View Filing Data

$ (80)

$ (25)

$ (98)

$ (41)

8,929

9,403

26,096

27,170

2,072

2,346

6,419

7,036

1,083

1,105

3,237

3,284

452

469

1,316

1,342

7,559

8,252

22,703

24,036

(17)

(5)

1,353

1,146

3,412

3,189

(403)

(387)

(1,202)

(1,119)

(6)

(19)

158

194

837

212

(251)

(199)

(384)

(926)

1,102

947

3,028

2,263

Equity in losses of unconsolidated affiliates

172

137

626

262

(170)

(10)

(182)

(22)

Net income attributable to noncontrolling interests

760

800

2,220

1,979

(12)

121

Net income (loss) attributable to common shareholders

772

733

2,164

1,858

Other comprehensive income (loss), net of income taxes

Prior service benefit reclassified to periodic benefit cost

(16)

(17)

(49)

(50)

Actuarial loss reclassified to periodic benefit cost

111

186

Pension and non-pension postretirement benefit plan valuation adjustment

(32)

Unrealized (loss) gain on cash flow hedges

Unrealized (loss) gain on investments in unconsolidated affiliates

Unrealized gain (loss) on foreign currency translation

(2)

(4)

Other comprehensive income

169

Comprehensive (loss) income attributable to noncontrolling interests

790

852

2,253

2,148

(9)

123

Comprehensive income attributable to common shareholders/membership interest

$ 799

$ 785

$ 2,196

$ 2,025

Average shares of common stock outstanding:

Basic average shares of common stock outstanding

973

968

972

967

Assumed exercise and/or distributions of stock-based awards

Diluted average shares of common stock outstanding

^[1]

974

970

973

969

Earnings per average common share:

Basic earnings per average common share

$ 0.79

$ 0.76

$ 2.23

$ 1.92

Diluted earnings per average common share

$ 0.79

$ 0.76

$ 2.22

$ 1.92

Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount

$ 275

$ 308

$ 844

$ 979

4,774

5,278

14,280

15,368

947

1,218

3,131

3,643

140

152

439

483

407

468

1,221

1,383

129

143

394

414

4,274

4,961

13,333

14,475

(18)

(6)

482

311

962

941

(101)

(93)

(310)

(278)

(8)

(26)

(27)

128

179

729

164

393

(141)

501

389

1,355

800

Equity in losses of unconsolidated affiliates

388

110

(170)

(11)

(183)

(23)

Net income attributable to noncontrolling interests

244

300

784

667

(13)

120

Net income attributable to membership interest

257

234

728

547

Other comprehensive income (loss), net of income taxes

Unrealized (loss) gain on cash flow hedges

Unrealized (loss) gain on investments in unconsolidated affiliates

Unrealized gain (loss) on foreign currency translation

(2)

(4)

Other comprehensive income

Comprehensive (loss) income attributable to noncontrolling interests

247

302

787

678

(10)

122

Comprehensive income attributable to common shareholders/membership interest

257

236

730

556

Commonwealth Edison Co [Member]

(56)

(15)

(98)

(27)

1,583

1,598

4,342

4,508

123

270

421

267

276

771

785

196

189

259

237

767

696

228

238

1,256

1,275

3,431

3,610

328

323

915

903

(87)

(82)

(258)

(251)

(4)

(3)

(10)

(83)

(78)

(241)

(240)

245

674

663

130

140

Other comprehensive income (loss), net of income taxes

200

193

544

523

200

193

544

523

PECO Energy Co [Member]

(11)

(16)

778

757

2,333

2,275

122

182

184

531

572

112

114

247

224

126

125

595

603

1,783

1,853

183

154

550

423

(30)

(28)

(91)

(85)

(3)

(4)

(9)

(11)

(29)

(30)

(89)

(92)

154

124

461

331

(2)

(5)

Other comprehensive income (loss), net of income taxes

140

126

410

336

Baltimore Gas and Electric Company [Member]

140

126

410

336

(5)

(6)

(23)

703

731

2,327

2,369

196

195

157

144

451

462

118

116

116

110

368

358

195

188

612

628

1,936

2,005

103

391

365

(31)

(27)

(89)

(78)

(24)

(22)

(71)

(64)

320

301

Other comprehensive income (loss), net of income taxes

261

242

261

242

(9)

(5)

1,380

1,361

3,700

3,688

254

268

254

261

706

751

105

106

193

192

562

555

122

123

342

343

1,124

1,116

3,106

3,165

256

245

594

523

(66)

(65)

(197)

(193)

(53)

(54)

(158)

(160)

203

191

436

363

Equity in losses of unconsolidated affiliates

Other comprehensive income (loss), net of income taxes

189

187

412

336

Comprehensive income attributable to common shareholders/membership interest

189

187

412

336

Potomac Electric Power Company [Member]

(3)

(4)

642

628

1,748

1,708

188

143

208

216

156

167

281

286

104

286

288

515

516

1,444

1,454

127

112

304

254

(33)

(32)

(100)

(96)

(24)

(25)

(78)

(73)

103

226

181

(2)

Other comprehensive income (loss), net of income taxes

217

174

Delmarva Power and Light Company [Member]

217

174

(6)

319

328

987

1,001

103

127

137

113

119

138

135

268

277

820

859

167

142

(15)

(45)

(42)

(13)

(35)

132

107

Other comprehensive income (loss), net of income taxes

116

Atlantic City Electric Company [Member]

116

(1)

(4)

419

406

966

981

142

146

104

114

107

340

322

838

847

128

134

(15)

(16)

(44)

(48)

(14)

(15)

(39)

(46)

Other comprehensive income (loss), net of income taxes

Generation commodities and services

Revenue from Contract with Customer, Including Assessed Tax

4,499

4,971

13,436

14,387

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

2,648

2,977

8,142

8,542

Revenue from Contract with Customer, Including Assessed Tax

4,499

4,970

13,436

14,389

Rate-regulated utility revenues

2,648

2,977

8,141

8,542

Revenue from Contract with Customer, Including Assessed Tax

4,510

4,457

12,758

12,824

Electricity, US Regulated | Commonwealth Edison Co [Member]

1,304

1,355

3,589

3,832

Revenue from Contract with Customer, Including Assessed Tax

1,635

1,609

4,427

4,512

Electricity, US Regulated | PECO Energy Co [Member]

494

496

1,199

1,281

Revenue from Contract with Customer, Including Assessed Tax

726

697

1,914

1,886

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

185

215

461

576

Revenue from Contract with Customer, Including Assessed Tax

623

652

1,814

1,847

Electricity, US Regulated | Pepco Holdings LLC [Member]

159

183

480

510

Revenue from Contract with Customer, Including Assessed Tax

1,365

1,340

3,570

3,541

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

428

415

1,086

1,077

Revenue from Contract with Customer, Including Assessed Tax

643

630

1,733

1,697

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

116

131

325

354

Revenue from Contract with Customer, Including Assessed Tax

304

302

872

861

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

105

298

258

Revenue from Contract with Customer, Including Assessed Tax

417

406

964

983

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

207

188

463

465

Revenue from Contract with Customer, Including Assessed Tax

431

382

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

184

148

Revenue from Contract with Customer, Including Assessed Tax

484

527

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

128

176

Revenue from Contract with Customer, Including Assessed Tax

115

129

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

Revenue from Contract with Customer, Including Assessed Tax

116

129

$ 8

$ 11

$ 51

$ 64

[1]

The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was immaterial for the three and nine months ended September 30, 2019 and approximately 2 million and 3 million for the three and nine months ended September 30, 2018, respectively.

Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018
Cash flows from operating activities
Net income	$ 2,220	$ 1,979
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization	4,393	4,511
Asset impairments	174	49
Gain on sales of assets and businesses	(15)	(55)
Deferred income taxes and amortization of investment tax credits	412	97
Net fair value changes related to derivatives	96	67
Net realized and unrealized gains on NDT funds	(467)	(21)
Other non-cash operating activities	460	804
Changes in assets and liabilities:
Accounts receivable	445	(167)
Inventories	(94)	(24)
Accounts payable and accrued expenses	(671)	84
Option premiums received (paid), net	13	(36)
Collateral (posted) received, net	(254)	222
Income taxes	143	166
Pension and non-pension postretirement benefit contributions	(377)	(362)
Other assets and liabilities	(1,079)	(639)
Net cash flows provided by operating activities	5,399	6,675
Cash flows from investing activities
Capital expenditures	(5,259)	(5,497)
Proceeds from NDT fund sales	8,443	6,379
Investment in NDT funds	(8,437)	(6,553)
Acquisition of assets and businesses, net	0	(57)
Proceeds from sales of assets and businesses	17	90
Other investing activities	21	29
Net cash flows used in investing activities	(5,215)	(5,609)
Cash flows from financing activities
Changes in short-term borrowings	430	(218)
Proceeds from short-term borrowings with maturities greater than 90 days	0	126
Repayments on short-term borrowings with maturities greater than 90 days	(125)	(1)
Issuance of long-term debt	1,576	2,664
Retirement of long-term debt	(644)	(1,480)
Dividends paid on common stock	(1,055)	(999)
Proceeds from employee stock plans	94	67
Other financing activities	(63)	(94)
Net cash flows provided by (used in) financing activities	213	65
Increase (Decrease) in cash, cash equivalents and restricted cash	397	1,131
Cash, cash equivalents and restricted cash at beginning of period	1,781	1,190
Cash, cash equivalents and restricted cash at end of period	2,178	2,321
Supplemental Cash Flow Information
Increase (decrease) in capital expenditures not paid	(96)	(175)
Increase in PPE related to ARO update	344	67
Exelon Generation Co L L C [Member]
Cash flows from operating activities
Net income	784	667
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization	2,377	2,608
Asset impairments	174	49
Gain on sales of assets and businesses	(15)	(48)
Deferred income taxes and amortization of investment tax credits	201	(278)
Net fair value changes related to derivatives	102	73
Net realized and unrealized gains on NDT funds	(467)	(21)
Other non-cash operating activities	(95)	187
Changes in assets and liabilities:
Accounts receivable	395	126
Receivables from and payables to affiliates, net	(12)	(7)
Inventories	(36)	(10)
Accounts payable and accrued expenses	(428)	(59)
Option premiums received (paid), net	13	(36)
Collateral (posted) received, net	(292)	228
Income taxes	327	220
Pension and non-pension postretirement benefit contributions	(165)	(134)
Other assets and liabilities	(390)	(154)
Net cash flows provided by operating activities	2,473	3,411
Cash flows from investing activities
Capital expenditures	(1,282)	(1,660)
Proceeds from NDT fund sales	8,443	6,379
Investment in NDT funds	(8,437)	(6,553)
Acquisition of assets and businesses, net	0	(57)
Proceeds from sales of assets and businesses	17	90
Other investing activities	(6)	(5)
Net cash flows used in investing activities	(1,265)	(1,806)
Cash flows from financing activities
Issuance of long-term debt	41	14
Retirement of long-term debt	(196)	(100)
Changes in Exelon/PHI intercompany money pool	(100)	(54)
Distributions to member	(674)	(688)
Contributions from member	0	54
Other financing activities	(37)	(46)
Net cash flows provided by (used in) financing activities	(966)	(820)
Increase (Decrease) in cash, cash equivalents and restricted cash	242	785
Cash, cash equivalents and restricted cash at beginning of period	903	554
Cash, cash equivalents and restricted cash at end of period	1,145	1,339
Supplemental Cash Flow Information
Increase (decrease) in capital expenditures not paid	(24)	(226)
Increase in PPE related to ARO update	342	47
Commonwealth Edison Co [Member]
Cash flows from operating activities
Net income	544	523
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization	767	696
Deferred income taxes and amortization of investment tax credits	115	214
Other non-cash operating activities	180	187
Changes in assets and liabilities:
Accounts receivable	(38)	(190)
Receivables from and payables to affiliates, net	(27)	8
Inventories	(16)	4
Accounts payable and accrued expenses	(132)	(38)
Collateral (posted) received, net	43	(10)
Income taxes	25	(65)
Pension and non-pension postretirement benefit contributions	(71)	(41)
Other assets and liabilities	(245)	(170)
Net cash flows provided by operating activities	1,145	1,118
Cash flows from investing activities
Capital expenditures	(1,413)	(1,540)
Other investing activities	25	22
Net cash flows used in investing activities	(1,388)	(1,518)
Cash flows from financing activities
Changes in short-term borrowings	387	0
Issuance of long-term debt	400	1,350
Retirement of long-term debt	(300)	(840)
Contributions from parent	187	387
Dividends paid on common stock	(380)	(345)
Other financing activities	(10)	(16)
Net cash flows provided by (used in) financing activities	284	536
Increase (Decrease) in cash, cash equivalents and restricted cash	41	136
Cash, cash equivalents and restricted cash at beginning of period	330	144
Cash, cash equivalents and restricted cash at end of period	371	280
Supplemental Cash Flow Information
Increase (decrease) in capital expenditures not paid	(52)	(28)
PECO Energy Co [Member]
Cash flows from operating activities
Net income	410	336
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization	247	224
Gain on sales of assets and businesses	0	(1)
Deferred income taxes and amortization of investment tax credits	6	5
Other non-cash operating activities	28	41
Changes in assets and liabilities:
Accounts receivable	46	(85)
Receivables from and payables to affiliates, net	(12)	1
Inventories	(3)	(13)
Accounts payable and accrued expenses	(32)	(1)
Income taxes	(15)	(16)
Pension and non-pension postretirement benefit contributions	(26)	(25)
Other assets and liabilities	(111)	26
Net cash flows provided by operating activities	538	492
Cash flows from investing activities
Capital expenditures	(675)	(615)
Other investing activities	7	6
Net cash flows used in investing activities	(668)	(609)
Cash flows from financing activities
Issuance of long-term debt	325	700
Retirement of long-term debt	0	(500)
Contributions from parent	174	71
Dividends paid on common stock	(268)	(300)
Other financing activities	(6)	(22)
Net cash flows provided by (used in) financing activities	225	(51)
Increase (Decrease) in cash, cash equivalents and restricted cash	95	(168)
Cash, cash equivalents and restricted cash at beginning of period	135	275
Cash, cash equivalents and restricted cash at end of period	230	107
Supplemental Cash Flow Information
Increase (decrease) in capital expenditures not paid	42	4
Baltimore Gas and Electric Company [Member]
Cash flows from operating activities
Net income	261	242
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization	368	358
Deferred income taxes and amortization of investment tax credits	66	82
Other non-cash operating activities	63	42
Changes in assets and liabilities:
Accounts receivable	110	72
Receivables from and payables to affiliates, net	(14)	(4)
Inventories	(5)	(8)
Accounts payable and accrued expenses	(28)	(3)
Collateral (posted) received, net	(5)	1
Income taxes	(43)	(48)
Pension and non-pension postretirement benefit contributions	(45)	(50)
Other assets and liabilities	(65)	(9)
Net cash flows provided by operating activities	663	675
Cash flows from investing activities
Capital expenditures	(842)	(667)
Other investing activities	4	8
Net cash flows used in investing activities	(838)	(659)
Cash flows from financing activities
Changes in short-term borrowings	(35)	(77)
Issuance of long-term debt	400	300
Contributions from parent	104	18
Dividends paid on common stock	(169)	(157)
Other financing activities	(7)	(2)
Net cash flows provided by (used in) financing activities	293	82
Increase (Decrease) in cash, cash equivalents and restricted cash	118	98
Cash, cash equivalents and restricted cash at beginning of period	13	18
Cash, cash equivalents and restricted cash at end of period	131	116
Supplemental Cash Flow Information
Increase (decrease) in capital expenditures not paid	6	44
Pepco Holdings LLC [Member]
Cash flows from operating activities
Net income	412	336
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization	562	555
Deferred income taxes and amortization of investment tax credits	8	50
Other non-cash operating activities	122	109
Changes in assets and liabilities:
Accounts receivable	(64)	(89)
Receivables from and payables to affiliates, net	1	10
Inventories	(36)	0
Accounts payable and accrued expenses	0	115
Income taxes	(11)	(31)
Pension and non-pension postretirement benefit contributions	(15)	(66)
Other assets and liabilities	(102)	(144)
Net cash flows provided by operating activities	877	845
Cash flows from investing activities
Capital expenditures	(1,006)	(988)
Other investing activities	3	2
Net cash flows used in investing activities	(1,003)	(986)
Cash flows from financing activities
Changes in short-term borrowings	78	(141)
Proceeds from short-term borrowings with maturities greater than 90 days	0	125
Repayments on short-term borrowings with maturities greater than 90 days	(125)	0
Issuance of long-term debt	410	300
Retirement of long-term debt	(130)	(33)
Changes in Exelon/PHI intercompany money pool	10	10
Distributions to member	(429)	(232)
Contributions from member	283	237
Other financing activities	(5)	(6)
Net cash flows provided by (used in) financing activities	92	260
Increase (Decrease) in cash, cash equivalents and restricted cash	(34)	119
Cash, cash equivalents and restricted cash at beginning of period	186	95
Cash, cash equivalents and restricted cash at end of period	152	214
Supplemental Cash Flow Information
Increase (decrease) in capital expenditures not paid	(62)	54
Potomac Electric Power Company [Member]
Cash flows from operating activities
Net income	217	174
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization	281	286
Deferred income taxes and amortization of investment tax credits	12	(5)
Other non-cash operating activities	43	42
Changes in assets and liabilities:
Accounts receivable	(49)	(36)
Receivables from and payables to affiliates, net	4	(9)
Inventories	(23)	6
Accounts payable and accrued expenses	(12)	104
Income taxes	(23)	(18)
Pension and non-pension postretirement benefit contributions	(10)	(11)
Other assets and liabilities	(55)	(137)
Net cash flows provided by operating activities	385	396
Cash flows from investing activities
Capital expenditures	(455)	(475)
Other investing activities	2	3
Net cash flows used in investing activities	(453)	(472)
Cash flows from financing activities
Changes in short-term borrowings	(28)	38
Issuance of long-term debt	260	100
Retirement of long-term debt	(118)	(8)
Contributions from parent	129	85
Dividends paid on common stock	(173)	(128)
Other financing activities	(3)	(4)
Net cash flows provided by (used in) financing activities	67	83
Increase (Decrease) in cash, cash equivalents and restricted cash	(1)	7
Cash, cash equivalents and restricted cash at beginning of period	53	40
Cash, cash equivalents and restricted cash at end of period	52	47
Supplemental Cash Flow Information
Increase (decrease) in capital expenditures not paid	(7)	15
Delmarva Power and Light Company [Member]
Cash flows from operating activities
Net income	116	90
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization	138	135
Deferred income taxes and amortization of investment tax credits	(2)	24
Other non-cash operating activities	21	16
Changes in assets and liabilities:
Accounts receivable	29	13
Receivables from and payables to affiliates, net	(7)	(14)
Inventories	(7)	(3)
Accounts payable and accrued expenses	3	18
Income taxes	11	0
Pension and non-pension postretirement benefit contributions	(1)	0
Other assets and liabilities	(22)	13
Net cash flows provided by operating activities	279	292
Cash flows from investing activities
Capital expenditures	(245)	(254)
Other investing activities	1	1
Net cash flows used in investing activities	(244)	(253)
Cash flows from financing activities
Changes in short-term borrowings	57	(216)
Issuance of long-term debt	0	200
Retirement of long-term debt	0	(4)
Contributions from parent	0	150
Dividends paid on common stock	(105)	(58)
Other financing activities	0	(3)
Net cash flows provided by (used in) financing activities	(48)	69
Increase (Decrease) in cash, cash equivalents and restricted cash	(13)	108
Cash, cash equivalents and restricted cash at beginning of period	24	2
Cash, cash equivalents and restricted cash at end of period	11	110
Supplemental Cash Flow Information
Increase (decrease) in capital expenditures not paid	(13)	20
Atlantic City Electric Company [Member]
Cash flows from operating activities
Net income	87	76
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization	114	107
Deferred income taxes and amortization of investment tax credits	2	24
Other non-cash operating activities	21	24
Changes in assets and liabilities:
Accounts receivable	(44)	(66)
Receivables from and payables to affiliates, net	(4)	(3)
Inventories	(4)	(2)
Accounts payable and accrued expenses	27	21
Income taxes	5	(3)
Pension and non-pension postretirement benefit contributions	0	(6)
Other assets and liabilities	(18)	(12)
Net cash flows provided by operating activities	186	160
Cash flows from investing activities
Capital expenditures	(300)	(247)
Other investing activities	0	(1)
Net cash flows used in investing activities	(300)	(248)
Cash flows from financing activities
Changes in short-term borrowings	49	37
Proceeds from short-term borrowings with maturities greater than 90 days	0	125
Repayments on short-term borrowings with maturities greater than 90 days	(125)	0
Issuance of long-term debt	150	0
Retirement of long-term debt	(13)	(22)
Contributions from parent	155	0
Dividends paid on common stock	(100)	(46)
Other financing activities	(1)	0
Net cash flows provided by (used in) financing activities	115	94
Increase (Decrease) in cash, cash equivalents and restricted cash	1	6
Cash, cash equivalents and restricted cash at beginning of period	30	31
Cash, cash equivalents and restricted cash at end of period	31	37
Supplemental Cash Flow Information
Increase (decrease) in capital expenditures not paid	$ (37)	$ 16

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

Sep. 30, 2019

Dec. 31, 2018

$ 1,683

$ 1,349

309

247

4,188

4,607

Mark-to-market derivative assets, current

1,085

1,256

601

804

Unamortized energy contract assets, current

325

334

1,458

1,351

1,194

1,222

Assets held for sale

904

1,296

1,238

12,206

13,360

78,593

76,707

Nuclear decommissioning trust funds

8,122

8,237

12,706

11,661

471

625

Mark-to-market derivative assets, noncurrent

6,677

487

452

Unamortized energy contract assets, noncurrent

353

372

3,123

1,575

31,939

29,599

^[1]

122,738

119,666

1,019

714

4,248

1,349

3,348

3,800

1,877

2,112

Mark-to-market derivative liabilities, current

400

644

239

475

Unamortized energy contract liabilities, current

138

149

Renewable energy credit obligation

375

344

Liabilities held for sale

777

1,425

1,035

13,085

11,404

Long-term debt to financing trusts

32,056

34,075

390

Deferred income taxes and unamortized investment tax credits

12,133

11,330

10,089

9,679

Pension obligations

3,712

3,988

Spent nuclear fuel obligation

2,029

1,928

1,193

1,171

Mark-to-market derivative liabilities, noncurrent

9,792

9,559

416

479

Unamortized energy contract liabilities, noncurrent

368

463

3,123

2,130

42,855

40,727

^[1]

88,386

86,596

19,238

19,116

Treasury stock, at cost

(123)

Accumulated other comprehensive loss, net

15,871

14,766

(2,963)

(2,995)

32,023

30,764

Noncontrolling Interests

2,329

2,306

Total equity

34,352

33,070

Variable Interest Entity, Consolidated, Assets, Pledged

122,738

119,666

9,465

9,667

Variable Interest Entity, Consolidated, Liabilities, No Recourse

3,517

3,548

1,019

750

126

153

2,587

2,941

Mark-to-market derivative assets, current

337

562

602

804

Unamortized energy contract assets, current

166

173

243

251

1,010

963

Assets held for sale

904

1,002

883

7,159

8,433

23,591

23,981

Nuclear decommissioning trust funds

12,706

11,661

248

414

Mark-to-market derivative assets, noncurrent

483

452

Unamortized energy contract assets, noncurrent

1,472

1,421

352

371

Deferred income taxes

1,915

755

17,234

15,142

^[2]

47,984

47,556

2,706

906

1,583

1,847

762

898

Borrowings from Exelon/PHI intercompany money pool

134

139

100

Mark-to-market derivative liabilities, current

212

449

Unamortized energy contract liabilities, current

Renewable energy credit obligation

374

343

Liabilities held for sale

777

541

279

6,344

5,769

Long-term debt to affiliates

5,018

6,989

889

898

Deferred income taxes and unamortized investment tax credits

3,607

3,383

9,855

9,450

Spent nuclear fuel obligation

885

900

1,193

1,171

Payables to affiliates, noncurrent

2,960

2,606

Mark-to-market derivative liabilities, noncurrent

163

252

Unamortized energy contract liabilities, noncurrent

1,466

610

20,140

18,392

^[2]

32,391

32,048

Accumulated other comprehensive loss, net

3,778

3,724

(36)

(38)

Membership interest

9,525

9,518

Total members' equity

13,267

13,204

Noncontrolling Interests

2,326

2,304

Total equity

15,593

15,508

Variable Interest Entity, Consolidated, Assets, Pledged

47,984

47,556

9,443

9,634

Variable Interest Entity, Consolidated, Liabilities, No Recourse

3,467

3,480

Commonwealth Edison Co [Member]

135

124

561

539

322

320

Inventories, net

162

148

286

293

1,606

1,570

22,795

22,058

1,436

1,307

Receivable from affiliates, noncurrent

2,625

2,487

2,217

1,020

1,035

351

395

7,925

7,585

32,326

31,213

387

500

300

520

607

275

373

119

116

111

Mark-to-market derivative liabilities, current

193

293

138

2,243

1,925

Long-term debt to financing trusts

7,696

7,801

205

Deferred income taxes and unamortized investment tax credits

4,016

3,813

120

118

185

201

Mark-to-market derivative liabilities, noncurrent

6,390

6,050

253

223

621

630

11,585

11,035

21,729

20,966

Retained deficit unappropriated

1,588

Other paid-in capital

7,509

7,322

(1,639)

Retained earnings appropriated

3,139

2,976

10,597

10,247

32,326

31,213

PECO Energy Co [Member]

224

130

286

321

118

151

843

782

9,100

8,610

540

460

Receivable from affiliates, noncurrent

473

389

367

349

1,436

1,250

11,379

10,642

382

370

113

175

722

809

Long-term debt to financing trusts

3,404

3,084

184

Deferred income taxes and unamortized investment tax credits

2,034

1,933

289

288

503

421

2,933

2,745

7,243

6,822

2,752

2,578

1,384

1,242

4,136

3,820

Baltimore Gas and Electric Company [Member]

11,379

10,642

130

242

353

110

180

177

751

786

8,796

8,243

386

398

276

279

757

687

10,304

9,716

245

295

165

155

120

665

774

3,270

2,876

Deferred income taxes and unamortized investment tax credits

1,329

1,222

198

201

1,158

1,192

112

2,819

2,712

6,754

6,362

1,818

1,714

1,732

1,640

3,550

3,354

10,304

9,716

124

512

453

189

177

203

163

479

489

1,578

1,533

13,968

13,446

2,095

2,312

135

130

4,005

426

486

Deferred income taxes

356

7,030

7,005

^[3]

22,576

21,984

132

179

118

125

416

496

279

256

Borrowings from Exelon/PHI intercompany money pool

118

116

Unamortized energy contract liabilities, current

117

119

152

123

1,515

1,592

6,376

6,134

Deferred income taxes and unamortized investment tax credits

2,289

2,146

103

Unamortized energy contract liabilities, noncurrent

1,725

1,864

357

442

610

369

5,137

4,976

^[3]

13,028

12,702

Membership interest

9,503

9,220

Total members' equity

9,548

9,282

Total equity

9,548

9,282

Variable Interest Entity, Consolidated, Assets, Pledged

22,576

21,984

Variable Interest Entity, Consolidated, Liabilities, No Recourse

Potomac Electric Power Company [Member]

258

225

114

Inventories, net

118

252

270

806

760

6,734

6,460

577

643

109

105

301

316

1,063

1,079

8,603

8,299

177

214

144

126

Merger related obligation

Current portion of DC PLUG obligation

564

628

2,852

2,704

Deferred income taxes and unamortized investment tax credits

1,150

1,064

749

822

311

275

2,274

2,227

5,690

5,559

1,765

1,636

1,148

1,104

2,913

2,740

Delmarva Power and Light Company [Member]

8,603

8,299

112

134

297

336

3,941

3,821

221

231

175

186

486

431

4,724

4,588

111

435

375

1,404

1,403

Deferred income taxes and unamortized investment tax credits

655

628

580

606

114

1,365

1,301

3,204

3,079

914

606

595

1,520

1,509

Atlantic City Electric Company [Member]

4,724

4,588

142

Inventories, net

307

240

3,124

2,966

370

386

485

493

^[4]

3,916

3,699

139

139

154

347

422

1,305

1,170

Deferred income taxes and unamortized investment tax credits

569

535

365

402

996

981

^[4]

2,648

2,573

1,134

979

134

147

1,268

1,126

Variable Interest Entity, Consolidated, Assets, Pledged

3,916

3,699

Variable Interest Entity, Consolidated, Liabilities, No Recourse

$ 46

$ 59

[1]	Exelon’s consolidated assets include $9,465 million and $9,667 million at September 30, 2019 and December 31, 2018, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $3,517 million and $3,548 million at September 30, 2019 and December 31, 2018, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 2 — Variable Interest Entities for additional information.
[2]	Generation’s consolidated assets include $9,443 million and $9,634 million at September 30, 2019 and December 31, 2018, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $3,467 million and $3,480 million at September 30, 2019 and December 31, 2018, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 2 — Variable Interest Entities for additional information.
[3]	PHI’s consolidated total assets include $22 million and $33 million at September 30, 2019 and December 31, 2018, respectively, of PHI's consolidated VIE that can only be used to settle the liabilities of the VIE. PHI’s consolidated total liabilities include $50 million and $69 million at September 30, 2019 and December 31, 2018, respectively, of PHI's consolidated VIE for which the VIE creditors do not have recourse to PHI. See Note 2 — Variable Interest Entities for additional information.
[4]	ACE’s consolidated total assets include $18 million and $23 million at September 30, 2019 and December 31, 2018, respectively, of ACE's consolidated VIE that can only be used to settle the liabilities of the VIE. ACE’s consolidated total liabilities include $46 million and $59 million at September 30, 2019 and December 31, 2018, respectively, of ACE's consolidated VIE for which the VIE creditors do not have recourse to ACE. See Note 2 — Variable Interest Entities for additional information.

Consolidated Balance Sheets (Unaudited) (Parenthetical) - USD ($) shares in Millions, $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Customer allowance for uncollectible accounts	$ 248	$ 283
Other allowance for uncollectible accounts	49	36
Accumulated depreciation and amortization	$ 23,590	$ 22,902
Common Stock, Shares Authorized	2,000	2,000
Common Stock, Shares, Outstanding	972	968
Treasury Stock, Shares held	2	2
Exelon Generation Co L L C [Member]
Customer allowance for uncollectible accounts	$ 75	$ 103
Other allowance for uncollectible accounts	1	1
Accumulated depreciation and amortization	11,972	12,206
Commonwealth Edison Co [Member]
Customer allowance for uncollectible accounts	65	61
Other allowance for uncollectible accounts	21	20
Accumulated depreciation and amortization	5,046	4,684
PECO Energy Co [Member]
Customer allowance for uncollectible accounts	54	53
Other allowance for uncollectible accounts	7	8
Accumulated depreciation and amortization	3,670	3,561
Baltimore Gas and Electric Company [Member]
Customer allowance for uncollectible accounts	13	16
Other allowance for uncollectible accounts	4	4
Accumulated depreciation and amortization	3,772	3,633
Pepco Holdings LLC [Member]
Customer allowance for uncollectible accounts	41	50
Other allowance for uncollectible accounts	16	3
Accumulated depreciation and amortization	1,124	841
Potomac Electric Power Company [Member]
Customer allowance for uncollectible accounts	16	20
Other allowance for uncollectible accounts	8	1
Accumulated depreciation and amortization	3,473	3,354
Delmarva Power and Light Company [Member]
Customer allowance for uncollectible accounts	10	12
Other allowance for uncollectible accounts	1	1
Accumulated depreciation and amortization	1,407	1,329
Atlantic City Electric Company [Member]
Customer allowance for uncollectible accounts	15	18
Other allowance for uncollectible accounts	5	1
Accumulated depreciation and amortization	$ 1,192	$ 1,137

Consolidated Statements of Changes in Shareholders Equity (Unaudited) - USD ($) shares in Thousands, $ in Millions	Total	Common Stock [Member]	Treasury Stock [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Noncontrolling Interest [Member]	Other Comprehensive Income (Loss) [Member]	Exelon Generation Co L L C [Member]	Exelon Generation Co L L C [Member] Membership Interest [Member]	Exelon Generation Co L L C [Member] Retained Earnings, Unappropriated/Undistributed [Member]	Exelon Generation Co L L C [Member] Accumulated Other Comprehensive Income (Loss) [Member]	Exelon Generation Co L L C [Member] Noncontrolling 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/Undistributed [Member]	Commonwealth Edison Co [Member] Retained Earnings, Appropriated	Commonwealth Edison Co [Member] Retained Earnings [Member]	PECO Energy Co [Member]	PECO Energy Co [Member] Common Stock [Member]	PECO Energy Co [Member] Retained Earnings [Member]	PECO Energy Co [Member] Accumulated Other Comprehensive Income (Loss) [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] Membership Interest [Member]	Pepco Holdings LLC [Member] Retained Earnings, Unappropriated/Undistributed [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, 2017	965,168
Beginning balance at Dec. 31, 2017	$ 32,187	$ 18,964	$ (123)	$ 14,081	$ (3,026)	$ 2,291
Beginning Balance at Dec. 31, 2017								$ 15,959	$ 9,357	$ 4,349	$ (37)	$ 2,290														$ 8,825	$ 8,835	$ (10)
Beginning Balance at Dec. 31, 2017													$ 9,542	$ 1,588	$ 6,822	$ (1,639)	$ 2,771		$ 3,577	$ 2,489	$ 1,087	$ 1	$ 3,141	$ 1,605	$ 1,536				$ 2,533	$ 1,470	$ 1,063	$ 1,335	$ 764	$ 571	$ 1,043	$ 912	$ 131
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	$ 636			585		51		186		136		50	165			165			113		113	0	128		128	65		65	31		31	31		31	7		7
Stock issued during period, shares, long-term incentive plan activity	1,685
Stock issued during period, value, long-term incentive plan activity	$ (3)	(3)	0	0	0	0
Stock issued during period, shares, employee stock purchase plan	361
Stock issued during period, value, employee stock purchase plan	$ 12	12	0	0	0	0
Changes in equity of noncontrolling interests	(9)					(9)		(9)				(9)
Common stock dividends	(334)			(334)									(114)				(114)		(287)		(287)		(52)		(52)				(25)		(25)	(36)		(36)	(9)		(9)
Contributions from parent													113		113
Distributions to member								(188)		(188)																(71)		(71)
Other comprehensive income (loss), net of income taxes					71	1	$ 72	7		0	6	1
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard	$ 4			14	(10)			3		6	(3)								0		1	(1)
Ending balance (in shares) at Mar. 31, 2018	967,214
Ending balance at Mar. 31, 2018	$ 32,565	18,973	(123)	14,346	(2,965)	2,334
Ending Balance at Mar. 31, 2018								15,958	9,357	4,303	(34)	2,332														8,819	8,835	(16)
Ending Balance at Mar. 31, 2018													9,706	1,588	6,935	(1,639)	2,822		3,403	2,489	914	0	3,217	1,605	1,612				2,539	1,470	1,069	1,330	764	566	1,041	912	129
Beginning balance (in shares) at Dec. 31, 2017	965,168
Beginning balance at Dec. 31, 2017	$ 32,187	18,964	(123)	14,081	(3,026)	2,291
Beginning Balance at Dec. 31, 2017								15,959	9,357	4,349	(37)	2,290														8,825	8,835	(10)
Beginning Balance at Dec. 31, 2017													9,542	1,588	6,822	(1,639)	2,771		3,577	2,489	1,087	1	3,141	1,605	1,536				2,533	1,470	1,063	1,335	764	571	1,043	912	131
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	1,979							667					523						336				242			336			174			90			76
Other comprehensive income (loss), net of income taxes	$ 169				167			11
Ending balance (in shares) at Sep. 30, 2018	968,842
Ending balance at Sep. 30, 2018	$ 33,388	19,063	(123)	14,949	(2,869)	2,368
Ending Balance at Sep. 30, 2018								15,960	9,411	4,214	(31)	2,366														9,166	9,072	94
Ending Balance at Sep. 30, 2018													10,107	1,588	7,209	(1,639)	2,949		3,684	2,560	1,124	0	3,244	1,623	1,621				2,664	1,555	1,109	1,517	914	603	1,073	912	161
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Appropriation of retained earnings for future dividends																(165)	165	$ 0
Beginning balance (in shares) at Mar. 31, 2018	967,214
Beginning balance at Mar. 31, 2018	$ 32,565	18,973	(123)	14,346	(2,965)	2,334
Beginning Balance at Mar. 31, 2018								15,958	9,357	4,303	(34)	2,332														8,819	8,835	(16)
Beginning Balance at Mar. 31, 2018													9,706	1,588	6,935	(1,639)	2,822		3,403	2,489	914	0	3,217	1,605	1,612				2,539	1,470	1,069	1,330	764	566	1,041	912	129
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	$ 542			539		3		181		178		3	164			164			96		96	0	51		51	84		84	54		54	26		26	8		8
Stock issued during period, shares, long-term incentive plan activity	183
Stock issued during period, value, long-term incentive plan activity	$ 20	20	0	0	0	0
Stock issued during period, shares, employee stock purchase plan	342
Stock issued during period, value, employee stock purchase plan	$ 15	15	0	0	0	0
Changes in equity of noncontrolling interests	(14)					(14)		(13)				(13)
Common stock dividends	$ (334)			(334)									(115)				(115)		(5)		(5)		(53)		(53)				(25)		(25)	(4)		(4)	(10)		(10)
Contributions from parent													112		112				41	41	0	0				235	235		85	85		150	150
Distributions to member								(189)		(189)																(38)		(38)
Other comprehensive income (loss), net of income taxes					44	1	45	2		0	1	1
Ending balance (in shares) at Jun. 30, 2018	967,739
Ending balance at Jun. 30, 2018	$ 32,839	19,008	(123)	14,551	(2,921)	2,324
Ending Balance at Jun. 30, 2018								15,939	9,357	4,292	(33)	2,323														9,100	9,070	30
Ending Balance at Jun. 30, 2018													9,867	1,588	7,047	(1,639)	2,871		3,535	2,530	1,005	0	3,215	1,605	1,610				2,653	1,555	1,098	1,502	914	588	1,039	912	127
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Appropriation of retained earnings for future dividends																(164)	164	0
Net income	$ 800			733		67		300		234		66	193			193			126		126	0	63		63	187		187	89		89	33		33	61		61
Stock issued during period, shares, long-term incentive plan activity	809
Stock issued during period, value, long-term incentive plan activity	$ 15	15	0	0	0	0
Stock issued during period, shares, employee stock purchase plan	294
Stock issued during period, value, employee stock purchase plan	$ 40	40	0	0	0	0
Changes in equity of noncontrolling interests	(23)					(23)		(23)				(23)
Common stock dividends	(335)			(335)									(115)				(115)		(7)		(7)		(52)		(52)				(78)		(78)	(18)		(18)	(27)		(27)
Contributions from parent								54	54				162		162				30	30	0	0	18	18	0	2	2
Distributions to member								(312)		(312)																(123)		(123)
Other comprehensive income (loss), net of income taxes	$ 52				52	0	52	2		0	2	0
Ending balance (in shares) at Sep. 30, 2018	968,842
Ending balance at Sep. 30, 2018	$ 33,388	19,063	(123)	14,949	(2,869)	2,368
Ending Balance at Sep. 30, 2018								15,960	9,411	4,214	(31)	2,366														9,166	9,072	94
Ending Balance at Sep. 30, 2018													10,107	1,588	7,209	(1,639)	2,949		3,684	2,560	1,124	0	3,244	1,623	1,621				2,664	1,555	1,109	1,517	914	603	1,073	912	161
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Appropriation of retained earnings for future dividends																(193)	193	0
Appropriation of retained earnings for future dividends													2,976
Beginning balance (in shares) at Dec. 31, 2018	970,020
Beginning balance at Dec. 31, 2018	$ 33,070	19,116	(123)	14,766	(2,995)	2,306
Beginning Balance at Dec. 31, 2018								15,508	9,518	3,724	(38)	2,304														9,282	9,220	62
Beginning Balance at Dec. 31, 2018	30,764												10,247	1,588	7,322	(1,639)	2,976		3,820	2,578	1,242	0	3,354	1,714	1,640				2,740	1,636	1,104	1,509	914	595	1,126	979	147
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	$ 966			907		59		422		363		59	157			157			168		168	0	160		160	117		117	55		55	53		53	10		10
Stock issued during period, shares, long-term incentive plan activity	2,446
Stock issued during period, value, long-term incentive plan activity	$ (3)	(3)	0	0	0	0
Stock issued during period, shares, employee stock purchase plan	320
Stock issued during period, value, employee stock purchase plan	$ 51	51	0	0	0	0
Changes in equity of noncontrolling interests	(17)					(17)		(17)				(17)
Sale of noncontrolling interests	7	7						7	7
Common stock dividends	$ (352)			(352)									(127)				(127)		(90)		(90)		(56)		(56)				(24)		(24)	(41)		(41)	(12)		(12)
Contributions from parent													63		63				145	145	0	0				19	19		14	14					5	5
Distributions to member								(225)		(225)																(128)		(128)
Other comprehensive income (loss), net of income taxes					(17)	(1)	(18)	1		0	2	(1)
Ending balance (in shares) at Mar. 31, 2019	972,786
Ending balance at Mar. 31, 2019	$ 33,704	19,171	(123)	15,321	(3,012)	2,347
Ending Balance at Mar. 31, 2019								15,696	9,525	3,862	(36)	2,345														9,290	9,239	51
Ending Balance at Mar. 31, 2019													10,340	1,588	7,385	(1,639)	3,006		4,043	2,723	1,320	0	3,458	1,714	1,744				2,785	1,650	1,135	1,521	914	607	1,129	984	145
Beginning balance (in shares) at Dec. 31, 2018	970,020
Beginning balance at Dec. 31, 2018	$ 33,070	19,116	(123)	14,766	(2,995)	2,306
Beginning Balance at Dec. 31, 2018								15,508	9,518	3,724	(38)	2,304														9,282	9,220	62
Beginning Balance at Dec. 31, 2018	30,764												10,247	1,588	7,322	(1,639)	2,976		3,820	2,578	1,242	0	3,354	1,714	1,640				2,740	1,636	1,104	1,509	914	595	1,126	979	147
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	2,220							784					544						410				261			412			217			116			87
Other comprehensive income (loss), net of income taxes	$ 33				32			3
Ending balance (in shares) at Sep. 30, 2019	973,941
Ending balance at Sep. 30, 2019	$ 34,352	19,238	(123)	15,871	(2,963)	2,329
Ending Balance at Sep. 30, 2019								15,593	9,525	3,778	(36)	2,326														9,548	9,503	45
Ending Balance at Sep. 30, 2019	$ 32,023												10,597	1,588	7,509	(1,639)	3,139		4,136	2,752	1,384	0	3,550	1,818	1,732				2,913	1,765	1,148	1,520	914	606	1,268	1,134	134
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Appropriation of retained earnings for future dividends																(157)	157	0
Beginning balance (in shares) at Mar. 31, 2019	972,786
Beginning balance at Mar. 31, 2019	$ 33,704	19,171	(123)	15,321	(3,012)	2,347
Beginning Balance at Mar. 31, 2019								15,696	9,525	3,862	(36)	2,345														9,290	9,239	51
Beginning Balance at Mar. 31, 2019													10,340	1,588	7,385	(1,639)	3,006		4,043	2,723	1,320	0	3,458	1,714	1,744				2,785	1,650	1,135	1,521	914	607	1,129	984	145
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	$ 494			484		10		118		108		10	186			186			102		102	0	45		45	106		106	64		64	30		30	14		14
Stock issued during period, shares, long-term incentive plan activity	320
Stock issued during period, value, long-term incentive plan activity	$ 14	14	0	0	0	0
Stock issued during period, shares, employee stock purchase plan	311
Stock issued during period, value, employee stock purchase plan	$ 24	24	0	0	0	0
Changes in equity of noncontrolling interests	3					3		3				3
Common stock dividends	$ (353)			(353)									(127)				(127)		(90)		(90)		(55)		(55)				(48)		(48)	(29)		(29)	(12)		(12)
Contributions from parent													61		61											264	264		115	115					150	150
Distributions to member								(224)		(224)																(88)		(88)
Other comprehensive income (loss), net of income taxes					22	(1)	21	(1)		0	0	(1)
Ending balance (in shares) at Jun. 30, 2019	973,417
Ending balance at Jun. 30, 2019	$ 33,907	19,209	(123)	15,452	(2,990)	2,359
Ending Balance at Jun. 30, 2019								15,592	9,525	3,746	(36)	2,357														9,572	9,503	69
Ending Balance at Jun. 30, 2019													10,460	1,588	7,446	(1,639)	3,065		4,055	2,723	1,332	0	3,448	1,714	1,734				2,916	1,765	1,151	1,522	914	608	1,281	1,134	147
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Appropriation of retained earnings for future dividends																(186)	186	0
Net income	$ 760			772		(12)		244		257		(13)	200			200			140		140	0	55		55	189		189	98		98	33		33	63		63
Stock issued during period, shares, long-term incentive plan activity	207
Stock issued during period, value, long-term incentive plan activity	$ 10	10	0	0	0	0
Stock issued during period, shares, employee stock purchase plan	317
Stock issued during period, value, employee stock purchase plan	$ 19	19	0	0	0	0
Changes in equity of noncontrolling interests	(18)					(18)		(18)				(18)
Sale of noncontrolling interests		0
Common stock dividends	(353)			(353)									(126)				(126)		(88)		(88)		(57)		(57)				(101)		(101)	(35)		(35)	(76)		(76)
Contributions from parent													63		63				29	29	0	0	104	104	0
Distributions to member								(225)		(225)																(213)		213
Other comprehensive income (loss), net of income taxes	$ 30				27	0	$ 27	3
Ending balance (in shares) at Sep. 30, 2019	973,941
Ending balance at Sep. 30, 2019	$ 34,352	$ 19,238	$ (123)	$ 15,871	$ (2,963)	$ 2,329
Ending Balance at Sep. 30, 2019								$ 15,593	$ 9,525	$ 3,778	$ (36)	$ 2,326														$ 9,548	$ 9,503	$ 45
Ending Balance at Sep. 30, 2019	$ 32,023												10,597	$ 1,588	$ 7,509	(1,639)	3,139		$ 4,136	$ 2,752	$ 1,384	$ 0	$ 3,550	$ 1,818	$ 1,732				$ 2,913	$ 1,765	$ 1,148	$ 1,520	$ 914	$ 606	$ 1,268	$ 1,134	$ 134
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Appropriation of retained earnings for future dividends													$ 3,139			$ (200)	$ 200	$ 0

