2020 USD ($)
Fair Value, Inputs, Level 3 [Member]
Derivatives Fair Value Footnotes [Abstract]
Cash Collateral Posted	$ (590,000,000)	$ 162,000,000
Fair Value, Inputs, Level 3 [Member] \| Economic Hedges [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	(1,257,000,000)	245,000,000
Fair Value, Inputs, Level 3 [Member] \| Derivative [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	$ (214,000,000)	$ (301,000,000)
Fair Value, Inputs, Level 3 [Member] \| Derivative [Member] \| Discounted Cash Flow [Member] \| Minimum [Member]
Fair Value Measurement Inputs and Valuation Techniques [Abstract]
Forward power price assets	9.77	2.25
Forward gas price assets	1.76	1.57
Derivative Asset (Liability) Net, Measurement Input	0.03	0.03
Forward heat rate	900.00%	800.00%
Fair Value Inputs Renewable Factor	95.00%	91.00%
Fair Value, Inputs, Level 3 [Member] \| Derivative [Member] \| Discounted Cash Flow [Member] \| Maximum [Member]
Fair Value Measurement Inputs and Valuation Techniques [Abstract]
Forward power price assets	301	163
Forward gas price assets	23.00	7.88
Derivative Asset (Liability) Net, Measurement Input	0.07	0.08
Forward heat rate	1000.00%	900.00%
Fair Value Inputs Renewable Factor	122.00%	123.00%
Fair Value, Inputs, Level 3 [Member] \| Derivative [Member] \| Discounted Cash Flow [Member] \| Arithmetic Average [Member]
Fair Value Measurement Inputs and Valuation Techniques [Abstract]
Forward power price assets	55	30
Forward gas price assets	4.16	2.59
Derivative Asset (Liability) Net, Measurement Input	0.0477	0.0493
Forward heat rate	913.00%	885.00%
Fair Value Inputs Renewable Factor	100.00%	99.00%
Fair Value, Inputs, Level 3 [Member] \| Derivative [Member] \| Option Model Valuation Technique [Member] \| Minimum [Member]
Fair Value Measurement Inputs and Valuation Techniques [Abstract]
Derivative Asset (Liability) Net, Measurement Input	0.35	0.11
Fair Value, Inputs, Level 3 [Member] \| Derivative [Member] \| Option Model Valuation Technique [Member] \| Maximum [Member]
Fair Value Measurement Inputs and Valuation Techniques [Abstract]
Derivative Asset (Liability) Net, Measurement Input	1.97	2.37
Fair Value, Inputs, Level 3 [Member] \| Derivative [Member] \| Option Model Valuation Technique [Member] \| Arithmetic Average [Member]
Fair Value Measurement Inputs and Valuation Techniques [Abstract]
Derivative Asset (Liability) Net, Measurement Input	0.49	0.32
Fair Value, Inputs, Level 3 [Member] \| Proprietary Trading [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	$ (14,000,000)	$ 23,000,000
Fair Value, Inputs, Level 3 [Member] \| Proprietary Trading [Member] \| Discounted Cash Flow [Member] \| Minimum [Member]
Fair Value Measurement Inputs and Valuation Techniques [Abstract]
Forward power price assets	16	10
Fair Value, Inputs, Level 3 [Member] \| Proprietary Trading [Member] \| Discounted Cash Flow [Member] \| Maximum [Member]
Fair Value Measurement Inputs and Valuation Techniques [Abstract]
Forward power price assets	156	106
Fair Value, Inputs, Level 3 [Member] \| Proprietary Trading [Member] \| Discounted Cash Flow [Member] \| Arithmetic Average [Member]
Fair Value Measurement Inputs and Valuation Techniques [Abstract]
Forward power price assets	53	27
Exelon Generation Co L L C [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	$ 2,554,000,000	$ 297,000,000
Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 3 [Member]
Derivatives Fair Value Footnotes [Abstract]
Cash Collateral Posted	(590,000,000)	162,000,000
Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 3 [Member] \| Economic Hedges [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	$ (1,257,000,000)	$ 245,000,000
Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 3 [Member] \| Derivative [Member] \| Discounted Cash Flow [Member] \| Minimum [Member]
Fair Value Measurement Inputs and Valuation Techniques [Abstract]
Forward power price assets	9.77	2.25
Forward gas price assets	1.76	1.57
Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 3 [Member] \| Derivative [Member] \| Discounted Cash Flow [Member] \| Maximum [Member]
Fair Value Measurement Inputs and Valuation Techniques [Abstract]
Forward power price assets	301	163
Forward gas price assets	23.00	7.88
Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 3 [Member] \| Derivative [Member] \| Discounted Cash Flow [Member] \| Arithmetic Average [Member]
Fair Value Measurement Inputs and Valuation Techniques [Abstract]
Forward power price assets	55	30
Forward gas price assets	4.16	2.59
Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 3 [Member] \| Derivative [Member] \| Option Model Valuation Technique [Member] \| Minimum [Member]
Fair Value Measurement Inputs and Valuation Techniques [Abstract]
Derivative Asset (Liability) Net, Measurement Input	0.35	0.11
Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 3 [Member] \| Derivative [Member] \| Option Model Valuation Technique [Member] \| Maximum [Member]
Fair Value Measurement Inputs and Valuation Techniques [Abstract]
Derivative Asset (Liability) Net, Measurement Input	1.97	2.37
Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 3 [Member] \| Derivative [Member] \| Option Model Valuation Technique [Member] \| Arithmetic Average [Member]
Fair Value Measurement Inputs and Valuation Techniques [Abstract]
Derivative Asset (Liability) Net, Measurement Input	0.49	0.32
Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 3 [Member] \| Proprietary Trading [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	$ (14,000,000)	$ 23,000,000
Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 3 [Member] \| Proprietary Trading [Member] \| Discounted Cash Flow [Member] \| Minimum [Member]
Fair Value Measurement Inputs and Valuation Techniques [Abstract]
Forward power price assets	16	10
Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 3 [Member] \| Proprietary Trading [Member] \| Discounted Cash Flow [Member] \| Maximum [Member]
Fair Value Measurement Inputs and Valuation Techniques [Abstract]
Forward power price assets	156	106
Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 3 [Member] \| Proprietary Trading [Member] \| Discounted Cash Flow [Member] \| Arithmetic Average [Member]
Fair Value Measurement Inputs and Valuation Techniques [Abstract]
Forward power price assets	53	27
Commonwealth Edison Co [Member] \| Fair Value, Inputs, Level 3 [Member] \| Derivative [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	$ (214,000,000)	$ (301,000,000)
Commonwealth Edison Co [Member] \| Fair Value, Inputs, Level 3 [Member] \| Derivative [Member] \| Discounted Cash Flow [Member] \| Minimum [Member]
Fair Value Measurement Inputs and Valuation Techniques [Abstract]
Derivative Asset (Liability) Net, Measurement Input	0.03	0.03
Forward heat rate	900.00%	800.00%
Fair Value Inputs Renewable Factor	95.00%	91.00%
Commonwealth Edison Co [Member] \| Fair Value, Inputs, Level 3 [Member] \| Derivative [Member] \| Discounted Cash Flow [Member] \| Maximum [Member]
Fair Value Measurement Inputs and Valuation Techniques [Abstract]
Derivative Asset (Liability) Net, Measurement Input	0.07	0.08
Forward heat rate	1000.00%	900.00%
Fair Value Inputs Renewable Factor	122.00%	123.00%
Commonwealth Edison Co [Member] \| Fair Value, Inputs, Level 3 [Member] \| Derivative [Member] \| Discounted Cash Flow [Member] \| Arithmetic Average [Member]
Fair Value Measurement Inputs and Valuation Techniques [Abstract]
Derivative Asset (Liability) Net, Measurement Input	0.0477	0.0493
Forward heat rate	913.00%	885.00%
Fair Value Inputs Renewable Factor	100.00%	99.00%