Consolidated Statements of Changes in Shareholders Equity (Unaudited) (Parenthetical) - $ / shares	3 Months Ended
	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018
Statement of Stockholders' Equity [Abstract]
Common Stock, Dividends, Per Share, Declared	$ 0.36	$ 0.36	$ 0.36	$ 0.35	$ 0.35	$ 0.35

Significant Accounting Policies

9 Months Ended

Sep. 30, 2019

Accounting Policies [Abstract]

Significant Accounting Policies [Text Block]

Basis of Presentation (All Registrants)

Each of the Registrant’s Consolidated Financial Statements includes the accounts of its subsidiaries. All intercompany transactions have been eliminated.

Through its business services subsidiary, BSC, Exelon provides its subsidiaries with a variety of support services

at cost, including legal, human resources, financial, information technology and supply management services. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services at cost, including legal, accounting, engineering, customer operations, distribution and transmission planning, asset management, system operations, and power procurement, to PHI operating companies. The costs of BSC and PHISCO are directly charged or allocated to the applicable subsidiaries. The results of Exelon’s corporate operations are presented as “Other” within the consolidated financial statements and include intercompany eliminations unless otherwise disclosed.

The accompanying consolidated financial statements as of September 30, 2019 and 2018 and for the three and nine months then ended 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, 2018 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, 2019. 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.

New Accounting Standards (All Registrants)

New Accounting Standards Adopted in 2019: In 2019, the Registrants have adopted the following new authoritative accounting guidance issued by the FASB.

Leases. The Registrants applied the new guidance with the following transition practical expedients:


•	a "package of three" expedients that must be taken together and allow entities to (1) not reassess whether existing contracts contain leases, (2) carry forward the existing lease classification, and (3) not reassess initial direct costs associated with existing leases,


•	an implementation expedient which allows the requirements of the standard in the period of adoption with no restatement of prior periods, and


•	a land easement expedient which allows entities to not evaluate land easements under the new standard at adoption if they were not previously accounted for as leases.

The standard materially impacted the Registrants' Consolidated Balance Sheets but did not have a material impact in the Registrants' Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and Consolidated Statements of Changes in Shareholders' Equity. The most significant impact was the recognition of the ROU assets and lease liabilities for operating leases. The operating ROU assets and lease liabilities recognized upon adoption are materially consistent with the balances presented in the Combined Notes to the Consolidated Financial Statements. See Note 5 - Leases for additional information.

See Note 1 — Significant Accounting Policies of the Exelon 2018 Form 10-K for additional information on new accounting standards issued and adopted as of January 1, 2019.

New Accounting Standards Issued and Not Yet Adopted as of September 30, 2019: The following new authoritative accounting guidance issued by the FASB has not yet been adopted and reflected by the Registrants in their consolidated financial statements as of September 30, 2019. Unless otherwise indicated, the Registrants are currently assessing the impacts such guidance may have (which could be material) in their financial statements. The Registrants have assessed other FASB issuances of new standards which are not listed below as the Registrants do not expect such standards to have a material impact to their financial statements.

Goodwill Impairment (Issued January 2017). Simplifies the accounting for goodwill impairment by removing Step 2 of the current test, which requires calculation of a hypothetical purchase price allocation. Under the revised guidance, goodwill impairment will be measured as the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill (currently Step 1 of the two-step impairment test). Entities will continue to have the option to perform a qualitative assessment to determine if a quantitative impairment test is necessary. Exelon, Generation, ComEd, PHI and DPL do not expect the updated guidance to have a material impact to their financial statements. The standard is effective January 1, 2020, with early adoption permitted, and must be applied on a prospective basis.

Impairment of Financial Instruments (Issued June 2016). Provides for a new Current Expected Credit Loss (CECL) impairment model for specified financial instruments including loans, trade receivables, debt securities classified as held-to-maturity investments and net investments in leases recognized by a lessor. Under the new guidance, on initial recognition and at each reporting period, an entity is required to recognize an allowance that reflects its current estimate of credit losses expected to be incurred over the life of the financial instrument based on historical experience, current conditions and reasonable and supportable forecasts. The standard will be effective January 1, 2020 (with early adoption as of January 1, 2019 permitted) and requires a modified retrospective transition approach through a cumulative-effect adjustment to retained earnings as of the beginning of the period of adoption. This standard is primarily applicable to Generation's and the Utility Registrants' trade accounts receivable balances. The Registrants do not expect that this guidance will have a significant impact on their consolidated financial statements.

Leases (All Registrants)

The Registrants recognize a ROU asset and lease liability for operating leases with a term of greater than one year. The ROU asset is included in Other deferred debits and other assets and the lease liability is included in Other current liabilities and Other deferred credits and other liabilities on the Consolidated Balance Sheets. The ROU asset is measured as the sum of (1) the present value of all remaining fixed and in-substance fixed payments using each Registrant’s incremental borrowing rate, (2) any lease payments made at or before the commencement date (less any lease incentives received) and (3) any initial direct costs incurred. The lease liability is measured the same as the ROU asset, but excludes any payments made before the commencement date and initial direct costs incurred. Lease terms include options to extend or terminate the lease if it is reasonably certain they will be exercised. The Registrants include non-lease components, which are service-related costs that are not integral to the use of the asset, in the measurement of the ROU asset and lease liability.

Expense for operating leases and leases with a term of one year or less is recognized on a straight-line basis over the term of the lease, unless another systematic and rational basis is more representative of the derivation of benefit from use of the leased property. Variable lease payments are recognized in the period in which the related obligation is incurred and consist primarily of payments for purchases of electricity under contracted generation and are based on the electricity produced by those generating assets. Operating lease expense and variable lease payments are recorded to Purchased power and fuel expense for contracted generation or Operating and maintenance expense for all other lease agreements on the Registrants’ Statements of Operations and Comprehensive Income.

Income from operating leases, including subleases, is recognized on a straight-line basis over the term of the lease, unless another systematic and rational basis is more representative of the pattern in which income is earned over the term of the lease. Variable lease payments are recognized in the period in which the related obligation is performed and consist primarily of payments received from sales of electricity under contracted generation and are based on the electricity produced by those generating assets. Operating lease income and variable lease payments are recorded to Operating revenues on the Registrants’ Statements of Operations and Comprehensive Income.

The Registrants’ operating leases consist primarily of contracted generation, real estate including office buildings, and vehicles and equipment. The Registrants generally account for contracted generation in which the generating asset is not renewable as a lease if the customer has dispatch rights and obtains substantially all of the economic benefits. For new agreements entered after January 1, 2019, the Registrants will generally not account for contracted generation in which the generating asset is renewable as a lease if the customer does not design the generating asset. The Registrants account for land right arrangements that provide for exclusive use as leases while shared use land arrangements are generally not leases. The Registrants do not account for secondary use pole attachments as leases.

See Note 5 —Leases for additional information.

Significant Accounting Policies (All Registrants)

Business Description [Text Block]

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

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

9 Months Ended

Sep. 30, 2019

Variable Interest Entity [Abstract]

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

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

At September 30, 2019 and December 31, 2018, 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, 2019 and December 31, 2018. 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, 2019								December 31, 2018
	Exelon		Generation		PHI ^(a)		ACE		Exelon		Generation		PHI ^(a)		ACE
Cash and cash equivalents	$	168	$	168	$	—	$	—	$	414	$	414	$	—	$	—
Restricted cash and cash equivalents	76		73		3		3		66		62		4		4
Accounts receivable, net
Customer	163		163		—		—		146		146		—		—
Other	43		43		—		—		23		23		—		—
Unamortized energy contract asset ^(b)	23		23		—		—		25		25		—		—
Inventory, net
Materials and supplies	222		222		—		—		212		212		—		—
Other current assets	50		48		2		—		52		49		3		—
Total current assets	745		740		5		3		938		931		7		4
Property, plant and equipment, net ^(c)	6,079		6,079		—		—		6,188		6,188		—		—
NDT funds	2,636		2,636		—		—		2,351		2,351		—		—
Unamortized energy contract asset ^(b)	258		258		—		—		274		274		—		—
Other noncurrent assets	69		52		17		15		258		232		26		19
Total noncurrent assets	9,042		9,025		17		15		9,071		9,045		26		19
Total assets	$	9,787	$	9,765	$	22	$	18	$	10,009	$	9,976	$	33	$	23
Long-term debt due within one year	$	556	$	535	$	21	$	19	$	87	$	66	$	21	$	18
Accounts payable	148		148		—		—		96		96		—		—
Accrued expenses	58		57		1		1		73		72		1		1
Unamortized energy contract liabilities	10		10		—		—		15		15		—		—
Other current liabilities	30		30		—		—		3		3		—		—
Total current liabilities	802		780		22		20		274		252		22		19
Long-term debt	532		504		28		26		1,072		1,025		47		40
Asset retirement obligations ^(d)	2,103		2,103		—		—		2,165		2,165		—		—
Unamortized energy contract liabilities	1		1		—		—		1		1		—		—
Other noncurrent liabilities	84		84		—		—		42		42		—		—
Total noncurrent liabilities	2,720		2,692		28		26		3,280		3,233		47		40
Total liabilities	$	3,522	$	3,472	$	50	$	46	$	3,554	$	3,485	$	69	$	59

_________


(a)	Includes certain purchase accounting adjustments not pushed down to the ACE standalone entity.


(b)	These are unrestricted assets to Exelon and Generation.


(c)	Exelon’s and Generation’s balances include unrestricted assets of $41 million and $43 million as of September 30, 2019 and December 31, 2018, respectively.


(d)	Exelon’s and Generation’s balances include liabilities with recourse of $5 million as of September 30, 2019 and December 31, 2018.

As of September 30, 2019 and December 31, 2018, Exelon's and Generation's consolidated VIEs consist of:



Consolidated VIE or VIE groups:	Reason entity is a VIE:	Reason Generation is primary beneficiary:
CENG - A joint venture between Generation and EDF. Generation has a 50.01% equity ownership in CENG. See additional discussion below.	Disproportionate relationship between equity interest and operational control as a result of the Nuclear Operating Services Agreement (NOSA) described further below.	Generation conducts the operational activities.
EGRP - A collection of wind and solar project entities. Generation has a 51% equity ownership in EGRP. See additional discussion below.	Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner.	Generation conducts the operational activities.
Bluestem Wind Energy Holdings, LLC - A Tax Equity structure which is consolidated by EGRP. Generation is a minority interest holder.	Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner.	Generation conducts the operational activities.
Antelope Valley - A solar generating facility, which is 100% owned by Generation. Antelope Valley sells all of its output to PG&E through a PPA.	The PPA contract absorbs variability through a performance guarantee.	Generation conducts all activities.
Equity investment in distributed energy company - Generation has a 31% equity ownership. This distributed energy company has an interest in an unconsolidated VIE (see Unconsolidated VIEs disclosure below). Generation fully impaired this investment in the third quarter of 2019. See Note 7— Asset Impairments for additional information.	Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner.	Generation conducts the operational activities.

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.

Exelon and Generation, where indicated, provide the following support to CENG:


•	Generation provided a $400 million loan to CENG. The loan balance was fully repaid by CENG in January 2019.

•

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 22 — Commitments and Contingencies of the Exelon 2018 Form 10-K for additional information.


•	Generation and EDF share in the $688 million of contingent payment obligations for the payment of contingent retrospective premium adjustments for the nuclear liability insurance.


•	Exelon has executed an agreement to provide up to $245 million to support the operations of CENG as well as a $165 million guarantee of CENG’s cash pooling agreement with its subsidiaries.

EGRP - EGRP is a collection of wind and solar project entities and some of these project entities are VIEs that are consolidated by EGRP. Generation owns a number of limited liability companies that build, own, and operate solar and wind power facilities some of which are owned by EGRP. While Generation or EGRP owns 100% of the solar entities and 100% of the majority of the wind entities, it has been determined that certain of the solar and wind entities are VIEs because the entities require additional subordinated financial support in the form of a parental guarantee of debt, loans from the customers in order to obtain the necessary funds for construction of the solar facilities, or the customers absorb price variability from the entities through the fixed price power and/or REC purchase agreements. Generation is the primary beneficiary of these solar and wind entities that qualify as VIEs because Generation controls the design, construction, and operation of the facilities. Generation provides operating and capital funding to the solar and wind entities for ongoing construction, operations and maintenance and there is limited recourse related to Generation related to certain solar and wind entities.

In 2017, Generation’s interests in EGRP were contributed to and are pledged for the EGR IV non-recourse debt project financing structure. Refer to Note 11— Debt and Credit Agreements for additional information.

As of September 30, 2019 and December 31, 2018, 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 Transition 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 ACETF. 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, 2019 and December 31, 2018, 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 unconsolidated VIE entities:



	September 30, 2019						December 31, 2018
	Commercial Agreement VIEs		Equity Investment VIEs		Total		Commercial Agreement VIEs		Equity Investment VIEs		Total
Total assets^(a)	$	614	$	453	$	1,067	$	597	$	472	$	1,069
Total liabilities^(a)	36		224		260		37		222		259
Exelon's ownership interest in VIE^(a)	—		201		201		—		223		223
Other ownership interests in VIE^(a)	587		28		615		560		27		587
Registrants’ maximum exposure to loss:
Carrying amount of equity method investments	—		12		12		—		223		223

_________


(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.

For each of the unconsolidated VIEs, Exelon and Generation have assessed the risk of a loss equal to their maximum exposure to be remote and, accordingly, Exelon and Generation have not recognized a liability associated with any portion of the maximum exposure to loss.

As of September 30, 2019 and December 31, 2018, 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 these investments in the third quarter of 2019. See Note 7— Asset Impairments for additional information.	Similar structures to a limited partnership and the limited partners do not have kick out rights with respect to the general partner.	Generation does not conduct the operational activities.
Energy Purchase and Sale agreements - Generation has several energy purchase and sale agreements with generating facilities.	PPA contracts that absorb variability through fixed pricing.	Generation does not conduct the operational activities.

Mergers, Acquisitions and Dispositions (Exelon and Generation)	9 Months Ended
	Sep. 30, 2019
Business Combinations [Abstract]
Mergers, Acquisitions and Dispositions Disclosures [Text Block]	Mergers, Acquisitions and Dispositions (Exelon and Generation) Acquisition of Handley Generating Station On November 7, 2017, ExGen Texas Power, LLC (EGTP), and all of its wholly owned subsidiaries filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Code in the United States Bankruptcy Court for the District of Delaware, which resulted in Exelon and Generation deconsolidating EGTP's assets and liabilities from their consolidated financial statements. Concurrently with the Chapter 11 filings, Generation entered into an asset purchase agreement to acquire one of EGTP's generating plants, the Handley Generating Station, which closed on April 4, 2018 for a purchase price of $62 million. Disposition of Oyster Creek On July 31, 2018, Generation entered into an agreement with Holtec International (Holtec) and its indirect wholly owned subsidiary, Oyster Creek Environmental Protection, LLC (OCEP), for the sale and decommissioning of Oyster Creek located in Forked River, New Jersey, which permanently ceased generation operations on September 17, 2018. Completion of the transaction contemplated by the sale agreement was subject to the satisfaction of several closing conditions, including approval of the license transfer from the NRC and other regulatory approvals, and a private letter ruling from the IRS, which were satisfied in the second quarter 2019. The sale was completed on July 1, 2019. Exelon and Generation recognized a loss on the sale in the third quarter, which was immaterial. Under the terms of the transaction, Generation transferred to OCEP substantially all the assets associated with Oyster Creek, including assets held in NDT funds, along with the assumption of liability for all responsibility for the site, including full decommissioning and ongoing management of spent fuel until the spent fuel is moved offsite. The terms of the transaction also include various forms of performance assurance for the obligations of OCEP to timely complete the required decommissioning, including a parental guaranty from Holtec for all performance and payment obligations of OCEP, and a requirement for Holtec to deliver a letter of credit to Generation upon the occurrence of specified events. As a result of the transaction, in the third quarter of 2018, Exelon and Generation reclassified certain Oyster Creek assets and liabilities in Exelon’s and Generation’s Consolidated Balance Sheets as held for sale at their respective fair values. Exelon and Generation had $897 million and $777 million of Assets and Liabilities held for sale, respectively, at December 31, 2018. Upon remeasurement of the Oyster Creek ARO, Exelon and Generation recognized an $84 million and a $9 million pre-tax charge to Operating and maintenance expense in the third quarter of 2018 and in the second quarter of 2019, respectively. See Note 13 — Nuclear Decommissioning for additional information. Other Asset Disposition On February 28, 2018, Generation completed the sale of its interest in an electrical contracting business that primarily installs, maintains and repairs underground and high-voltage cable transmission and distribution systems for $87 million, resulting in a pre-tax gain which is included within Gain on sales of assets and businesses in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income for the nine months ended September 30, 2018.

Revenue from Contracts with Customers (All Registrants)

9 Months Ended

Sep. 30, 2019

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 3 — Revenue from Contracts with Customers of the Exelon 2018 Form 10-K for additional information regarding the primary sources of revenue for the Registrants.

Contract Balances (All Registrants)

Contract Assets and Liabilities

Generation records contract assets for the revenue recognized on the construction and installation of energy efficiency assets and new power generating facilities before Generation has an unconditional right to bill for and receive the consideration from the customer. These contract assets are subsequently reclassified to receivables when the right to payment becomes unconditional. Generation records contract assets and contract receivables within Other current assets and Accounts receivable, net - Customer, respectively, within Exelon’s and Generation’s Consolidated Balance Sheets.

Generation records contract liabilities when consideration is received or due prior to the satisfaction of the performance obligations. These contract liabilities primarily relate to upfront consideration received or due for equipment service plans, solar panel leases and the Illinois ZEC program that introduces a cap on the total consideration to be received by Generation. Generation records contract liabilities within Other current liabilities and Other noncurrent liabilities within Exelon's and Generation's Consolidated Balance Sheets.

The following table provides a rollforward of the contract assets and liabilities reflected in Exelon's and Generation's Consolidated Balance Sheets from January 1, 2018 to September 30, 2019:



	Contract Assets						Contract Liabilities
	Exelon			Generation			Exelon			Generation
Balance as of January 1, 2018	$	283		$	283		$	35		$	35
Consideration received or due	(146		)	(146		)	179			465
Revenues recognized	50			50			(187		)	(458		)
Balance at December 31, 2018	187			187			27			42
Consideration received or due	(109		)	(109		)	65			198
Revenues recognized	92			92			(66		)	(192		)
Balance at September 30, 2019	170			170			26			48

The Utility Registrants do not have any contract assets. The Utility Registrants also record contract liabilities when consideration is received prior to the satisfaction of the performance obligations. As of September 30, 2019 and December 31, 2018, the Utility Registrants' contract liabilities were immaterial.

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, 2019. 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.



	2019	2020	2021	2022	2023 and thereafter	Total
Exelon	156	341	142	74	244	957
Generation	215	442	197	89	244	1,187

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 18 — Segment Information for the presentation of the Registrant's revenue disaggregation.

Leases (All Registrants)

9 Months Ended

Sep. 30, 2019

Leases [Abstract]

Lessee, Finance and Operating Leases [Text Block]

Leases (All Registrants)

Lessee

The Registrants have operating leases for which they are the lessees. The following tables outline the significant types of operating leases at each registrant and other terms and conditions of the lease agreements. The Registrants do not have material finance leases.

Exelon

Generation

ComEd

PECO

BGE

PHI

Pepco

DPL

ACE

Contracted generation

●

Real estate

●

Vehicles and equipment

●



(in years)	Exelon	Generation	ComEd	PECO	BGE	PHI	Pepco	DPL	ACE
Remaining lease terms	1-87	1-37	1-6	1-15	1-87	1-13	1-13	1-13	1-8
Options to extend the term	3-30	3-30	5	N/A	N/A	3-30	5	3-30	N/A
Options to terminate within	2-14	2	4	N/A	3	N/A	N/A	N/A	N/A

The components of lease costs for the three months ended September 30, 2019 were as follows:



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Operating lease costs	$	97	$	73	$	1	$	—	$	8	$	12	$	3	$	3	$	2
Variable lease costs	79		74		—		—		1		1		—		—		—
Short-term lease costs	5		5		—		—		—		—		—		—		—
Total lease costs ^(a)	$	181	$	152	$	1	$	—	$	9	$	13	$	3	$	3	$	2

__________


(a)	Excludes $29 million, $28 million, $1 million and $1 million of sublease income recorded at Exelon, Generation, PHI and DPL, respectively

The components of lease costs for the nine months ended September 30, 2019 were as follows:



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Operating lease costs	$	252	$	180	$	2	$	1	$	25	$	35	$	9	$	10	$	5
Variable lease costs	229		214		1		—		1		5		2		2		1
Short-term lease costs	16		16		—		—		—		—		—		—		—
Total lease costs ^(a)	$	497	$	410	$	3	$	1	$	26	$	40	$	11	$	12	$	6

__________


(a)	Excludes $48 million, $42 million, $6 million and $6 million of sublease income recorded at Exelon, Generation, PHI and DPL, respectively.

The following table provides additional information regarding the presentation of operating lease ROU assets and lease liabilities within the Registrants’ Consolidated Balance Sheets as of September 30, 2019:



	Exelon^(a)		Generation^(a)		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Operating lease ROU assets
Other deferred debits and other assets	$	1,374	$	926	$	10	$	2	$	83	$	304	$	66	$	75	$	24

Operating lease liabilities
Other current liabilities	242		170		3		—		32		35		8		11		5
Other deferred credits and other liabilities	1,355		949		8		1		50		279		60		74		19
Total operating lease liabilities	$	1,597	$	1,119	$	11	$	1	$	82	$	314	$	68	$	85	$	24

__________


(a)	Exelon's and Generation's operating ROU assets and lease liabilities include $542 million and $703 million, respectively, related to contracted generation.

The weighted average remaining lease terms, in years, and discount rates for operating leases as of September 30, 2019 were as follows:



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Remaining lease term	10.1		10.6		4.7		4.3		5.6		9.0		9.6		9.5		5.3
Discount rate	4.5	%	4.8	%	3.1	%	3.3	%	3.6	%	4.0	%	3.7	%	3.7	%	3.3	%

Future minimum lease payments for operating leases as of September 30, 2019 were as follows:



Year	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
2019	$	65	$	50	$	1	$	—	$	1	$	11	$	3	$	2	$	2
2020	289		203		3		1		34		45		10		13		5
2021	246		162		3		—		31		43		9		12		5
2022	179		113		2		—		16		42		9		12		4
2023	148		100		1		—		—		41		8		11		4
Remaining years	1,123		837		2		—		19		197		43		53		6
Total	2,050		1,465		12		1		101		379		82		103		26
Interest	453		346		1		—		19		65		14		18		2
Total operating lease liabilities	$	1,597	$	1,119	$	11	$	1	$	82	$	314	$	68	$	85	$	24

Future minimum lease payments for operating leases under the prior lease accounting guidance as of December 31, 2018 were as follows:



Year	Exelon^(a)(b)		Generation^(a)(b)		ComEd^(a)(c)		PECO^(a)(c)		BGE^(a)(c)(d)(e)		PHI^(a)		Pepco^(a)		DPL^(a)(c)		ACE^(a)
2019	$	140	$	33	$	7	$	5	$	35	$	48	$	11	$	14	$	7
2020	149		46		5		5		35		46		10		13		6
2021	143		46		4		5		33		43		9		12		5
2022	126		47		4		5		18		42		8		12		5
2023	97		46		3		5		3		39		8		10		4
Remaining years	723		545		—		—		19		159		40		35		5
Total minimum future lease payments	$	1,378	$	763	$	23	$	25	$	143	$	377	$	86	$	96	$	32

__________


(a)	Includes amounts related to shared use land arrangements.


(b)	Excludes Generation’s contingent operating lease payments associated with contracted generation.

(c)

Amounts related to certain real estate leases and railroad licenses effectively have indefinite payment periods. As a result, ComEd, PECO, BGE and DPL have excluded these payments from the remaining years as such amounts would not be meaningful. ComEd's, PECO’s, BGE’s and DPL's average annual obligation for these arrangements, included in each of the years 2019 - 2023, was $3 million, $5 million, $1 million and $1 million respectively. Also includes amounts related to shared use land arrangements.


(d)	Includes all future lease payments on a 99-year real estate lease that expires in 2106.


(e)	The BGE column above includes minimum future lease payments associated with a 6-year lease for the Baltimore City conduit system that became effective during the fourth quarter of 2016. BGE's total commitments under the lease agreement are $26 million, $28 million, $28 million and $14 million related to years 2019 - 2022, respectively.

Cash paid for amounts included in the measurement of lease liabilities for the nine months ended September 30, 2019 were as follows:



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Operating cash flows from operating leases	$	225	$	156	$	2	$	—	$	32	$	29	$	7	$	6	$	4

ROU assets obtained in exchange for lease obligations for the nine months ended September 30, 2019 were as follows:



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Operating leases	$	70	$	11	$	6	$	—	$	1	$	20	$	7	$	9	$	4

Lessor, Operating Leases [Text Block]

Lessor

The Registrants have operating leases for which they are the lessors. The following tables outline the significant types of leases at each registrant and other terms and conditions of their lease agreements.

Exelon

Generation

ComEd

PECO

BGE

PHI

Pepco

DPL

ACE

Contracted generation

●

Real estate

●



(in years)	Exelon	Generation	ComEd	PECO	BGE	PHI	Pepco	DPL	ACE
Remaining lease terms	1-84	1-33	1-18	1-84	24	1-14	2-7	13-14	1-3
Options to extend the term	1-79	1-5	5-79	5-50	N/A	5	N/A	N/A	N/A

The components of lease income for the three months ended September 30, 2019 were as follows:



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Operating lease income	$	30	$	29	$	—	$	—	$	—	$	1	$	—	$	1	$	—
Variable lease income	80		80		—		—		—		—		—		—		—

The components of lease income for the nine months ended September 30, 2019 were as follows:



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Operating lease income	$	48	$	44	$	—	$	—	$	—	$	3	$	—	$	3	$	—
Variable lease income	209		206		—		—		—		3		—		3		—

Future minimum lease payments to be recovered under operating leases as of September 30, 2019 were as follows:



Year	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
2019	$	4	$	3	$	—	$	—	$	—	$	1	$	—	$	1	$	—
2020	51		46		—		—		—		4		—		3		—
2021	50		45		—		—		—		4		1		3		—
2022	50		45		—		—		—		5		—		4		—
2023	49		45		—		—		—		4		—		3		—
Remaining years	314		271		1		3		1		38		—		38		—
Total	$	518	$	455	$	1	$	3	$	1	$	56	$	1	$	52	$	—

Leases (All Registrants)

Regulatory Matters (All Registrants)

9 Months Ended

Sep. 30, 2019

Regulated Operations [Abstract]

Regulatory Matters (All Registrants)

As discussed in Note 4 — Regulatory Matters of the Exelon 2018 Form 10-K, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The following discusses developments in 2019 and updates to the 2018 Form 10-K.

Utility Regulatory Matters (Exelon and the Utility Registrants)

Distribution Base Rate Case Proceedings

The following tables show the completed and pending distribution base rate case proceedings in 2019.

Completed Distribution Base Rate Case Proceedings



Registrant/Jurisdiction	Filing Date	Requested Revenue Requirement (Decrease) Increase				Approved Revenue Requirement (Decrease) Increase				Approved ROE		Approval Date	Rate Effective Date
ComEd - Illinois (Electric)	April 16, 2018	$	(23	)		$	(24	)		8.69%		December 4, 2018	January 1, 2019
PECO - Pennsylvania (Electric)	March 29, 2018	$	82			$	25			N/A	^(a)	December 20, 2018	January 1, 2019
BGE - Maryland (Natural Gas)	June 8, 2018 (amended October 12, 2018)	$	61			$	43			9.8%		January 4, 2019	January 4, 2019
ACE - New Jersey (Electric)	August 21, 2018 (amended November 19, 2018)	$	122		^(b)	$	70		^(b)	9.6%		March 13, 2019	April 1, 2019
Pepco - Maryland (Electric)	January 15, 2019 (amended May 16, 2019)	$	27			$	10			9.6%		August 12, 2019	August 13, 2019

__________


(a)	The PECO rate case proceeding was resolved through a settlement agreement, which did not specify an approved ROE.


(b)	Requested and approved increases are before New Jersey sales and use tax.

Pending Distribution Base Rate Case Proceedings



Registrant/Jurisdiction	Filing Date	Requested Revenue Requirement (Decrease) Increase			Requested ROE		Expected Approval Timing
ComEd - Illinois (Electric)^(a)	April 8, 2019	$	(6	)	8.91	%	December 2019
BGE - Maryland (Electric)^(b)	May 24, 2019 (amended October 4, 2019)	$	74		10.3	%	December 2019
BGE - Maryland (Natural Gas)^(b)	May 24, 2019 (amended October 4, 2019)	$	59		10.3	%	December 2019
Pepco - District of Columbia (Electric)^(c)	May 30, 2019 (amended September 16, 2019)	$	160		10.3	%	Fourth quarter of 2020

__________

(a)

Reflects an increase of $57 million for the initial revenue requirement for 2019 and a decrease of $63 million related to the annual reconciliation for 2018. The revenue requirement for 2019 and annual reconciliation for 2018 provides for a weighted average debt and equity return on distribution rate base of 6.53%. See Note 4 — Regulatory Matters of the Exelon 2018 Form 10-K for additional information on ComEd's distribution formula rate filings.


(b)	On October 25, 2019, BGE filed a settlement agreement with the MDPSC. The settlement provides for an increase to BGE’s annual electric and natural gas distribution rates of $18 million and $45 million, respectively.


(c)	Reflects a three-year cumulative multi-year plan and total requested revenue requirement increases of $84 million, $40 million and $36 million for years 2020, 2021, and 2022, respectively, to recover capital investments made in 2018 and 2019 and planned capital investments from 2020 to 2022.

Transmission Formula Rates

Transmission Formula Rate (Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE). ComEd’s, BGE’s, Pepco's, DPL's and ACE's 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, with the resulting rates effective on June 1 of the same year. The annual formula rate update is based on prior year actual costs and current year projected capital additions (initial year revenue requirement). The update also reconciles any differences between the revenue requirement in effect beginning June 1 of the prior year and actual costs incurred for that year (annual reconciliation).

For 2019, the following total increases/(decreases) were included in ComEd’s, BGE’s, Pepco's, DPL's and ACE's electric transmission formula rate filings:



Registrant^(a)	Initial Revenue Requirement Increase (Decrease)			Annual Reconciliation (Decrease) Increase			Total Revenue Requirement Increase (Decrease)				Allowed Return on Rate Base^(c)		Allowed ROE^(d)
ComEd	$	21		$	(16	)	$	5			8.21	%	11.50	%
BGE	(10		)	(23		)	(19		)	^(b)	7.35	%	10.50	%
Pepco	15			11			26				7.75	%	10.50	%
DPL	17			(1		)	16				7.14	%	10.50	%
ACE	11			(2		)	9				7.79	%	10.50	%

__________


(a)	All rates are effective June 2019, subject to review by the FERC and other parties, which is due by the fourth quarter of 2019.


(b)	The change in BGE's transmission revenue requirement includes a FERC approved dedicated facilities charge of $14 million to recover the costs of providing transmission service to specifically designated load by BGE.


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


(d)	As part of the FERC-approved settlement of ComEd’s 2007 transmission rate case, the rate of return on common equity is 11.50%, 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%. 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.

Pending Transmission Formula Rate (Exelon and PECO). On May 1, 2017, PECO filed a request with FERC seeking approval to update its transmission rates and change the manner in which PECO’s transmission rate is determined from a fixed rate to a formula rate. The formula rate will be updated annually to ensure that under this rate customers pay the actual costs of providing transmission services. PECO’s initial formula rate filing included a requested increase of $22 million to PECO’s annual transmission revenue requirement, which reflected a ROE of 11%, inclusive of a 50 basis point adder for being a member of a RTO. On June 27, 2017, FERC issued an Order accepting the filing and suspending the proposed rates until December 1, 2017, subject to refund, and set the matter for hearing and settlement judge procedures.

Pursuant to the transmission formula rate request discussed above, PECO made its annual formula rate updates in May 2018 and 2019, which included a decrease of $6 million and an increase of $8 million, respectively, to the annual transmission revenue requirement. The updated transmission formula rates were effective on June 1, 2018 and 2019, respectively, subject to refund.

On July 22, 2019, PECO and other parties filed with FERC a settlement agreement, which includes a ROE of 10.35%, inclusive of a 50 basis point adder for being a member of a RTO. The settlement did not have a material impact on PECO’s 2017, 2018, or 2019 annual transmission revenue requirements. A final order from FERC is expected before the end of the first quarter of 2020. PECO cannot predict the outcome of this proceeding, or the transmission formula FERC may approve.

Other State Regulatory Matters

Energy Efficiency Formula Rate. ComEd filed its annual energy efficiency formula rate update with the ICC on May 23, 2019. The filing establishes the revenue requirement used to set the rates that will take effect in January 2020 after the ICC’s review and approval. The revenue requirement requested is based on a reconciliation of the 2018 actual costs plus projected 2019 and 2020 expenditures.



Registrant	Initial Revenue Requirement Increase (Decrease)		Annual Reconciliation Increase (Decrease)			Total Revenue Requirement Increase (Decrease)			Requested Return on Rate Base		Requested ROE
ComEd	$	53	$	(2	)	$	51	^(a)	6.53	%	8.91	%

__________

(a)

The requested revenue requirement increase provides for a weighted average debt and equity return on rate base of 6.53% inclusive of an allowed ROE of 8.91%. The ROE reflects the average rate on 30-year treasury notes plus 580 basis points. The ROE applicable to the 2018 reconciliation year is 10.91% and the return on rate base is 7.49%, which include the Performance Adjustment, which can either increase or decrease the ROE by up to a maximum of 200 basis points.

Maryland Regulatory Matters

Maryland Alternative Rate Plans Rulemaking (Exelon, BGE, PHI, Pepco and DPL). On August 9, 2019, the MDPSC issued an order in which the MDPSC determined that it is now appropriate to move forward to implement alternative rate plans in Maryland. The MDPSC found that a multi-year rate plan, based on a historic test year and allowing up to three future test years, can produce just and reasonable rates. A working group has been convened to develop and submit a detailed implementation report to the MDPSC by December 20, 2019. The MDPSC will issue another order on next steps by January 30, 2020. BGE, Pepco and DPL cannot predict the outcome or the potential financial impact, if any, on BGE, Pepco or DPL.

New Jersey Regulatory Matters

ACE Infrastructure Investment Program Filing (Exelon, PHI and ACE). On February 28, 2018, ACE filed with the NJBPU the company’s Infrastructure Investment Program (IIP) proposing to seek recovery of a series of investments through a new rider mechanism, totaling $338 million, between 2019-2022 to provide safe and reliable service for its customers. The IIP allowed for more timely recovery of investments made to modernize and enhance ACE’s electric system. On April 15, 2019, ACE entered into a settlement agreement with other parties, which allows

for a recovery totaling $96 million of reliability related capital investments from July 1, 2019 through June 30, 2023. On April 18, 2019, the NJBPU approved the settlement agreement.

New Jersey Clean Energy Legislation (Exelon, PHI and ACE). On May 23, 2018, New Jersey enacted legislation that established and modified New Jersey’s clean energy and energy efficiency programs and solar and renewable energy portfolio standards. On the same day, New Jersey enacted legislation that established a ZEC program that provides compensation for nuclear plants that demonstrate to the NJBPU that they meet certain requirements, including that they make a significant contribution to air quality in the state and that their revenues are insufficient to cover their costs and risks. Electric distribution utilities in New Jersey, including ACE, began collecting from retail distribution customers, through a non-bypassable charge, all costs associated with the utility’s procurement of the ZECs effective April 18, 2019. See Generation Regulatory Matters below for additional information.

Other Federal Regulatory Matters

Transmission-Related Income Tax Regulatory Assets (Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE). On December 13, 2016 (and as amended on March 13, 2017), BGE filed with FERC to begin recovering certain existing and future transmission-related income tax regulatory assets through its transmission formula rate. BGE’s existing regulatory assets included (1) amounts that, if BGE’s transmission formula rate provided for recovery, would have been previously amortized and (2) amounts that would be amortized and recovered prospectively. ComEd, Pepco, DPL and ACE had similar transmission-related income tax regulatory liabilities and assets also requiring FERC approval. On November 16, 2017, FERC issued an order rejecting BGE’s proposed revisions to its transmission formula rate to recover these transmission-related income tax regulatory assets. As a result of the FERC’s order, ComEd, BGE, Pepco, DPL and ACE took a charge to Income tax expense within their Consolidated Statements of Operations and Comprehensive Income in the fourth quarter of 2017 reducing their associated transmission-related income tax regulatory assets for the portion of the total transmission-related income tax regulatory assets that would have been previously amortized and recovered through rates. Similar regulatory assets and liabilities at PECO are not subject to the same FERC transmission rate recovery formula. See above for additional information regarding PECO's transmission formula rate filing.

On December 18, 2017, BGE filed for clarification and rehearing of FERC’s November 16, 2017 order and on February 23, 2018 (as amended on July 9, 2018), ComEd, Pepco, DPL, and ACE each filed with FERC to revise their transmission formula rate mechanisms to permit recovery of transmission-related income tax regulatory assets, including those amounts that would have been previously amortized and recovered through rates had the transmission formula rate provided for such recovery.

On September 7, 2018, FERC issued orders rejecting BGE’s December 18, 2017 request for rehearing and clarification and ComEd's, Pepco's, DPL's and ACE's February 23, 2018 (as amended on July 9, 2018) filings, citing the lack of timeliness of the requests to recover amounts that would have been previously amortized, but indicating that ongoing recovery of certain transmission-related income tax regulatory assets would provide for a more accurate revenue requirement, consistent with its November 16, 2017 order.

On October 1, 2018, ComEd, BGE, Pepco, DPL, and ACE submitted filings to recover ongoing non-TCJA amortization amounts and refund TCJA transmission-related income tax regulatory liabilities for the prospective period starting on October 1, 2018. In addition, on October 9, 2018, ComEd, Pepco, DPL, and ACE sought rehearing of FERC's September 7, 2018 order. On November 2, 2018, BGE filed an appeal of FERC’s September 7, 2018 order to the Court of Appeals for the D.C. Circuit. On April 26, 2019, FERC issued an order accepting ComEd’s, BGE’s, Pepco’s, DPL’s, and ACE’s October 1, 2018 filings, effective October 1, 2018, subject to refund and established hearing and settlement judge procedures. ComEd, BGE, Pepco, DPL, and ACE cannot predict the outcome of these proceedings.

If FERC ultimately rules that the future, ongoing non-TCJA amortization amounts are not recoverable, Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE would record additional charges to Income tax expense, which could be up to approximately $80 million, $52 million, $16 million, $12 million, $4 million, $6 million and $2 million, respectively, as of September 30, 2019.

Regulatory Assets and Liabilities

The Utility Registrants' regulatory assets and liabilities have not changed materially since December 31, 2018, unless noted below. See Note 4 — Regulatory Matters of the Exelon 2018 Form 10-K for additional information on the specific regulatory assets and liabilities.

ComEd. Regulatory assets increased $122 million primarily due to an increase of $186 million in Energy Efficiency Costs and $32 million Renewable Energy partially offset by a decrease of $97 million in Electric Distribution Formula Rate Annual Reconciliations.

PECO. Regulatory assets increased $62 million primarily due to an increase of $95 million in Deferred Income Taxes offset by a $34 million decrease in Electric Energy and Natural Gas Costs.

BGE. Regulatory liabilities decreased $90 million primarily due to a decrease of $40 million in Deferred Income Taxes and $43 million in Removal Costs.

Pepco. Regulatory assets decreased $84 million primarily due to a decrease of $39 million in Electric Energy and Natural Gas Costs, $26 million in DC PLUG charge and $14 million in AMI Programs - Deployment Costs and Legacy Meters. Regulatory liabilities decreased by $71 million primarily due to a decrease of $73 million in Deferred Income Taxes.

DPL. Regulatory liabilities decreased $42 million primarily due to a decrease of $29 million in Deferred Income Taxes and $10 million in Electric Energy and Natural Gas Costs.

ACE. Regulatory liabilities decreased $30 million primarily due to a decrease of $32 million in Deferred Income Taxes.

Capitalized Ratemaking Amounts Not Recognized (Exelon and the Utility Registrants)

The following table presents authorized amounts capitalized for ratemaking purposes related to earnings on shareholders’ investment that are not recognized for financial reporting purposes in Exelon's and the Utility Registrant's Consolidated Balance Sheets. These amounts will be recognized as revenues in the related Consolidated Statements of Operations and Comprehensive Income in the periods they are billable to our customers.



	Exelon		ComEd^(a)		PECO		BGE^(b)		PHI		Pepco^(c)		DPL^(c)		ACE
September 30, 2019	$	59	$	4	$	—	$	47	$	8	$	5	$	3	$	—
December 31, 2018	$	65	$	8	$	—	$	49	$	8	$	5	$	3	$	—

_________


(a)	Reflects ComEd's unrecognized equity returns earned for ratemaking purposes on its electric distribution formula rate regulatory assets.


(b)	BGE's authorized amounts capitalized for ratemaking purposes primarily relate to earnings on shareholders' investment on its AMI programs.


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

Generation Regulatory Matters (Exelon and Generation)

Illinois Regulatory Matters

Zero Emission Standard. Pursuant to FEJA, on January 25, 2018, the ICC announced that Generation’s Clinton Unit 1, Quad Cities Unit 1 and Quad Cities Unit 2 nuclear plants were selected as the winning bidders through the IPA's ZEC procurement event. Generation executed the ZEC procurement contracts with Illinois utilities, including ComEd, effective January 26, 2018 and began recognizing revenue with compensation for the sale of ZECs retroactive to the June 1, 2017 effective date of FEJA. During the first quarter of 2018, Generation recognized $150 million of revenue related to ZECs generated from June 1, 2017 through December 31, 2017.

On February 14, 2017, two lawsuits were filed in the Northern District of Illinois against the IPA alleging that the state’s ZEC program violates certain provisions of the U.S. Constitution. Both lawsuits argued that the Illinois ZEC program would distort PJM's FERC-approved energy and capacity market auction system of setting wholesale prices and sought a permanent injunction preventing the implementation of the program. The lawsuits were dismissed by the district court on July 14, 2017. On September 13, 2018, the U.S. Circuit Court of Appeals for the Seventh Circuit affirmed the lower court's dismissal of both lawsuits. On January 7, 2019, plaintiffs filed a petition seeking U.S. Supreme Court review of the case, which was denied on April 15, 2019.

New Jersey Regulatory Matters

New Jersey Clean Energy Legislation. On May 23, 2018, New Jersey enacted legislation that established a ZEC program that will provide 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 November 19, 2018, NJBPU issued an order providing for the method and application process for determining the eligibility of nuclear power plants, a draft method and process for ranking and selecting eligible nuclear power plants, and the establishment of a mechanism for each regulated utility to purchase ZECs from selected nuclear power plants. On December 19, 2018, PSEG filed complete applications seeking NJBPU approval for Salem 1 and Salem 2, of which Generation owns a 42.59% ownership interest, to participate in the ZEC program. On April 18, 2019, the NJBPU approved the award of ZECs to Salem 1 and Salem 2. Upon approval, Generation began recognizing revenue for the sale of New Jersey ZECs in the month they are generated and has recognized $21 million and $31 million for the three and nine months ended September 30, 2019. On May 15, 2019, New Jersey Rate Counsel appealed the NJBPU's decision to the New Jersey Superior Court. The appeal does not prevent implementation of the ZEC program. Exelon and Generation cannot predict the outcome of the appeal. See Note 8 — Early Plant Retirements for additional information related to Salem.

New York Regulatory Matters

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

On October 19, 2016, a coalition of fossil-generation companies filed a complaint in federal district court against the NYPSC alleging that the ZEC program violates certain provisions of the U.S. Constitution; specifically, that the ZEC program interferes with FERC’s jurisdiction over wholesale rates and that it discriminates against out of state competitors, which was dismissed by the district court on July 25, 2017. On September 27, 2018, the U.S. Court of Appeals for the Second Circuit affirmed the lower court's dismissal of the complaint against the ZEC program. On January 7, 2019, the fossil-generation companies filed a petition seeking U.S. Supreme Court review of the case which was denied on April 15, 2019.

In addition, on November 30, 2016 (as amended on January 13, 2017), a group of parties filed a Petition in New York State court seeking to invalidate the ZEC program, which argued that the NYPSC did not have authority to establish the program, that it violated state environmental law and that it violated certain technical provisions of the State Administrative Procedures Act when adopting the ZEC program. Subsequently, Generation, CENG and the NYPSC filed motions to dismiss the state court action, which were later opposed by the plaintiffs. On January 22, 2018, the court dismissed the environmental claims and the majority of the plaintiffs from the case but denied the motions to dismiss with respect to the remaining five plaintiffs and claims, without commenting on the merits of the case. On October 8, 2019, the court dismissed all remaining claims. The petitioners have until November 11, 2019 to file a notice of appeal.

See Note 8 — Early Plant Retirements for additional information related to Ginna and Nine Mile Point.

Federal Regulatory Matters

Operating License Renewals

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

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

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

On October 29, 2019, Generation and MDE entered into a settlement agreement (MDE Settlement) that would resolve all outstanding issues relating to the 401 Certification. Under the MDE Settlement, the parties will propose license articles to FERC for approval as an offer of settlement to be incorporated by FERC into the new license in accordance with FERC’s discretionary authority under the Federal Power Act. The MDE Settlement provides that if FERC approves the offer of settlement, MDE would waive its rights to issue a 401 Certification and Generation would agree to implement environmental protection, mitigation and enhancement measures over the anticipated 50-year term of the new license. These measures address ecological and water quality matters, including modifications to river flows to improve aquatic habitat, along with other additional fish and eel passage improvements and initiatives to support rare, threatened and endangered wildlife, among other commitments. Exelon’s commitments under the DOI and MDE Settlements are not effective until incorporated by FERC into the new license.

The financial impact of the DOI and MDE Settlements and other anticipated license commitments are estimated to be $11 million to $14 million per year, on average, recognized over the new license term, including capital and operating costs. The actual timing and amount of the majority of these costs are not currently fixed and will vary from year to year throughout the life of the new license. Generation cannot currently predict when FERC will issue the new license. As of September 30, 2019, $41 million of direct costs associated with Conowingo licensing efforts have been capitalized. Generation’s current depreciation provision for Conowingo assumes renewal of the FERC license.

Asset Impairments (Exelon and Generation)	9 Months Ended
Asset Impairments (Exelon and Generation)	Sep. 30, 2019
Property, Plant and Equipment [Abstract]
Asset Impairment Charges [Text Block]	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. Equity Method Investments in Certain Distributed Energy Companies In the third quarter of 2019, Generation’s equity method investments in certain distributed energy companies were fully impaired due to an other-than-temporary decline in market conditions and underperforming projects. Exelon and Generation recorded a pre-tax impairment charge of $164 million in Equity in losses of unconsolidated affiliates and an offsetting pre-tax $96 million in Net income attributable to noncontrolling interests in their Consolidated Statements of Operations and Comprehensive Income. As a result, Generation accelerated the amortization of investment tax credits associated with these companies and Exelon and Generation recorded a benefit of $46 million in Income taxes. The impairment charge and the accelerated amortization of investment tax credits resulted in a net $15 million decrease to Exelon’s and Generation’s earnings. See Note 2 — Variable Interest Entities for additional information. Antelope Valley Solar Facility Generation’s Antelope Valley, a 242 MW solar facility in Lancaster, CA, sells all of its output to PG&E through a PPA. As of September 30, 2019, Generation had approximately $730 million of net long-lived assets related to Antelope Valley. As a result of the PG&E bankruptcy filing in the first quarter of 2019, Generation completed a comprehensive review of Antelope Valley's estimated undiscounted future cash flows and no impairment charge was recorded. Significant changes in assumptions such as the likelihood of the PPA being rejected as part of the bankruptcy proceedings could potentially result in future impairments of Antelope Valley’s net long-lived assets, which could be material. Antelope Valley is a wholly owned indirect subsidiary of EGR IV, which had approximately $1,930 million of additional net long-lived assets as of September 30, 2019. EGR IV is a wholly owned indirect subsidiary of Exelon and Generation and includes Generation's interest in EGRP and other projects with non-controlling interests. To date, there have been no indicators to suggest that the carrying amount of other net long-lived assets of EGR IV may not be recoverable. Generation will continue to monitor the bankruptcy proceedings for any changes in circumstances that may indicate the carrying amount of the net long-lived assets of Antelope Valley or other long-lived assets of EGR IV may not be recoverable. See Note 11 - Debt and Credit Agreements for additional information on the PG&E bankruptcy.

Early Plant Retirements (Exelon and Generation)

9 Months Ended

Sep. 30, 2019

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

In 2015 and 2016, Generation identified the Clinton and Quad Cities nuclear plants in Illinois, Ginna and Nine Mile Point nuclear plants in New York and Three Mile Island nuclear plant in Pennsylvania as having the greatest risk of early retirement based on economic valuation and other factors. In 2017, PSEG made public similar financial challenges facing its New Jersey nuclear plants, including Salem, of which Generation owns a 42.59% ownership interest. PSEG is the operator of Salem and also has the decision-making authority to retire Salem.

Assuming the continued effectiveness of the Illinois ZES, New Jersey ZEC program and the New York CES, Generation and CENG, through its ownership of Ginna and Nine Mile Point, no longer consider Clinton, Quad Cities, Salem, Ginna or Nine Mile Point to be at heightened risk for early retirement. However, to the extent the Illinois ZES, New Jersey ZEC program or the New York CES do not operate as expected over their full terms, each of these plants could again be at heightened risk for early retirement, which could have a material impact on Exelon’s and Generation’s future financial statements. See Note 6 — Regulatory Matters for additional information on the Illinois ZES, New Jersey ZEC program and New York CES.

In Pennsylvania, the TMI nuclear plant did not clear in the May 2017 PJM capacity auction for the 2020-2021 planning year, the third consecutive year that TMI failed to clear the PJM base residual capacity auction and on May 30, 2017, based on these capacity auction results, prolonged periods of low wholesale power prices, and the absence of federal or state policies that place a value on nuclear energy for its ability to produce electricity without air pollution, Generation announced that it would permanently cease generation operations at TMI. On September 20, 2019, Generation permanently ceased generation operations at TMI.

On February 2, 2018, Generation announced that it would permanently cease generation operations at the Oyster Creek nuclear plant at the end of its current operating cycle and permanently ceased generation operations on September 17, 2018.

As a result of these early nuclear plant retirement decisions, Exelon and Generation recognized incremental non-cash charges to earnings stemming from shortening the expected economic useful lives primarily related to accelerated depreciation of plant assets (including any ARC) and accelerated amortization of nuclear fuel, as well as operating and maintenance expenses. See Note 13 — Nuclear Decommissioning for additional information on changes to the nuclear decommissioning ARO balance. The total impact for the three and nine months ended September 30, 2019 and 2018 are summarized in the table below.



	Three Months Ended September 30,				Nine Months Ended September 30,
Income statement expense (pre-tax)	2019		2018		2019			2018
Depreciation and amortization^(a)
Accelerated depreciation	$	71	$	152	$	216		$	441
Accelerated nuclear fuel amortization	3		18		13			52
Operating and maintenance^(b)	39		4		(44		)	32
Total	$	113	$	174	$	185		$	525

_________


(a)	Reflects incremental accelerated depreciation and amortization for TMI for the three and nine months ended September 30, 2019. Reflects incremental accelerated depreciation for TMI and Oyster Creek for the three and nine months ended September 30, 2018. The Oyster Creek amounts are from February 2, 2018 through September 17, 2018. The TMI amounts are through September 20, 2019.

(b)

In 2019, primarily reflects the net impacts associated with the remeasurements of the TMI ARO in the first and third quarters. See Note 13 — Nuclear Decommissioning for additional information on the first quarter 2019 TMI ARO update. In 2018, primarily reflects materials and supplies inventory reserve adjustments, employee related costs and CWIP impairments associated with the early retirement decisions for TMI and Oyster Creek. Excludes the charges in the third quarter of 2018 and second quarter of 2019 to Operating and maintenance expense for the ARO remeasurement due to the sale of Oyster Creek. See Note 3 — Mergers, Acquisitions and Dispositions for additional information.

Generation’s Dresden, Byron and Braidwood nuclear plants in Illinois are also showing increased signs of economic distress, which could lead to an early retirement, in a market that does not currently compensate them for their unique contribution to grid resiliency and their ability to produce large amounts of energy without carbon and air pollution. The May 2018 PJM capacity auction for the 2021-2022 planning year resulted in the largest volume of nuclear capacity ever not selected in the auction, including all of Dresden, and portions of Byron and Braidwood. Exelon continues to work with stakeholders on state policy solutions, while also advocating for broader market reforms at the regional and federal level.

Other Generation

On March 29, 2018, Generation notified grid operator ISO-NE of its plans to early retire its Mystic Generating Station assets absent regulatory reforms on June 1, 2022, at the end of the then-current capacity commitment for Mystic Units 7 and 8. Mystic Unit 9 was then committed through May 2021.

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 and 9 for the period between June 1, 2022 - May 31, 2024. On December 20, 2018, FERC issued an order accepting the cost of service agreement 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 Everett Marine Terminal. Those adjustments were reflected in a compliance filing filed March 1, 2019. In the December 20, 2018 order, FERC also directed a paper hearing on ROE using a new methodology. Initial briefs in the ROE proceeding were filed on April 19, 2019 and reply briefs were filed on July 18, 2019. On January 4, 2019, Generation notified ISO-NE that it will participate in the Forward Capacity Market auction for the 2022 - 2023 capacity commitment period. In addition, on January 22, 2019, Exelon and several other parties filed requests for rehearing of certain findings of the December 20, 2018 order, which does not alter Generation's commitment to participate in the Forward Capacity Auction for the 2022-2023 capacity commitment period. On June 10, 2019, ISO-NE announced that it has determined that Mystic 8 and 9 are needed for fuel security for the 2023-2024 capacity commitment period.

On March 25, 2019, ISO-NE filed the Inventoried Energy Program, which is intended to provide an interim fuel security program pending conclusion of the stakeholder process to develop a long-term, market-based solution to address fuel security. Exelon filed comments on the Inventoried Energy Program proposal on April 15, 2019. On May 8, 2019, FERC issued a deficiency letter to ISO-NE seeking additional information on the Inventoried Energy Program proposal, and ISO-NE filed a response on June 6, 2019. On August 5, 2019, FERC allowed the Inventoried Energy Program to take effect by operation of law. Several parties have filed requests for rehearing. FERC ordered ISO-NE to file long-term, market-based fuel security rules by October 15, 2019. On August 30, 2019, FERC granted an extension of time to file the long-term, market-based fuel security rules to April 15, 2020.

The following table provides the balance sheet amounts as of September 30, 2019 for Exelon's and Generation’s significant assets and liabilities associated with the Mystic Units 8 and 9 and Everett Marine Terminal assets that would potentially be impacted by the failure to adopt long-term solutions for reliability and fuel security.



	September 30, 2019
Asset Balances
Materials and supplies inventory	$	31
Fuel inventory	5
Completed plant, net	889
Construction work in progress	7
Liability Balances
Asset retirement obligation	(2		)

Fair Value of Financial Assets and Liabilities (All Registrants)

9 Months Ended

Sep. 30, 2019

Fair Value Disclosures [Abstract]

Fair Value of Financial Assets and Liabilities (All Registrants)

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


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


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


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

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 11 — Fair Value of Financial Assets and Liabilities of the Exelon 2018 Form 10-K, unless otherwise noted below.

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, 2019 and December 31, 2018. The Registrants have no financial liabilities classified as Level 1.

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



	September 30, 2019								December 31, 2018
	Carrying Amount		Fair Value						Carrying Amount		Fair Value
	Carrying Amount		Level 2		Level 3		Total		Carrying Amount		Level 2		Level 3		Total
Long-Term Debt, including amounts due within one year^(a)
Exelon	$	36,304	$	38,056	$	2,541	$	40,597	$	35,424	$	33,711	$	2,158	$	35,869
Generation	8,613		7,962		1,398		9,360		8,793		7,467		1,443		8,910
ComEd	8,196		9,622		—		9,622		8,101		8,390		—		8,390
PECO	3,404		3,891		50		3,941		3,084		3,157		50		3,207
BGE	3,270		3,678		—		3,678		2,876		2,950		—		2,950
PHI	6,494		5,993		1,093		7,086		6,259		5,436		665		6,101
Pepco	2,860		3,249		395		3,644		2,719		2,901		196		3,097
DPL	1,495		1,437		232		1,669		1,494		1,303		193		1,496
ACE	1,324		1,034		466		1,500		1,188		987		275		1,262
Long-Term Debt to Financing Trusts^(a)
Exelon	$	390	$	—	$	426	$	426	$	390	$	—	$	400	$	400
ComEd	205		—		223		223		205		—		209		209
PECO	184		—		203		203		184		—		191		191
SNF Obligation
Exelon	$	1,193	$	1,017	$	—	$	1,017	$	1,171	$	949	$	—	$	949
Generation	1,193		1,017		—		1,017		1,171		949		—		949

____


(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, 2019 and December 31, 2018:

Exelon and Generation



	Exelon										Generation
As of September 30, 2019	Level 1		Level 2		Level 3		Not subject to leveling		Total		Level 1		Level 2		Level 3		Not subject to leveling		Total
Assets
Cash equivalents^(a)	$	1,719	$	—	$	—	$	—	$	1,719	$	896	$	—	$	—	$	—	$	896
NDT fund investments
Cash equivalents^(b)	315		78		—		—		393		315		78		—		—		393
Equities	3,121		1,727		—		1,314		6,162		3,121		1,727		—		1,314		6,162
Fixed income
Corporate debt	—		1,473		259		—		1,732		—		1,473		259		—		1,732
U.S. Treasury and agencies	1,777		152		—		—		1,929		1,777		152		—		—		1,929
Foreign governments	—		56		—		—		56		—		56		—		—		56
State and municipal debt	—		85		—		—		85		—		85		—		—		85
Other^(c)	—		23		—		979		1,002		—		23		—		979		1,002



	Exelon														Generation
As of September 30, 2019	Level 1			Level 2			Level 3			Not subject to leveling		Total			Level 1			Level 2			Level 3			Not subject to leveling		Total
Fixed income subtotal	1,777			1,789			259			979		4,804			1,777			1,789			259			979		4,804
Middle market lending	—			—			255			445		700			—			—			255			445		700
Private equity	—			—			—			398		398			—			—			—			398		398
Real estate	—			—			—			581		581			—			—			—			581		581
NDT fund investments subtotal^(d)	5,213			3,594			514			3,717		13,038			5,213			3,594			514			3,717		13,038
Rabbi trust investments
Cash equivalents	49			—			—			—		49			4			—			—			—		4
Mutual funds	77			—			—			—		77			24			—			—			—		24
Fixed income	—			13			—			—		13			—			—			—			—		—
Life insurance contracts	—			76			40			—		116			—			24			—			—		24
Rabbi trust investments subtotal	126			89			40			—		255			28			24			—			—		52
Commodity derivative assets
Economic hedges	533			1,488			1,817			—		3,838			533			1,488			1,817			—		3,838
Proprietary trading	—			54			156			—		210			—			54			156			—		210
Effect of netting and allocation of collateral^(e)(f)	(677		)	(1,261		)	(1,025		)	—		(2,963		)	(677		)	(1,261		)	(1,025		)	—		(2,963		)
Commodity derivative assets subtotal	(144		)	281			948			—		1,085			(144		)	281			948			—		1,085
Total assets	6,914			3,964			1,502			3,717		16,097			5,993			3,899			1,462			3,717		15,071
Liabilities
Commodity derivative liabilities
Economic hedges	(773		)	(1,695		)	(1,686		)	—		(4,154		)	(773		)	(1,695		)	(1,406		)	—		(3,874		)
Proprietary trading	—			(59		)	(89		)	—		(148		)	—			(59		)	(89		)	—		(148		)
Effect of netting and allocation of collateral^(e)(f)	770			1,585			1,329			—		3,684			770			1,585			1,329			—		3,684
Commodity derivative liabilities subtotal	(3		)	(169		)	(446		)	—		(618		)	(3		)	(169		)	(166		)	—		(338		)
Deferred compensation obligation	—			(140		)	—			—		(140		)	—			(37		)	—			—		(37		)
Total liabilities	(3		)	(309		)	(446		)	—		(758		)	(3		)	(206		)	(166		)	—		(375		)
Total net assets	$	6,911		$	3,655		$	1,056		$	3,717	$	15,339		$	5,990		$	3,693		$	1,296		$	3,717	$	14,696



	Exelon														Generation
As of December 31, 2018	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)	$	1,243		$	—		$	—		$	—	$	1,243		$	581		$	—		$	—		$	—	$	581
NDT fund investments
Cash equivalents^(b)	252			86			—			—		338			252			86			—			—		338
Equities	2,918			1,591			—			1,381		5,890			2,918			1,591			—			1,381		5,890
Fixed income
Corporate debt	—			1,593			230			—		1,823			—			1,593			230			—		1,823
U.S. Treasury and agencies	2,081			99			—			—		2,180			2,081			99			—			—		2,180
Foreign governments	—			50			—			—		50			—			50			—			—		50
State and municipal debt	—			149			—			—		149			—			149			—			—		149
Other^(c)	—			30			—			846		876			—			30			—			846		876
Fixed income subtotal	2,081			1,921			230			846		5,078			2,081			1,921			230			846		5,078
Middle market lending	—			—			313			367		680			—			—			313			367		680
Private equity	—			—			—			329		329			—			—			—			329		329
Real estate	—			—			—			510		510			—			—			—			510		510
NDT fund investments subtotal^(d)	5,251			3,598			543			3,433		12,825			5,251			3,598			543			3,433		12,825
Rabbi trust investments
Cash equivalents	48			—			—			—		48			5			—			—			—		5
Mutual funds	72			—			—			—		72			24			—			—			—		24
Fixed income	—			15			—			—		15			—			—			—			—		—
Life insurance contracts	—			70			38			—		108			—			22			—			—		22
Rabbi trust investments subtotal	120			85			38			—		243			29			22			—			—		51
Commodity derivative assets
Economic hedges	541			2,760			1,470			—		4,771			541			2,760			1,470			—		4,771
Proprietary trading	—			69			77			—		146			—			69			77			—		146
Effect of netting and allocation of collateral^(e)(f)	(582		)	(2,357		)	(732		)	—		(3,671		)	(582		)	(2,357		)	(732		)	—		(3,671		)
Commodity derivative assets subtotal	(41		)	472			815			—		1,246			(41		)	472			815			—		1,246
Total assets	6,573			4,155			1,396			3,433		15,557			5,820			4,092			1,358			3,433		14,703



	Exelon														Generation
As of December 31, 2018	Level 1			Level 2			Level 3			Not subject to leveling		Total			Level 1			Level 2			Level 3			Not subject to leveling		Total
Liabilities
Commodity derivative liabilities
Economic hedges	(642		)	(2,963		)	(1,276		)	—		(4,881		)	(642		)	(2,963		)	(1,027		)	—		(4,632		)
Proprietary trading	—			(73		)	(21		)	—		(94		)	—			(73		)	(21		)	—		(94		)
Effect of netting and allocation of collateral^(e)(f)	639			2,581			808			—		4,028			639			2,581			808			—		4,028
Commodity derivative liabilities subtotal	(3		)	(455		)	(489		)	—		(947		)	(3		)	(455		)	(240		)	—		(698		)
Deferred compensation obligation	—			(137		)	—			—		(137		)	—			(35		)	—			—		(35		)
Total liabilities	(3		)	(592		)	(489		)	—		(1,084		)	(3		)	(490		)	(240		)	—		(733		)
Total net assets	$	6,570		$	3,563		$	907		$	3,433	$	14,473		$	5,817		$	3,602		$	1,118		$	3,433	$	13,970

_________

(a)

Exelon excludes cash of $347 million and $458 million at September 30, 2019 and December 31, 2018, respectively, and restricted cash of $112 million and $80 million at September 30, 2019 and December 31, 2018, respectively, and includes long-term restricted cash of $186 million and $185 million at September 30, 2019 and December 31, 2018, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. Generation excludes cash of $183 million and $283 million at September 30, 2019 and December 31, 2018, respectively, and restricted cash of $66 million and $39 million at September 30, 2019 and December 31, 2018, respectively.


(b)	Includes $85 million and $50 million of cash received from outstanding repurchase agreements at September 30, 2019 and December 31, 2018, respectively, and is offset by an obligation to repay upon settlement of the agreement as discussed in (d) below.

(c)

Includes a derivative liability of $2 million and a derivative asset of $44 million, which have total notional amounts of $864 million and $1,432 million at September 30, 2019 and December 31, 2018, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not represent the amount of Exelon and Generation's exposure to credit or market loss.

(d)

Excludes net liabilities of $176 million and $130 million at September 30, 2019 and December 31, 2018, 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.

(e)

Collateral posted/(received) from counterparties totaled $93 million, $324 million and $304 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of September 30, 2019. Collateral posted/(received) from counterparties, net of collateral paid to counterparties, totaled $57 million, $224 million and $76 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2018.


(f)	Of the collateral posted/(received), $306 million and $(94) million represents variation margin on the exchanges as of September 30, 2019 and December 31, 2018, respectively.

As of September 30, 2019, Exelon and Generation have outstanding commitments to invest in fixed income, middle market lending, private equity and real estate investments of approximately $93 million, $241 million, $383 million, and $388 million, respectively. These commitments will be funded by Generation’s existing NDT funds.

Exelon and Generation hold investments without readily determinable fair values with carrying amounts of $75 million as of September 30, 2019. Changes were immaterial in fair value, cumulative adjustments and impairments for the three and nine months ended September 30, 2019.

Valuation Techniques Used to Determine Net Asset Value

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

ComEd, PECO and BGE



	ComEd											PECO										BGE
As of September 30, 2019	Level 1		Level 2			Level 3			Total			Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3		Total
Assets
Cash equivalents^(a)	$	264	$	—		$	—		$	264		$	207	$	—		$	—	$	207		$	122	$	—		$	—	$	122
Rabbi trust investments
Mutual funds	—		—			—			—			8		—			—		8			7		—			—		7
Life insurance contracts	—		—			—			—			—		11			—		11			—		—			—		—
Rabbi trust investments subtotal	—		—			—			—			8		11			—		19			7		—			—		7
Total assets	264		—			—			264			215		11			—		226			129		—			—		129
Liabilities
Deferred compensation obligation	—		(7		)	—			(7		)	—		(8		)	—		(8		)	—		(5		)	—		(5		)
Mark-to-market derivative liabilities^(b)	—		—			(280		)	(280		)	—		—			—		—			—		—			—		—
Total liabilities	—		(7		)	(280		)	(287		)	—		(8		)	—		(8		)	—		(5		)	—		(5		)
Total net assets (liabilities)	$	264	$	(7	)	$	(280	)	$	(23	)	$	215	$	3		$	—	$	218		$	129	$	(5	)	$	—	$	124



	ComEd											PECO										BGE
As of December 31, 2018	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)	$	209	$	—		$	—		$	209		$	111	$	—		$	—	$	111		$	4	$	—		$	—	$	4
Rabbi trust investments
Mutual funds	—		—			—			—			7		—			—		7			6		—			—		6
Life insurance contracts	—		—			—			—			—		10			—		10			—		—			—		—
Rabbi trust investments subtotal	—		—			—			—			7		10			—		17			6		—			—		6
Total assets	209		—			—			209			118		10			—		128			10		—			—		10
Liabilities
Deferred compensation obligation	—		(6		)	—			(6		)	—		(10		)	—		(10		)	—		(5		)	—		(5		)
Mark-to-market derivative liabilities^(b)	—		—			(249		)	(249		)	—		—			—		—			—		—			—		—
Total liabilities	—		(6		)	(249		)	(255		)	—		(10		)	—		(10		)	—		(5		)	—		(5		)
Total net assets (liabilities)	$	209	$	(6	)	$	(249	)	$	(46	)	$	118	$	—		$	—	$	118		$	10	$	(5	)	$	—	$	5

_________

(a)

ComEd excludes cash of $76 million and $93 million at September 30, 2019 and December 31, 2018, respectively, and restricted cash of $31 million and $28 million at September 30, 2019 and December 31, 2018, respectively, and includes long-term restricted cash of $171 million and $166 million at September 30, 2019 and December 31, 2018, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. PECO excludes cash of $23 million and $24 million at September 30, 2019 and December 31, 2018, respectively. BGE excludes cash of $8 million and $7 million at September 30, 2019 and December 31, 2018, respectively, and restricted cash of $1 million and $2 million at September 30, 2019 and December 31, 2018, respectively.


(b)	The Level 3 balance consists of the current and noncurrent liability of $27 million and $253 million, respectively, at September 30, 2019, and $26 million and $223 million, respectively, at December 31, 2018, related to floating-to-fixed energy swap contracts with unaffiliated suppliers.

PHI, Pepco, DPL and ACE



	As of September 30, 2019										As of December 31, 2018
PHI	Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3		Total
Assets
Cash equivalents^(a)	$	107	$	—		$	—	$	107		$	147	$	—		$	—	$	147
Rabbi trust investments
Cash equivalents	43		—			—		43			42		—			—		42
Mutual funds	13		—			—		13			13		—			—		13
Fixed income	—		13			—		13			—		15			—		15
Life insurance contracts	—		24			40		64			—		22			38		60
Rabbi trust investments subtotal	56		37			40		133			55		37			38		130
Total assets	163		37			40		240			202		37			38		277
Liabilities
Deferred compensation obligation	—		(19		)	—		(19		)	—		(21		)	—		(21		)
Total liabilities	—		(19		)	—		(19		)	—		(21		)	—		(21		)
Total net assets	$	163	$	18		$	40	$	221		$	202	$	16		$	38	$	256



	Pepco										DPL								ACE
As of September 30, 2019	Level 1		Level 2			Level 3		Total			Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents^(a)	$	34	$	—		$	—	$	34		$	—	$	—	$	—	$	—	$	18	$	—	$	—	$	18
Rabbi trust investments
Cash equivalents	43		—			—		43			—		—		—		—		—		—		—		—
Fixed income	—		3			—		3			—		—		—		—		—		—		—		—
Life insurance contracts	—		24			40		64			—		—		—		—		—		—		—		—
Rabbi trust investments subtotal	43		27			40		110			—		—		—		—		—		—		—		—
Total assets	77		27			40		144			—		—		—		—		18		—		—		18
Liabilities
Deferred compensation obligation	—		(2		)	—		(2		)	—		—		—		—		—		—		—		—
Total liabilities	—		(2		)	—		(2		)	—		—		—		—		—		—		—		—
Total net assets	$	77	$	25		$	40	$	142		$	—	$	—	$	—	$	—	$	18	$	—	$	—	$	18



	Pepco										DPL										ACE
As of December 31, 2018	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)	$	38	$	—		$	—	$	38		$	16	$	—		$	—	$	16		$	23	$	—	$	—	$	23
Rabbi trust investments
Cash equivalents	41		—			—		41			—		—			—		—			—		—		—		—
Fixed income	—		5			—		5			—		—			—		—			—		—		—		—
Life insurance contracts	—		22			37		59			—		—			—		—			—		—		—		—
Rabbi trust investments subtotal	41		27			37		105			—		—			—		—			—		—		—		—
Total assets	79		27			37		143			16		—			—		16			23		—		—		23
Liabilities
Deferred compensation obligation	—		(3		)	—		(3		)	—		(1		)	—		(1		)	—		—		—		—
Total liabilities	—		(3		)	—		(3		)	—		(1		)	—		(1		)	—		—		—		—
Total net assets (liabilities)	$	79	$	24		$	37	$	140		$	16	$	(1	)	$	—	$	15		$	23	$	—	$	—	$	23

_________

(a)

PHI excludes cash of $45 million and $39 million at September 30, 2019 and December 31, 2018, respectively, and includes long-term restricted cash of $15 million and $19 million at September 30, 2019 and December 31, 2018, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. Pepco excludes cash of $18 million and $15 million at September 30, 2019 and December 31, 2018, respectively. DPL excludes cash of $11 million and $8 million at September 30, 2019 and December 31, 2018, respectively. ACE excludes cash of $13 million and $7 million at September 30, 2019 and December 31, 2018, respectively, and includes long-term restricted cash of $15 million and $19 million at September 30, 2019 and December 31, 2018, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets.

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, 2019 and 2018:



	Exelon			Generation										ComEd				PHI and Pepco
Three Months Ended September 30, 2019	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, 2019	$	1,179		$	539		$	873			$	1,412		$	(273	)		$	40	$	—
Total realized / unrealized gains (losses)
Included in net income	(171		)	2			(173		)	^(a)	(171		)	—				—		—
Included in noncurrent payables to affiliates	—			11			—				11			—				—		(11		)
Included in regulatory assets/liabilities	4			—			—				—			(7		)	^(b)	—		11
Change in collateral	41			—			41				41			—				—		—
Purchases, sales, issuances and settlements
Purchases	53			1			52				53			—				—		—
Sales	(22		)	(21		)	(1		)		(22		)	—				—		—
Settlements	(18		)	(18		)	—				(18		)	—				—		—
Transfers into Level 3	1			—			1			^(c)	1			—				—		—
Transfers out of Level 3	(11		)	—			(11		)	^(c)	(11		)	—				—		—
Balance at September 30, 2019	$	1,056		$	514		$	782			$	1,296		$	(280	)		$	40	$	—
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, 2019	$	(18	)	$	2		$	(20	)		$	(18	)	$	—			$	—	$	—



	Exelon			Generation										ComEd				PHI and Pepco
Nine Months Ended September 30, 2019	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, 2018	$	907		$	543		$	575			$	1,118		$	(249	)		$	38	$	—
Total realized / unrealized gains (losses)
Included in net income	(125		)	5			(132		)	^(a)	(127		)	—				2		—
Included in noncurrent payables to affiliates	—			32			—				32			—				—		(32		)
Included in regulatory assets	1			—			—				—			(31		)	^(b)	—		32
Change in collateral	227			—			227				227			—				—		—
Purchases, sales, issuances and settlements
Purchases	163			43			120				163			—				—		—
Sales	(23		)	(21		)	(2		)		(23		)	—				—		—
Settlements	(88		)	(88		)	—				(88		)	—				—		—
Transfers into Level 3	5			—			5			^(c)	5			—				—		—
Transfers out of Level 3	(11		)	—			(11		)	^(c)	(11		)	—				—		—
Balance as of September 30, 2019	$	1,056		$	514		$	782			$	1,296		$	(280	)		$	40	$	—
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2019	$	173		$	5		$	166			$	171		$	—			$	2	$	—

__________


(a)	Includes a reduction for the reclassification of $153 million and $298 million of realized gains due to the settlement of derivative contracts for the three and nine months ended September 30, 2019, respectively.

(b)

Includes $7 million of decreases in fair value and an increase for realized losses due to settlements of $4 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended September 30, 2019. Includes $31 million of decreases in fair value and an increase for realized losses due to settlements of $17 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the nine months ended September 30, 2019.