Commitments and Contingencies - Narrative (Details) $ in Millions		3 Months Ended	9 Months Ended	12 Months Ended
	Mar. 23, 2016 USD ($) MW	Dec. 31, 2020 USD ($)	Sep. 30, 2021 USD ($) MGPSite Open_claim MW	Dec. 31, 2022 MW	Dec. 31, 2018 MW	Dec. 31, 2017 MW	Mar. 31, 2021 USD ($)
Commitments And Contingencies Additional Narrative Information [Line Items]
Other Commitment			$ 3,621
Accrual for Environmental Loss Contingencies, Gross		$ 483	474
Liability for Asbestos and Environmental Claims, Gross		89	82
LDC Damages - Accrued Liability
Commitments And Contingencies Additional Narrative Information [Line Items]
LDC Damages			40
Exelon Generation Co L L C [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Other Commitment			3,049
Accrual for Environmental Loss Contingencies, Gross		121	119
Liability for Asbestos and Environmental Claims, Gross		89	82
Exelon Generation Co L L C [Member] \| LDC Damages
Commitments And Contingencies Additional Narrative Information [Line Items]
LDC Damages							$ 40
Exelon Generation Co L L C [Member] \| LDC Damages - Accrued Liability
Commitments And Contingencies Additional Narrative Information [Line Items]
LDC Damages			40
Commonwealth Edison Co [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Other Commitment			$ 224
Mgp Site Contingency Monitoring Count \| MGPSite			21
Accrual for Environmental Loss Contingencies, Gross		293	$ 284
Deferred Prosecution Agreement Payments		200
PECO Energy Co [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Other Commitment			$ 181
Mgp Site Contingency Monitoring Count \| MGPSite			6
Accrual for Environmental Loss Contingencies, Gross		23	$ 23
Baltimore Gas and Electric Company [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Other Commitment			$ 5
Mgp Site Contingency Monitoring Count \| MGPSite			4
Accrual for Environmental Loss Contingencies, Gross		2	$ 6
Pepco Holdings LLC [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Other Commitment			54
Accrual for Environmental Loss Contingencies, Gross		44	42
Potomac Electric Power Company [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Other Commitment			24
Accrual for Environmental Loss Contingencies, Gross		42	40
Delmarva Power and Light Company [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Other Commitment			$ 18
Mgp Site Contingency Monitoring Count \| MGPSite			1
Accrual for Environmental Loss Contingencies, Gross		$ 1	$ 1
Open Claims [Member] \| Exelon Generation Co L L C [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Liability for Asbestos and Environmental Claims, Gross			$ 19
Open Asbestos Related Personal Injury Claims \| Open_claim			211
Estimated Future Claims [Member] \| Exelon Generation Co L L C [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Liability for Asbestos and Environmental Claims, Gross			$ 63
Pepco Holdings Inc [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Other Commitment			513
Pepco Holdings Inc [Member] \| Pepco Holdings LLC [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Other Commitment			320
Pepco Holdings Inc [Member] \| Potomac Electric Power Company [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Other Commitment			120
Pepco Holdings Inc [Member] \| Delmarva Power and Light Company [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Other Commitment			89
West Lake [Member] \| Exelon Generation Co L L C [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Accrual for Environmental Loss Contingencies, Gross			290
West Lake [Member] \| Exelon Generation Co L L C [Member] \| Groundwater
Commitments And Contingencies Additional Narrative Information [Line Items]
Accrual for Environmental Loss Contingencies, Gross			40
West Lake [Member] \| Exelon Generation Co L L C [Member] \| Radioactive Residues Environmental Remediation
Commitments And Contingencies Additional Narrative Information [Line Items]
Accrual for Environmental Loss Contingencies, Component Amount			90
Other Solar Projects [Member] \| Pepco Holdings Inc [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Business Acquisition, Expected New Generation Mwh \| MW	37
Other Commitment	$ 135		$ 121
Other Non-Financial Commitment \| MW			33
Other Solar Projects [Member] \| Pepco Holdings Inc [Member] \| Generation Solar Business
Commitments And Contingencies Additional Narrative Information [Line Items]
Other Non-Financial Commitment \| MW			30
Other Solar Projects [Member] \| Pepco Holdings Inc [Member] \| Exelon Generation Co L L C [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Other Commitment			$ 121
Wind Assets [Member] \| Pepco Holdings Inc [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Other Non-Financial Commitment \| MW	100
Wind Assets [Member] \| Pepco Holdings Inc [Member] \| Delmarva Power and Light Company [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Purchase Commitment \| MW	120			40	40	40