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



	Exelon			Generation										ComEd				PHI and Pepco
Three Months Ended September 30, 2018	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, 2018	$	1,106		$	585		$	737			$	1,322		$	(252	)		$	36	$	—
Total realized / unrealized gains (losses)
Included in net income	(259		)	(1		)	(259		)	^(a)	(260		)	—				1		—
Included in noncurrent payables to affiliates	—			(4		)	—				(4		)	—				—		4
Included in regulatory assets	(11		)	—			—				—			(7		)	^(b)	—		(4		)
Change in collateral	(44		)	—			(44		)		(44		)	—				—		—
Purchases, sales, issuances and settlements
Purchases	96			15			81				96			—				—		—
Settlements	(29		)	(29		)	—				(29		)	—				—		—
Transfers into Level 3	3			—			3			^(c)	3			—				—		—
Transfers out of Level 3	(6		)	—			(6		)	^(c)	(6		)	—				—		—
Balance as of September 30, 2018	$	856		$	566		$	512			$	1,078		$	(259	)		$	37	$	—
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2018	$	(105	)	$	(1	)	$	(104	)		$	(105	)	$	—			$	—	$	—



	Exelon			Generation										ComEd				PHI and Pepco
Nine Months Ended September 30, 2018	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, 2017	$	966		$	648		$	552			$	1,200		$	(256	)		$	22	$	—
Total realized / unrealized gains (losses)
Included in net income	(186		)	(1		)	(188		)	^(a)	(189		)	—				3		—
Included in regulatory assets	(3		)	—			—				—			(3		)	^(b)	—		—
Change in collateral	14			—			14				14			—				—		—
Purchases, sales, issuances and settlements
Purchases	215			34			181				215			—				—		—
Sales	(3		)	—			(3		)		(3		)	—				—		—
Settlements	(103		)	(115		)	—				(115		)	—				12		—
Transfers into Level 3	(21		)	—			(21		)	^(c)	(21		)	—				—		—
Transfers out of Level 3	(23		)	—			(23		)	^(c)	(23		)	—				—		—
Balance as of September 30, 2018	$	856		$	566		$	512			$	1,078		$	(259	)		$	37	$	—
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2018	$	154		$	(5	)	$	159			$	154		$	—			$	—	$	—

__________


(a)	Includes a reduction for the reclassification of $155 million and $347 million of realized losses due to the settlement of derivative contracts for the three and nine months ended September 30, 2018, respectively.

(b)

Includes $4 million of increases in fair value and an increase for realized losses due to settlements of $3 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended September 30, 2018. Includes $9 million of decreases in fair value and an increase for realized losses due to settlements of $12 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the nine months ended September 30, 2018.


(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, 2019 and 2018:



	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 realized (losses) gains for the three months ended September 30, 2019	$	(25	)	$	(148	)	$	—	$	2	$	(25	)	$	(148	)	$	2	$	—
Total realized gains (losses) for the nine months ended September 30, 2019	122			(254		)	—		5		122			(254		)	5		—
Total unrealized gains (losses) for the three months ended September 30, 2019	99			(119		)	—		2		99			(119		)	2		—
Total unrealized gains (losses) for the nine months ended September 30, 2019	368			(202		)	2		5		368			(202		)	5		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 realized (losses) gains for the three months ended September 30, 2018	$	(176	)	$	(83	)	$	1	$	(1	)	$	(176	)	$	(83	)	$	(1	)	$	1
Total realized (losses) gains for the nine months ended September 30, 2018	(32		)	(156		)	3		(1		)	(32		)	(156		)	(1		)	3
Total unrealized (losses) for the three months ended September 30, 2018	(64		)	(40		)	—		(1		)	(64		)	(40		)	(1		)	—
Total unrealized gains (losses) for the nine months ended September 30, 2018	174			(15		)	—		(5		)	174			(15		)	(5		)	—

The table below discloses the significant inputs to the forward curve used to value these positions.



Type of trade	Fair Value at September 30, 2019			Fair Value at December 31, 2018			Valuation Technique	Unobservable Input	2019 Range			2018 Range
Mark-to-market derivatives — Economic Hedges (Exelon and Generation)^(a)(b)	$	411		$	443		Discounted Cash Flow	Forward power price	$11	-	$167	$12	-	$174
								Forward gas price	$1.36	-	$10.82	$0.78	-	$12.38
							Option Model	Volatility percentage	9%	-	200%	10%	-	277%

Mark-to-market derivatives — Proprietary trading (Exelon and Generation)^(a)(b)	$	67		$	56		Discounted Cash Flow	Forward power price	$17	-	$167	$14	-	$174

Mark-to-market derivatives (Exelon and ComEd)	$	(280	)	$	(249	)	Discounted Cash Flow	Forward heat rate^(c)	9x	-	10x	10x	-	11x
								Marketability reserve	4%	-	7%	4%	-	8%
								Renewable factor	87%	-	119%	86%	-	120%

_________


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


(b)	The fair values do not include cash collateral posted on level three positions of $304 million and $76 million as of September 30, 2019 and December 31, 2018, 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.

- Definition

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

Derivative Financial Instruments (All Registrants)

9 Months Ended

Sep. 30, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments (All Registrants)

Derivative Financial Instruments (All Registrants)

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

Authoritative guidance requires that derivative instruments be recognized as either assets or liabilities at fair value, with changes in fair value of the derivative recognized in earnings immediately. Other accounting treatments are available through special election and designation, provided they meet specific, restrictive criteria both at the time of designation and on an ongoing basis. These alternative permissible accounting treatments include NPNS, cash flow hedges and fair value hedges. All derivative economic hedges related to commodities, referred to as economic hedges, are recorded at fair value through earnings at Generation and offset by a corresponding regulatory asset or liability at ComEd. For all NPNS derivative instruments, accounts receivable or accounts payable are recorded when derivative settles and revenue or expense is recognized in earnings as the underlying physical commodity is sold or consumed.

Authoritative guidance about offsetting assets and liabilities requires the fair value of derivative instruments to be shown in the Combined Notes to Consolidated Financial Statements on a gross basis, even when the derivative instruments are subject to legally enforceable master netting agreements and qualify for net presentation in the Consolidated Balance Sheets. A master netting agreement is an agreement between two counterparties that may have derivative and non-derivative contracts with each other providing for the net settlement of all referencing 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 that 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.
ComEd	Electricity	Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability^(a)	20-year floating-to-fixed energy swap contracts beginning June 2012 based on the renewable energy resource procurement requirements in the Illinois Settlement Legislation of approximately 1.3 million MWhs per year.
PECO^(b)	Gas	NPNS	Fixed price contracts to cover about 20% 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.
BGE	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 price contracts through full requirements contracts.
	Gas	Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability ^(c)	Exchange traded future contracts for 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 4 - Regulatory Matters for additional information.


(b)	As part of its hedging program, PECO enters into electric supply procurement contracts that do not meet the definition of a derivative instrument.


(c)	The fair value of the DPL economic hedge is not material as of September 30, 2019 and December 31, 2018 and is not presented in the fair value tables below.

The following table provides a summary of the derivative fair value balances recorded by Exelon, Generation and ComEd as of September 30, 2019 and December 31, 2018:



September 30, 2019	Exelon			Generation														ComEd
Derivatives	Total Derivatives			Economic Hedges			Proprietary Trading			Collateral ^(a)(b)		Netting ^(a)			Subtotal			Economic Hedges
Mark-to-market derivative assets (current assets)	$	602		$	2,452		$	143		$	212	$	(2,205	)	$	602		$	—
Mark-to-market derivative assets (noncurrent assets)	483			1,386			67			104		(1,074		)	483			—
Total mark-to-market derivative assets	1,085			3,838			210			316		(3,279		)	1,085			—
Mark-to-market derivative liabilities (current liabilities)	(224		)	(2,550		)	(101		)	249		2,205			(197		)	(27		)
Mark-to-market derivative liabilities (noncurrent liabilities)	(394		)	(1,324		)	(47		)	156		1,074			(141		)	(253		)
Total mark-to-market derivative liabilities	(618		)	(3,874		)	(148		)	405		3,279			(338		)	(280		)
Total mark-to-market derivative net assets (liabilities)	$	467		$	(36	)	$	62		$	721	$	—		$	747		$	(280	)



December 31, 2018	Exelon			Generation														ComEd
Description	Total Derivatives			Economic Hedges			Proprietary Trading			Collateral (a)(b)		Netting (a)			Subtotal			Economic Hedges
Mark-to-market derivative assets (current assets)	$	801		$	3,505		$	105		$	121	$	(2,930	)	$	801		$	—
Mark-to-market derivative assets (noncurrent assets)	445			1,266			41			51		(913		)	445			—
Total mark-to-market derivative assets	1,246			4,771			146			172		(3,843		)	1,246			—
Mark-to-market derivative liabilities (current liabilities)	(473		)	(3,429		)	(74		)	125		2,931			(447		)	(26		)
Mark-to-market derivative liabilities (noncurrent liabilities)	(474		)	(1,203		)	(20		)	60		912			(251		)	(223		)
Total mark-to-market derivative liabilities	(947		)	(4,632		)	(94		)	185		3,843			(698		)	(249		)
Total mark-to-market derivative net assets (liabilities)	$	299		$	139		$	52		$	357	$	—		$	548		$	(249	)

_________

(a)

Exelon and Generation net all available amounts allowed under the derivative authoritative guidance in the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, letters of credit and other forms of non-cash collateral. These amounts are immaterial and not reflected in the table above.


(b)	Of the collateral posted/(received), $306 million and $(94) million represents variation margin on the exchanges at September 30, 2019 and December 31, 2018 respectively.

Economic Hedges (Commodity Price Risk)

Generation. For the three and nine months ended September 30, 2019 and 2018, Exelon and Generation recognized the following net pre-tax commodity mark-to-market gains (losses) which are also located in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows.



	Three Months Ended September 30,					Nine Months Ended September 30,
	2019			2018		2019			2018
Income Statement Location	Gain (Loss)					Gain (Loss)
Operating revenues	$	76		$	8	$	65		$	(99	)
Purchased power and fuel	(45		)	66		(127		)	(4		)
Total Exelon and Generation	$	31		$	74	$	(62	)	$	(103	)

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, 2019, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York and ERCOT reportable segments is 96%-99%, 84%-87% and 54%-57% for 2019, 2020 and 2021, respectively.

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, 2019 and 2018, net pre-tax commodity mark-to-market gains (losses) for Exelon and Generation were not material. The Utility Registrants do not execute derivatives for proprietary trading purposes.

Interest Rate and Foreign Exchange Risk (Exelon and Generation)

Exelon and Generation utilize interest rate swaps, which are treated as economic hedges, to manage their interest rate exposure. On July 1, 2018, Exelon de-designated its fair value hedges related to interest rate risk and Generation de-designated its cash flow hedges related to interest rate risk. The notional amounts were $1,371 million and $1,420 million at September 30, 2019 and December 31, 2018, respectively, for Exelon and $571 million and $620 million at September 30, 2019 and December 31, 2018, respectively, for Generation.

Generation utilizes foreign currency derivatives to manage foreign exchange rate exposure associated with international commodity purchases in currencies other than U.S. dollars, which are treated as economic hedges. The notional amounts were $257 million and $268 million at September 30, 2019 and December 31, 2018, respectively.

The mark-to-market derivative assets and liabilities as of September 30, 2019 and December 31, 2018 and the mark-to-market gains and losses for the three and nine months ended September 30, 2019 and 2018 were not material for Exelon and Generation.

Credit Risk (All Registrants)

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

Generation. For commodity derivatives, Generation enters into enabling agreements that allow for payment netting with its counterparties, which reduces Generation’s exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. Typically, each enabling agreement is for a specific commodity and so, with respect to each individual counterparty, netting is limited to

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

The following tables provide information on Generation’s credit exposure for all derivative instruments, NPNS and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of September 30, 2019. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties. The figures in the tables below exclude credit risk exposure from individual retail counterparties, nuclear fuel procurement contracts and exposure through RTOs, ISOs, NYMEX, ICE, NASDAQ, NGX and Nodal commodity exchanges. Additionally, the figures in the tables below exclude exposures with affiliates, including net receivables with ComEd, PECO, BGE, Pepco, DPL and ACE of $68 million, $30 million, $32 million, $39 million, $15 million and $8 million as of September 30, 2019, respectively.



Rating as of September 30, 2019	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	$	693	$	10	$	683	—	$	—
Non-investment grade	74		38		36
No external ratings
Internally rated — investment grade	297		1		296
Internally rated — non-investment grade	175		24		151
Total	$	1,239	$	73	$	1,166	—	$	—



Net Credit Exposure by Type of Counterparty	As of September 30, 2019
Financial institutions	$	1
Investor-owned utilities, marketers, power producers	875
Energy cooperatives and municipalities	255
Other	35
Total	$	1,166

_________


(a)	As of September 30, 2019, credit collateral held from counterparties where Generation had credit exposure included $18 million of cash and $55 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, 2019, the Utility Registrants’ counterparty credit risk with suppliers was immaterial.

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, 2019			December 31, 2018
Gross fair value of derivative contracts containing this feature^(a)	$	(1,249	)	$	(1,723	)
Offsetting fair value of in-the-money contracts under master netting arrangements^(b)	947			1,105
Net fair value of derivative contracts containing this feature^(c)	$	(302	)	$	(618	)

_________


(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 a Registrant 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, 2019 and December 31, 2018, 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, 2019		December 31, 2018
Cash collateral posted	$	787	$	418
Letters of credit posted	273		367
Cash collateral held	96		47
Letters of credit held	58		44
Additional collateral required in the event of a credit downgrade below investment grade	1,481		2,104

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, and DPL’s credit rating. As of September 30, 2019, 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 ratings as of September 30, 2019, they could have been required to post incremental collateral to its counterparties of $28 million, $26 million and $11 million, respectively.

Debt and Credit Agreements (All Registrants)

9 Months Ended

Sep. 30, 2019

Debt Disclosure [Abstract]

Debt and Credit Agreements (All Registrants)

Short-Term Borrowings

Exelon Corporate, ComEd, BGE, Pepco, DPL and ACE 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. 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, 2019 and December 31, 2018. Generation and PECO had no commercial paper borrowings as of both September 30, 2019 and December 31, 2018.



	Outstanding Commercial Paper as of				Average Interest Rate on Commercial Paper Borrowings as of
Commercial Paper Issuer	September 30, 2019		December 31, 2018		September 30, 2019		December 31, 2018
Exelon	$	519	$	89	2.50	%	2.15	%
ComEd	387		—		2.51	%	2.14	%
BGE	—		35		2.49	%	2.18	%
PHI	132		54		2.52	%	2.15	%
PEPCO	12		40		2.61	%	2.24	%
DPL	57		—		2.42	%	2.07	%
ACE	63		14		2.57	%	2.21	%

See Note 13— Debt and Credit Agreements of the Exelon 2018 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, which was renewed on March 22, 2018 with an expiration of March 21, 2019. The loan agreement was renewed on March 20, 2019 and will expire on March 19, 2020. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.95% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon's Consolidated Balance Sheet within Short-Term borrowings.

Credit Agreements

On February 21, 2019, Generation entered into a credit agreement establishing a $100 million bilateral credit facility. The facility will mature in March 2021. This facility will solely be used by Generation to issue letters of credit.

Long-Term Debt

Issuance of Long-Term Debt

During the nine months ended September 30, 2019, the following long-term debt was issued:



Company	Type	Interest Rate		Maturity	Amount		Use of Proceeds
Generation	Energy Efficiency Project Financing	3.95	%	August 31, 2020	$	4	Funding to install energy conservation measures for the Fort Meade project.
Generation	Energy Efficiency Project Financing	3.46	%	May 1, 2020	$	39	Funding to install energy conservation measures for the Marine Corps. Logistics Project.
ComEd	First Mortgage Bonds, Series 126	4.00	%	March 1, 2049	$	400	Repay a portion of ComEd’s outstanding commercial paper obligations and fund other general corporate purposes.
PECO	First and Refunding Mortgage Bonds	3.00	%	September 15, 2049	$	325	Repay short-term borrowings and for general corporate purposes
BGE	Senior Notes	3.20	%	September 15, 2049	$	400	Repay commercial paper obligations and for general corporate purposes
Pepco	First Mortgage Bonds	3.45	%	June 13, 2029	$	150	Repay existing indebtedness and for general corporate purposes
Pepco	Unsecured Tax-Exempt Bonds	1.70	%	September 1, 2022	$	110	Refinance existing indebtedness
ACE	First Mortgage Bonds	3.50	%	May 21, 2029	$	100	Repay existing indebtedness and for general corporate purposes
ACE	First Mortgage Bonds	4.14	%	May 21, 2049	$	50	Repay existing indebtedness and for general corporate purposes

Debt Covenants

As of September 30, 2019, the Registrants are in compliance with debt covenants, except for Antelope Valley's nonrecourse debt event of default as discussed below.

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.

Antelope Valley Solar Ranch One. In December 2011, the DOE Loan Programs Office issued a guarantee for up to $646 million for a nonrecourse loan from the Federal Financing Bank to support the financing of the construction of the Antelope Valley facility. The project became fully operational in 2014. The loan will mature on January 5, 2037. As of September 30, 2019, approximately $495 million was outstanding. In 2017, Generation’s interests in Antelope Valley were also contributed to and are pledged as collateral for the EGR IV financing structure referenced below.

Antelope Valley sells all of its output to PG&E through a PPA. On January 29, 2019, PG&E filed for protection under Chapter 11 of the U.S. Bankruptcy Code, which created an event of default for Antelope Valley’s nonrecourse debt that provides the lender with a right to accelerate amounts outstanding under the loan such that they would become immediately due and payable. As a result of the ongoing event of default and the absence of a waiver from the lender foregoing their acceleration rights, the debt was reclassified as current in Exelon’s and Generation’s Consolidated Balance Sheets in the first quarter of 2019 and continues to be classified as current as of September 30, 2019. Further, distributions from Antelope Valley to EGR IV are currently suspended.

ExGen Renewables IV. In November 2017, EGR IV, an indirect subsidiary of Exelon and Generation, entered into an $850 million nonrecourse senior secured term loan credit facility agreement. Generation’s interests in EGRP, Antelope Valley, SolGen, and Albany Green Energy were all contributed to and are pledged as collateral for this

financing. The loan is scheduled to mature on November 28, 2024. As of September 30, 2019, $796 million was outstanding.

Although Antelope Valley’s debt is in default, it is nonrecourse to EGR IV. However, if in the future Antelope Valley were to file for bankruptcy protection as a result of events culminating from PG&E’s bankruptcy proceedings this would represent an event of default for EGR IV’s debt that would provide the lender with an opportunity to accelerate EGR IV’s debt.

See Note 13— Debt and Credit Agreements of the Exelon 2018 Form 10-K for additional information on nonrecourse debt.

Income Taxes (All Registrants)

9 Months Ended

Sep. 30, 2019

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, 2019
	Exelon	Generation	ComEd	PECO	BGE	PHI	Pepco	DPL	ACE
U.S. Federal statutory rate	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	6.4	5.2	8.1	(0.3)	6.3	4.8	1.9	6.6	6.9
Qualified NDT fund income	3.2	7.1	—	—	—	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(4.1)	(8.9)	(0.2)	—	(0.1)	(0.2)	(0.1)	(0.2)	(0.3)
Plant basis differences	(1.7)	—	(1.0)	(7.5)	(1.1)	(1.8)	(2.6)	(0.6)	(1.9)
Production tax credits and other credits	(1.2)	(2.7)	—	—	—	—	—	—	—
Noncontrolling interests	(2.2)	(4.8)	—	—	—	—	—	—	—
Excess deferred tax amortization	(6.5)	—	(9.9)	(3.6)	(8.0)	(17.7)	(16.3)	(13.5)	(23.3)
Other	0.7	0.5	0.4	(0.5)	(0.2)	0.8	1.0	(0.1)	0.7
Effective income tax rate	15.6%	17.4%	18.4%	9.1%	17.9%	6.9%	4.9%	13.2%	3.1%



	Three Months Ended September 30, 2018
	Exelon	Generation	ComEd	PECO	BGE	PHI	Pepco	DPL	ACE
U.S. Federal statutory rate	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	(1.2)	(9.0)	8.3	(3.6)	7.3	0.2	1.0	6.6	7.3
Qualified NDT fund income	2.4	5.8	—	—	—	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(0.6)	(1.1)	(0.2)	(0.1)	—	(0.2)	(0.1)	(0.3)	(0.3)
Plant basis differences	(2.5)	—	(0.3)	(15.2)	(0.8)	(2.0)	(3.4)	(0.7)	(1.3)
Production tax credits and other credits	(1.2)	(2.9)	(0.1)	—	—	—	—	—	—
Noncontrolling interests	(1.1)	(2.8)	—	—	—	—	—	—	—
Excess deferred tax amortization	(6.8)	—	(7.8)	(4.6)	(7.9)	(17.7)	(21.2)	(14.0)	(15.4)
Tax Cuts and Jobs Act of 2017	1.3	3.5	—	—	—	0.2	0.1	—	—
Other	3.2	5.6	0.3	0.9	2.6	0.6	0.3	0.6	0.3
Effective income tax rate	14.5%	20.1%	21.2%	(1.6)%	22.2%	2.1%	(2.3)%	13.2%	11.6%




	Nine Months Ended September 30, 2019
	Exelon	Generation	ComEd	PECO	BGE	PHI	Pepco	DPL	ACE
U.S. Federal statutory rate	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	5.1	4.2	8.2	—	6.4	4.8	2.0	6.7	6.9
Qualified NDT fund income	5.3	11.9	—	—	—	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(1.9)	(4.0)	(0.2)	—	(0.1)	(0.2)	(0.1)	(0.2)	(0.3)
Plant basis differences	(1.6)	—	(0.7)	(6.8)	(1.1)	(1.8)	(2.3)	(0.6)	(2.0)
Production tax credits and other credits	(1.0)	(2.1)	—	—	—	—	—	—	—
Noncontrolling interests	(1.0)	(2.3)	—	—	—	—	—	—	—
Excess deferred tax amortization	(6.0)	—	(9.2)	(2.9)	(7.9)	(18.6)	(17.3)	(15.0)	(23.4)
Other	0.8	(0.1)	0.2	(0.2)	0.1	0.5	0.7	0.2	—
Effective income tax rate	20.7%	28.6%	19.3%	11.1%	18.4%	5.7%	4.0%	12.1%	2.2%



	Nine Months Ended September 30, 2018
	Exelon	Generation	ComEd	PECO	BGE	PHI	Pepco	DPL	ACE
U.S. Federal statutory rate	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	1.7	(2.6)	8.2	(3.6)	6.6	2.7	2.4	6.5	7.3
Qualified NDT fund income	0.9	2.6	—	—	—	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(0.9)	(2.2)	(0.2)	(0.1)	(0.1)	(0.2)	(0.1)	(0.3)	(0.3)
Plant basis differences	(2.7)	—	(0.1)	(15.4)	(0.7)	(1.9)	(2.9)	(0.7)	(1.3)
Production tax credits and other credits	(1.8)	(5.1)	(0.1)	—	—	—	—	—	—
Noncontrolling interests	(1.1)	(3.2)	—	—	—	—	—	—	—
Excess deferred tax amortization	(6.1)	—	(7.6)	(3.4)	(8.1)	(14.5)	(16.5)	(11.0)	(14.0)
Tax Cuts and Jobs Act of 2017	0.2	1.3	(0.2)	—	—	0.3	—	—	—
Other	0.4	2.0	0.1	—	0.9	0.3	—	0.4	0.9
Effective income tax rate	11.6%	13.8%	21.1%	(1.5)%	19.6%	7.7%	3.9%	15.9%	13.6%

Accounting for Uncertainty in Income Taxes

Exelon, Generation, ComEd, PHI and ACE have the following unrecognized tax benefits as of September 30, 2019 and December 31, 2018. PECO, BGE, Pepco and DPL do not have unrecognized tax benefits for the periods presented.



	Exelon		Generation		ComEd		PHI		ACE
September 30, 2019	$	448	$	411	$	—	$	45	$	14
December 31, 2018	$	477	$	408	$	2	$	45	$	14

In 2016, the Tax Court held that Exelon was not entitled to defer a gain on its 1999 like-kind exchange transaction. In addition to the tax and interest related to the gain deferral, the Tax Court also ruled that Exelon was liable for penalties and interest on the penalties. Exelon had fully paid the amounts assessed resulting from the Tax Court decision in 2017. In September 2017, Exelon appealed the Tax Court decision to the U.S. Court of Appeals for the Seventh Circuit. In October 2018, the U.S. Court of Appeals for the Seventh Circuit affirmed the Tax Court’s decision. Exelon filed a petition seeking rehearing of the Seventh Circuit’s decision, but the Seventh Circuit denied that petition in December 2018. In the first quarter of 2019, Exelon elected not to seek a further review by the U.S. Supreme Court. As a result, Exelon's and ComEd's unrecognized tax benefits decreased by approximately $33 million and $2 million, respectively, in the first quarter of 2019.

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

Settlement of Income Tax Audits, Refund Claims, and Litigation

Exelon, Generation, PHI and ACE have the following unrecognized federal and state tax benefits that could significantly decrease within the 12 months after the reporting date as a result of completing audits, potential settlements, refund claims, and the outcomes of pending court cases as of September 30, 2019:



Exelon^(a)		Generation^(a)		PHI^(b)		ACE^(b)
$	425	$	411	$	14	$	14

__________


(a)	Exelon and Generation have $411 million that, if recognized, would decrease the effective tax rate.


(b)	The unrecognized tax benefit related to PHI and ACE, 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

Marginal State Income Tax Rate (Exelon, Generation)

In the third quarter of 2019, Exelon reviewed and updated its marginal state income tax rates based on 2018 state apportionment rates. As a result of the rate changes, the following accounting adjustments were recorded as of September 30, 2019:



	Exelon		Generation
Increase to deferred income tax liability	$	23	$	9
Increase to income tax expense, net of federal taxes	23		9

State Income Tax Law Changes

On June 5, 2019, the Governor of Illinois signed a tax bill which would increase the Illinois corporate income tax rate from 9.50% to 10.49% effective for tax years beginning on or after January 1, 2021. The tax rate is contingent upon ratification of state constitutional amendments in November 2020. The effect of the rate change will be recognized in the period in which the new legislation is enacted. Exelon, Generation and ComEd do not expect a material impact to their financial statements as a result of the rate change.

Nuclear Decommissioning (Exelon and Generation)

9 Months Ended

Sep. 30, 2019

Environmental Remediation Obligations [Abstract]

Nuclear Decommissioning (Exelon and Generation)

Nuclear Decommissioning Asset Retirement Obligations (Exelon and Generation)

Generation has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. To estimate its decommissioning obligation related to its nuclear generating stations for financial accounting and reporting purposes, Generation uses a probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models and discount rates. Generation updates its ARO annually, unless circumstances warrant more frequent updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios.

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

The following table provides a rollforward of the nuclear decommissioning ARO reflected in Exelon’s and Generation’s Consolidated Balance Sheets from December 31, 2018 to September 30, 2019:



Nuclear decommissioning ARO at December 31, 2018 ^(a)(b)	$	10,005
Sale of Oyster Creek	(755		)
Accretion expense	361
Net increase due to changes in, and timing of, estimated future cash flows	211
Costs incurred related to decommissioning plants	(52		)
Nuclear decommissioning ARO at September 30, 2019 ^(a)	$	9,770

_________


(a)	Includes $127 million and $22 million as the current portion of the ARO at September 30, 2019 and December 31, 2018, respectively, which is included in Other current liabilities in Exelon’s and Generation’s Consolidated Balance Sheets.


(b)	Includes $772 million of ARO related to Oyster Creek which was classified as Liabilities held for sale in Exelon's and Generation's Consolidated Balance Sheets at December 31, 2018. See Note 3 — Mergers, Acquisitions and Dispositions for additional information.

During the nine months ended September 30, 2019, Exelon's and Generation’s total nuclear ARO decreased by approximately $235 million, primarily reflecting the sale of Oyster Creek, partially offset by the accretion of the ARO liability due to the passage of time and the net impacts of ARO updates completed during the first and third quarters of 2019.

The first quarter 2019 ARO update included an increase of approximately $330 million for a change in the assumed retirement timing probabilities for certain economically challenged nuclear plants and a $110 million decrease for the impacts of revised decommissioning cost estimates for TMI which incorporate site specific decommissioning planning activities associated with the early retirement of TMI on September 20, 2019. The TMI ARO adjustment resulted in an $85 million decrease in Operating and maintenance expense within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. See Note 8 — Early Plant Retirements for additional information.

The third quarter 2019 ARO update included a decrease of approximately $300 million due to lower estimated costs to decommission Nine Mile Point, Ginna, Braidwood, Byron and LaSalle nuclear units resulting from the completion of updated cost studies, partially offset by an increase of approximately $280 million for other impacts that included updated cost escalation rates, primarily for labor, equipment and materials, and current discount rates. The third quarter ARO adjustment resulted in a $65 million decrease in Operating and maintenance expense within Exelon and Generation's Consolidated Statements of Operations and Comprehensive Income.

NDT Funds (Exelon and Generation)

Exelon and Generation had NDT funds totaling $12,862 million and $12,695 million at September 30, 2019 and December 31, 2018, respectively. The NDT funds included $890 million at December 31, 2018, related to Oyster Creek NDT funds which were classified as Assets held for sale in Exelon's and Generation's Consolidated Balance Sheets. See Note 3 — Mergers, Acquisitions and Dispositions for additional information regarding the sale of Oyster Creek. The NDT funds also include $156 million and $144 million for the current portion of the NDT funds at September 30, 2019 and December 31, 2018, respectively, which are included in Other current assets in Exelon's and Generation's Consolidated Balance Sheets. See Note 17 — Supplemental Financial Information for additional information on activities of the NDT funds.

NRC Minimum Funding Requirements (Exelon and Generation)

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 April 1, 2019 for all units except for Zion Station which is included in a separate report to the NRC submitted by ZionSolutions, LLC. The status report demonstrated adequate decommissioning funding assurance as of December 31, 2018 for all units except for Clinton and Peach Bottom Unit 1. As of February 28, 2019, Clinton demonstrated adequate minimum funding assurance due to market recovery and no further action is required. This demonstration was also included in the

April 1, 2019 submittal. As a former PECO plant, financial assurance for decommissioning Peach Bottom Unit 1 is provided by the NDT fund, collections from PECO ratepayers, and the ability to adjust those collections in accordance with the approved PAPUC tariff. No additional actions are required aside from the PAPUC filing in accordance with the tariff. See Note 15 — Asset Retirement Obligations of the Exelon 2018 Form 10-K for information regarding the amount collected from PECO ratepayers for decommissioning cost.

Retirement Benefits (All Registrants)

9 Months Ended

Sep. 30, 2019

Retirement Benefits [Abstract]

Retirement Benefits (All Registrants)

Effective January 1, 2019, Exelon merged the Exelon Corporation Cash Balance Pension Plan (CBPP) into the Exelon Corporation Retirement Program (ECRP). The merging of the plans is not changing the benefits offered to the plan participants and, thus, has no impact on Exelon's pension obligation. However, beginning in 2019, actuarial losses and gains related to the CBPP and ECRP are being amortized over participants’ average remaining service period of the merged ECRP rather than each individual plan.

Defined Benefit Pension and OPEB

During the first quarter of 2019, Exelon received an updated valuation of its pension and OPEB to reflect actual census data as of January 1, 2019. This valuation resulted in an increase to the pension and OPEB obligations of $75 million and $36 million, respectively. Additionally, accumulated other comprehensive loss increased by $39 million (after-tax) and regulatory assets and liabilities increased by $53 million and decreased by $5 million, respectively.

The majority of the 2019 pension benefit cost for Exelon-sponsored plans is calculated using an expected long-term rate of return on plan assets of 7.00% and a discount rate of 4.31%. The majority of the 2019 OPEB cost is calculated using an expected long-term rate of return on plan assets of 6.67% for funded plans and a discount rate of 4.30%.

A portion of the net periodic benefit cost for all plans is capitalized within the Consolidated Balance Sheets. The following table presents the components of Exelon's net periodic benefit costs, prior to capitalization, for the three and nine months ended September 30, 2019 and 2018.



	Pension Benefits Three Months Ended September 30,						OPEB Three Months Ended September 30,
	2019			2018			2019			2018
Components of net periodic benefit cost:
Service cost	$	89		$	100		$	23		$	28
Interest cost	221			201			47			43
Expected return on assets	(306		)	(312		)	(38		)	(43		)
Amortization of:
Prior service benefit	—			—			(45		)	(47		)
Actuarial loss	104			158			11			18
Settlement charges	7			—			—			—
Contractual termination benefits	1			—			—			—
Net periodic benefit cost	$	116		$	147		$	(2	)	$	(1	)



	Pension Benefits Nine Months Ended September 30,						OPEB Nine Months Ended September 30,
	2019			2018			2019			2018
Components of net periodic benefit cost:
Service cost	$	267		$	303		$	70		$	84
Interest cost	663			602			141			131
Expected return on assets	(918		)	(939		)	(115		)	(130		)
Amortization of:
Prior service cost (benefit)	—			1			(134		)	(140		)
Actuarial loss	310			472			34			50
Settlement charges	7			1			—			—
Contractual termination benefits	1			—			—			—
Net periodic benefit cost	$	330		$	440		$	(4	)	$	(5	)

The amounts below represent the Registrants' allocated pension and OPEB plan 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	2019		2018		2019		2018
Exelon	$	114	$	145	$	326	$	435
Generation	37		50		100		151
ComEd	23		45		70		133
PECO	4		5		9		14
BGE	16		15		47		44
PHI	23		17		71		51
Pepco	6		3		19		10
DPL	4		2		11		5
ACE	4		3		12		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 during the three and nine months ended September 30, 2019 and 2018, respectively.



	Three Months Ended September 30,				Nine Months Ended September 30,
Savings Plan Matching Contributions	2019		2018		2019		2018
Exelon	$	36	$	44	$	101	$	126
Generation	14		23		41		65
ComEd	9		8		26		23
PECO	2		2		7		7
BGE	4		2		9		5
PHI	4		4		8		10
Pepco	1		1		2		2
DPL	1		1		2		2
ACE	1		1		1		2

Changes in Accumulated Other Comprehensive Income (Exelon)

9 Months Ended

Sep. 30, 2019

Changes in Accumulated Other Comprehensive Income [Abstract]

Changes in Accumulated Other Comprehensive Income Note [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, 2019	Losses on Cash Flow Hedges			Pension and Non-Pension Postretirement Benefit Plan Items ^(a)			Foreign Currency Items			AOCI of Investments in Unconsolidated Affiliates ^(b)			Total
Beginning balance	$	(2	)	$	(2,957	)	$	(29	)	$	(2	)	$	(2,990	)
OCI before reclassifications	—			6			(2		)	—			4
Amounts reclassified from AOCI	—			21			—			2			23
Net current-period OCI	—			27			(2		)	2			27
Ending balance	$	(2	)	$	(2,930	)	$	(31	)	$	—		$	(2,963	)



Three Months Ended September 30, 2018	Losses on Cash Flow Hedges			Pension and Non-Pension Postretirement Benefit Plan Items ^(a)			Foreign Currency Items			AOCI of Investments in Unconsolidated Affiliates ^(b)		Total
Beginning balance	$	(2	)	$	(2,890	)	$	(29	)	$	—	$	(2,921	)
OCI before reclassifications	—			5			2			—		7
Amounts reclassified from AOCI	—			45			—			—		45
Net current-period OCI	—			50			2			—		52
Ending balance	$	(2	)	$	(2,840	)	$	(27	)	$	—	$	(2,869	)



Nine Months Ended September 30, 2019	Losses on Cash Flow Hedges			Pension and Non-Pension Postretirement Benefit Plan Items ^(a)			Foreign Currency Items			AOCI of Investments in Unconsolidated Affiliates ^(b)			Total
Beginning balance	$	(2	)	$	(2,960	)	$	(33	)	$	—		$	(2,995	)
OCI before reclassifications	—			(32		)	2			(2		)	(32		)
Amounts reclassified from AOCI	—			62			—			2			64
Net current-period OCI	—			30			2			—			32
Ending balance	$	(2	)	$	(2,930	)	$	(31	)	$	—		$	(2,963	)



Nine Months Ended September 30, 2018	Gains (Losses) on Cash Flow Hedges			Unrealized gains (losses) on Marketable Securities			Pension and Non-Pension Postretirement Benefit Plan Items ^(a)			Foreign Currency Items			AOCI of Investments in Unconsolidated Affiliates ^(b)			Total
Beginning balance	$	(14	)	$	10		$	(2,998	)	$	(23	)	$	(1	)	$	(3,026	)
OCI before reclassifications	11			—			22			(4		)	1			30
Amounts reclassified from AOCI	1			—			136			—			—			137
Net current-period OCI	12			—			158			(4		)	1			167
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard^(c)	—			(10		)	—			—			—			(10		)
Ending balance	$	(2	)	$	—		$	(2,840	)	$	(27	)	$	—		$	(2,869	)

_________


(a)	AOCI amounts are included in the computation of net periodic pension and OPEB cost. See Note 14 — Retirement Benefits for additional information. See Exelon's Statements of Operations and Comprehensive Income for individual components of AOCI.


(b)	All amounts are net of noncontrolling interests.


(c)	Exelon prospectively adopted the new standard Recognition and Measurement of Financial Assets and Liabilities. The standard was adopted as of January 1, 2018, which resulted in an increase to Retained earnings and Accumulated other comprehensive loss of $10 million for Exelon. The amounts reclassified related to Rabbi Trusts.

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	$	6		$	6		$	18		$	18
Actuarial loss reclassified to periodic benefit cost	(13		)	(21		)	(39		)	(65		)
Pension and non-pension postretirement benefit plans valuation adjustment	—			(2		)	14			(8		)

Commitments and Contingencies (All Registrants)

9 Months Ended

Sep. 30, 2019

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies (All Registrants)

The following is an update to the current status of commitments and contingencies set forth in Note 22 of the Exelon 2018 Form 10-K. See Note 5 — Mergers, Acquisitions and Dispositions of the Exelon 2018 Form 10-K for additional information on the PHI Merger commitments.

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, 2019:



Description	Exelon		PHI		Pepco		DPL		ACE
Total commitments	$	513	$	320	$	120	$	89	$	111
Remaining commitments^(a)	112		82		67		9		6

_________


(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 $127 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, 2019, 27 MWs of new generation were developed and Exelon and Generation have incurred costs of $107 million. Exelon has also committed to purchase 100 MWs of wind energy in PJM. DPL has committed to conducting three RFPs to procure up to a total of 120 MWs of wind RECs for the purpose of meeting Delaware's renewable portfolio standards. DPL has conducted two of the three wind REC RFPs. The first 40 MW wind REC tranche was conducted in 2017 and did not result in a purchase agreement. The second 40 MW wind REC tranche was conducted in 2018 and resulted in a proposed REC purchase agreement that was approved by the DPSC in March 2019. The third and final 40 MW wind REC tranche will be conducted in 2022.

Commercial Commitments (All Registrants). The Registrants’ commercial commitments as of September 30, 2019, representing commitments potentially triggered by future events were as follows:



			Expiration within
	Total		2019		2020		2021		2022		2023		2024 and beyond
Exelon
Letters of credit	$	1,718	$	1,192	$	515	$	11	$	—	$	—	$	—
Surety bonds^(a)	991		315		638		38		—		—		—
Financing trust guarantees	378		—		—		—		—		—		378
Guaranteed lease residual values^(b)	26		—		2		3		4		3		15
Total commercial commitments	$	3,113	$	1,507	$	1,155	$	52	$	4	$	3	$	393

Generation
Letters of credit	$	1,686	$	1,179	$	496	$	11	$	—	$	—	$	—
Surety bonds^(a)	790		298		492		—		—		—		—
Total commercial commitments	$	2,476	$	1,477	$	988	$	11	$	—	$	—	$	—

ComEd
Letters of credit	$	7	$	4	$	3	$	—	$	—	$	—	$	—
Surety bonds^(a)	50		5		43		2		—		—		—
Financing trust guarantees	200		—		—		—		—		—		200
Total commercial commitments	$	257	$	9	$	46	$	2	$	—	$	—	$	200

PECO
Surety bonds^(a)	$	9	$	1	$	8	$	—	$	—	$	—	$	—
Financing trust guarantees	178		—		—		—		—		—		178
Total commercial commitments	$	187	$	1	$	8	$	—	$	—	$	—	$	178

BGE
Letters of credit	$	8	$	2	$	6	$	—	$	—	$	—	$	—
Surety bonds^(a)	17		2		15		—		—		—		—
Total commercial commitments	$	25	$	4	$	21	$	—	$	—	$	—	$	—

PHI
Letters of credit	$	11	$	1	$	10	$	—	$	—	$	—	$	—
Surety bonds^(a)	24		5		19		—		—		—		—
Guaranteed lease residual values^(b)	26		—		2		3		4		3		15
Total commercial commitments	$	61	$	6	$	31	$	3	$	4	$	3	$	15

Pepco
Letters of credit	$	10	$	—	$	10	$	—	$	—	$	—	$	—
Surety bonds^(a)	17		2		15		—		—		—		—
Guaranteed lease residual values^(b)	9		—		—		1		1		1		6
Total commercial commitments	$	36	$	2	$	25	$	1	$	1	$	1	$	6

DPL
Letters of credit	$	1	$	1	$	—	$	—	$	—	$	—	$	—
Surety bonds^(a)	4		2		2		—		—		—		—
Guaranteed lease residual values^(b)	11		—		1		1		2		1		6
Total commercial commitments	$	16	$	3	$	3	$	1	$	2	$	1	$	6

ACE
Surety bonds^(a)	$	3	$	1	$	2	$	—	$	—	$	—	$	—
Guaranteed lease residual values^(b)	7		—		1		1		1		1		3
Total commercial commitments	$	10	$	1	$	3	$	1	$	1	$	1	$	3

_________


(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 $68 million guaranteed by Exelon and PHI, of which $22 million, $29 million and $17 million is guaranteed by Pepco, DPL and ACE, respectively. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.

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 in the Registrants' financial statements.

MGP Sites (Exelon, ComEd, PECO, BGE, PHI and DPL). 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 identified 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 2025.


•	PECO has 8 sites that are currently under some degree of active study and/or remediation. PECO expects the majority of the remediation at these sites to continue through at least 2022.


•	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 2021.


•	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, 2019 and December 31, 2018, the Registrants had accrued the following undiscounted amounts for environmental liabilities in Other current liabilities and Other deferred credits and other liabilities within their respective Consolidated Balance Sheets:



	September 30, 2019				December 31, 2018
	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	$	507	$	346	$	496	$	356
Generation	107		—		108		—
ComEd	328		327		329		327
PECO	20		18		27		25
BGE	3		1		5		4
PHI	49		—		27		—
Pepco	47		—		25		—
DPL	1		—		1		—
ACE	1		—		1		—

Cotter Corporation (Exelon and Generation). The EPA has advised Cotter Corporation (Cotter), a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. In 2000, ComEd sold Cotter to an unaffiliated third-party. As part of the sale, ComEd agreed to indemnify Cotter for any liability arising in connection with the West Lake Landfill. In connection with Exelon’s 2001 corporate restructuring, this responsibility to indemnify Cotter was transferred to Generation. Including Cotter, there are three PRPs participating in the West Lake Landfill remediation proceeding. Investigation by Generation has identified a number of other parties who also may be PRPs and could be liable to contribute to the final remedy. Further investigation is ongoing.

In September 2018 the EPA issued its Record of Decision (ROD) Amendment for the selection of the final remedy. The ROD modified the EPA’s previously proposed plan for partial excavation of the radiological materials by reducing the depths of the excavation. The ROD 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 the 2020 - 2021 time frame. In March 2019 the PRPs received Special Notice Letters from the EPA to perform the Remedial Action work. The EPA has established a deadline of October 2019 for the PRPs to provide a good faith offer to conduct, or finance, the Remedial Action work. This schedule can be extended by the EPA pending completion of the Remedial Design. The estimated cost of the remedy, taking into account the current EPA technical requirements and the total costs expected to be incurred by the PRPs in fully executing the remedy, is approximately $280 million, including cost escalation on an undiscounted basis, which would be allocated among the final group of PRPs. Generation has determined that a loss associated with the EPA’s partial excavation and enhanced landfill cover remedy is probable and has recorded a liability included in the table above, that reflects management’s best estimate of Cotter’s allocable share of the ultimate cost. Given the joint and several nature of this liability, the magnitude of Generation’s ultimate liability will depend on the actual costs incurred to implement the required remediation 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 Generation’s associated allocable share could differ significantly once these uncertainties are resolved, which could have a material impact on Exelon's and Generation's future financial statements.

One of the other PRPs has indicated it will be making a contribution claim against Cotter for costs that it has incurred to prevent the subsurface fire from spreading to those areas of the West Lake Landfill where radiological materials are believed to have been disposed. At this time, Exelon and Generation do not 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 on Exelon’s and Generation's financial statements.

In January 2018, the PRPs were advised by the EPA that it will begin an additional investigation and evaluation of groundwater conditions at the West Lake Landfill. In September 2018, the PRPs agreed to an Administrative Settlement Agreement and Order on Consent for the performance by the PRPs of the groundwater 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 $20 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 on Exelon’s and Generation’s future financial statements.

In August 2011, Cotter was notified by the DOJ that Cotter is considered a PRP with respect to the government’s clean-up costs for contamination attributable to low level radioactive residues at a former storage and reprocessing facility named Latty Avenue near St. Louis, Missouri. The Latty Avenue site is included in ComEd’s 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. The DOJ has not yet formally advised the PRPs of the amount that it is seeking, but it is believed to be approximately $90 million from all PRPs. Pursuant to a series of annual agreements since 2011, the DOJ and the PRPs have tolled the statute of limitations until February 2020 so that settlement discussions could proceed. 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 Remediation Investigation (RI)/ Feasibility Study (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. Once the RI work is completed, Pepco and Generation will issue a draft “final” RI report for review and comment by DOEE and the public. Pepco and Generation will then proceed to develop a FS to evaluate possible remedial alternatives for submission to DOEE. The Court has established a schedule for completion of the RI and FS, and approval by the DOEE, by September 16, 2021.

DOEE will then prepare a Proposed Plan and issue a Record of Decision identifying any further response actions determined to be necessary, after considering public comment on the Proposed Plan. PHI, Pepco and Generation have determined that a loss associated with this matter is probable and have accrued an estimated liability, which is included in the table above.

Anacostia River Tidal Reach (Exelon, PHI and Pepco). Contemporaneous with the Benning Road site RI/FS being performed by Pepco and Generation, DOEE and the National Park Service have been conducting a separate RI/FS focused on the entire tidal reach of the Anacostia River extending from just north of the Maryland-District of Columbia boundary line to the confluence of the Anacostia and Potomac Rivers. The river-wide RI incorporated the results of the river sampling performed by Pepco and Pepco Energy Services as part of the Benning RI/FS, as well as similar sampling efforts conducted by owners of other sites adjacent to this segment of the river and supplemental river sampling conducted by DOEE’s contractor. DOEE asked Pepco, along with parties responsible for other sites along the river, to participate in a "Consultative Working Group" to provide input into the process for future remedial actions and to ensure proper coordination with the other river cleanup efforts currently underway, including cleanup of the river segment adjacent to the Benning Road site resulting from the Benning Road site RI/FS. In addition, the District of Columbia Council directed DOEE to form an official advisory committee made up of members of federal, state and local environmental regulators, community and environmental groups and various academic and technical experts to provide guidance and support to DOEE as the project progressed. This group, called the Anacostia Leadership Council, has met regularly since it was formed. Pepco has participated in the Consultative Working

Group. 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. The District of Columbia Council has set a deadline of December 31, 2019 for completion of the Record of Decision. An appropriate liability for Pepco’s share of investigation costs has been accrued and is included in the table above.

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 based on DOEE’s stated position following a series of meetings attended by representatives from the Anacostia Leadership Council and the Consultative Working Group. A draft FS, which Pepco believes will include the process to identify potential short-term remedies and actions based on the technical findings in the RI report and their estimated costs to the extent possible, is being prepared by DOEE and is expected later in the fourth quarter of 2019. DOEE and likely the National Park Service will continue to oversee ongoing remediation efforts and potential longer-term remedies for the Anacostia River. Pepco has concluded that incremental exposure remains reasonably possible, however management cannot reasonably estimate a range of loss beyond the amounts recorded, which are included in the table above.

In addition to the activities associated with the remedial process outlined above, there is a complementary statutory program that requires an assessment to determine if any natural resources have been damaged as a result of the contamination that is being remediated, and, if so, that a plan be developed by the federal, state and local Natural Resource Damage Trustees, who are defined by CERCLA as the responsible parties for the restoration or compensation for any loss of those resources from the environmental contaminants at the site. If natural resources cannot be restored, then compensation for the injury can be sought from the responsible parties. The assessment of Natural Resource Damages (NRD) typically takes place following cleanup because cleanups sometimes also effectively restore habitat. During the second quarter of 2018, Pepco became aware that the Trustees are in the beginning stages of this 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 it 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, 2019 and December 31, 2018, Exelon and Generation had recorded estimated liabilities of approximately $83 million and $79 million, respectively, in total for asbestos-related bodily injury claims. As of September 30, 2019, approximately $25 million of this amount related to 257 open claims presented to Generation, while the remaining $58 million is for estimated future asbestos-related bodily injury claims anticipated to arise through 2055, based on actuarial assumptions and analyses, which are updated on an annual basis. On a quarterly basis, Generation monitors actual experience against the number of forecasted claims to be received and expected claim payments and evaluates whether adjustments to the estimated liabilities are necessary.

It is reasonably possible that additional exposure to estimated future asbestos-related bodily injury claims in excess of the amount accrued could have a material, unfavorable impact on Exelon’s and Generation’s financial statements.

City of Everett Tax Increment Financing Agreement (Exelon and Generation). On April 10, 2017, the City of Everett petitioned the Massachusetts Economic Assistance Coordinating Council (EACC) to revoke the 1999 tax increment financing agreement (TIF Agreement) relating to Mystic Units 8 and 9 on the grounds that the total investment in Mystic Units 8 and 9 materially deviates from the investment set forth in the TIF Agreement. On October 31, 2017, a three-member panel of the EACC conducted an administrative hearing on the City’s petition. On November 30, 2017, the hearing panel issued a tentative decision denying the City’s petition, finding that there was no material misrepresentation that would justify revocation of the TIF Agreement. On December 13, 2017, the tentative decision was adopted by the full EACC. On January 12, 2018, the City filed a complaint in Massachusetts Superior Court requesting, among other things, that the court set aside the EACC’s decision, grant the City’s request to decertify the Project and the TIF Agreement, and award the City damages for alleged underpaid taxes over the period of the TIF Agreement. Generation vigorously contested the City’s claims before the EACC and will continue to do so in the Massachusetts Superior Court proceeding. Generation continues to believe that the City’s claim lacks merit. Accordingly, Generation has not recorded a liability for payment resulting from such a revocation, nor can Generation estimate a reasonably possible range of loss, if any, associated with any such revocation. Further,

it is reasonably possible that property taxes assessed in future periods, including those following the expiration of the current TIF Agreement in 2020, could be material to Generation’s financial statements.

Subpoenas (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 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 U.S. Attorney's Office for the Northern District of Illinois requiring production of records of any communications with certain individuals and entities. On October 22, 2019, the SEC notified Exelon and ComEd that it has also opened an investigation into their lobbying activities. Exelon and ComEd have cooperated fully and intend to continue to cooperate fully and expeditiously with the U.S. Attorney’s Office and the SEC. Exelon and ComEd cannot predict the outcome of the subpoenas or the SEC investigation.

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.

Supplemental Financial Information (All Registrants)

9 Months Ended

Sep. 30, 2019

Supplemental Financial Information [Abstract]

Supplemental Financial Information (All Registrants)

Supplemental Statement of Operations Information

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



	Taxes other than income
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Three Months Ended September 30, 2019
Utility taxes^(a)	$	241	$	29	$	66	$	38	$	21	$	86	$	81	$	5	$	—
Property	148		66		7		5		39		31		21		9		—
Payroll	57		28		7		3		4		6		2		1		1

Three Months Ended September 30, 2018
Utility taxes^(a)	$	253	$	32	$	67	$	39	$	23	$	92	$	87	$	5	$	—
Property	145		70		7		4		37		26		16		9		—
Payroll	58		31		6		3		4		5		1		1		1

Nine Months Ended September 30, 2019
Utility taxes^(a)	$	672	$	87	$	183	$	102	$	68	$	231	$	217	$	14	$	—
Property	444		205		22		12		114		91		64		25		2
Payroll	185		92		21		11		13		20		5		3		2

Nine Months Ended September 30, 2018
Utility taxes^(a)	$	705	$	92	$	188	$	102	$	70	$	253	$	238	$	15	$	—
Property	416		204		22		12		106		71		45		24		2
Payroll	191		99		20		11		12		19		5		3		2

_________

(a)

Generation’s utility tax represents gross receipts tax related to its retail operations, and the Utility Registrants' utility taxes represents municipal and state utility taxes and gross receipts taxes related to their operating revenues. The offsetting collection of utility taxes from customers is recorded in revenues in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.



	Other, Net
	Exelon			Generation			ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Three Months Ended September 30, 2019
Decommissioning-related activities:
Net realized income on NDT funds^(a)
Regulatory agreement units	$	67		$	67		$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-regulatory agreement units	33			33			—		—		—		—		—		—		—
Net unrealized gains on NDT funds
Regulatory agreement units	89			89			—		—		—		—		—		—		—
Non-regulatory agreement units	55			55			—		—		—		—		—		—		—
Regulatory offset to NDT fund-related activities^(b)	(125		)	(125		)	—		—		—		—		—		—		—
Decommissioning-related activities	119			119			—		—		—		—		—		—		—
AFUDC — Equity	22			—			4		3		6		9		7		1		1
Non-service net periodic benefit cost	(2		)	—			—		—		—		—		—		—		—

Three Months Ended September 30, 2018
Decommissioning-related activities:
Net realized income on NDT funds^(a)
Regulatory agreement units	$	214		$	214		$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-regulatory agreement units	58			58			—		—		—		—		—		—		—
Net unrealized (losses) gains on NDT funds
Regulatory agreement units	(66		)	(66		)	—		—		—		—		—		—		—
Non-regulatory agreement units	72			72			—		—		—		—		—		—		—
Regulatory offset to NDT fund-related activities^(b)	(110		)	(110		)	—		—		—		—		—		—		—
Decommissioning-related activities	168			168			—		—		—		—		—		—		—
AFUDC — Equity	16			—			4		1		5		6		6		—		—
Non-service net periodic benefit cost	(12		)	—			—		—		—		—		—		—		—



	Other, Net
	Exelon			Generation			ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Nine Months Ended September 30, 2019
Decommissioning-related activities:
Net realized income on NDT funds^(a)
Regulatory agreement units	$	197		$	197		$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-regulatory agreement units	316			316			—		—		—		—		—		—		—
Net unrealized gains on NDT funds
Regulatory agreement units	565			565			—		—		—		—		—		—		—
Non-regulatory agreement units	236			236			—		—		—		—		—		—		—
Regulatory offset to NDT fund-related activities^(b)	(611		)	(611		)	—		—		—		—		—		—		—
Decommissioning-related activities	703			703			—		—		—		—		—		—		—
AFUDC — Equity	64			—			13		9		16		26		18		3		4
Non-service net periodic benefit cost	8			—			—		—		—		—		—		—		—

Nine Months Ended September 30, 2018
Decommissioning-related activities:
Net realized income on NDT funds^(a)
Regulatory agreement units	$	476		$	476		$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-regulatory agreement units	257			257			—		—		—		—		—		—		—
Net unrealized losses on NDT funds
Regulatory agreement units	(335		)	(335		)	—		—		—		—		—		—		—
Non-regulatory agreement units	(143		)	(143		)	—		—		—		—		—		—		—
Regulatory offset to NDT fund-related activities^(b)	(110		)	(110		)	—		—		—		—		—		—		—
Decommissioning-related activities	145			145			—		—		—		—		—		—		—
AFUDC — Equity	47			—			12		3		13		19		17		2		—
Non-service net periodic benefit cost	(33		)	—			—		—		—		—		—		—		—

_________


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


(b)	Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units, including the elimination of income taxes related to all NDT fund activity for those units. See Note 15 — Asset Retirement Obligations of the Exelon 2018 Form 10-K for additional information regarding the accounting for nuclear decommissioning.

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, 2019
Property, plant and equipment^(a)	$	2,803	$	1,184	$	661	$	225	$	263	$	405	$	178	$	109	$	89
Amortization of regulatory assets^(a)	390		—		106		22		105		157		103		29		25
Amortization of intangible assets, net^(a)	44		37		—		—		—		—		—		—		—
Amortization of energy contract assets and liabilities^(b)	14		14		—		—		—		—		—		—		—
Nuclear fuel^(c)	771		771		—		—		—		—		—		—		—
ARO accretion^(d)	371		371		—		—		—		—		—		—		—
Total depreciation, amortization and accretion	$	4,393	$	2,377	$	767	$	247	$	368	$	562	$	281	$	138	$	114

Nine Months Ended September 30, 2018
Property, plant and equipment^(a)	$	2,829	$	1,347	$	613	$	204	$	249	$	355	$	161	$	97	$	70
Amortization of regulatory assets^(a)	412		—		83		20		109		200		125		38		37
Amortization of intangible assets, net^(a)	43		36		—		—		—		—		—		—		—
Amortization of energy contract assets and liabilities^(b)	8		8		—		—		—		—		—		—		—
Nuclear fuel^(c)	852		852		—		—		—		—		—		—		—
ARO accretion^(d)	367		365		—		—		—		—		—		—		—
Total depreciation, amortization and accretion	$	4,511	$	2,608	$	696	$	224	$	358	$	555	$	286	$	135	$	107

_________


(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, 2019
Pension and non-pension postretirement benefit costs	$	324		$	98		$	70	$	9	$	45	$	71		$	19		$	11		$	12
Provision for uncollectible accounts	89			20			26		22		5		16			7			2			6
Other decommissioning-related activity^(a)	(400		)	(400		)	—		—		—		—			—			—			—
Energy-related options^(b)	21			21			—		—		—		—			—			—			—
Amortization of rate stabilization deferral	(8		)	—			—		—		—		(8		)	(9		)	1			—
Discrete impacts from EIMA and FEJA^(c)	80			—			80		—		—		—			—			—			—
Long-term incentive plan	33			—			—		—		—		—			—			—			—
Amortization of operating ROU asset	193			138			2		—		23		26			6			7			4
Change in environmental liabilities	23			—			—		—		—		23			23			—			—

Nine Months Ended September 30, 2018
Pension and non-pension postretirement benefit costs	$	435		$	151		$	133	$	14	$	43	$	51		$	10		$	5		$	10
Provision for uncollectible accounts	133			38			30		25		6		32			12			6			14
Other decommissioning-related activity^(a)	(39		)	(39		)	—		—		—		—			—			—			—
Energy-related options^(b)	4			4			—		—		—		—			—			—			—
Amortization of rate stabilization deferral	—			—			—		—		—		—			—			—			—
Discrete impacts from EIMA and FEJA^(c)	27			—			27		—		—		—			—			—			—
Long-term incentive plan	84			—			—		—		—		—			—			—			—
Asset retirement costs	20			—			—		—		—		20			22			(1		)	(1		)

_______

(a)

Includes the elimination of decommissioning-related activity for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income and income taxes related to all NDT fund activity for these units. See Note 15 — Asset Retirement Obligations of the Exelon 2018 Form 10-K for additional information regarding the accounting for nuclear decommissioning.


(b)	Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded in Operating revenues and expenses.


(c)	Reflects the change in ComEd's distribution and energy efficiency formula rates. See Note 6 — Regulatory Matters for additional information.

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, 2019
Cash and cash equivalents	$	1,683	$	1,019	$	76	$	224	$	130	$	99	$	18	$	11	$	13
Restricted cash	309		126		124		6		1		38		34		—		3
Restricted cash included in other long-term assets	186		—		171		—		—		15		—		—		15
Total cash, cash equivalents and restricted cash	$	2,178	$	1,145	$	371	$	230	$	131	$	152	$	52	$	11	$	31

December 31, 2018
Cash and cash equivalents	$	1,349	$	750	$	135	$	130	$	7	$	124	$	16	$	23	$	7
Restricted cash	247		153		29		5		6		43		37		1		4
Restricted cash included in other long-term assets	185		—		166		—		—		19		—		—		19
Total cash, cash equivalents and restricted cash	$	1,781	$	903	$	330	$	135	$	13	$	186	$	53	$	24	$	30

September 30, 2018
Cash and cash equivalents	$	1,918	$	1,187	$	124	$	102	$	113	$	153	$	12	$	110	$	11
Restricted cash	240		152		12		5		3		42		35		—		7
Restricted cash included in other long-term assets	163		—		144		—		—		19		—		—		19
Total cash, cash equivalents and restricted cash	$	2,321	$	1,339	$	280	$	107	$	116	$	214	$	47	$	110	$	37

December 31, 2017
Cash and cash equivalents	$	898	$	416	$	76	$	271	$	17	$	30	$	5	$	2	$	2
Restricted cash	207		138		5		4		1		42		35		—		6
Restricted cash included in other long-term assets	85		—		63		—		—		23		—		—		23
Total cash, cash equivalents and restricted cash	$	1,190	$	554	$	144	$	275	$	18	$	95	$	40	$	2	$	31

For additional information on restricted cash see Note 1 — Significant Accounting Policies of the Exelon 2018 Form 10-K.

Supplemental Balance Sheet Information

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



	Unbilled customer revenues
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
September 30, 2019	$	1,256	$	676	$	212	$	102	$	103	$	163	$	91	$	38	$	34
December 31, 2018	1,656		965		223		114		168		186		97		59		30



	Accrued expenses
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
September 30, 2019
Compensation-related accruals^(a)	$	880	$	336	$	133	$	48	$	63	$	86	$	26	$	17	$	13
Taxes accrued	431		247		56		13		64		80		61		17		3
Interest accrued	421		106		62		33		36		78		37		20		19

December 31, 2018
Compensation-related accruals^(a)	$	1,191	$	479	$	187	$	49	$	68	$	99	$	29	$	19	$	12
Taxes accrued	412		226		71		28		46		74		58		4		5
Interest accrued	334		77		105		33		39		50		25		8		12

_________

(a)

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

Segment Information (All Registrants)

9 Months Ended

Sep. 30, 2019

Segment Reporting [Abstract]

Segment Information (All Registrants)

Operating segments for each of the Registrants are determined based on information used by the CODM in deciding how to evaluate performance and allocate resources at each of the Registrants.

Exelon has eleven reportable segments, which include Generation's five reportable segments consisting of the Mid-Atlantic, Midwest, New York, ERCOT and all other power regions referred to collectively as “Other Power Regions” and ComEd, PECO, BGE, and PHI's three reportable segments consisting of Pepco, DPL and ACE. ComEd, PECO, BGE, Pepco, DPL and ACE each represent a single reportable segment, and as such, no separate segment information is provided for these Registrants. Exelon, ComEd, PECO, BGE, Pepco, DPL and ACE's CODMs evaluate the performance of and allocate resources to ComEd, PECO, BGE, Pepco, DPL and ACE based on net income.

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


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


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


•	New York represents operations within ISO-NY.


•	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 California ISO.


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

The CODMs for Exelon and Generation evaluate the performance of Generation’s electric business activities and allocate resources based on RNF. Generation believes that RNF is a useful measurement of operational performance. RNF is not a presentation defined under GAAP and may not be comparable to other companies’

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

During the first quarter of 2019, due to a change in economics in our New England region, Generation changed the way that information is reviewed by the CODM. The New England region is no longer regularly reviewed as a separate region by the CODM nor is it presented separately in any external information presented to third parties. Information for the New England region is reviewed by the CODM as part of Other Power Regions. Exelon and Generation retrospectively applied this change.

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, 2019 and 2018 is as follows:

Three Months Ended September 30, 2019 and 2018



	Generation^(a)		ComEd		PECO		BGE		PHI		Other^(b)		Intersegment Eliminations			Exelon
Operating revenues^(c):
2019
Competitive businesses electric revenues	$	4,314	$	—	$	—	$	—	$	—	$	—	$	(275	)	$	4,039
Competitive businesses natural gas revenues	265		—		—		—		—		—		1			266
Competitive businesses other revenues	195		—		—		—		—		—		(1		)	194
Rate-regulated electric revenues	—		1,583		716		619		1,357		—		(7		)	4,268
Rate-regulated natural gas revenues	—		—		62		84		20		—		(3		)	163
Shared service and other revenues	—		—		—		—		3		474		(478		)	(1		)
Total operating revenues	$	4,774	$	1,583	$	778	$	703	$	1,380	$	474	$	(763	)	$	8,929



	Generation^(a)		ComEd		PECO			BGE		PHI		Other^(b)			Intersegment Eliminations			Exelon
2018
Competitive businesses electric revenues	$	4,741	$	—	$	—		$	—	$	—	$	—		$	(306	)	$	4,435
Competitive businesses natural gas revenues	397		—		—			—		—		—			—			397
Competitive businesses other revenues	140		—		—			—		—		—			(1		)	139
Rate-regulated electric revenues	—		1,598		700			645		1,334		—			(7		)	4,270
Rate-regulated natural gas revenues	—		—		57			86		24		—			(5		)	162
Shared service and other revenues	—		—		—			—		3		458			(461		)	—
Total operating revenues	$	5,278	$	1,598	$	757		$	731	$	1,361	$	458		$	(780	)	$	9,403
Intersegment revenues^(d):
2019	$	275	$	4	$	1		$	6	$	4	$	474		$	(764	)	$	—
2018	308		4		2			6		3		456			(779		)	—
Depreciation and amortization:
2019	$	407	$	259	$	83		$	116	$	193	$	25		$	—		$	1,083
2018	468		237		75			110		192		23			—			1,105
Operating expenses:
2019	$	4,274	$	1,256	$	595		$	612	$	1,124	$	457		$	(759	)	$	7,559
2018	4,961		1,275		603			628		1,116		459			(790		)	8,252
Interest expense, net:
2019	$	109	$	91	$	33		$	31	$	66	$	79		$	—		$	409
2018	101		85		32			27		65		83			—			393
Income (loss) before income taxes:
2019	$	501	$	245	$	154		$	67	$	203	$	(68	)	$	—		$	1,102
2018	389		245		124			81		191		(83		)	—			947
Income Taxes:
2019	$	87	$	45	$	14		$	12	$	14	$	—		$	—		$	172
2018	78		52		(2		)	18		4		(13		)	—			137
Net income (loss):
2019	$	244	$	200	$	140		$	55	$	189	$	(68	)	$	—		$	760
2018	300		193		126			63		187		(69		)	—			800
Capital Expenditures
2019	$	392	$	452	$	228		$	300	$	308	$	7		$	—		$	1,687
2018	362		514		204			233		359		18			—			1,690

__________

(a)

Intersegment revenues for Generation in 2019 include revenue from sales to PECO of $43 million, sales to BGE of $65 million, sales to Pepco of $65 million, sales to DPL of $14 million and sales to ACE of $3 million in the Mid-Atlantic region, and sales to ComEd of $83 million in the Midwest region, which eliminate upon consolidation. Intersegment revenues for Generation in 2018 include revenue from sales to PECO of $35 million, sales to BGE of $69 million, sales to Pepco of $46 million, sales to DPL of $26 million and sales to ACE of $10 million in the Mid-Atlantic region, and sales to ComEd of $122 million in the Midwest region, which eliminate upon consolidation.


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


(c)	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 17 — Supplemental Financial Information for additional information on total utility taxes.

(d)

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.

PHI:



	Pepco			DPL		ACE		Other^(b)			Intersegment Eliminations			PHI
Operating revenues^(a):
2019
Rate-regulated electric revenues	$	642		$	299	$	419	$	—		$	(3	)	$	1,357
Rate-regulated natural gas revenues	—			20		—		—			—			20
Shared service and other revenues	—			—		—		92			(89		)	3
Total operating revenues	$	642		$	319	$	419	$	92		$	(92	)	$	1,380
2018
Rate-regulated electric revenues	$	628		$	304	$	406	$	—		$	(4	)	$	1,334
Rate-regulated natural gas revenues	—			24		—		—			—			24
Shared service and other revenues	—			—		—		103			(100		)	3
Total operating revenues	$	628		$	328	$	406	$	103		$	(104	)	$	1,361
Intersegment revenues:
2019	$	2		$	1	$	1	$	93		$	(93	)	$	4
2018	2			2		1		103			(105		)	3
Depreciation and amortization:
2019	$	95		$	46	$	43	$	9		$	—		$	193
2018	99			47		38		8			—			192
Operating expenses:
2019	$	515		$	268	$	340	$	95		$	(94	)	$	1,124
2018	516			277		322		105			(104		)	1,116
Interest expense, net:
2019	$	33		$	15	$	15	$	3		$	—		$	66
2018	32			15		16		2			—			65
Income (loss) before income taxes:
2019	$	103		$	38	$	65	$	192		$	(195	)	$	203
2018	87			38		69		179			(182		)	191
Income Taxes:
2019	$	5		$	5	$	2	$	3		$	(1	)	$	14
2018	(2		)	5		8		(8		)	1			4
Net income (loss):
2019	$	98		$	33	$	63	$	(9	)	$	4		$	189
2018	89			33		61		1			3			187
Capital Expenditures
2019	$	157		$	85	$	73	$	(7	)	$	—		$	308
2018	188			88		77		6			—			359

__________


(a)	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 17 — Supplemental Financial Information for additional information on total utility taxes.


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

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, 2019
	Revenues from external customers^(a)						Intersegment revenues			Total Revenues
	Contracts with customers		Other^(b)		Total		Intersegment revenues			Total Revenues
Mid-Atlantic	$	1,351	$	10	$	1,361	$	3		$	1,364
Midwest	1,052		47		1,099		(17		)	1,082
New York	414		15		429		—			429
ERCOT	288		72		360		5			365
Other Power Regions	873		192		1,065		(25		)	1,040
Total Competitive Businesses Electric Revenues	3,978		336		4,314		(34		)	4,280
Competitive Businesses Natural Gas Revenues	160		105		265		34			299
Competitive Businesses Other Revenues^(c)	112		83		195		—			195
Total Generation Consolidated Operating Revenues	$	4,250	$	524	$	4,774	$	—		$	4,774



	Three Months Ended September 30, 2018
	Revenues from external customers^(a)							Intersegment revenues			Total Revenues
	Contracts with customers		Other^(b)			Total		Intersegment revenues			Total Revenues
Mid-Atlantic	$	1,397	$	52		$	1,449	$	7		$	1,456
Midwest	1,095		26			1,121		(4		)	1,117
New York	475		(6		)	469		—			469
ERCOT	156		289			445		(1		)	444
Other Power Regions	959		298			1,257		(45		)	1,212
Total Competitive Businesses Electric Revenues	4,082		659			4,741		(43		)	4,698
Competitive Businesses Natural Gas Revenues	200		197			397		43			440
Competitive Businesses Other Revenues^(c)	130		10			140		—			140
Total Generation Consolidated Operating Revenues	$	4,412	$	866		$	5,278	$	—		$	5,278

__________


(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 gains of $77 million and $6 million in 2019 and 2018, respectively, and elimination of intersegment revenues.

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



	Three Months Ended September 30, 2019							Three Months Ended September 30, 2018
	RNF from external customers^(a)		Intersegment RNF			Total RNF		RNF from external customers^(a)		Intersegment RNF			Total RNF
Mid-Atlantic	$	684	$	5		$	689	$	746	$	17		$	763
Midwest	763		(16		)	747		763		5			768
New York	288		3			291		290		2			292
ERCOT	76		(4		)	72		161		(63		)	98
Other Power Regions	212		(28		)	184		226		(46		)	180
Total Revenues net of purchased power and fuel for Reportable Segments	2,023		(40		)	1,983		2,186		(85		)	2,101
Other^(b)	100		40			140		112		85			197
Total Generation Revenues net of purchased power and fuel expense	$	2,123	$	—		$	2,123	$	2,298	$	—		$	2,298

__________


(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 $17 million and $71 million in 2019 and 2018, respectively, accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 8 — Early Plant Retirements of $3 million and $18 million decrease to RNF in 2019 and 2018, respectively, and the elimination of intersegment RNF.

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



	Three Months Ended September 30, 2019
Revenues from contracts with customers	ComEd			PECO			BGE			PHI			Pepco			DPL			ACE
Rate-regulated electric revenues
Residential	$	865		$	479		$	352		$	741		$	311		$	178		$	252
Small commercial & industrial	393			109			64			147			41			48			58
Large commercial & industrial	141			63			116			297			222			26			49
Public authorities & electric railroads	12			9			7			17			11			3			3
Other^(a)	222			63			82			164			58			50			56
Total rate-regulated electric revenues^(b)	$	1,633		$	723		$	621		$	1,366		$	643		$	305		$	418
Rate-regulated natural gas revenues
Residential	$	—		$	38		$	49		$	9		$	—		$	9		$	—
Small commercial & industrial	—			17			9			4			—			4			—
Large commercial & industrial	—			—			20			1			—			1			—
Transportation	—			5			—			4			—			4			—
Other^(c)	—			2			5			2			—			2			—
Total rate-regulated natural gas revenues^(d)	$	—		$	62		$	83		$	20		$	—		$	20		$	—
Total rate-regulated revenues from contracts with customers	$	1,633		$	785		$	704		$	1,386		$	643		$	325		$	418

Other revenues
Revenues from alternative revenue programs	$	(56	)	$	(11	)	$	(5	)	$	(9	)	$	(3	)	$	(6	)	$	1
Other rate-regulated electric revenues^(e)	6			4			3			3			2			—			—
Other rate-regulated natural gas revenues^(e)	—			—			1			—			—			—			—
Total other revenues	$	(50	)	$	(7	)	$	(1	)	$	(6	)	$	(1	)	$	(6	)	$	1
Total rate-regulated revenues for reportable segments	$	1,583		$	778		$	703		$	1,380		$	642		$	319		$	419



	Three Months Ended September 30, 2018
Revenues from contracts with customers	ComEd			PECO		BGE			PHI			Pepco			DPL		ACE
Rate-regulated electric revenues
Residential	$	861		$	458	$	366		$	726		$	306		$	180	$	240
Small commercial & industrial	391			108		68			140			39			48		53
Large commercial & industrial	131			64		117			303			230			25		48
Public authorities & electric railroads	11			7		7			14			8			3		3
Other^(a)	212			59		91			156			47			47		63
Total rate-regulated electric revenues^(b)	$	1,606		$	696	$	649		$	1,339		$	630		$	303	$	407
Rate-regulated natural gas revenues
Residential	$	—		$	36	$	46		$	8		$	—		$	8	$	—
Small commercial & industrial	—			15		8			5			—			5		—
Large commercial & industrial	—			—		17			2			—			2		—
Transportation	—			5		—			3			—			3		—
Other^(c)	—			1		12			6			—			6		—
Total rate-regulated natural gas revenues^(d)	$	—		$	57	$	83		$	24		$	—		$	24	$	—
Total rate-regulated revenues from contracts with customers	$	1,606		$	753	$	732		$	1,363		$	630		$	327	$	407

Other revenues
Revenues from alternative revenue programs	$	(15	)	$	1	$	(6	)	$	(5	)	$	(4	)	$	—	$	(1	)
Other rate-regulated electric revenues^(e)	7			3		4			3			2			1		—
Other rate-regulated natural gas revenues^(e)	—			—		1			—			—			—		—
Total other revenues	$	(8	)	$	4	$	(1	)	$	(2	)	$	(2	)	$	1	$	(1	)
Total rate-regulated revenues for reportable segments	$	1,598		$	757	$	731		$	1,361		$	628		$	328	$	406

__________


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


(b)	Includes operating revenues from affiliates of $4 million, $1 million, $2 million, $4 million, $2 million, $1 million and $1 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2019 and $4 million, $2 million, $1 million, $3 million $2 million, $2 million and $1 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2018.


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


(d)	Includes operating revenues from affiliates of less than $1 million and $4 million at PECO and BGE, respectively, in 2019 and less than $1 million and $5 million at PECO and BGE, respectively, in 2018.


(e)	Includes late payment charge revenues.

Nine Months Ended September 30, 2019 and 2018



	Generation^(a)		ComEd		PECO		BGE		PHI		Other^(b)		Intersegment Eliminations			Exelon
Operating revenues^(c):
2019
Competitive businesses electric revenues	$	12,365	$	—	$	—	$	—	$	—	$	—	$	(840	)	$	11,525
Competitive businesses natural gas revenues	1,479		—		—		—		—		—		—			1,479
Competitive businesses other revenues	436		—		—		—		—		—		(4		)	432
Rate-regulated electric revenues	—		4,342		1,901		1,817		3,574		—		(25		)	11,609
Rate-regulated natural gas revenues	—		—		432		510		116		—		(12		)	1,046
Shared service and other revenues	—		—		—		—		10		1,410		(1,415		)	5
Total operating revenues	$	14,280	$	4,342	$	2,333	$	2,327	$	3,700	$	1,410	$	(2,296	)	$	26,096
2018
Competitive businesses electric revenues	$	13,190	$	—	$	—	$	—	$	—	$	—	$	(969	)	$	12,221
Competitive businesses natural gas revenues	1,839		—		—		—		—		—		(8		)	1,831
Competitive businesses other revenues	339		—		—		—		—		—		(4		)	335
Rate-regulated electric revenues	—		4,508		1,893		1,850		3,549		—		(34		)	11,766
Rate-regulated natural gas revenues	—		—		382		519		129		—		(13		)	1,017
Shared service and other revenues	—		—		—		—		10		1,398		(1,408		)	—
Total operating revenues	$	15,368	$	4,508	$	2,275	$	2,369	$	3,688	$	1,398	$	(2,436	)	$	27,170
Shared service and other revenues
Intersegment revenues^(d):
2019	$	844	$	13	$	4	$	18	$	11	$	1,410	$	(2,300	)	$	—
2018	981		23		5		18		11		1,392		(2,430		)	—
Depreciation and amortization:
2019	$	1,221	$	767	$	247	$	368	$	562	$	72	$	—		$	3,237
2018	1,383		696		224		358		555		68		—			3,284
Operating expenses:
2019	$	13,333	$	3,431	$	1,783	$	1,936	$	3,106	$	1,405	$	(2,291	)	$	22,703
2018	14,475		3,610		1,853		2,005		3,165		1,395		(2,467		)	24,036
Interest expense, net:
2019	$	336	$	268	$	100	$	89	$	197	$	231	$	—		$	1,221
2018	305		261		96		78		193		205		—			1,138



	Generation^(a)		ComEd		PECO			BGE		PHI		Other^(b)			Intersegment Eliminations			Exelon
Income (loss) before income taxes:
2019	$	1,355	$	674	$	461		$	320	$	436	$	(218	)	$	—		$	3,028
2018	800		663		331			301		363		(195		)	—			2,263
Income Taxes:
2019	$	388	$	130	$	51		$	59	$	25	$	(27	)	$	—		$	626
2018	110		140		(5		)	59		28		(70		)	—			262
Net income (loss):
2019	$	784	$	544	$	410		$	261	$	412	$	(191	)	$	—		$	2,220
2018	667		523		336			242		336		(125		)	—			1,979
Capital Expenditures
2019	$	1,282	$	1,413	$	675		$	842	$	1,006	$	41		$	—		$	5,259
2018	1,660		1,540		615			667		988		27			—			5,497
Total assets:
September 30, 2019	$	47,984	$	32,326	$	11,379		$	10,304	$	22,576	$	8,254		$	(10,085	)	$	122,738
December 31, 2018	47,556		31,213		10,642			9,716		21,984		8,355			(9,800		)	119,666

__________

(a)

Intersegment revenues for Generation in 2019 include revenue from sales to PECO of $123 million, sales to BGE of $199 million, sales to Pepco of $188 million, sales to DPL of $50 million and sales to ACE of $16 million in the Mid-Atlantic region, and sales to ComEd of $266 million in the Midwest region, which eliminate upon consolidation. Intersegment revenues for Generation in 2018 include revenue from sales to PECO of $97 million, sales to BGE of $198 million, sales to Pepco of $143 million, sales to DPL of $103 million and sales to ACE of $21 million in the Mid-Atlantic region, and sales to ComEd of $419 million in the Midwest region, which eliminate upon consolidation.


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


(c)	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 17 — Supplemental Financial Information for additional information on total utility taxes.