Commitments and Contingencies - Merger Commitment (Details) $ in Millions	Sep. 30, 2021 USD ($)
Other Commitments [Line Items]
Other Commitment	$ 3,621
Pepco Holdings LLC [Member]
Other Commitments [Line Items]
Other Commitment	54
Potomac Electric Power Company [Member]
Other Commitments [Line Items]
Other Commitment	24
Delmarva Power and Light Company [Member]
Other Commitments [Line Items]
Other Commitment	18
Atlantic City Electric Company [Member]
Other Commitments [Line Items]
Other Commitment	12
Pepco Holdings Inc [Member]
Other Commitments [Line Items]
Other Commitment	513
Pepco Holdings Inc [Member] \| Remaining commitment
Other Commitments [Line Items]
Other Commitment	74
Pepco Holdings Inc [Member] \| Pepco Holdings LLC [Member]
Other Commitments [Line Items]
Other Commitment	320
Pepco Holdings Inc [Member] \| Pepco Holdings LLC [Member] \| Remaining commitment
Other Commitments [Line Items]
Other Commitment	62
Pepco Holdings Inc [Member] \| Potomac Electric Power Company [Member]
Other Commitments [Line Items]
Other Commitment	120
Pepco Holdings Inc [Member] \| Potomac Electric Power Company [Member] \| Remaining commitment
Other Commitments [Line Items]
Other Commitment	51
Pepco Holdings Inc [Member] \| Delmarva Power and Light Company [Member]
Other Commitments [Line Items]
Other Commitment	89
Pepco Holdings Inc [Member] \| Delmarva Power and Light Company [Member] \| Remaining commitment
Other Commitments [Line Items]
Other Commitment	7
Pepco Holdings Inc [Member] \| Atlantic City Electric Company [Member]
Other Commitments [Line Items]
Other Commitment	111
Pepco Holdings Inc [Member] \| Atlantic City Electric Company [Member] \| Remaining commitment
Other Commitments [Line Items]
Other Commitment	$ 4

Commitments and Contingencies - Schedule of Accruals for Environmental Matters (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Site Contingency [Line Items]
Total environmental investigation and remediation reserve	$ 474	$ 483
Exelon Generation Co L L C [Member]
Site Contingency [Line Items]
Total environmental investigation and remediation reserve	119	121
Commonwealth Edison Co [Member]
Site Contingency [Line Items]
Total environmental investigation and remediation reserve	284	293
PECO Energy Co [Member]
Site Contingency [Line Items]
Total environmental investigation and remediation reserve	23	23
Baltimore Gas and Electric Company [Member]
Site Contingency [Line Items]
Total environmental investigation and remediation reserve	6	2
Pepco Holdings LLC [Member]
Site Contingency [Line Items]
Total environmental investigation and remediation reserve	42	44
Potomac Electric Power Company [Member]
Site Contingency [Line Items]
Total environmental investigation and remediation reserve	40	42
Delmarva Power and Light Company [Member]
Site Contingency [Line Items]
Total environmental investigation and remediation reserve	1	1
Atlantic City Electric Company [Member]
Site Contingency [Line Items]
Total environmental investigation and remediation reserve	1	1
Manufactured Gas Plants [Member]
Site Contingency [Line Items]
Total environmental investigation and remediation reserve	310	314
Manufactured Gas Plants [Member] \| Exelon Generation Co L L C [Member]
Site Contingency [Line Items]
Total environmental investigation and remediation reserve	0	0
Manufactured Gas Plants [Member] \| Commonwealth Edison Co [Member]
Site Contingency [Line Items]
Total environmental investigation and remediation reserve	284	293
Manufactured Gas Plants [Member] \| PECO Energy Co [Member]
Site Contingency [Line Items]
Total environmental investigation and remediation reserve	21	21
Manufactured Gas Plants [Member] \| Baltimore Gas and Electric Company [Member]
Site Contingency [Line Items]
Total environmental investigation and remediation reserve	5	0
Manufactured Gas Plants [Member] \| Pepco Holdings LLC [Member]
Site Contingency [Line Items]
Total environmental investigation and remediation reserve	0	0
Manufactured Gas Plants [Member] \| Potomac Electric Power Company [Member]
Site Contingency [Line Items]
Total environmental investigation and remediation reserve	0	0
Manufactured Gas Plants [Member] \| Delmarva Power and Light Company [Member]
Site Contingency [Line Items]
Total environmental investigation and remediation reserve	0	0
Manufactured Gas Plants [Member] \| Atlantic City Electric Company [Member]
Site Contingency [Line Items]
Total environmental investigation and remediation reserve	$ 0	$ 0