(d)

PHI:



	Pepco		DPL		ACE		Other^(b)			Intersegment Eliminations			PHI
Operating revenues^(a):
2019
Rate-regulated electric revenues	$	1,748	$	871	$	966	$	(1	)	$	(10	)	$	3,574
Rate-regulated natural gas revenues	—		116		—		—			—			116
Shared service and other revenues	—		—		—		298			(288		)	10
Total operating revenues	$	1,748	$	987	$	966	$	297		$	(298	)	$	3,700
2018
Rate-regulated electric revenues	$	1,708	$	872	$	981	$	—		$	(12	)	$	3,549
Rate-regulated natural gas revenues	—		129		—		—			—			129
Shared service and other revenues	—		—		—		326			(316		)	10
Total operating revenues	$	1,708	$	1,001	$	981	$	326		$	(328	)	$	3,688
Intersegment revenues:
2019	$	5	$	5	$	2	$	297		$	(298	)	$	11
2018	5		6		2		325			(327		)	11
Depreciation and amortization:
2019	$	281	$	138	$	114	$	29		$	—		$	562
2018	286		135		107		27			—			555
Operating expenses:
2019	$	1,444	$	820	$	838	$	302		$	(298	)	$	3,106
2018	1,454		859		847		329			(324		)	3,165
Interest expense, net:
2019	$	100	$	45	$	44	$	8		$	—		$	197
2018	96		42		48		7			—			193
Income (loss) before income taxes:
2019	$	226	$	132	$	89	$	411		$	(422	)	$	436
2018	181		107		88		326			(339		)	363
Income Taxes:
2019	$	9	$	16	$	2	$	(1	)	$	(1	)	$	25
2018	7		17		12		(8		)	—			28
Net income (loss):
2019	$	217	$	116	$	87	$	(19	)	$	11		$	412
2018	174		90		76		(15		)	11			336
Capital Expenditures
2019	$	455	$	245	$	300	$	6		$	—		$	1,006
2018	475		254		247		12			—			988
Total assets:
September 30, 2019	$	8,603	$	4,724	$	3,916	$	11,071		$	(5,738	)	$	22,576
December 31, 2018	8,299		4,588		3,699		10,819			(5,421		)	21,984

__________


(a)	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 17 — Supplemental Financial Information for additional information on total utility taxes.


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

Competitive Business Revenues (Generation):



	Nine Months Ended September 30, 2019
	Revenues from external customers^(a)						Intersegment Revenues			Total Revenues
	Contracts with customers		Other^(b)		Total		Intersegment Revenues			Total Revenues
Mid-Atlantic	$	3,798	$	9	$	3,807	$	2		$	3,809
Midwest	3,083		172		3,255		(31		)	3,224
New York	1,195		16		1,211		—			1,211
ERCOT	594		198		792		13			805
Other Power Regions	2,849		451		3,300		(46		)	3,254
Total Competitive Businesses Electric Revenues	11,519		846		12,365		(62		)	12,303
Competitive Businesses Natural Gas Revenues	1,041		438		1,479		62			1,541
Competitive Businesses Other Revenues^(c)	343		93		436		—			436
Total Generation Consolidated Operating Revenues	$	12,903	$	1,377	$	14,280	$	—		$	14,280



	Nine Months Ended September 30, 2018
	Revenues from external customers^(a)							Intersegment revenues			Total Revenues
	Contracts with customers		Other^(b)			Total		Intersegment revenues			Total Revenues
Mid-Atlantic	$	3,971	$	191		$	4,162	$	17		$	4,179
Midwest	3,432		169			3,601		(8		)	3,593
New York	1,305		(37		)	1,268		1			1,269
ERCOT	470		459			929		1			930
Other Power Regions	2,656		574			3,230		(116		)	3,114
Total Competitive Businesses Electric Revenues	11,834		1,356			13,190		(105		)	13,085
Competitive Businesses Natural Gas Revenues	1,016		823			1,839		105			1,944
Competitive Businesses Other Revenues^(c)	385		(46		)	339		—			339
Total Generation Consolidated Operating Revenues	$	13,235	$	2,133		$	15,368	$	—		$	15,368

__________


(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 gains of $64 million and losses of $96 million in 2019 and 2018, respectively, and elimination of intersegment revenues.

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



	Nine Months Ended September 30, 2019							Nine Months Ended September 30, 2018
	RNF from external customers^(a)		Intersegment RNF			Total RNF		RNF from external customers^(a)		Intersegment RNF			Total RNF
Mid-Atlantic	$	2,007	$	16		$	2,023	$	2,303	$	45		$	2,348
Midwest	2,269		(22		)	2,247		2,381		19			2,400
New York	800		10			810		832		9			841
ERCOT	252		(27		)	225		396		(180		)	216
Other Power Regions	542		(64		)	478		740		(133		)	607
Total Revenues net of purchased power and fuel expense for Reportable Segments	5,870		(87		)	5,783		6,652		(240		)	6,412
Other^(b)	262		87			349		164		240			404
Total Generation Revenues net of purchased power and fuel expense	$	6,132	$	—		$	6,132	$	6,816	$	—		$	6,816

__________


(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 losses of $84 million and $104 million in 2019 and 2018, respectively, accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 8 — Early Plant Retirements of $13 million and $53 million decrease to RNF in 2019 and 2018, respectively, and the elimination of intersegment RNF.

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



	Nine Months Ended September 30, 2019
Revenues from contracts with customers	ComEd			PECO			BGE		PHI		Pepco		DPL			ACE
Rate-regulated electric revenues
Residential	$	2,221		$	1,231		$	1,019	$	1,816	$	792	$	499		$	525
Small commercial & industrial	1,103			304			193		387		114		141			132
Large commercial & industrial	399			163			335		843		633		75			135
Public authorities & electric railroads	35			23			20		47		27		10			10
Other^(a)	660			186			242		481		166		151			164
Total rate-regulated electric revenues^(b)	4,418			1,907			1,809		3,574		1,732		876			966
Rate-regulated natural gas revenues
Residential	—			285			327		64		—		64			—
Small commercial & industrial	—			122			55		30		—		30			—
Large commercial & industrial	—			1			93		4		—		4			—
Transportation	—			18			—		11		—		11			—
Other^(c)	—			5			19		6		—		6			—
Total rate-regulated natural gas revenues^(d)	—			431			494		115		—		115			—
Total rate-regulated revenues from contracts with customers	4,418			2,338			2,303		3,689		1,732		991			966

Other revenues
Revenues from alternative revenue programs	(98		)	(16		)	11		4		10		(6		)	—
Other rate-regulated electric revenues^(e)	22			10			10		7		6		1			—
Other rate-regulated natural gas revenues^(e)	—			1			3		—		—		1			—
Total other revenues	(76		)	(5		)	24		11		16		(4		)	—
Total rate-regulated revenues for reportable segments	$	4,342		$	2,333		$	2,327	$	3,700	$	1,748	$	987		$	966



	Nine Months Ended September 30, 2018
Revenues from contracts with customers	ComEd			PECO		BGE			PHI		Pepco		DPL		ACE
Rate-regulated electric revenues
Residential	$	2,277		$	1,199	$	1,054		$	1,839	$	792	$	513	$	534
Small commercial & industrial	1,132			306		196			370		104		138		128
Large commercial & industrial	411			174		325			845		632		74		139
Public authorities & electric railroads	36			21		21			44		24		10		10
Other^(a)	656			181		246			446		145		129		174
Total rate-regulated electric revenues^(b)	4,512			1,881		1,842			3,544		1,697		864		985
Rate-regulated natural gas revenues
Residential	—			259		345			68		—		68		—
Small commercial & industrial	—			102		55			31		—		31		—
Large commercial & industrial	—			1		88			7		—		7		—
Transportation	—			16		—			12		—		12		—
Other^(c)	—			4		49			11		—		11		—
Total rate-regulated natural gas revenues^(d)	—			382		537			129		—		129		—
Total rate-regulated revenues from contracts with customers	4,512			2,263		2,379			3,673		1,697		993		985

Other revenues
Revenues from alternative revenue programs	(27		)	2		(23		)	7		6		5		(4		)
Other rate-regulated electric revenues^(e)	23			10		10			8		5		3		—
Other rate-regulated natural gas revenues^(e)	—			—		3			—		—		—		—
Total other revenues	(4		)	12		(10		)	15		11		8		(4		)
Total rate-regulated revenues for reportable segments	$	4,508		$	2,275	$	2,369		$	3,688	$	1,708	$	1,001	$	981

__________


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


(b)	Includes operating revenues from affiliates of $13 million, $4 million, $5 million, $11 million, $5 million, $5 million and $2 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2019 and $23 million, $5 million, $5 million, $11 million $5 million, $6 million and $2 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2018.


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


(d)	Includes operating revenues from affiliates of less than $1 million and $13 million at PECO and BGE in 2019 and 2018, respectively.

(e)

Includes late payment charge revenues.

Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2019

Accounting Policies [Abstract]

Basis of Accounting, Policy [Policy Text Block]

Basis of Presentation (All Registrants)

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

New Accounting Pronouncements, Policy [Policy Text Block]

New Accounting Standards (All Registrants)

New Accounting Standards Adopted in 2019: In 2019, the Registrants have adopted the following new authoritative accounting guidance issued by the FASB.

Leases. The Registrants applied the new guidance with the following transition practical expedients:


•	a "package of three" expedients that must be taken together and allow entities to (1) not reassess whether existing contracts contain leases, (2) carry forward the existing lease classification, and (3) not reassess initial direct costs associated with existing leases,


•	an implementation expedient which allows the requirements of the standard in the period of adoption with no restatement of prior periods, and


•	a land easement expedient which allows entities to not evaluate land easements under the new standard at adoption if they were not previously accounted for as leases.

See Note 1 — Significant Accounting Policies of the Exelon 2018 Form 10-K for additional information on new accounting standards issued and adopted as of January 1, 2019.

Revenues [Policy Text Block]

Lessee, Leases [Policy Text Block]

Leases (All Registrants)

See Note 5 —Leases for additional information.

Fair Value of Financial Instruments, Policy [Policy Text Block]

Valuation Techniques Used to Determine Net Asset Value

Variable Interest Entities (Tables)

9 Months Ended

Sep. 30, 2019

Variable Interest Entity [Abstract]

VIE - Assets and Liabilities of VIEs which Creditors or Beneficiaries have no Recourse [Table Text Block]



	September 30, 2019								December 31, 2018
	Exelon		Generation		PHI ^(a)		ACE		Exelon		Generation		PHI ^(a)		ACE
Cash and cash equivalents	$	168	$	168	$	—	$	—	$	414	$	414	$	—	$	—
Restricted cash and cash equivalents	76		73		3		3		66		62		4		4
Accounts receivable, net
Customer	163		163		—		—		146		146		—		—
Other	43		43		—		—		23		23		—		—
Unamortized energy contract asset ^(b)	23		23		—		—		25		25		—		—
Inventory, net
Materials and supplies	222		222		—		—		212		212		—		—
Other current assets	50		48		2		—		52		49		3		—
Total current assets	745		740		5		3		938		931		7		4
Property, plant and equipment, net ^(c)	6,079		6,079		—		—		6,188		6,188		—		—
NDT funds	2,636		2,636		—		—		2,351		2,351		—		—
Unamortized energy contract asset ^(b)	258		258		—		—		274		274		—		—
Other noncurrent assets	69		52		17		15		258		232		26		19
Total noncurrent assets	9,042		9,025		17		15		9,071		9,045		26		19
Total assets	$	9,787	$	9,765	$	22	$	18	$	10,009	$	9,976	$	33	$	23
Long-term debt due within one year	$	556	$	535	$	21	$	19	$	87	$	66	$	21	$	18
Accounts payable	148		148		—		—		96		96		—		—
Accrued expenses	58		57		1		1		73		72		1		1
Unamortized energy contract liabilities	10		10		—		—		15		15		—		—
Other current liabilities	30		30		—		—		3		3		—		—
Total current liabilities	802		780		22		20		274		252		22		19
Long-term debt	532		504		28		26		1,072		1,025		47		40
Asset retirement obligations ^(d)	2,103		2,103		—		—		2,165		2,165		—		—
Unamortized energy contract liabilities	1		1		—		—		1		1		—		—
Other noncurrent liabilities	84		84		—		—		42		42		—		—
Total noncurrent liabilities	2,720		2,692		28		26		3,280		3,233		47		40
Total liabilities	$	3,522	$	3,472	$	50	$	46	$	3,554	$	3,485	$	69	$	59

_________


(a)	Includes certain purchase accounting adjustments not pushed down to the ACE standalone entity.


(b)	These are unrestricted assets to Exelon and Generation.


(c)	Exelon’s and Generation’s balances include unrestricted assets of $41 million and $43 million as of September 30, 2019 and December 31, 2018, respectively.

(d)

Exelon’s and Generation’s balances include liabilities with recourse of $5 million as of September 30, 2019 and December 31, 2018.

VIE - Summary of Unconsolidated VIEs [Table Text Block]

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



	September 30, 2019						December 31, 2018
	Commercial Agreement VIEs		Equity Investment VIEs		Total		Commercial Agreement VIEs		Equity Investment VIEs		Total
Total assets^(a)	$	614	$	453	$	1,067	$	597	$	472	$	1,069
Total liabilities^(a)	36		224		260		37		222		259
Exelon's ownership interest in VIE^(a)	—		201		201		—		223		223
Other ownership interests in VIE^(a)	587		28		615		560		27		587
Registrants’ maximum exposure to loss:
Carrying amount of equity method investments	—		12		12		—		223		223

_________

(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.

Revenue from Contracts with Customers (Tables)

9 Months Ended

Sep. 30, 2019

Revenue from Contract with Customer [Abstract]

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

The following table provides a rollforward of the contract assets and liabilities reflected in Exelon's and Generation's Consolidated Balance Sheets from January 1, 2018 to September 30, 2019:



	Contract Assets						Contract Liabilities
	Exelon			Generation			Exelon			Generation
Balance as of January 1, 2018	$	283		$	283		$	35		$	35
Consideration received or due	(146		)	(146		)	179			465
Revenues recognized	50			50			(187		)	(458		)
Balance at December 31, 2018	187			187			27			42
Consideration received or due	(109		)	(109		)	65			198
Revenues recognized	92			92			(66		)	(192		)
Balance at September 30, 2019	170			170			26			48

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



	2019	2020	2021	2022	2023 and thereafter	Total
Exelon	156	341	142	74	244	957
Generation	215	442	197	89	244	1,187

Leases (Tables)

9 Months Ended

Sep. 30, 2019

Leases [Abstract]

Components of Lease Cost [Table Text Block]

The components of lease costs for the three months ended September 30, 2019 were as follows:



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Operating lease costs	$	97	$	73	$	1	$	—	$	8	$	12	$	3	$	3	$	2
Variable lease costs	79		74		—		—		1		1		—		—		—
Short-term lease costs	5		5		—		—		—		—		—		—		—
Total lease costs ^(a)	$	181	$	152	$	1	$	—	$	9	$	13	$	3	$	3	$	2

__________


(a)	Excludes $29 million, $28 million, $1 million and $1 million of sublease income recorded at Exelon, Generation, PHI and DPL, respectively

The components of lease costs for the nine months ended September 30, 2019 were as follows:



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Operating lease costs	$	252	$	180	$	2	$	1	$	25	$	35	$	9	$	10	$	5
Variable lease costs	229		214		1		—		1		5		2		2		1
Short-term lease costs	16		16		—		—		—		—		—		—		—
Total lease costs ^(a)	$	497	$	410	$	3	$	1	$	26	$	40	$	11	$	12	$	6

__________

(a)

Excludes $48 million, $42 million, $6 million and $6 million of sublease income recorded at Exelon, Generation, PHI and DPL, respectively.

The weighted average remaining lease terms, in years, and discount rates for operating leases as of September 30, 2019 were as follows:



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Remaining lease term	10.1		10.6		4.7		4.3		5.6		9.0		9.6		9.5		5.3
Discount rate	4.5	%	4.8	%	3.1	%	3.3	%	3.6	%	4.0	%	3.7	%	3.7	%	3.3	%

Supplemental Balance Sheet Information Related to Lessee Right-of-Use Assets and Lease Liabilities [Table Text Block]



	Exelon^(a)		Generation^(a)		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Operating lease ROU assets
Other deferred debits and other assets	$	1,374	$	926	$	10	$	2	$	83	$	304	$	66	$	75	$	24

Operating lease liabilities
Other current liabilities	242		170		3		—		32		35		8		11		5
Other deferred credits and other liabilities	1,355		949		8		1		50		279		60		74		19
Total operating lease liabilities	$	1,597	$	1,119	$	11	$	1	$	82	$	314	$	68	$	85	$	24

__________

(a)

Exelon's and Generation's operating ROU assets and lease liabilities include $542 million and $703 million, respectively, related to contracted generation.

Lessee, Operating Lease, Liability, Maturity [Table Text Block]

Future minimum lease payments for operating leases as of September 30, 2019 were as follows:



Year	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
2019	$	65	$	50	$	1	$	—	$	1	$	11	$	3	$	2	$	2
2020	289		203		3		1		34		45		10		13		5
2021	246		162		3		—		31		43		9		12		5
2022	179		113		2		—		16		42		9		12		4
2023	148		100		1		—		—		41		8		11		4
Remaining years	1,123		837		2		—		19		197		43		53		6
Total	2,050		1,465		12		1		101		379		82		103		26
Interest	453		346		1		—		19		65		14		18		2
Total operating lease liabilities	$	1,597	$	1,119	$	11	$	1	$	82	$	314	$	68	$	85	$	24

Schedule of Future Minimum Lease Payments for Operating Leases [Table Text Block]

Future minimum lease payments for operating leases under the prior lease accounting guidance as of December 31, 2018 were as follows:



Year	Exelon^(a)(b)		Generation^(a)(b)		ComEd^(a)(c)		PECO^(a)(c)		BGE^(a)(c)(d)(e)		PHI^(a)		Pepco^(a)		DPL^(a)(c)		ACE^(a)
2019	$	140	$	33	$	7	$	5	$	35	$	48	$	11	$	14	$	7
2020	149		46		5		5		35		46		10		13		6
2021	143		46		4		5		33		43		9		12		5
2022	126		47		4		5		18		42		8		12		5
2023	97		46		3		5		3		39		8		10		4
Remaining years	723		545		—		—		19		159		40		35		5
Total minimum future lease payments	$	1,378	$	763	$	23	$	25	$	143	$	377	$	86	$	96	$	32

__________


(a)	Includes amounts related to shared use land arrangements.


(b)	Excludes Generation’s contingent operating lease payments associated with contracted generation.

(c)


(d)	Includes all future lease payments on a 99-year real estate lease that expires in 2106.

(e)

The BGE column above includes minimum future lease payments associated with a 6-year lease for the Baltimore City conduit system that became effective during the fourth quarter of 2016. BGE's total commitments under the lease agreement are $26 million, $28 million, $28 million and $14 million related to years 2019 - 2022, respectively.

Schedule of Supplemental Cash Flow Information Related to Leases [Table Text Block]

Cash paid for amounts included in the measurement of lease liabilities for the nine months ended September 30, 2019 were as follows:



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Operating cash flows from operating leases	$	225	$	156	$	2	$	—	$	32	$	29	$	7	$	6	$	4

ROU assets obtained in exchange for lease obligations for the nine months ended September 30, 2019 were as follows:



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Operating leases	$	70	$	11	$	6	$	—	$	1	$	20	$	7	$	9	$	4

Components of Operating Lease Income [Table Text Block]

The components of lease income for the three months ended September 30, 2019 were as follows:



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Operating lease income	$	30	$	29	$	—	$	—	$	—	$	1	$	—	$	1	$	—
Variable lease income	80		80		—		—		—		—		—		—		—

The components of lease income for the nine months ended September 30, 2019 were as follows:



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Operating lease income	$	48	$	44	$	—	$	—	$	—	$	3	$	—	$	3	$	—
Variable lease income	209		206		—		—		—		3		—		3		—

Lessor, Operating Lease, Payments to be Received, Maturity [Table Text Block]

Future minimum lease payments to be recovered under operating leases as of September 30, 2019 were as follows:



Year	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
2019	$	4	$	3	$	—	$	—	$	—	$	1	$	—	$	1	$	—
2020	51		46		—		—		—		4		—		3		—
2021	50		45		—		—		—		4		1		3		—
2022	50		45		—		—		—		5		—		4		—
2023	49		45		—		—		—		4		—		3		—
Remaining years	314		271		1		3		1		38		—		38		—
Total	$	518	$	455	$	1	$	3	$	1	$	56	$	1	$	52	$	—

Regulatory Matters (Tables)

9 Months Ended

Sep. 30, 2019

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 2019.

Completed Distribution Base Rate Case Proceedings



Registrant/Jurisdiction	Filing Date	Requested Revenue Requirement (Decrease) Increase				Approved Revenue Requirement (Decrease) Increase				Approved ROE		Approval Date	Rate Effective Date
ComEd - Illinois (Electric)	April 16, 2018	$	(23	)		$	(24	)		8.69%		December 4, 2018	January 1, 2019
PECO - Pennsylvania (Electric)	March 29, 2018	$	82			$	25			N/A	^(a)	December 20, 2018	January 1, 2019
BGE - Maryland (Natural Gas)	June 8, 2018 (amended October 12, 2018)	$	61			$	43			9.8%		January 4, 2019	January 4, 2019
ACE - New Jersey (Electric)	August 21, 2018 (amended November 19, 2018)	$	122		^(b)	$	70		^(b)	9.6%		March 13, 2019	April 1, 2019
Pepco - Maryland (Electric)	January 15, 2019 (amended May 16, 2019)	$	27			$	10			9.6%		August 12, 2019	August 13, 2019

__________


(a)	The PECO rate case proceeding was resolved through a settlement agreement, which did not specify an approved ROE.


(b)	Requested and approved increases are before New Jersey sales and use tax.

Pending Distribution Base Rate Case Proceedings



Registrant/Jurisdiction	Filing Date	Requested Revenue Requirement (Decrease) Increase			Requested ROE		Expected Approval Timing
ComEd - Illinois (Electric)^(a)	April 8, 2019	$	(6	)	8.91	%	December 2019
BGE - Maryland (Electric)^(b)	May 24, 2019 (amended October 4, 2019)	$	74		10.3	%	December 2019
BGE - Maryland (Natural Gas)^(b)	May 24, 2019 (amended October 4, 2019)	$	59		10.3	%	December 2019
Pepco - District of Columbia (Electric)^(c)	May 30, 2019 (amended September 16, 2019)	$	160		10.3	%	Fourth quarter of 2020

__________

(a)


(b)	On October 25, 2019, BGE filed a settlement agreement with the MDPSC. The settlement provides for an increase to BGE’s annual electric and natural gas distribution rates of $18 million and $45 million, respectively.

(c)

Reflects a three-year cumulative multi-year plan and total requested revenue requirement increases of $84 million, $40 million and $36 million for years 2020, 2021, and 2022, respectively, to recover capital investments made in 2018 and 2019 and planned capital investments from 2020 to 2022.

Public Utilities Transmission Rate Filings [Table Text Block]

For 2019, the following total increases/(decreases) were included in ComEd’s, BGE’s, Pepco's, DPL's and ACE's electric transmission formula rate filings:



Registrant^(a)	Initial Revenue Requirement Increase (Decrease)			Annual Reconciliation (Decrease) Increase			Total Revenue Requirement Increase (Decrease)				Allowed Return on Rate Base^(c)		Allowed ROE^(d)
ComEd	$	21		$	(16	)	$	5			8.21	%	11.50	%
BGE	(10		)	(23		)	(19		)	^(b)	7.35	%	10.50	%
Pepco	15			11			26				7.75	%	10.50	%
DPL	17			(1		)	16				7.14	%	10.50	%
ACE	11			(2		)	9				7.79	%	10.50	%

__________


(a)	All rates are effective June 2019, subject to review by the FERC and other parties, which is due by the fourth quarter of 2019.


(b)	The change in BGE's transmission revenue requirement includes a FERC approved dedicated facilities charge of $14 million to recover the costs of providing transmission service to specifically designated load by BGE.


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


(d)	As part of the FERC-approved settlement of ComEd’s 2007 transmission rate case, the rate of return on common equity is 11.50%, 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

Public Utilities Energy Efficiency Revenue [Table Text Block]

ComEd filed its annual energy efficiency formula rate update with the ICC on May 23, 2019. The filing establishes the revenue requirement used to set the rates that will take effect in January 2020 after the ICC’s review and approval. The revenue requirement requested is based on a reconciliation of the 2018 actual costs plus projected 2019 and 2020 expenditures.



Registrant	Initial Revenue Requirement Increase (Decrease)		Annual Reconciliation Increase (Decrease)			Total Revenue Requirement Increase (Decrease)			Requested Return on Rate Base		Requested ROE
ComEd	$	53	$	(2	)	$	51	^(a)	6.53	%	8.91	%

__________

(a)

Public Utilities General Disclosures [Table Text Block]



	Exelon		ComEd^(a)		PECO		BGE^(b)		PHI		Pepco^(c)		DPL^(c)		ACE
September 30, 2019	$	59	$	4	$	—	$	47	$	8	$	5	$	3	$	—
December 31, 2018	$	65	$	8	$	—	$	49	$	8	$	5	$	3	$	—

_________


(a)	Reflects ComEd's unrecognized equity returns earned 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.

Early Plant Retirements (Tables)

9 Months Ended

Sep. 30, 2019

Property, Plant and Equipment [Abstract]

Income statement expense (pre-tax)



	Three Months Ended September 30,				Nine Months Ended September 30,
Income statement expense (pre-tax)	2019		2018		2019			2018
Depreciation and amortization^(a)
Accelerated depreciation	$	71	$	152	$	216		$	441
Accelerated nuclear fuel amortization	3		18		13			52
Operating and maintenance^(b)	39		4		(44		)	32
Total	$	113	$	174	$	185		$	525

_________


(a)	Reflects incremental accelerated depreciation and amortization for TMI for the three and nine months ended September 30, 2019. Reflects incremental accelerated depreciation for TMI and Oyster Creek for the three and nine months ended September 30, 2018. The Oyster Creek amounts are from February 2, 2018 through September 17, 2018. The TMI amounts are through September 20, 2019.

(b)

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



	September 30, 2019
Asset Balances
Materials and supplies inventory	$	31
Fuel inventory	5
Completed plant, net	889
Construction work in progress	7
Liability Balances
Asset retirement obligation	(2		)

Fair Value of Financial Assets and Liabilities (Tables)

9 Months Ended

Sep. 30, 2019

Fair Value Disclosures [Abstract]

Fair Value of Financial Liabilities Recorded at Amortized Cost



	September 30, 2019								December 31, 2018
	Carrying Amount		Fair Value						Carrying Amount		Fair Value
	Carrying Amount		Level 2		Level 3		Total		Carrying Amount		Level 2		Level 3		Total
Long-Term Debt, including amounts due within one year^(a)
Exelon	$	36,304	$	38,056	$	2,541	$	40,597	$	35,424	$	33,711	$	2,158	$	35,869
Generation	8,613		7,962		1,398		9,360		8,793		7,467		1,443		8,910
ComEd	8,196		9,622		—		9,622		8,101		8,390		—		8,390
PECO	3,404		3,891		50		3,941		3,084		3,157		50		3,207
BGE	3,270		3,678		—		3,678		2,876		2,950		—		2,950
PHI	6,494		5,993		1,093		7,086		6,259		5,436		665		6,101
Pepco	2,860		3,249		395		3,644		2,719		2,901		196		3,097
DPL	1,495		1,437		232		1,669		1,494		1,303		193		1,496
ACE	1,324		1,034		466		1,500		1,188		987		275		1,262
Long-Term Debt to Financing Trusts^(a)
Exelon	$	390	$	—	$	426	$	426	$	390	$	—	$	400	$	400
ComEd	205		—		223		223		205		—		209		209
PECO	184		—		203		203		184		—		191		191
SNF Obligation
Exelon	$	1,193	$	1,017	$	—	$	1,017	$	1,171	$	949	$	—	$	949
Generation	1,193		1,017		—		1,017		1,171		949		—		949

____

(a)

Includes unamortized debt issuance costs which are not fair valued.

Assets and liabilities measured and recorded at fair value on recurring basis

Recurring Fair Value Measurements

Exelon and Generation



	Exelon										Generation
As of September 30, 2019	Level 1		Level 2		Level 3		Not subject to leveling		Total		Level 1		Level 2		Level 3		Not subject to leveling		Total
Assets
Cash equivalents^(a)	$	1,719	$	—	$	—	$	—	$	1,719	$	896	$	—	$	—	$	—	$	896
NDT fund investments
Cash equivalents^(b)	315		78		—		—		393		315		78		—		—		393
Equities	3,121		1,727		—		1,314		6,162		3,121		1,727		—		1,314		6,162
Fixed income
Corporate debt	—		1,473		259		—		1,732		—		1,473		259		—		1,732
U.S. Treasury and agencies	1,777		152		—		—		1,929		1,777		152		—		—		1,929
Foreign governments	—		56		—		—		56		—		56		—		—		56
State and municipal debt	—		85		—		—		85		—		85		—		—		85
Other^(c)	—		23		—		979		1,002		—		23		—		979		1,002



	Exelon														Generation
As of September 30, 2019	Level 1			Level 2			Level 3			Not subject to leveling		Total			Level 1			Level 2			Level 3			Not subject to leveling		Total
Fixed income subtotal	1,777			1,789			259			979		4,804			1,777			1,789			259			979		4,804
Middle market lending	—			—			255			445		700			—			—			255			445		700
Private equity	—			—			—			398		398			—			—			—			398		398
Real estate	—			—			—			581		581			—			—			—			581		581
NDT fund investments subtotal^(d)	5,213			3,594			514			3,717		13,038			5,213			3,594			514			3,717		13,038
Rabbi trust investments
Cash equivalents	49			—			—			—		49			4			—			—			—		4
Mutual funds	77			—			—			—		77			24			—			—			—		24
Fixed income	—			13			—			—		13			—			—			—			—		—
Life insurance contracts	—			76			40			—		116			—			24			—			—		24
Rabbi trust investments subtotal	126			89			40			—		255			28			24			—			—		52
Commodity derivative assets
Economic hedges	533			1,488			1,817			—		3,838			533			1,488			1,817			—		3,838
Proprietary trading	—			54			156			—		210			—			54			156			—		210
Effect of netting and allocation of collateral^(e)(f)	(677		)	(1,261		)	(1,025		)	—		(2,963		)	(677		)	(1,261		)	(1,025		)	—		(2,963		)
Commodity derivative assets subtotal	(144		)	281			948			—		1,085			(144		)	281			948			—		1,085
Total assets	6,914			3,964			1,502			3,717		16,097			5,993			3,899			1,462			3,717		15,071
Liabilities
Commodity derivative liabilities
Economic hedges	(773		)	(1,695		)	(1,686		)	—		(4,154		)	(773		)	(1,695		)	(1,406		)	—		(3,874		)
Proprietary trading	—			(59		)	(89		)	—		(148		)	—			(59		)	(89		)	—		(148		)
Effect of netting and allocation of collateral^(e)(f)	770			1,585			1,329			—		3,684			770			1,585			1,329			—		3,684
Commodity derivative liabilities subtotal	(3		)	(169		)	(446		)	—		(618		)	(3		)	(169		)	(166		)	—		(338		)
Deferred compensation obligation	—			(140		)	—			—		(140		)	—			(37		)	—			—		(37		)
Total liabilities	(3		)	(309		)	(446		)	—		(758		)	(3		)	(206		)	(166		)	—		(375		)
Total net assets	$	6,911		$	3,655		$	1,056		$	3,717	$	15,339		$	5,990		$	3,693		$	1,296		$	3,717	$	14,696



	Exelon														Generation
As of December 31, 2018	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)	$	1,243		$	—		$	—		$	—	$	1,243		$	581		$	—		$	—		$	—	$	581
NDT fund investments
Cash equivalents^(b)	252			86			—			—		338			252			86			—			—		338
Equities	2,918			1,591			—			1,381		5,890			2,918			1,591			—			1,381		5,890
Fixed income
Corporate debt	—			1,593			230			—		1,823			—			1,593			230			—		1,823
U.S. Treasury and agencies	2,081			99			—			—		2,180			2,081			99			—			—		2,180
Foreign governments	—			50			—			—		50			—			50			—			—		50
State and municipal debt	—			149			—			—		149			—			149			—			—		149
Other^(c)	—			30			—			846		876			—			30			—			846		876
Fixed income subtotal	2,081			1,921			230			846		5,078			2,081			1,921			230			846		5,078
Middle market lending	—			—			313			367		680			—			—			313			367		680
Private equity	—			—			—			329		329			—			—			—			329		329
Real estate	—			—			—			510		510			—			—			—			510		510
NDT fund investments subtotal^(d)	5,251			3,598			543			3,433		12,825			5,251			3,598			543			3,433		12,825
Rabbi trust investments
Cash equivalents	48			—			—			—		48			5			—			—			—		5
Mutual funds	72			—			—			—		72			24			—			—			—		24
Fixed income	—			15			—			—		15			—			—			—			—		—
Life insurance contracts	—			70			38			—		108			—			22			—			—		22
Rabbi trust investments subtotal	120			85			38			—		243			29			22			—			—		51
Commodity derivative assets
Economic hedges	541			2,760			1,470			—		4,771			541			2,760			1,470			—		4,771
Proprietary trading	—			69			77			—		146			—			69			77			—		146
Effect of netting and allocation of collateral^(e)(f)	(582		)	(2,357		)	(732		)	—		(3,671		)	(582		)	(2,357		)	(732		)	—		(3,671		)
Commodity derivative assets subtotal	(41		)	472			815			—		1,246			(41		)	472			815			—		1,246
Total assets	6,573			4,155			1,396			3,433		15,557			5,820			4,092			1,358			3,433		14,703



	Exelon														Generation
As of December 31, 2018	Level 1			Level 2			Level 3			Not subject to leveling		Total			Level 1			Level 2			Level 3			Not subject to leveling		Total
Liabilities
Commodity derivative liabilities
Economic hedges	(642		)	(2,963		)	(1,276		)	—		(4,881		)	(642		)	(2,963		)	(1,027		)	—		(4,632		)
Proprietary trading	—			(73		)	(21		)	—		(94		)	—			(73		)	(21		)	—		(94		)
Effect of netting and allocation of collateral^(e)(f)	639			2,581			808			—		4,028			639			2,581			808			—		4,028
Commodity derivative liabilities subtotal	(3		)	(455		)	(489		)	—		(947		)	(3		)	(455		)	(240		)	—		(698		)
Deferred compensation obligation	—			(137		)	—			—		(137		)	—			(35		)	—			—		(35		)
Total liabilities	(3		)	(592		)	(489		)	—		(1,084		)	(3		)	(490		)	(240		)	—		(733		)
Total net assets	$	6,570		$	3,563		$	907		$	3,433	$	14,473		$	5,817		$	3,602		$	1,118		$	3,433	$	13,970

_________

(a)


(b)	Includes $85 million and $50 million of cash received from outstanding repurchase agreements at September 30, 2019 and December 31, 2018, respectively, and is offset by an obligation to repay upon settlement of the agreement as discussed in (d) below.

(c)

(d)

(e)


(f)	Of the collateral posted/(received), $306 million and $(94) million represents variation margin on the exchanges as of September 30, 2019 and December 31, 2018, respectively.

Valuation Techniques Used to Determine Net Asset Value

ComEd, PECO and BGE



	ComEd											PECO										BGE
As of September 30, 2019	Level 1		Level 2			Level 3			Total			Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3		Total
Assets
Cash equivalents^(a)	$	264	$	—		$	—		$	264		$	207	$	—		$	—	$	207		$	122	$	—		$	—	$	122
Rabbi trust investments
Mutual funds	—		—			—			—			8		—			—		8			7		—			—		7
Life insurance contracts	—		—			—			—			—		11			—		11			—		—			—		—
Rabbi trust investments subtotal	—		—			—			—			8		11			—		19			7		—			—		7
Total assets	264		—			—			264			215		11			—		226			129		—			—		129
Liabilities
Deferred compensation obligation	—		(7		)	—			(7		)	—		(8		)	—		(8		)	—		(5		)	—		(5		)
Mark-to-market derivative liabilities^(b)	—		—			(280		)	(280		)	—		—			—		—			—		—			—		—
Total liabilities	—		(7		)	(280		)	(287		)	—		(8		)	—		(8		)	—		(5		)	—		(5		)
Total net assets (liabilities)	$	264	$	(7	)	$	(280	)	$	(23	)	$	215	$	3		$	—	$	218		$	129	$	(5	)	$	—	$	124



	ComEd											PECO										BGE
As of December 31, 2018	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)	$	209	$	—		$	—		$	209		$	111	$	—		$	—	$	111		$	4	$	—		$	—	$	4
Rabbi trust investments
Mutual funds	—		—			—			—			7		—			—		7			6		—			—		6
Life insurance contracts	—		—			—			—			—		10			—		10			—		—			—		—
Rabbi trust investments subtotal	—		—			—			—			7		10			—		17			6		—			—		6
Total assets	209		—			—			209			118		10			—		128			10		—			—		10
Liabilities
Deferred compensation obligation	—		(6		)	—			(6		)	—		(10		)	—		(10		)	—		(5		)	—		(5		)
Mark-to-market derivative liabilities^(b)	—		—			(249		)	(249		)	—		—			—		—			—		—			—		—
Total liabilities	—		(6		)	(249		)	(255		)	—		(10		)	—		(10		)	—		(5		)	—		(5		)
Total net assets (liabilities)	$	209	$	(6	)	$	(249	)	$	(46	)	$	118	$	—		$	—	$	118		$	10	$	(5	)	$	—	$	5

_________

(a)


(b)	The Level 3 balance consists of the current and noncurrent liability of $27 million and $253 million, respectively, at September 30, 2019, and $26 million and $223 million, respectively, at December 31, 2018, related to floating-to-fixed energy swap contracts with unaffiliated suppliers.

PHI, Pepco, DPL and ACE



	As of September 30, 2019										As of December 31, 2018
PHI	Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3		Total
Assets
Cash equivalents^(a)	$	107	$	—		$	—	$	107		$	147	$	—		$	—	$	147
Rabbi trust investments
Cash equivalents	43		—			—		43			42		—			—		42
Mutual funds	13		—			—		13			13		—			—		13
Fixed income	—		13			—		13			—		15			—		15
Life insurance contracts	—		24			40		64			—		22			38		60
Rabbi trust investments subtotal	56		37			40		133			55		37			38		130
Total assets	163		37			40		240			202		37			38		277
Liabilities
Deferred compensation obligation	—		(19		)	—		(19		)	—		(21		)	—		(21		)
Total liabilities	—		(19		)	—		(19		)	—		(21		)	—		(21		)
Total net assets	$	163	$	18		$	40	$	221		$	202	$	16		$	38	$	256



	Pepco										DPL								ACE
As of September 30, 2019	Level 1		Level 2			Level 3		Total			Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents^(a)	$	34	$	—		$	—	$	34		$	—	$	—	$	—	$	—	$	18	$	—	$	—	$	18
Rabbi trust investments
Cash equivalents	43		—			—		43			—		—		—		—		—		—		—		—
Fixed income	—		3			—		3			—		—		—		—		—		—		—		—
Life insurance contracts	—		24			40		64			—		—		—		—		—		—		—		—
Rabbi trust investments subtotal	43		27			40		110			—		—		—		—		—		—		—		—
Total assets	77		27			40		144			—		—		—		—		18		—		—		18
Liabilities
Deferred compensation obligation	—		(2		)	—		(2		)	—		—		—		—		—		—		—		—
Total liabilities	—		(2		)	—		(2		)	—		—		—		—		—		—		—		—
Total net assets	$	77	$	25		$	40	$	142		$	—	$	—	$	—	$	—	$	18	$	—	$	—	$	18



	Pepco										DPL										ACE
As of December 31, 2018	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)	$	38	$	—		$	—	$	38		$	16	$	—		$	—	$	16		$	23	$	—	$	—	$	23
Rabbi trust investments
Cash equivalents	41		—			—		41			—		—			—		—			—		—		—		—
Fixed income	—		5			—		5			—		—			—		—			—		—		—		—
Life insurance contracts	—		22			37		59			—		—			—		—			—		—		—		—
Rabbi trust investments subtotal	41		27			37		105			—		—			—		—			—		—		—		—
Total assets	79		27			37		143			16		—			—		16			23		—		—		23
Liabilities
Deferred compensation obligation	—		(3		)	—		(3		)	—		(1		)	—		(1		)	—		—		—		—
Total liabilities	—		(3		)	—		(3		)	—		(1		)	—		(1		)	—		—		—		—
Total net assets (liabilities)	$	79	$	24		$	37	$	140		$	16	$	(1	)	$	—	$	15		$	23	$	—	$	—	$	23

_________

(a)

Fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis



	Exelon			Generation										ComEd				PHI and Pepco
Three Months Ended September 30, 2019	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, 2019	$	1,179		$	539		$	873			$	1,412		$	(273	)		$	40	$	—
Total realized / unrealized gains (losses)
Included in net income	(171		)	2			(173		)	^(a)	(171		)	—				—		—
Included in noncurrent payables to affiliates	—			11			—				11			—				—		(11		)
Included in regulatory assets/liabilities	4			—			—				—			(7		)	^(b)	—		11
Change in collateral	41			—			41				41			—				—		—
Purchases, sales, issuances and settlements
Purchases	53			1			52				53			—				—		—
Sales	(22		)	(21		)	(1		)		(22		)	—				—		—
Settlements	(18		)	(18		)	—				(18		)	—				—		—
Transfers into Level 3	1			—			1			^(c)	1			—				—		—
Transfers out of Level 3	(11		)	—			(11		)	^(c)	(11		)	—				—		—
Balance at September 30, 2019	$	1,056		$	514		$	782			$	1,296		$	(280	)		$	40	$	—
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, 2019	$	(18	)	$	2		$	(20	)		$	(18	)	$	—			$	—	$	—



	Exelon			Generation										ComEd				PHI and Pepco
Nine Months Ended September 30, 2019	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, 2018	$	907		$	543		$	575			$	1,118		$	(249	)		$	38	$	—
Total realized / unrealized gains (losses)
Included in net income	(125		)	5			(132		)	^(a)	(127		)	—				2		—
Included in noncurrent payables to affiliates	—			32			—				32			—				—		(32		)
Included in regulatory assets	1			—			—				—			(31		)	^(b)	—		32
Change in collateral	227			—			227				227			—				—		—
Purchases, sales, issuances and settlements
Purchases	163			43			120				163			—				—		—
Sales	(23		)	(21		)	(2		)		(23		)	—				—		—
Settlements	(88		)	(88		)	—				(88		)	—				—		—
Transfers into Level 3	5			—			5			^(c)	5			—				—		—
Transfers out of Level 3	(11		)	—			(11		)	^(c)	(11		)	—				—		—
Balance as of September 30, 2019	$	1,056		$	514		$	782			$	1,296		$	(280	)		$	40	$	—
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2019	$	173		$	5		$	166			$	171		$	—			$	2	$	—

__________


(a)	Includes a reduction for the reclassification of $153 million and $298 million of realized gains due to the settlement of derivative contracts for the three and nine months ended September 30, 2019, respectively.