Changes in Accumulated Other Comprehensive Income - Schedule of Changes in AOCI (Details) - USD ($) $ in Millions	3 Months Ended						9 Months Ended
	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Sep. 30, 2021	Sep. 30, 2020
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	$ 34,500	$ 34,313	$ 34,868	$ 34,871	$ 34,616	$ 34,573	$ 34,868	$ 34,573
Other comprehensive income	66	57	54	28	41	21	177	90
Ending balance	34,259	34,500	34,313	35,103	34,871	34,616	34,259	35,103
Gains (Losses) on Cash Flow Hedges
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	(5)		(5)	(3)		(2)	(5)	(2)
OCI before reclassifications	0			(1)			(1)	(2)
Amounts reclassified from AOCI	0			0			0	0
Other comprehensive income	0			(1)			(1)	(2)
Ending balance	(6)	(5)		(4)	(3)		(6)	(4)
Gains (Losses) on Cash Flow Hedges \| Total
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Ending balance	(5)						(5)
Pension and Non-Pension Postretirement Benefit Plan Items
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	(3,264)		(3,372)	(3,096)		(3,165)	(3,372)	(3,165)
OCI before reclassifications	14			(13)			15	(17)
Amounts reclassified from AOCI	55			39			163	112
Other comprehensive income	69			26			178	95
Ending balance	(3,194)	(3,264)		(3,070)	(3,096)		(3,194)	(3,070)
Pension and Non-Pension Postretirement Benefit Plan Items \| Total
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Ending balance	(3,195)						(3,195)
Foreign Currency Items
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	(20)		(23)	(33)		(27)	(23)	(27)
OCI before reclassifications	(3)			3			0	(3)
Amounts reclassified from AOCI	0			0			0	0
Other comprehensive income	(3)			3			0	(3)
Ending balance	(23)	(20)		(30)	(33)		(23)	(30)
Total
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	(3,289)	(3,346)	(3,400)	(3,132)	(3,173)	(3,194)	(3,400)	(3,194)
OCI before reclassifications	11			(11)			14	(22)
Amounts reclassified from AOCI	55			39			163	112
Other comprehensive income	66	57	54	28	41	21	177	90
Ending balance	$ (3,223)	$ (3,289)	$ (3,346)	$ (3,104)	$ (3,132)	$ (3,173)	$ (3,223)	$ (3,104)

Changes in Accumulated Other Comprehensive Income - Income Taxes Allocated to Other Comprehensive Income (Loss) Components (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Prior service costs
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), Tax	$ 1	$ 4	$ 3	$ 12
Actuarial losses
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), Tax	(19)	(16)	(57)	(50)
Pension and Non-Pension Postretirement Benefit Plan Items
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), Tax	$ (7)	$ 3	$ (8)	$ 6

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

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Variable Interest Entities - Narrative (Details) - USD ($) $ in Millions	Sep. 30, 2021	Aug. 06, 2021	Dec. 31, 2020	Apr. 01, 2014
Variable Interest Entity [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	$ 75
Distributed Energy Company [Member]
Variable Interest Entity [Line Items]
Equity Method Investment, Ownership Percentage	90.00%		90.00%
VIE Distributed Energy Company
Variable Interest Entity [Line Items]
Equity Method Investment, Ownership Percentage	90.00%		90.00%
CENG [Member]
Variable Interest Entity [Line Items]
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners	49.99%	49.99%	49.99%
CENG [Member]
Variable Interest Entity [Line Items]
Equity Method Investment, Ownership Percentage	50.01%	50.01%	50.01%
CENG [Member] \| Payment Guarantee [Member]
Variable Interest Entity [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted				$ 245
CENG [Member] \| Financial Guarantee [Member]
Variable Interest Entity [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted				$ 165
EGRP [Member]
Variable Interest Entity [Line Items]
Equity Method Investment, Ownership Percentage	51.00%		51.00%
Antelope Valley [Member]
Variable Interest Entity [Line Items]
Equity Method Investment, Ownership Percentage	100.00%		100.00%
Distributed Energy Company [Member]
Variable Interest Entity [Line Items]
Equity Method Investment, Ownership Percentage	31.00%		31.00%
NER [Member]
Variable Interest Entity [Line Items]
Equity Method Investment, Ownership Percentage	100.00%		100.00%
Exelon Generation Co L L C [Member] \| Distributed Energy Company [Member]
Variable Interest Entity [Line Items]
Equity Method Investment, Ownership Percentage	90.00%		90.00%
Exelon Generation Co L L C [Member] \| VIE Distributed Energy Company
Variable Interest Entity [Line Items]
Equity Method Investment, Ownership Percentage	90.00%		90.00%
Exelon Generation Co L L C [Member] \| CENG [Member]
Variable Interest Entity [Line Items]
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners	49.99%	49.99%	49.99%
Exelon Generation Co L L C [Member] \| CENG [Member]
Variable Interest Entity [Line Items]
Equity Method Investment, Ownership Percentage	50.01%	50.01%	50.01%
Guarantor Obligations, Current Carrying Value	$ 688
Exelon Generation Co L L C [Member] \| EGRP [Member]
Variable Interest Entity [Line Items]
Equity Method Investment, Ownership Percentage	51.00%		51.00%
Exelon Generation Co L L C [Member] \| EGRP [Member] \| Solar project entities [Member]
Variable Interest Entity [Line Items]
Equity Method Investment, Ownership Percentage	100.00%
Exelon Generation Co L L C [Member] \| EGRP [Member] \| Wind project entities [Member]
Variable Interest Entity [Line Items]
Equity Method Investment, Ownership Percentage	100.00%
Exelon Generation Co L L C [Member] \| Antelope Valley [Member]
Variable Interest Entity [Line Items]
Equity Method Investment, Ownership Percentage	100.00%		100.00%
Exelon Generation Co L L C [Member] \| Distributed Energy Company [Member]
Variable Interest Entity [Line Items]
Equity Method Investment, Ownership Percentage	31.00%		31.00%
Exelon Generation Co L L C [Member] \| NER [Member]
Variable Interest Entity [Line Items]
Equity Method Investment, Ownership Percentage	100.00%		100.00%

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

Sep. 30, 2021

Dec. 31, 2020

Sep. 30, 2020

Dec. 31, 2019

$ 2,957

$ 663

$ 1,858

$ 587

473

438

485

358

3,121

3,231

1,475

1,425

958

1,665

1,609

14,877

12,562

82,852

82,584

15,404

14,464

265

294

2,818

2,982

^[1]

132,621

129,317

3,375

1,819

3,694

3,562

1,949

2,078

100

375

1,180

1,264

15,826

12,771

35,269

35,093

12,907

12,300

169

238

2,850

2,942

Variable Interest Entity, Primary Beneficiary [Member]

^[1]