(b)


(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.



	Exelon			Generation										ComEd				PHI and Pepco
Three Months Ended September 30, 2018	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, 2018	$	1,106		$	585		$	737			$	1,322		$	(252	)		$	36	$	—
Total realized / unrealized gains (losses)
Included in net income	(259		)	(1		)	(259		)	^(a)	(260		)	—				1		—
Included in noncurrent payables to affiliates	—			(4		)	—				(4		)	—				—		4
Included in regulatory assets	(11		)	—			—				—			(7		)	^(b)	—		(4		)
Change in collateral	(44		)	—			(44		)		(44		)	—				—		—
Purchases, sales, issuances and settlements
Purchases	96			15			81				96			—				—		—
Settlements	(29		)	(29		)	—				(29		)	—				—		—
Transfers into Level 3	3			—			3			^(c)	3			—				—		—
Transfers out of Level 3	(6		)	—			(6		)	^(c)	(6		)	—				—		—
Balance as of September 30, 2018	$	856		$	566		$	512			$	1,078		$	(259	)		$	37	$	—
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2018	$	(105	)	$	(1	)	$	(104	)		$	(105	)	$	—			$	—	$	—



	Exelon			Generation										ComEd				PHI and Pepco
Nine Months Ended September 30, 2018	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, 2017	$	966		$	648		$	552			$	1,200		$	(256	)		$	22	$	—
Total realized / unrealized gains (losses)
Included in net income	(186		)	(1		)	(188		)	^(a)	(189		)	—				3		—
Included in regulatory assets	(3		)	—			—				—			(3		)	^(b)	—		—
Change in collateral	14			—			14				14			—				—		—
Purchases, sales, issuances and settlements
Purchases	215			34			181				215			—				—		—
Sales	(3		)	—			(3		)		(3		)	—				—		—
Settlements	(103		)	(115		)	—				(115		)	—				12		—
Transfers into Level 3	(21		)	—			(21		)	^(c)	(21		)	—				—		—
Transfers out of Level 3	(23		)	—			(23		)	^(c)	(23		)	—				—		—
Balance as of September 30, 2018	$	856		$	566		$	512			$	1,078		$	(259	)		$	37	$	—
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2018	$	154		$	(5	)	$	159			$	154		$	—			$	—	$	—

__________


(a)	Includes a reduction for the reclassification of $155 million and $347 million of realized losses due to the settlement of derivative contracts for the three and nine months ended September 30, 2018, respectively.

(b)

(c)

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

Total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis



	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 realized (losses) gains for the three months ended September 30, 2019	$	(25	)	$	(148	)	$	—	$	2	$	(25	)	$	(148	)	$	2	$	—
Total realized gains (losses) for the nine months ended September 30, 2019	122			(254		)	—		5		122			(254		)	5		—
Total unrealized gains (losses) for the three months ended September 30, 2019	99			(119		)	—		2		99			(119		)	2		—
Total unrealized gains (losses) for the nine months ended September 30, 2019	368			(202		)	2		5		368			(202		)	5		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 realized (losses) gains for the three months ended September 30, 2018	$	(176	)	$	(83	)	$	1	$	(1	)	$	(176	)	$	(83	)	$	(1	)	$	1
Total realized (losses) gains for the nine months ended September 30, 2018	(32		)	(156		)	3		(1		)	(32		)	(156		)	(1		)	3
Total unrealized (losses) for the three months ended September 30, 2018	(64		)	(40		)	—		(1		)	(64		)	(40		)	(1		)	—
Total unrealized gains (losses) for the nine months ended September 30, 2018	174			(15		)	—		(5		)	174			(15		)	(5		)	—

Fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis, valuation technique

The table below discloses the significant inputs to the forward curve used to value these positions.



Type of trade	Fair Value at September 30, 2019			Fair Value at December 31, 2018			Valuation Technique	Unobservable Input	2019 Range			2018 Range
Mark-to-market derivatives — Economic Hedges (Exelon and Generation)^(a)(b)	$	411		$	443		Discounted Cash Flow	Forward power price	$11	-	$167	$12	-	$174
								Forward gas price	$1.36	-	$10.82	$0.78	-	$12.38
							Option Model	Volatility percentage	9%	-	200%	10%	-	277%

Mark-to-market derivatives — Proprietary trading (Exelon and Generation)^(a)(b)	$	67		$	56		Discounted Cash Flow	Forward power price	$17	-	$167	$14	-	$174

Mark-to-market derivatives (Exelon and ComEd)	$	(280	)	$	(249	)	Discounted Cash Flow	Forward heat rate^(c)	9x	-	10x	10x	-	11x
								Marketability reserve	4%	-	7%	4%	-	8%
								Renewable factor	87%	-	119%	86%	-	120%

_________


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


(b)	The fair values do not include cash collateral posted on level three positions of $304 million and $76 million as of September 30, 2019 and December 31, 2018, 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.

Derivative Financial Instruments (Tables)

9 Months Ended

Sep. 30, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Summary of the derivative fair value

The following table provides a summary of the derivative fair value balances recorded by Exelon, Generation and ComEd as of September 30, 2019 and December 31, 2018:



September 30, 2019	Exelon			Generation														ComEd
Derivatives	Total Derivatives			Economic Hedges			Proprietary Trading			Collateral ^(a)(b)		Netting ^(a)			Subtotal			Economic Hedges
Mark-to-market derivative assets (current assets)	$	602		$	2,452		$	143		$	212	$	(2,205	)	$	602		$	—
Mark-to-market derivative assets (noncurrent assets)	483			1,386			67			104		(1,074		)	483			—
Total mark-to-market derivative assets	1,085			3,838			210			316		(3,279		)	1,085			—
Mark-to-market derivative liabilities (current liabilities)	(224		)	(2,550		)	(101		)	249		2,205			(197		)	(27		)
Mark-to-market derivative liabilities (noncurrent liabilities)	(394		)	(1,324		)	(47		)	156		1,074			(141		)	(253		)
Total mark-to-market derivative liabilities	(618		)	(3,874		)	(148		)	405		3,279			(338		)	(280		)
Total mark-to-market derivative net assets (liabilities)	$	467		$	(36	)	$	62		$	721	$	—		$	747		$	(280	)



December 31, 2018	Exelon			Generation														ComEd
Description	Total Derivatives			Economic Hedges			Proprietary Trading			Collateral (a)(b)		Netting (a)			Subtotal			Economic Hedges
Mark-to-market derivative assets (current assets)	$	801		$	3,505		$	105		$	121	$	(2,930	)	$	801		$	—
Mark-to-market derivative assets (noncurrent assets)	445			1,266			41			51		(913		)	445			—
Total mark-to-market derivative assets	1,246			4,771			146			172		(3,843		)	1,246			—
Mark-to-market derivative liabilities (current liabilities)	(473		)	(3,429		)	(74		)	125		2,931			(447		)	(26		)
Mark-to-market derivative liabilities (noncurrent liabilities)	(474		)	(1,203		)	(20		)	60		912			(251		)	(223		)
Total mark-to-market derivative liabilities	(947		)	(4,632		)	(94		)	185		3,843			(698		)	(249		)
Total mark-to-market derivative net assets (liabilities)	$	299		$	139		$	52		$	357	$	—		$	548		$	(249	)

_________

(a)

(b)

Of the collateral posted/(received), $306 million and $(94) million represents variation margin on the exchanges at September 30, 2019 and December 31, 2018 respectively.

Economic Hedges (Commodity Price Risk)

For the three and nine months ended September 30, 2019 and 2018, Exelon and Generation recognized the following net pre-tax commodity mark-to-market gains (losses) which are also located in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows.



	Three Months Ended September 30,					Nine Months Ended September 30,
	2019			2018		2019			2018
Income Statement Location	Gain (Loss)					Gain (Loss)
Operating revenues	$	76		$	8	$	65		$	(99	)
Purchased power and fuel	(45		)	66		(127		)	(4		)
Total Exelon and Generation	$	31		$	74	$	(62	)	$	(103	)

Credit-Risk Related Contingent



Rating as of September 30, 2019	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	$	693	$	10	$	683	—	$	—
Non-investment grade	74		38		36
No external ratings
Internally rated — investment grade	297		1		296
Internally rated — non-investment grade	175		24		151
Total	$	1,239	$	73	$	1,166	—	$	—



Net Credit Exposure by Type of Counterparty	As of September 30, 2019
Financial institutions	$	1
Investor-owned utilities, marketers, power producers	875
Energy cooperatives and municipalities	255
Other	35
Total	$	1,166

_________

(a)

As of September 30, 2019, credit collateral held from counterparties where Generation had credit exposure included $18 million of cash and $55 million of letters of credit. The credit collateral does not include non-liquid collateral.

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



Credit-Risk Related Contingent Features	September 30, 2019			December 31, 2018
Gross fair value of derivative contracts containing this feature^(a)	$	(1,249	)	$	(1,723	)
Offsetting fair value of in-the-money contracts under master netting arrangements^(b)	947			1,105
Net fair value of derivative contracts containing this feature^(c)	$	(302	)	$	(618	)

_________


(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 a Registrant could potentially be required to post collateral.

(c)

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

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



	September 30, 2019		December 31, 2018
Cash collateral posted	$	787	$	418
Letters of credit posted	273		367
Cash collateral held	96		47
Letters of credit held	58		44
Additional collateral required in the event of a credit downgrade below investment grade	1,481		2,104

Debt and Credit Agreements (Tables)

9 Months Ended

Sep. 30, 2019

Debt Disclosure [Abstract]

Commercial Paper Borrowings



	Outstanding Commercial Paper as of				Average Interest Rate on Commercial Paper Borrowings as of
Commercial Paper Issuer	September 30, 2019		December 31, 2018		September 30, 2019		December 31, 2018
Exelon	$	519	$	89	2.50	%	2.15	%
ComEd	387		—		2.51	%	2.14	%
BGE	—		35		2.49	%	2.18	%
PHI	132		54		2.52	%	2.15	%
PEPCO	12		40		2.61	%	2.24	%
DPL	57		—		2.42	%	2.07	%
ACE	63		14		2.57	%	2.21	%

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

During the nine months ended September 30, 2019, the following long-term debt was issued:



Company	Type	Interest Rate		Maturity	Amount		Use of Proceeds
Generation	Energy Efficiency Project Financing	3.95	%	August 31, 2020	$	4	Funding to install energy conservation measures for the Fort Meade project.
Generation	Energy Efficiency Project Financing	3.46	%	May 1, 2020	$	39	Funding to install energy conservation measures for the Marine Corps. Logistics Project.
ComEd	First Mortgage Bonds, Series 126	4.00	%	March 1, 2049	$	400	Repay a portion of ComEd’s outstanding commercial paper obligations and fund other general corporate purposes.
PECO	First and Refunding Mortgage Bonds	3.00	%	September 15, 2049	$	325	Repay short-term borrowings and for general corporate purposes
BGE	Senior Notes	3.20	%	September 15, 2049	$	400	Repay commercial paper obligations and for general corporate purposes
Pepco	First Mortgage Bonds	3.45	%	June 13, 2029	$	150	Repay existing indebtedness and for general corporate purposes
Pepco	Unsecured Tax-Exempt Bonds	1.70	%	September 1, 2022	$	110	Refinance existing indebtedness
ACE	First Mortgage Bonds	3.50	%	May 21, 2029	$	100	Repay existing indebtedness and for general corporate purposes
ACE	First Mortgage Bonds	4.14	%	May 21, 2049	$	50	Repay existing indebtedness and for general corporate purposes

- Definition

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.

+ References

Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.22)
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 2: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=114775744&loc=d3e28541-108399

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

Reference 4: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(e),(f))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

Reference 5: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=114775744&loc=d3e28551-108399

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

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

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

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

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

+ Details

Income Taxes (Tables)

9 Months Ended

Sep. 30, 2019

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, 2019
	Exelon	Generation	ComEd	PECO	BGE	PHI	Pepco	DPL	ACE
U.S. Federal statutory rate	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	6.4	5.2	8.1	(0.3)	6.3	4.8	1.9	6.6	6.9
Qualified NDT fund income	3.2	7.1	—	—	—	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(4.1)	(8.9)	(0.2)	—	(0.1)	(0.2)	(0.1)	(0.2)	(0.3)
Plant basis differences	(1.7)	—	(1.0)	(7.5)	(1.1)	(1.8)	(2.6)	(0.6)	(1.9)
Production tax credits and other credits	(1.2)	(2.7)	—	—	—	—	—	—	—
Noncontrolling interests	(2.2)	(4.8)	—	—	—	—	—	—	—
Excess deferred tax amortization	(6.5)	—	(9.9)	(3.6)	(8.0)	(17.7)	(16.3)	(13.5)	(23.3)
Other	0.7	0.5	0.4	(0.5)	(0.2)	0.8	1.0	(0.1)	0.7
Effective income tax rate	15.6%	17.4%	18.4%	9.1%	17.9%	6.9%	4.9%	13.2%	3.1%



	Three Months Ended September 30, 2018
	Exelon	Generation	ComEd	PECO	BGE	PHI	Pepco	DPL	ACE
U.S. Federal statutory rate	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	(1.2)	(9.0)	8.3	(3.6)	7.3	0.2	1.0	6.6	7.3
Qualified NDT fund income	2.4	5.8	—	—	—	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(0.6)	(1.1)	(0.2)	(0.1)	—	(0.2)	(0.1)	(0.3)	(0.3)
Plant basis differences	(2.5)	—	(0.3)	(15.2)	(0.8)	(2.0)	(3.4)	(0.7)	(1.3)
Production tax credits and other credits	(1.2)	(2.9)	(0.1)	—	—	—	—	—	—
Noncontrolling interests	(1.1)	(2.8)	—	—	—	—	—	—	—
Excess deferred tax amortization	(6.8)	—	(7.8)	(4.6)	(7.9)	(17.7)	(21.2)	(14.0)	(15.4)
Tax Cuts and Jobs Act of 2017	1.3	3.5	—	—	—	0.2	0.1	—	—
Other	3.2	5.6	0.3	0.9	2.6	0.6	0.3	0.6	0.3
Effective income tax rate	14.5%	20.1%	21.2%	(1.6)%	22.2%	2.1%	(2.3)%	13.2%	11.6%




	Nine Months Ended September 30, 2019
	Exelon	Generation	ComEd	PECO	BGE	PHI	Pepco	DPL	ACE
U.S. Federal statutory rate	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	5.1	4.2	8.2	—	6.4	4.8	2.0	6.7	6.9
Qualified NDT fund income	5.3	11.9	—	—	—	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(1.9)	(4.0)	(0.2)	—	(0.1)	(0.2)	(0.1)	(0.2)	(0.3)
Plant basis differences	(1.6)	—	(0.7)	(6.8)	(1.1)	(1.8)	(2.3)	(0.6)	(2.0)
Production tax credits and other credits	(1.0)	(2.1)	—	—	—	—	—	—	—
Noncontrolling interests	(1.0)	(2.3)	—	—	—	—	—	—	—
Excess deferred tax amortization	(6.0)	—	(9.2)	(2.9)	(7.9)	(18.6)	(17.3)	(15.0)	(23.4)
Other	0.8	(0.1)	0.2	(0.2)	0.1	0.5	0.7	0.2	—
Effective income tax rate	20.7%	28.6%	19.3%	11.1%	18.4%	5.7%	4.0%	12.1%	2.2%



	Nine Months Ended September 30, 2018
	Exelon	Generation	ComEd	PECO	BGE	PHI	Pepco	DPL	ACE
U.S. Federal statutory rate	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	1.7	(2.6)	8.2	(3.6)	6.6	2.7	2.4	6.5	7.3
Qualified NDT fund income	0.9	2.6	—	—	—	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(0.9)	(2.2)	(0.2)	(0.1)	(0.1)	(0.2)	(0.1)	(0.3)	(0.3)
Plant basis differences	(2.7)	—	(0.1)	(15.4)	(0.7)	(1.9)	(2.9)	(0.7)	(1.3)
Production tax credits and other credits	(1.8)	(5.1)	(0.1)	—	—	—	—	—	—
Noncontrolling interests	(1.1)	(3.2)	—	—	—	—	—	—	—
Excess deferred tax amortization	(6.1)	—	(7.6)	(3.4)	(8.1)	(14.5)	(16.5)	(11.0)	(14.0)
Tax Cuts and Jobs Act of 2017	0.2	1.3	(0.2)	—	—	0.3	—	—	—
Other	0.4	2.0	0.1	—	0.9	0.3	—	0.4	0.9
Effective income tax rate	11.6%	13.8%	21.1%	(1.5)%	19.6%	7.7%	3.9%	15.9%	13.6%

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



	Exelon		Generation		ComEd		PHI		ACE
September 30, 2019	$	448	$	411	$	—	$	45	$	14
December 31, 2018	$	477	$	408	$	2	$	45	$	14

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



Exelon^(a)		Generation^(a)		PHI^(b)		ACE^(b)
$	425	$	411	$	14	$	14

__________


(a)	Exelon and Generation have $411 million that, if recognized, would decrease the effective tax rate.

(b)

The unrecognized tax benefit related to PHI and ACE, if recognized, may be included in future base rates and that portion would have no impact to the effective tax rate.

Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]



	Exelon		Generation
Increase to deferred income tax liability	$	23	$	9
Increase to income tax expense, net of federal taxes	23		9

Nuclear Decommissioning (Tables)

9 Months Ended

Sep. 30, 2019

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, 2018 to September 30, 2019:



Nuclear decommissioning ARO at December 31, 2018 ^(a)(b)	$	10,005
Sale of Oyster Creek	(755		)
Accretion expense	361
Net increase due to changes in, and timing of, estimated future cash flows	211
Costs incurred related to decommissioning plants	(52		)
Nuclear decommissioning ARO at September 30, 2019 ^(a)	$	9,770

_________


(a)	Includes $127 million and $22 million as the current portion of the ARO at September 30, 2019 and December 31, 2018, respectively, which is included in Other current liabilities in Exelon’s and Generation’s Consolidated Balance Sheets.

(b)

Includes $772 million of ARO related to Oyster Creek which was classified as Liabilities held for sale in Exelon's and Generation's Consolidated Balance Sheets at December 31, 2018. See Note 3 — Mergers, Acquisitions and Dispositions for additional information.

Retirement Benefits (Tables)

9 Months Ended

Sep. 30, 2019

Retirement Benefits [Abstract]

Calculation of Net Periodic Benefit Costs



	Pension Benefits Three Months Ended September 30,						OPEB Three Months Ended September 30,
	2019			2018			2019			2018
Components of net periodic benefit cost:
Service cost	$	89		$	100		$	23		$	28
Interest cost	221			201			47			43
Expected return on assets	(306		)	(312		)	(38		)	(43		)
Amortization of:
Prior service benefit	—			—			(45		)	(47		)
Actuarial loss	104			158			11			18
Settlement charges	7			—			—			—
Contractual termination benefits	1			—			—			—
Net periodic benefit cost	$	116		$	147		$	(2	)	$	(1	)



	Pension Benefits Nine Months Ended September 30,						OPEB Nine Months Ended September 30,
	2019			2018			2019			2018
Components of net periodic benefit cost:
Service cost	$	267		$	303		$	70		$	84
Interest cost	663			602			141			131
Expected return on assets	(918		)	(939		)	(115		)	(130		)
Amortization of:
Prior service cost (benefit)	—			1			(134		)	(140		)
Actuarial loss	310			472			34			50
Settlement charges	7			1			—			—
Contractual termination benefits	1			—			—			—
Net periodic benefit cost	$	330		$	440		$	(4	)	$	(5	)

Allocated Portion of Pension and Postretirement Benefit Costs



	Three Months Ended September 30,				Nine Months Ended September 30,
Pension and OPEB Costs	2019		2018		2019		2018
Exelon	$	114	$	145	$	326	$	435
Generation	37		50		100		151
ComEd	23		45		70		133
PECO	4		5		9		14
BGE	16		15		47		44
PHI	23		17		71		51
Pepco	6		3		19		10
DPL	4		2		11		5
ACE	4		3		12		10

Defined Contribution Savings Plans



	Three Months Ended September 30,				Nine Months Ended September 30,
Savings Plan Matching Contributions	2019		2018		2019		2018
Exelon	$	36	$	44	$	101	$	126
Generation	14		23		41		65
ComEd	9		8		26		23
PECO	2		2		7		7
BGE	4		2		9		5
PHI	4		4		8		10
Pepco	1		1		2		2
DPL	1		1		2		2
ACE	1		1		1		2

Changes in Accumulated Other Comprehensive Income (Tables)

9 Months Ended

Sep. 30, 2019

Changes in Accumulated Other Comprehensive Income [Abstract]

Schedule of Accumulated Other Comprehensive Income (Loss)

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



Three Months Ended September 30, 2019	Losses on Cash Flow Hedges			Pension and Non-Pension Postretirement Benefit Plan Items ^(a)			Foreign Currency Items			AOCI of Investments in Unconsolidated Affiliates ^(b)			Total
Beginning balance	$	(2	)	$	(2,957	)	$	(29	)	$	(2	)	$	(2,990	)
OCI before reclassifications	—			6			(2		)	—			4
Amounts reclassified from AOCI	—			21			—			2			23
Net current-period OCI	—			27			(2		)	2			27
Ending balance	$	(2	)	$	(2,930	)	$	(31	)	$	—		$	(2,963	)



Three Months Ended September 30, 2018	Losses on Cash Flow Hedges			Pension and Non-Pension Postretirement Benefit Plan Items ^(a)			Foreign Currency Items			AOCI of Investments in Unconsolidated Affiliates ^(b)		Total
Beginning balance	$	(2	)	$	(2,890	)	$	(29	)	$	—	$	(2,921	)
OCI before reclassifications	—			5			2			—		7
Amounts reclassified from AOCI	—			45			—			—		45
Net current-period OCI	—			50			2			—		52
Ending balance	$	(2	)	$	(2,840	)	$	(27	)	$	—	$	(2,869	)



Nine Months Ended September 30, 2019	Losses on Cash Flow Hedges			Pension and Non-Pension Postretirement Benefit Plan Items ^(a)			Foreign Currency Items			AOCI of Investments in Unconsolidated Affiliates ^(b)			Total
Beginning balance	$	(2	)	$	(2,960	)	$	(33	)	$	—		$	(2,995	)
OCI before reclassifications	—			(32		)	2			(2		)	(32		)
Amounts reclassified from AOCI	—			62			—			2			64
Net current-period OCI	—			30			2			—			32
Ending balance	$	(2	)	$	(2,930	)	$	(31	)	$	—		$	(2,963	)



Nine Months Ended September 30, 2018	Gains (Losses) on Cash Flow Hedges			Unrealized gains (losses) on Marketable Securities			Pension and Non-Pension Postretirement Benefit Plan Items ^(a)			Foreign Currency Items			AOCI of Investments in Unconsolidated Affiliates ^(b)			Total
Beginning balance	$	(14	)	$	10		$	(2,998	)	$	(23	)	$	(1	)	$	(3,026	)
OCI before reclassifications	11			—			22			(4		)	1			30
Amounts reclassified from AOCI	1			—			136			—			—			137
Net current-period OCI	12			—			158			(4		)	1			167
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard^(c)	—			(10		)	—			—			—			(10		)
Ending balance	$	(2	)	$	—		$	(2,840	)	$	(27	)	$	—		$	(2,869	)

_________


(a)	AOCI amounts are included in the computation of net periodic pension and OPEB cost. See Note 14 — Retirement Benefits for additional information. See Exelon's Statements of Operations and Comprehensive Income for individual components of AOCI.


(b)	All amounts are net of noncontrolling interests.

(c)

Exelon prospectively adopted the new standard Recognition and Measurement of Financial Assets and Liabilities. The standard was adopted as of January 1, 2018, which resulted in an increase to Retained earnings and Accumulated other comprehensive loss of $10 million for Exelon. The amounts reclassified related to Rabbi Trusts.

Schedule Of 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,
	2019			2018			2019			2018
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	$	6		$	6		$	18		$	18
Actuarial loss reclassified to periodic benefit cost	(13		)	(21		)	(39		)	(65		)
Pension and non-pension postretirement benefit plans valuation adjustment	—			(2		)	14			(8		)

Commitments and Contingencies (Tables)

9 Months Ended

Sep. 30, 2019

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, 2019:



Description	Exelon		PHI		Pepco		DPL		ACE
Total commitments	$	513	$	320	$	120	$	89	$	111
Remaining commitments^(a)	112		82		67		9		6

Commercial Commitments

The Registrants’ commercial commitments as of September 30, 2019, representing commitments potentially triggered by future events were as follows:



			Expiration within
	Total		2019		2020		2021		2022		2023		2024 and beyond
Exelon
Letters of credit	$	1,718	$	1,192	$	515	$	11	$	—	$	—	$	—
Surety bonds^(a)	991		315		638		38		—		—		—
Financing trust guarantees	378		—		—		—		—		—		378
Guaranteed lease residual values^(b)	26		—		2		3		4		3		15
Total commercial commitments	$	3,113	$	1,507	$	1,155	$	52	$	4	$	3	$	393

Generation
Letters of credit	$	1,686	$	1,179	$	496	$	11	$	—	$	—	$	—
Surety bonds^(a)	790		298		492		—		—		—		—
Total commercial commitments	$	2,476	$	1,477	$	988	$	11	$	—	$	—	$	—

ComEd
Letters of credit	$	7	$	4	$	3	$	—	$	—	$	—	$	—
Surety bonds^(a)	50		5		43		2		—		—		—
Financing trust guarantees	200		—		—		—		—		—		200
Total commercial commitments	$	257	$	9	$	46	$	2	$	—	$	—	$	200

PECO
Surety bonds^(a)	$	9	$	1	$	8	$	—	$	—	$	—	$	—
Financing trust guarantees	178		—		—		—		—		—		178
Total commercial commitments	$	187	$	1	$	8	$	—	$	—	$	—	$	178

BGE
Letters of credit	$	8	$	2	$	6	$	—	$	—	$	—	$	—
Surety bonds^(a)	17		2		15		—		—		—		—
Total commercial commitments	$	25	$	4	$	21	$	—	$	—	$	—	$	—

PHI
Letters of credit	$	11	$	1	$	10	$	—	$	—	$	—	$	—
Surety bonds^(a)	24		5		19		—		—		—		—
Guaranteed lease residual values^(b)	26		—		2		3		4		3		15
Total commercial commitments	$	61	$	6	$	31	$	3	$	4	$	3	$	15

Pepco
Letters of credit	$	10	$	—	$	10	$	—	$	—	$	—	$	—
Surety bonds^(a)	17		2		15		—		—		—		—
Guaranteed lease residual values^(b)	9		—		—		1		1		1		6
Total commercial commitments	$	36	$	2	$	25	$	1	$	1	$	1	$	6

DPL
Letters of credit	$	1	$	1	$	—	$	—	$	—	$	—	$	—
Surety bonds^(a)	4		2		2		—		—		—		—
Guaranteed lease residual values^(b)	11		—		1		1		2		1		6
Total commercial commitments	$	16	$	3	$	3	$	1	$	2	$	1	$	6

ACE
Surety bonds^(a)	$	3	$	1	$	2	$	—	$	—	$	—	$	—
Guaranteed lease residual values^(b)	7		—		1		1		1		1		3
Total commercial commitments	$	10	$	1	$	3	$	1	$	1	$	1	$	3

_________


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

(b)

Accrued environmental liabilities



	September 30, 2019				December 31, 2018
	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	$	507	$	346	$	496	$	356
Generation	107		—		108		—
ComEd	328		327		329		327
PECO	20		18		27		25
BGE	3		1		5		4
PHI	49		—		27		—
Pepco	47		—		25		—
DPL	1		—		1		—
ACE	1		—		1		—

Supplemental Financial Information (Tables)

9 Months Ended

Sep. 30, 2019

Supplemental Financial Information [Abstract]

Taxes Other Than Income

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



	Taxes other than income
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Three Months Ended September 30, 2019
Utility taxes^(a)	$	241	$	29	$	66	$	38	$	21	$	86	$	81	$	5	$	—
Property	148		66		7		5		39		31		21		9		—
Payroll	57		28		7		3		4		6		2		1		1

Three Months Ended September 30, 2018
Utility taxes^(a)	$	253	$	32	$	67	$	39	$	23	$	92	$	87	$	5	$	—
Property	145		70		7		4		37		26		16		9		—
Payroll	58		31		6		3		4		5		1		1		1

Nine Months Ended September 30, 2019
Utility taxes^(a)	$	672	$	87	$	183	$	102	$	68	$	231	$	217	$	14	$	—
Property	444		205		22		12		114		91		64		25		2
Payroll	185		92		21		11		13		20		5		3		2

Nine Months Ended September 30, 2018
Utility taxes^(a)	$	705	$	92	$	188	$	102	$	70	$	253	$	238	$	15	$	—
Property	416		204		22		12		106		71		45		24		2
Payroll	191		99		20		11		12		19		5		3		2

_________

(a)

Schedule of Other Nonoperating Income, by Component



	Other, Net
	Exelon			Generation			ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Three Months Ended September 30, 2019
Decommissioning-related activities:
Net realized income on NDT funds^(a)
Regulatory agreement units	$	67		$	67		$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-regulatory agreement units	33			33			—		—		—		—		—		—		—
Net unrealized gains on NDT funds
Regulatory agreement units	89			89			—		—		—		—		—		—		—
Non-regulatory agreement units	55			55			—		—		—		—		—		—		—
Regulatory offset to NDT fund-related activities^(b)	(125		)	(125		)	—		—		—		—		—		—		—
Decommissioning-related activities	119			119			—		—		—		—		—		—		—
AFUDC — Equity	22			—			4		3		6		9		7		1		1
Non-service net periodic benefit cost	(2		)	—			—		—		—		—		—		—		—

Three Months Ended September 30, 2018
Decommissioning-related activities:
Net realized income on NDT funds^(a)
Regulatory agreement units	$	214		$	214		$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-regulatory agreement units	58			58			—		—		—		—		—		—		—
Net unrealized (losses) gains on NDT funds
Regulatory agreement units	(66		)	(66		)	—		—		—		—		—		—		—
Non-regulatory agreement units	72			72			—		—		—		—		—		—		—
Regulatory offset to NDT fund-related activities^(b)	(110		)	(110		)	—		—		—		—		—		—		—
Decommissioning-related activities	168			168			—		—		—		—		—		—		—
AFUDC — Equity	16			—			4		1		5		6		6		—		—
Non-service net periodic benefit cost	(12		)	—			—		—		—		—		—		—		—



	Other, Net
	Exelon			Generation			ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Nine Months Ended September 30, 2019
Decommissioning-related activities:
Net realized income on NDT funds^(a)
Regulatory agreement units	$	197		$	197		$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-regulatory agreement units	316			316			—		—		—		—		—		—		—
Net unrealized gains on NDT funds
Regulatory agreement units	565			565			—		—		—		—		—		—		—
Non-regulatory agreement units	236			236			—		—		—		—		—		—		—
Regulatory offset to NDT fund-related activities^(b)	(611		)	(611		)	—		—		—		—		—		—		—
Decommissioning-related activities	703			703			—		—		—		—		—		—		—
AFUDC — Equity	64			—			13		9		16		26		18		3		4
Non-service net periodic benefit cost	8			—			—		—		—		—		—		—		—

Nine Months Ended September 30, 2018
Decommissioning-related activities:
Net realized income on NDT funds^(a)
Regulatory agreement units	$	476		$	476		$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-regulatory agreement units	257			257			—		—		—		—		—		—		—
Net unrealized losses on NDT funds
Regulatory agreement units	(335		)	(335		)	—		—		—		—		—		—		—
Non-regulatory agreement units	(143		)	(143		)	—		—		—		—		—		—		—
Regulatory offset to NDT fund-related activities^(b)	(110		)	(110		)	—		—		—		—		—		—		—
Decommissioning-related activities	145			145			—		—		—		—		—		—		—
AFUDC — Equity	47			—			12		3		13		19		17		2		—
Non-service net periodic benefit cost	(33		)	—			—		—		—		—		—		—		—

_________


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

(b)

Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units, including the elimination of income taxes related to all NDT fund activity for those units. See Note 15 — Asset Retirement Obligations of the Exelon 2018 Form 10-K for additional information regarding the accounting for nuclear decommissioning.

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, 2019
Property, plant and equipment^(a)	$	2,803	$	1,184	$	661	$	225	$	263	$	405	$	178	$	109	$	89
Amortization of regulatory assets^(a)	390		—		106		22		105		157		103		29		25
Amortization of intangible assets, net^(a)	44		37		—		—		—		—		—		—		—
Amortization of energy contract assets and liabilities^(b)	14		14		—		—		—		—		—		—		—
Nuclear fuel^(c)	771		771		—		—		—		—		—		—		—
ARO accretion^(d)	371		371		—		—		—		—		—		—		—
Total depreciation, amortization and accretion	$	4,393	$	2,377	$	767	$	247	$	368	$	562	$	281	$	138	$	114

Nine Months Ended September 30, 2018
Property, plant and equipment^(a)	$	2,829	$	1,347	$	613	$	204	$	249	$	355	$	161	$	97	$	70
Amortization of regulatory assets^(a)	412		—		83		20		109		200		125		38		37
Amortization of intangible assets, net^(a)	43		36		—		—		—		—		—		—		—
Amortization of energy contract assets and liabilities^(b)	8		8		—		—		—		—		—		—		—
Nuclear fuel^(c)	852		852		—		—		—		—		—		—		—
ARO accretion^(d)	367		365		—		—		—		—		—		—		—
Total depreciation, amortization and accretion	$	4,511	$	2,608	$	696	$	224	$	358	$	555	$	286	$	135	$	107

_________


(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, 2019
Pension and non-pension postretirement benefit costs	$	324		$	98		$	70	$	9	$	45	$	71		$	19		$	11		$	12
Provision for uncollectible accounts	89			20			26		22		5		16			7			2			6
Other decommissioning-related activity^(a)	(400		)	(400		)	—		—		—		—			—			—			—
Energy-related options^(b)	21			21			—		—		—		—			—			—			—
Amortization of rate stabilization deferral	(8		)	—			—		—		—		(8		)	(9		)	1			—
Discrete impacts from EIMA and FEJA^(c)	80			—			80		—		—		—			—			—			—
Long-term incentive plan	33			—			—		—		—		—			—			—			—
Amortization of operating ROU asset	193			138			2		—		23		26			6			7			4
Change in environmental liabilities	23			—			—		—		—		23			23			—			—

Nine Months Ended September 30, 2018
Pension and non-pension postretirement benefit costs	$	435		$	151		$	133	$	14	$	43	$	51		$	10		$	5		$	10
Provision for uncollectible accounts	133			38			30		25		6		32			12			6			14
Other decommissioning-related activity^(a)	(39		)	(39		)	—		—		—		—			—			—			—
Energy-related options^(b)	4			4			—		—		—		—			—			—			—
Amortization of rate stabilization deferral	—			—			—		—		—		—			—			—			—
Discrete impacts from EIMA and FEJA^(c)	27			—			27		—		—		—			—			—			—
Long-term incentive plan	84			—			—		—		—		—			—			—			—
Asset retirement costs	20			—			—		—		—		20			22			(1		)	(1		)

_______

(a)


(b)	Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded in Operating revenues and expenses.


(c)	Reflects the change in ComEd's distribution and energy efficiency formula rates. See Note 6 — Regulatory Matters for additional information.



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
September 30, 2019
Cash and cash equivalents	$	1,683	$	1,019	$	76	$	224	$	130	$	99	$	18	$	11	$	13
Restricted cash	309		126		124		6		1		38		34		—		3
Restricted cash included in other long-term assets	186		—		171		—		—		15		—		—		15
Total cash, cash equivalents and restricted cash	$	2,178	$	1,145	$	371	$	230	$	131	$	152	$	52	$	11	$	31

December 31, 2018
Cash and cash equivalents	$	1,349	$	750	$	135	$	130	$	7	$	124	$	16	$	23	$	7
Restricted cash	247		153		29		5		6		43		37		1		4
Restricted cash included in other long-term assets	185		—		166		—		—		19		—		—		19
Total cash, cash equivalents and restricted cash	$	1,781	$	903	$	330	$	135	$	13	$	186	$	53	$	24	$	30

September 30, 2018
Cash and cash equivalents	$	1,918	$	1,187	$	124	$	102	$	113	$	153	$	12	$	110	$	11
Restricted cash	240		152		12		5		3		42		35		—		7
Restricted cash included in other long-term assets	163		—		144		—		—		19		—		—		19
Total cash, cash equivalents and restricted cash	$	2,321	$	1,339	$	280	$	107	$	116	$	214	$	47	$	110	$	37

December 31, 2017
Cash and cash equivalents	$	898	$	416	$	76	$	271	$	17	$	30	$	5	$	2	$	2
Restricted cash	207		138		5		4		1		42		35		—		6
Restricted cash included in other long-term assets	85		—		63		—		—		23		—		—		23
Total cash, cash equivalents and restricted cash	$	1,190	$	554	$	144	$	275	$	18	$	95	$	40	$	2	$	31

For additional information on restricted cash see Note 1 — Significant Accounting Policies of the Exelon 2018 Form 10-K.