98,362

94,449

148

244

101

517

674

669

1,370

2,052

5,803

3,007

210

249

2,284

9,111

2,953

10,481

105

270

832

889

149

2,318

129

984

3,336

Unrestricted Assets [Member] | Variable Interest Entity, Primary Beneficiary [Member]

1,089

3,606

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

210

249

Other Assets

1,957

226

623

303

100

146

1,328

1,298

998

978

958

1,319

1,357

8,587

6,947

19,574

22,214

15,404

14,464

265

293

1,589

1,826

^[2]

48,010

48,094

1,216

197

1,612

1,253

691

788

375

347

444

7,796

5,219

4,593

5,566

12,635

12,054

1,224

1,308

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

^[2]

35,975

33,418

148

244

101

513

669

660

1,362

2,052

5,803

3,007

210

249

2,275

9,101

2,935

10,463

244

832

889

149

2,318

129

984

3,336

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

1,079

3,580

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

210

249

Other Assets

111

196

131

566

525

207

198

1,690

1,599

16,163

15,377

283

307

^[3]

24,502

23,736

405

347

479

539

300

299

154

141

2,015

2,154

7,077

6,659

168

235

589

622

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

^[3]

13,861

13,692

Atlantic City Electric Company [Member]

$ 4

$ 2

184

124

376

326

3,649

3,475

^[4]

4,532

4,286

261

146

177

528

780

1,502

1,152

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

^[4]

2,977

2,895

$ 6

$ 21

[1]	Exelon’s consolidated assets include $2,722 million and $10,200 million at September 30, 2021 and December 31, 2020, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $1,088 million and $3,598 million at September 30, 2021 and December 31, 2020, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 17 — Variable Interest Entities for additional information.
[2]	Generation’s consolidated assets include $2,704 million and $10,182 million at September 30, 2021 and December 31, 2020, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $1,078 million and $3,572 million at September 30, 2021 and December 31, 2020, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 17 — Variable Interest Entities for additional information.
[3]	PHI’s consolidated total assets include $18 million at both September 30, 2021 and December 31, 2020 of PHI's consolidated VIE that can only be used to settle the liabilities of the VIE. PHI’s consolidated total liabilities include $10 million and $26 million at September 30, 2021 and December 31, 2020, respectively, of PHI's consolidated VIE for which the VIE creditors do not have recourse to PHI. See Note 17 — Variable Interest Entities for additional information.
[4]	ACE’s consolidated total assets include $14 million and $13 million at September 30, 2021 and December 31, 2020, respectively, of ACE's consolidated VIE that can only be used to settle the liabilities of the VIE. ACE’s consolidated total liabilities include $6 million and $21 million at September 30, 2021 and December 31, 2020, respectively, of ACE's consolidated VIE for which the VIE creditors do not have recourse to ACE. See Note 17 — Variable Interest Entities for additional information.

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

Sep. 30, 2021

Dec. 31, 2020

^[1]

$ 132,621

$ 129,317

Variable Interest Entity, Not Primary Beneficiary [Member]

^[1]

98,362

94,449

1,151

1,178

289

284

143

157

719

737

^[2]

48,010

48,094

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

^[2]

35,975

33,418

1,151

1,178

289

284

143

157

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

719

737

781

777

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

701

716

781

777

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

701

716

370

401

209

223

143

157

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

370

401

209

223

143

157

$ 18

$ 21

[1]

Exelon’s consolidated assets include $2,722 million and $10,200 million at September 30, 2021 and December 31, 2020, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $1,088 million and $3,598 million at September 30, 2021 and December 31, 2020, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 17 — Variable Interest Entities for additional information.

[2]

Generation’s consolidated assets include $2,704 million and $10,182 million at September 30, 2021 and December 31, 2020, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $1,078 million and $3,572 million at September 30, 2021 and December 31, 2020, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 17 — Variable Interest Entities for additional information.

Sum of the carrying amounts as of the balance sheet date of all assets that are recognized. Assets are probable future economic benefits obtained or controlled by an entity as a result of past transactions or events.

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