Supplemental Balance Sheet Disclosures

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



	Unbilled customer revenues
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
September 30, 2019	$	1,256	$	676	$	212	$	102	$	103	$	163	$	91	$	38	$	34
December 31, 2018	1,656		965		223		114		168		186		97		59		30



	Accrued expenses
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
September 30, 2019
Compensation-related accruals^(a)	$	880	$	336	$	133	$	48	$	63	$	86	$	26	$	17	$	13
Taxes accrued	431		247		56		13		64		80		61		17		3
Interest accrued	421		106		62		33		36		78		37		20		19

December 31, 2018
Compensation-related accruals^(a)	$	1,191	$	479	$	187	$	49	$	68	$	99	$	29	$	19	$	12
Taxes accrued	412		226		71		28		46		74		58		4		5
Interest accrued	334		77		105		33		39		50		25		8		12

_________

(a)

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

Segment Information (Tables)

3 Months Ended

9 Months Ended

Sep. 30, 2019

Segment Reporting [Abstract]

Analysis and reconciliation of reportable segment information

Three Months Ended September 30, 2019 and 2018



	Generation^(a)		ComEd		PECO		BGE		PHI		Other^(b)		Intersegment Eliminations			Exelon
Operating revenues^(c):
2019
Competitive businesses electric revenues	$	4,314	$	—	$	—	$	—	$	—	$	—	$	(275	)	$	4,039
Competitive businesses natural gas revenues	265		—		—		—		—		—		1			266
Competitive businesses other revenues	195		—		—		—		—		—		(1		)	194
Rate-regulated electric revenues	—		1,583		716		619		1,357		—		(7		)	4,268
Rate-regulated natural gas revenues	—		—		62		84		20		—		(3		)	163
Shared service and other revenues	—		—		—		—		3		474		(478		)	(1		)
Total operating revenues	$	4,774	$	1,583	$	778	$	703	$	1,380	$	474	$	(763	)	$	8,929



	Generation^(a)		ComEd		PECO			BGE		PHI		Other^(b)			Intersegment Eliminations			Exelon
2018
Competitive businesses electric revenues	$	4,741	$	—	$	—		$	—	$	—	$	—		$	(306	)	$	4,435
Competitive businesses natural gas revenues	397		—		—			—		—		—			—			397
Competitive businesses other revenues	140		—		—			—		—		—			(1		)	139
Rate-regulated electric revenues	—		1,598		700			645		1,334		—			(7		)	4,270
Rate-regulated natural gas revenues	—		—		57			86		24		—			(5		)	162
Shared service and other revenues	—		—		—			—		3		458			(461		)	—
Total operating revenues	$	5,278	$	1,598	$	757		$	731	$	1,361	$	458		$	(780	)	$	9,403
Intersegment revenues^(d):
2019	$	275	$	4	$	1		$	6	$	4	$	474		$	(764	)	$	—
2018	308		4		2			6		3		456			(779		)	—
Depreciation and amortization:
2019	$	407	$	259	$	83		$	116	$	193	$	25		$	—		$	1,083
2018	468		237		75			110		192		23			—			1,105
Operating expenses:
2019	$	4,274	$	1,256	$	595		$	612	$	1,124	$	457		$	(759	)	$	7,559
2018	4,961		1,275		603			628		1,116		459			(790		)	8,252
Interest expense, net:
2019	$	109	$	91	$	33		$	31	$	66	$	79		$	—		$	409
2018	101		85		32			27		65		83			—			393
Income (loss) before income taxes:
2019	$	501	$	245	$	154		$	67	$	203	$	(68	)	$	—		$	1,102
2018	389		245		124			81		191		(83		)	—			947
Income Taxes:
2019	$	87	$	45	$	14		$	12	$	14	$	—		$	—		$	172
2018	78		52		(2		)	18		4		(13		)	—			137
Net income (loss):
2019	$	244	$	200	$	140		$	55	$	189	$	(68	)	$	—		$	760
2018	300		193		126			63		187		(69		)	—			800
Capital Expenditures
2019	$	392	$	452	$	228		$	300	$	308	$	7		$	—		$	1,687
2018	362		514		204			233		359		18			—			1,690

__________

(a)


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


(c)	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 17 — Supplemental Financial Information for additional information on total utility taxes.

(d)

PHI:



	Pepco			DPL		ACE		Other^(b)			Intersegment Eliminations			PHI
Operating revenues^(a):
2019
Rate-regulated electric revenues	$	642		$	299	$	419	$	—		$	(3	)	$	1,357
Rate-regulated natural gas revenues	—			20		—		—			—			20
Shared service and other revenues	—			—		—		92			(89		)	3
Total operating revenues	$	642		$	319	$	419	$	92		$	(92	)	$	1,380
2018
Rate-regulated electric revenues	$	628		$	304	$	406	$	—		$	(4	)	$	1,334
Rate-regulated natural gas revenues	—			24		—		—			—			24
Shared service and other revenues	—			—		—		103			(100		)	3
Total operating revenues	$	628		$	328	$	406	$	103		$	(104	)	$	1,361
Intersegment revenues:
2019	$	2		$	1	$	1	$	93		$	(93	)	$	4
2018	2			2		1		103			(105		)	3
Depreciation and amortization:
2019	$	95		$	46	$	43	$	9		$	—		$	193
2018	99			47		38		8			—			192
Operating expenses:
2019	$	515		$	268	$	340	$	95		$	(94	)	$	1,124
2018	516			277		322		105			(104		)	1,116
Interest expense, net:
2019	$	33		$	15	$	15	$	3		$	—		$	66
2018	32			15		16		2			—			65
Income (loss) before income taxes:
2019	$	103		$	38	$	65	$	192		$	(195	)	$	203
2018	87			38		69		179			(182		)	191
Income Taxes:
2019	$	5		$	5	$	2	$	3		$	(1	)	$	14
2018	(2		)	5		8		(8		)	1			4
Net income (loss):
2019	$	98		$	33	$	63	$	(9	)	$	4		$	189
2018	89			33		61		1			3			187
Capital Expenditures
2019	$	157		$	85	$	73	$	(7	)	$	—		$	308
2018	188			88		77		6			—			359

__________


(a)	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 17 — Supplemental Financial Information for additional information on total utility taxes.

(b)

Other primarily includes PHI’s corporate operations, shared service entities and other financing and investment activities.

Nine Months Ended September 30, 2019 and 2018



	Generation^(a)		ComEd		PECO		BGE		PHI		Other^(b)		Intersegment Eliminations			Exelon
Operating revenues^(c):
2019
Competitive businesses electric revenues	$	12,365	$	—	$	—	$	—	$	—	$	—	$	(840	)	$	11,525
Competitive businesses natural gas revenues	1,479		—		—		—		—		—		—			1,479
Competitive businesses other revenues	436		—		—		—		—		—		(4		)	432
Rate-regulated electric revenues	—		4,342		1,901		1,817		3,574		—		(25		)	11,609
Rate-regulated natural gas revenues	—		—		432		510		116		—		(12		)	1,046
Shared service and other revenues	—		—		—		—		10		1,410		(1,415		)	5
Total operating revenues	$	14,280	$	4,342	$	2,333	$	2,327	$	3,700	$	1,410	$	(2,296	)	$	26,096
2018
Competitive businesses electric revenues	$	13,190	$	—	$	—	$	—	$	—	$	—	$	(969	)	$	12,221
Competitive businesses natural gas revenues	1,839		—		—		—		—		—		(8		)	1,831
Competitive businesses other revenues	339		—		—		—		—		—		(4		)	335
Rate-regulated electric revenues	—		4,508		1,893		1,850		3,549		—		(34		)	11,766
Rate-regulated natural gas revenues	—		—		382		519		129		—		(13		)	1,017
Shared service and other revenues	—		—		—		—		10		1,398		(1,408		)	—
Total operating revenues	$	15,368	$	4,508	$	2,275	$	2,369	$	3,688	$	1,398	$	(2,436	)	$	27,170
Shared service and other revenues
Intersegment revenues^(d):
2019	$	844	$	13	$	4	$	18	$	11	$	1,410	$	(2,300	)	$	—
2018	981		23		5		18		11		1,392		(2,430		)	—
Depreciation and amortization:
2019	$	1,221	$	767	$	247	$	368	$	562	$	72	$	—		$	3,237
2018	1,383		696		224		358		555		68		—			3,284
Operating expenses:
2019	$	13,333	$	3,431	$	1,783	$	1,936	$	3,106	$	1,405	$	(2,291	)	$	22,703
2018	14,475		3,610		1,853		2,005		3,165		1,395		(2,467		)	24,036
Interest expense, net:
2019	$	336	$	268	$	100	$	89	$	197	$	231	$	—		$	1,221
2018	305		261		96		78		193		205		—			1,138



	Generation^(a)		ComEd		PECO			BGE		PHI		Other^(b)			Intersegment Eliminations			Exelon
Income (loss) before income taxes:
2019	$	1,355	$	674	$	461		$	320	$	436	$	(218	)	$	—		$	3,028
2018	800		663		331			301		363		(195		)	—			2,263
Income Taxes:
2019	$	388	$	130	$	51		$	59	$	25	$	(27	)	$	—		$	626
2018	110		140		(5		)	59		28		(70		)	—			262
Net income (loss):
2019	$	784	$	544	$	410		$	261	$	412	$	(191	)	$	—		$	2,220
2018	667		523		336			242		336		(125		)	—			1,979
Capital Expenditures
2019	$	1,282	$	1,413	$	675		$	842	$	1,006	$	41		$	—		$	5,259
2018	1,660		1,540		615			667		988		27			—			5,497
Total assets:
September 30, 2019	$	47,984	$	32,326	$	11,379		$	10,304	$	22,576	$	8,254		$	(10,085	)	$	122,738
December 31, 2018	47,556		31,213		10,642			9,716		21,984		8,355			(9,800		)	119,666

__________

(a)


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


(c)	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 17 — Supplemental Financial Information for additional information on total utility taxes.

(d)

PHI:



	Pepco		DPL		ACE		Other^(b)			Intersegment Eliminations			PHI
Operating revenues^(a):
2019
Rate-regulated electric revenues	$	1,748	$	871	$	966	$	(1	)	$	(10	)	$	3,574
Rate-regulated natural gas revenues	—		116		—		—			—			116
Shared service and other revenues	—		—		—		298			(288		)	10
Total operating revenues	$	1,748	$	987	$	966	$	297		$	(298	)	$	3,700
2018
Rate-regulated electric revenues	$	1,708	$	872	$	981	$	—		$	(12	)	$	3,549
Rate-regulated natural gas revenues	—		129		—		—			—			129
Shared service and other revenues	—		—		—		326			(316		)	10
Total operating revenues	$	1,708	$	1,001	$	981	$	326		$	(328	)	$	3,688
Intersegment revenues:
2019	$	5	$	5	$	2	$	297		$	(298	)	$	11
2018	5		6		2		325			(327		)	11
Depreciation and amortization:
2019	$	281	$	138	$	114	$	29		$	—		$	562
2018	286		135		107		27			—			555
Operating expenses:
2019	$	1,444	$	820	$	838	$	302		$	(298	)	$	3,106
2018	1,454		859		847		329			(324		)	3,165
Interest expense, net:
2019	$	100	$	45	$	44	$	8		$	—		$	197
2018	96		42		48		7			—			193
Income (loss) before income taxes:
2019	$	226	$	132	$	89	$	411		$	(422	)	$	436
2018	181		107		88		326			(339		)	363
Income Taxes:
2019	$	9	$	16	$	2	$	(1	)	$	(1	)	$	25
2018	7		17		12		(8		)	—			28
Net income (loss):
2019	$	217	$	116	$	87	$	(19	)	$	11		$	412
2018	174		90		76		(15		)	11			336
Capital Expenditures
2019	$	455	$	245	$	300	$	6		$	—		$	1,006
2018	475		254		247		12			—			988
Total assets:
September 30, 2019	$	8,603	$	4,724	$	3,916	$	11,071		$	(5,738	)	$	22,576
December 31, 2018	8,299		4,588		3,699		10,819			(5,421		)	21,984

__________


(a)	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 17 — Supplemental Financial Information for additional information on total utility taxes.

(b)

Other primarily includes PHI’s corporate operations, shared service entities and other financing and investment activities.

Analysis and reconciliation of reportable segment revenues for Generation

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, 2019
	Revenues from external customers^(a)						Intersegment revenues			Total Revenues
	Contracts with customers		Other^(b)		Total		Intersegment revenues			Total Revenues
Mid-Atlantic	$	1,351	$	10	$	1,361	$	3		$	1,364
Midwest	1,052		47		1,099		(17		)	1,082
New York	414		15		429		—			429
ERCOT	288		72		360		5			365
Other Power Regions	873		192		1,065		(25		)	1,040
Total Competitive Businesses Electric Revenues	3,978		336		4,314		(34		)	4,280
Competitive Businesses Natural Gas Revenues	160		105		265		34			299
Competitive Businesses Other Revenues^(c)	112		83		195		—			195
Total Generation Consolidated Operating Revenues	$	4,250	$	524	$	4,774	$	—		$	4,774



	Three Months Ended September 30, 2018
	Revenues from external customers^(a)							Intersegment revenues			Total Revenues
	Contracts with customers		Other^(b)			Total		Intersegment revenues			Total Revenues
Mid-Atlantic	$	1,397	$	52		$	1,449	$	7		$	1,456
Midwest	1,095		26			1,121		(4		)	1,117
New York	475		(6		)	469		—			469
ERCOT	156		289			445		(1		)	444
Other Power Regions	959		298			1,257		(45		)	1,212
Total Competitive Businesses Electric Revenues	4,082		659			4,741		(43		)	4,698
Competitive Businesses Natural Gas Revenues	200		197			397		43			440
Competitive Businesses Other Revenues^(c)	130		10			140		—			140
Total Generation Consolidated Operating Revenues	$	4,412	$	866		$	5,278	$	—		$	5,278

__________


(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 gains of $77 million and $6 million in 2019 and 2018, respectively, and elimination of intersegment revenues.

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



	Three Months Ended September 30, 2019							Three Months Ended September 30, 2018
	RNF from external customers^(a)		Intersegment RNF			Total RNF		RNF from external customers^(a)		Intersegment RNF			Total RNF
Mid-Atlantic	$	684	$	5		$	689	$	746	$	17		$	763
Midwest	763		(16		)	747		763		5			768
New York	288		3			291		290		2			292
ERCOT	76		(4		)	72		161		(63		)	98
Other Power Regions	212		(28		)	184		226		(46		)	180
Total Revenues net of purchased power and fuel for Reportable Segments	2,023		(40		)	1,983		2,186		(85		)	2,101
Other^(b)	100		40			140		112		85			197
Total Generation Revenues net of purchased power and fuel expense	$	2,123	$	—		$	2,123	$	2,298	$	—		$	2,298

__________


(a)	Includes purchases and sales from/to third parties and affiliated sales to the Utility Registrants.

(b)

Competitive Business Revenues (Generation):



	Nine Months Ended September 30, 2019
	Revenues from external customers^(a)						Intersegment Revenues			Total Revenues
	Contracts with customers		Other^(b)		Total		Intersegment Revenues			Total Revenues
Mid-Atlantic	$	3,798	$	9	$	3,807	$	2		$	3,809
Midwest	3,083		172		3,255		(31		)	3,224
New York	1,195		16		1,211		—			1,211
ERCOT	594		198		792		13			805
Other Power Regions	2,849		451		3,300		(46		)	3,254
Total Competitive Businesses Electric Revenues	11,519		846		12,365		(62		)	12,303
Competitive Businesses Natural Gas Revenues	1,041		438		1,479		62			1,541
Competitive Businesses Other Revenues^(c)	343		93		436		—			436
Total Generation Consolidated Operating Revenues	$	12,903	$	1,377	$	14,280	$	—		$	14,280



	Nine Months Ended September 30, 2018
	Revenues from external customers^(a)							Intersegment revenues			Total Revenues
	Contracts with customers		Other^(b)			Total		Intersegment revenues			Total Revenues
Mid-Atlantic	$	3,971	$	191		$	4,162	$	17		$	4,179
Midwest	3,432		169			3,601		(8		)	3,593
New York	1,305		(37		)	1,268		1			1,269
ERCOT	470		459			929		1			930
Other Power Regions	2,656		574			3,230		(116		)	3,114
Total Competitive Businesses Electric Revenues	11,834		1,356			13,190		(105		)	13,085
Competitive Businesses Natural Gas Revenues	1,016		823			1,839		105			1,944
Competitive Businesses Other Revenues^(c)	385		(46		)	339		—			339
Total Generation Consolidated Operating Revenues	$	13,235	$	2,133		$	15,368	$	—		$	15,368

__________


(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 gains of $64 million and losses of $96 million in 2019 and 2018, respectively, and elimination of intersegment revenues.

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



	Nine Months Ended September 30, 2019							Nine Months Ended September 30, 2018
	RNF from external customers^(a)		Intersegment RNF			Total RNF		RNF from external customers^(a)		Intersegment RNF			Total RNF
Mid-Atlantic	$	2,007	$	16		$	2,023	$	2,303	$	45		$	2,348
Midwest	2,269		(22		)	2,247		2,381		19			2,400
New York	800		10			810		832		9			841
ERCOT	252		(27		)	225		396		(180		)	216
Other Power Regions	542		(64		)	478		740		(133		)	607
Total Revenues net of purchased power and fuel expense for Reportable Segments	5,870		(87		)	5,783		6,652		(240		)	6,412
Other^(b)	262		87			349		164		240			404
Total Generation Revenues net of purchased power and fuel expense	$	6,132	$	—		$	6,132	$	6,816	$	—		$	6,816

__________


(a)	Includes purchases and sales from/to third parties and affiliated sales to the Utility Registrants.

(b)

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, 2019
Revenues from contracts with customers	ComEd			PECO			BGE			PHI			Pepco			DPL			ACE
Rate-regulated electric revenues
Residential	$	865		$	479		$	352		$	741		$	311		$	178		$	252
Small commercial & industrial	393			109			64			147			41			48			58
Large commercial & industrial	141			63			116			297			222			26			49
Public authorities & electric railroads	12			9			7			17			11			3			3
Other^(a)	222			63			82			164			58			50			56
Total rate-regulated electric revenues^(b)	$	1,633		$	723		$	621		$	1,366		$	643		$	305		$	418
Rate-regulated natural gas revenues
Residential	$	—		$	38		$	49		$	9		$	—		$	9		$	—
Small commercial & industrial	—			17			9			4			—			4			—
Large commercial & industrial	—			—			20			1			—			1			—
Transportation	—			5			—			4			—			4			—
Other^(c)	—			2			5			2			—			2			—
Total rate-regulated natural gas revenues^(d)	$	—		$	62		$	83		$	20		$	—		$	20		$	—
Total rate-regulated revenues from contracts with customers	$	1,633		$	785		$	704		$	1,386		$	643		$	325		$	418

Other revenues
Revenues from alternative revenue programs	$	(56	)	$	(11	)	$	(5	)	$	(9	)	$	(3	)	$	(6	)	$	1
Other rate-regulated electric revenues^(e)	6			4			3			3			2			—			—
Other rate-regulated natural gas revenues^(e)	—			—			1			—			—			—			—
Total other revenues	$	(50	)	$	(7	)	$	(1	)	$	(6	)	$	(1	)	$	(6	)	$	1
Total rate-regulated revenues for reportable segments	$	1,583		$	778		$	703		$	1,380		$	642		$	319		$	419



	Three Months Ended September 30, 2018
Revenues from contracts with customers	ComEd			PECO		BGE			PHI			Pepco			DPL		ACE
Rate-regulated electric revenues
Residential	$	861		$	458	$	366		$	726		$	306		$	180	$	240
Small commercial & industrial	391			108		68			140			39			48		53
Large commercial & industrial	131			64		117			303			230			25		48
Public authorities & electric railroads	11			7		7			14			8			3		3
Other^(a)	212			59		91			156			47			47		63
Total rate-regulated electric revenues^(b)	$	1,606		$	696	$	649		$	1,339		$	630		$	303	$	407
Rate-regulated natural gas revenues
Residential	$	—		$	36	$	46		$	8		$	—		$	8	$	—
Small commercial & industrial	—			15		8			5			—			5		—
Large commercial & industrial	—			—		17			2			—			2		—
Transportation	—			5		—			3			—			3		—
Other^(c)	—			1		12			6			—			6		—
Total rate-regulated natural gas revenues^(d)	$	—		$	57	$	83		$	24		$	—		$	24	$	—
Total rate-regulated revenues from contracts with customers	$	1,606		$	753	$	732		$	1,363		$	630		$	327	$	407

Other revenues
Revenues from alternative revenue programs	$	(15	)	$	1	$	(6	)	$	(5	)	$	(4	)	$	—	$	(1	)
Other rate-regulated electric revenues^(e)	7			3		4			3			2			1		—
Other rate-regulated natural gas revenues^(e)	—			—		1			—			—			—		—
Total other revenues	$	(8	)	$	4	$	(1	)	$	(2	)	$	(2	)	$	1	$	(1	)
Total rate-regulated revenues for reportable segments	$	1,598		$	757	$	731		$	1,361		$	628		$	328	$	406

__________


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


(b)	Includes operating revenues from affiliates of $4 million, $1 million, $2 million, $4 million, $2 million, $1 million and $1 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2019 and $4 million, $2 million, $1 million, $3 million $2 million, $2 million and $1 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2018.


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


(d)	Includes operating revenues from affiliates of less than $1 million and $4 million at PECO and BGE, respectively, in 2019 and less than $1 million and $5 million at PECO and BGE, respectively, in 2018.

(e)

Includes late payment charge revenues.

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



	Nine Months Ended September 30, 2019
Revenues from contracts with customers	ComEd			PECO			BGE		PHI		Pepco		DPL			ACE
Rate-regulated electric revenues
Residential	$	2,221		$	1,231		$	1,019	$	1,816	$	792	$	499		$	525
Small commercial & industrial	1,103			304			193		387		114		141			132
Large commercial & industrial	399			163			335		843		633		75			135
Public authorities & electric railroads	35			23			20		47		27		10			10
Other^(a)	660			186			242		481		166		151			164
Total rate-regulated electric revenues^(b)	4,418			1,907			1,809		3,574		1,732		876			966
Rate-regulated natural gas revenues
Residential	—			285			327		64		—		64			—
Small commercial & industrial	—			122			55		30		—		30			—
Large commercial & industrial	—			1			93		4		—		4			—
Transportation	—			18			—		11		—		11			—
Other^(c)	—			5			19		6		—		6			—
Total rate-regulated natural gas revenues^(d)	—			431			494		115		—		115			—
Total rate-regulated revenues from contracts with customers	4,418			2,338			2,303		3,689		1,732		991			966

Other revenues
Revenues from alternative revenue programs	(98		)	(16		)	11		4		10		(6		)	—
Other rate-regulated electric revenues^(e)	22			10			10		7		6		1			—
Other rate-regulated natural gas revenues^(e)	—			1			3		—		—		1			—
Total other revenues	(76		)	(5		)	24		11		16		(4		)	—
Total rate-regulated revenues for reportable segments	$	4,342		$	2,333		$	2,327	$	3,700	$	1,748	$	987		$	966



	Nine Months Ended September 30, 2018
Revenues from contracts with customers	ComEd			PECO		BGE			PHI		Pepco		DPL		ACE
Rate-regulated electric revenues
Residential	$	2,277		$	1,199	$	1,054		$	1,839	$	792	$	513	$	534
Small commercial & industrial	1,132			306		196			370		104		138		128
Large commercial & industrial	411			174		325			845		632		74		139
Public authorities & electric railroads	36			21		21			44		24		10		10
Other^(a)	656			181		246			446		145		129		174
Total rate-regulated electric revenues^(b)	4,512			1,881		1,842			3,544		1,697		864		985
Rate-regulated natural gas revenues
Residential	—			259		345			68		—		68		—
Small commercial & industrial	—			102		55			31		—		31		—
Large commercial & industrial	—			1		88			7		—		7		—
Transportation	—			16		—			12		—		12		—
Other^(c)	—			4		49			11		—		11		—
Total rate-regulated natural gas revenues^(d)	—			382		537			129		—		129		—
Total rate-regulated revenues from contracts with customers	4,512			2,263		2,379			3,673		1,697		993		985

Other revenues
Revenues from alternative revenue programs	(27		)	2		(23		)	7		6		5		(4		)
Other rate-regulated electric revenues^(e)	23			10		10			8		5		3		—
Other rate-regulated natural gas revenues^(e)	—			—		3			—		—		—		—
Total other revenues	(4		)	12		(10		)	15		11		8		(4		)
Total rate-regulated revenues for reportable segments	$	4,508		$	2,275	$	2,369		$	3,688	$	1,708	$	1,001	$	981

__________


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


(b)	Includes operating revenues from affiliates of $13 million, $4 million, $5 million, $11 million, $5 million, $5 million and $2 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2019 and $23 million, $5 million, $5 million, $11 million $5 million, $6 million and $2 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2018.


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


(d)	Includes operating revenues from affiliates of less than $1 million and $13 million at PECO and BGE in 2019 and 2018, respectively.

(e)

Includes late payment charge revenues.

Variable Interest Entities - Narrative (Details) - USD ($) $ in Millions	Sep. 30, 2019	Apr. 01, 2014
Variable Interest Entity [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	$ 68
Payment Guarantee [Member] \| CENG [Member]
Variable Interest Entity [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted		$ 245
Financial Guarantee [Member] \| CENG [Member]
Variable Interest Entity [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted		165
Exelon Generation Co L L C [Member] \| CENG [Member]
Variable Interest Entity [Line Items]
Due from Affiliates		$ 400
Guarantor Obligations, Current Carrying Value	688
Atlantic City Electric Company [Member]
Variable Interest Entity [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	17
Pepco Holdings LLC [Member]
Variable Interest Entity [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	$ 68

Variable Interest Entities - Assets and Liabilities of VIES which Creditors or Beneficiaries have no Recourse (Details) - USD ($)
$ in Millions

Sep. 30, 2019

Dec. 31, 2018

Sep. 30, 2018

Dec. 31, 2017

$ 1,683

$ 1,349

$ 1,918

$ 898

309

247

240

207

4,188

4,607

1,085

1,256

1,458

1,351

1,296

1,238

12,206

13,360

78,593

76,707

12,706

11,661

353

372

3,123

1,575

^[1]

122,738

119,666

4,248

1,349

3,348

3,800

1,877

2,112

138

149

1,425

1,035

13,085

11,404

32,056

34,075

10,089

9,679

368

463

3,123

2,130

Variable Interest Entity, Primary Beneficiary [Member]

^[1]

88,386

86,596

168

414

163

146

222

212

745

938

6,079

6,188

2,636

2,351

258

274

258

9,042

9,071

9,787

10,009

556

148

802

274

532

1,072

2,103

2,165

2,720

3,280

PP&E - unrestricted asset

3,522

3,554

Variable Interest Entity, Consolidated, Liabilities, Recourse

1,019

750

1,187

416

126

153

152

138

2,587

2,941

337

562

1,010

963

1,002

883

7,159

8,433

23,591

23,981

12,706

11,661

352

371

1,915

755

^[2]

47,984

47,556

2,706

906

1,583

1,847

762

898

541

279

6,344

5,769

5,018

6,989

9,855

9,450

1,466

610

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

^[2]

32,391

32,048

168

414

163

146

222

212

740

931

6,079

6,188

2,636

2,351

258

274

232

9,025

9,045

9,765

9,976

535

148

780

252

504

1,025

2,103

2,165

2,692

3,233

PP&E - unrestricted asset

3,472

3,485

Variable Interest Entity, Consolidated, Liabilities, Recourse

124

153

512

453

189

177

203

163

1,578

1,533

13,968

13,446

356

^[3]

22,576

21,984

118

125

416

496

279

256

117

119

152

123

1,515

1,592

6,376

6,134

357

442

610

369

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

^[3]

13,028

12,702

Atlantic City Electric Company [Member]

$ 7

$ 6

142

307

240

3,124

2,966

^[4]

3,916

3,699

139

154

347

422

1,305

1,170

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

^[4]

2,648

2,573

$ 46

$ 59

[1]	Exelon’s consolidated assets include $9,465 million and $9,667 million at September 30, 2019 and December 31, 2018, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $3,517 million and $3,548 million at September 30, 2019 and December 31, 2018, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 2 — Variable Interest Entities for additional information.
[2]	Generation’s consolidated assets include $9,443 million and $9,634 million at September 30, 2019 and December 31, 2018, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $3,467 million and $3,480 million at September 30, 2019 and December 31, 2018, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 2 — Variable Interest Entities for additional information.
[3]	PHI’s consolidated total assets include $22 million and $33 million at September 30, 2019 and December 31, 2018, respectively, of PHI's consolidated VIE that can only be used to settle the liabilities of the VIE. PHI’s consolidated total liabilities include $50 million and $69 million at September 30, 2019 and December 31, 2018, respectively, of PHI's consolidated VIE for which the VIE creditors do not have recourse to PHI. See Note 2 — Variable Interest Entities for additional information.
[4]	ACE’s consolidated total assets include $18 million and $23 million at September 30, 2019 and December 31, 2018, respectively, of ACE's consolidated VIE that can only be used to settle the liabilities of the VIE. ACE’s consolidated total liabilities include $46 million and $59 million at September 30, 2019 and December 31, 2018, respectively, of ACE's consolidated VIE for which the VIE creditors do not have recourse to ACE. See Note 2 — Variable Interest Entities for additional information.

Variable Interest Entities - Summary of Significant Unconsolidated VIEs (Details) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Variable Interest Entity [Line Items]
Total assets	$ 1,067	$ 1,069
Total liabilities	260	259
Exelon's ownership interest in VIE	201	223
Other ownership interests in VIE	615	587
Carrying amount of equity method investments
Variable Interest Entity [Line Items]
Registrants' maximum exposure to loss	12	223
Commercial Agreement Variable Interest Entities [Member]
Variable Interest Entity [Line Items]
Total assets	614	597
Total liabilities	36	37
Exelon's ownership interest in VIE	0	0
Other ownership interests in VIE	587	560
Commercial Agreement Variable Interest Entities [Member] \| Carrying amount of equity method investments
Variable Interest Entity [Line Items]
Registrants' maximum exposure to loss	0	0
Equity Investment VIE [Member]
Variable Interest Entity [Line Items]
Total assets	453	472
Total liabilities	224	222
Exelon's ownership interest in VIE	201	223
Other ownership interests in VIE	28	27
Equity Investment VIE [Member] \| Carrying amount of equity method investments
Variable Interest Entity [Line Items]
Registrants' maximum exposure to loss	12	223
Exelon Generation Co L L C [Member]
Variable Interest Entity [Line Items]
Total assets	1,067	1,069
Total liabilities	260	259
Exelon's ownership interest in VIE	201	223
Other ownership interests in VIE	615	587
Exelon Generation Co L L C [Member] \| Carrying amount of equity method investments
Variable Interest Entity [Line Items]
Registrants' maximum exposure to loss	12	223
Exelon Generation Co L L C [Member] \| Commercial Agreement Variable Interest Entities [Member]
Variable Interest Entity [Line Items]
Total assets	614	597
Total liabilities	36	37
Exelon's ownership interest in VIE	0	0
Other ownership interests in VIE	587	560
Exelon Generation Co L L C [Member] \| Commercial Agreement Variable Interest Entities [Member] \| Carrying amount of equity method investments
Variable Interest Entity [Line Items]
Registrants' maximum exposure to loss	0	0
Exelon Generation Co L L C [Member] \| Equity Investment VIE [Member]
Variable Interest Entity [Line Items]
Total assets	453	472
Total liabilities	224	222
Exelon's ownership interest in VIE	201	223
Other ownership interests in VIE	28	27
Exelon Generation Co L L C [Member] \| Equity Investment VIE [Member] \| Carrying amount of equity method investments
Variable Interest Entity [Line Items]
Registrants' maximum exposure to loss	$ 12	$ 223

Mergers, Acquisitions and Dispositions - Acquisitions Narrative (Details) - USD ($) $ in Millions		9 Months Ended
	Apr. 04, 2018	Sep. 30, 2019	Sep. 30, 2018
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross		$ 0	$ 57
Handley [Member]
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross	$ 62
Exelon Generation Co L L C [Member]
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross		$ 0	$ 57
Exelon Generation Co L L C [Member] \| Handley [Member]
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross	$ 62

Mergers, Acquisitions and Dispositions - Dispositions Narrative (Details) - USD ($) $ in Millions		3 Months Ended				9 Months Ended
	Feb. 28, 2018	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Sep. 30, 2018	Sep. 30, 2018	Dec. 31, 2018
Business Dispositions [Line Items]
Assets held for sale		$ 18					$ 904
Liabilities held for sale		11					777
Asset Retirement Obligation, Revision of Estimate		(300)		$ 330		$ 20
Exelon Generation Co L L C [Member]
Business Dispositions [Line Items]
Assets held for sale		18					904
Liabilities held for sale		11					777
Asset Retirement Obligation, Revision of Estimate		(300)		$ 330		$ 0
Oyster Creek [Member]
Business Dispositions [Line Items]
Assets held for sale							897
Liabilities held for sale							777
Oyster Creek [Member] \| Exelon Generation Co L L C [Member]
Business Dispositions [Line Items]
Assets held for sale							897
Liabilities held for sale							$ 777
Electrical Contracting Business [Member]
Business Dispositions [Line Items]
Proceeds from Divestiture of Businesses	$ 87
Electrical Contracting Business [Member] \| Exelon Generation Co L L C [Member]
Business Dispositions [Line Items]
Proceeds from Divestiture of Businesses	$ 87
Operating Expense [Member]
Business Dispositions [Line Items]
Asset Retirement Obligation, Revision of Estimate		(65)
Operating Expense [Member] \| Exelon Generation Co L L C [Member]
Business Dispositions [Line Items]
Asset Retirement Obligation, Revision of Estimate		$ (65)
Operating Expense [Member] \| Oyster Creek [Member]
Business Dispositions [Line Items]
Asset Retirement Obligation, Revision of Estimate			$ 9		$ 84
Operating Expense [Member] \| Oyster Creek [Member] \| Exelon Generation Co L L C [Member]
Business Dispositions [Line Items]
Asset Retirement Obligation, Revision of Estimate			$ 9		$ 84

Revenue from Contracts with Customers - Change in Contract with Customer, Asset and Liability (Details) - USD ($) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2019	Dec. 31, 2018	Dec. 31, 2017
Change in Contract with Customer, Asset and Liability [Line Items]
Contract Assets	$ 170	$ 187	$ 283
Contract Liabilities	26	27	35
Consideration (received) due, contract assets	(109)	(146)
Consideration received (due), contract liabilities	65	179
Revenues recognized, contract assets	92	50
Revenues recognized, contract liabilities	(66)	(187)
Exelon Generation Co L L C [Member]
Change in Contract with Customer, Asset and Liability [Line Items]
Contract Assets	170	187	283
Contract Liabilities	48	42	$ 35
Consideration (received) due, contract assets	(109)	(146)
Consideration received (due), contract liabilities	198	465
Revenues recognized, contract assets	92	50
Revenues recognized, contract liabilities	$ (192)	$ (458)

Leases Lessee - Components of Lease Cost (Details) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2019 USD ($)	Sep. 30, 2019 USD ($)
Schedule of Components of Lease Cost [Line Items]
Operating Lease Costs	$ 97	$ 252
Variable Lease Costs	79	229
Short-term Lease Costs	5	16
Total Lease Costs	181	497
Sublease Income	$ 29	$ 48
Operating Lease, Weighted Average Remaining Lease Term	10 years 1 month 6 days	10 years 1 month 6 days
Operating Lease Weighted Average Discount Rate, Percent	4.50%	4.50%
Exelon Generation Co L L C [Member]
Schedule of Components of Lease Cost [Line Items]
Operating Lease Costs	$ 73	$ 180
Variable Lease Costs	74	214
Short-term Lease Costs	5	16
Total Lease Costs	152	410
Sublease Income	$ 28	$ 42
Operating Lease, Weighted Average Remaining Lease Term	10 years 7 months 6 days	10 years 7 months 6 days
Operating Lease Weighted Average Discount Rate, Percent	4.80%	4.80%
Commonwealth Edison Co [Member]
Schedule of Components of Lease Cost [Line Items]
Operating Lease Costs	$ 1	$ 2
Variable Lease Costs	0	1
Short-term Lease Costs	0	0
Total Lease Costs	$ 1	$ 3
Operating Lease, Weighted Average Remaining Lease Term	4 years 8 months 12 days	4 years 8 months 12 days
Operating Lease Weighted Average Discount Rate, Percent	3.10%	3.10%
PECO Energy Co [Member]
Schedule of Components of Lease Cost [Line Items]
Operating Lease Costs	$ 0	$ 1
Variable Lease Costs	0	0
Short-term Lease Costs	0	0
Total Lease Costs	$ 0	$ 1
Operating Lease, Weighted Average Remaining Lease Term	4 years 3 months 18 days	4 years 3 months 18 days
Operating Lease Weighted Average Discount Rate, Percent	3.30%	3.30%
Baltimore Gas and Electric Company [Member]
Schedule of Components of Lease Cost [Line Items]
Operating Lease Costs	$ 8	$ 25
Variable Lease Costs	1	1
Short-term Lease Costs	0	0
Total Lease Costs	$ 9	$ 26
Operating Lease, Weighted Average Remaining Lease Term	5 years 7 months 6 days	5 years 7 months 6 days
Operating Lease Weighted Average Discount Rate, Percent	3.60%	3.60%
Pepco Holdings LLC [Member]
Schedule of Components of Lease Cost [Line Items]
Operating Lease Costs	$ 12	$ 35
Variable Lease Costs	1	5
Short-term Lease Costs	0	0
Total Lease Costs	13	40
Sublease Income	$ 1	$ 6
Operating Lease, Weighted Average Remaining Lease Term	9 years	9 years
Operating Lease Weighted Average Discount Rate, Percent	4.00%	4.00%
Potomac Electric Power Company [Member]
Schedule of Components of Lease Cost [Line Items]
Operating Lease Costs	$ 3	$ 9
Variable Lease Costs	0	2
Short-term Lease Costs	0	0
Total Lease Costs	$ 3	$ 11
Operating Lease, Weighted Average Remaining Lease Term	9 years 7 months 6 days	9 years 7 months 6 days
Operating Lease Weighted Average Discount Rate, Percent	3.70%	3.70%
Delmarva Power and Light Company [Member]
Schedule of Components of Lease Cost [Line Items]
Operating Lease Costs	$ 3	$ 10
Variable Lease Costs	0	2
Short-term Lease Costs	0	0
Total Lease Costs	3	12
Sublease Income	$ 1	$ 6
Operating Lease, Weighted Average Remaining Lease Term	9 years 6 months	9 years 6 months
Operating Lease Weighted Average Discount Rate, Percent	3.70%	3.70%
Atlantic City Electric Company [Member]
Schedule of Components of Lease Cost [Line Items]
Operating Lease Costs	$ 2	$ 5
Variable Lease Costs	0	1
Short-term Lease Costs	0	0
Total Lease Costs	$ 2	$ 6
Operating Lease, Weighted Average Remaining Lease Term	5 years 3 months 18 days	5 years 3 months 18 days
Operating Lease Weighted Average Discount Rate, Percent	3.30%	3.30%

Leases Lessee - Future Minimum Operating Lease Maturity Payments (Details) $ in Millions	Sep. 30, 2019 USD ($)
Schedule of Lessee, Operating Lease, Liability, Maturity [Line Items]
2019	$ 65
2020	289
2021	246
2022	179
2023	148
Remaining Years	1,123
Total	2,050
Interest	453
Total Operating Lease Liabilities	1,597
Exelon Generation Co L L C [Member]
Schedule of Lessee, Operating Lease, Liability, Maturity [Line Items]
2019	50
2020	203
2021	162
2022	113
2023	100
Remaining Years	837
Total	1,465
Interest	346
Total Operating Lease Liabilities	1,119
Commonwealth Edison Co [Member]
Schedule of Lessee, Operating Lease, Liability, Maturity [Line Items]
2019	1
2020	3
2021	3
2022	2
2023	1
Remaining Years	2
Total	12
Interest	1
Total Operating Lease Liabilities	11
PECO Energy Co [Member]
Schedule of Lessee, Operating Lease, Liability, Maturity [Line Items]
2019	0
2020	1
2021	0
2022	0
2023	0
Remaining Years	0
Total	1
Interest	0
Total Operating Lease Liabilities	1
Baltimore Gas and Electric Company [Member]
Schedule of Lessee, Operating Lease, Liability, Maturity [Line Items]
2019	1
2020	34
2021	31
2022	16
2023	0
Remaining Years	19
Total	101
Interest	19
Total Operating Lease Liabilities	82
Pepco Holdings LLC [Member]
Schedule of Lessee, Operating Lease, Liability, Maturity [Line Items]
2019	11
2020	45
2021	43
2022	42
2023	41
Remaining Years	197
Total	379
Interest	65
Total Operating Lease Liabilities	314
Potomac Electric Power Company [Member]
Schedule of Lessee, Operating Lease, Liability, Maturity [Line Items]
2019	3
2020	10
2021	9
2022	9
2023	8
Remaining Years	43
Total	82
Interest	14
Total Operating Lease Liabilities	68
Delmarva Power and Light Company [Member]
Schedule of Lessee, Operating Lease, Liability, Maturity [Line Items]
2019	2
2020	13
2021	12
2022	12
2023	11
Remaining Years	53
Total	103
Interest	18
Total Operating Lease Liabilities	85
Atlantic City Electric Company [Member]
Schedule of Lessee, Operating Lease, Liability, Maturity [Line Items]
2019	2
2020	5
2021	5
2022	4
2023	4
Remaining Years	6
Total	26
Interest	2
Total Operating Lease Liabilities	$ 24

Leases Lessee - 2018 Schedule of Minimum Future Operating Lease Payments (Details) $ in Millions	Dec. 31, 2018 USD ($)
Operating Leases Future Minimum Payments Due [Line Items]
2019	$ 140
2020	149
2021	143
2022	126
2023	97
Remaining Years	723
Total Minimum Future Lease Payments	1,378
Exelon Generation Co L L C [Member]
Operating Leases Future Minimum Payments Due [Line Items]
2019	33
2020	46
2021	46
2022	47
2023	46
Remaining Years	545
Total Minimum Future Lease Payments	763
Commonwealth Edison Co [Member]
Operating Leases Future Minimum Payments Due [Line Items]
2019	7
2020	5
2021	4
2022	4
2023	3
Remaining Years	0
Total Minimum Future Lease Payments	23
PECO Energy Co [Member]
Operating Leases Future Minimum Payments Due [Line Items]
2019	5
2020	5
2021	5
2022	5
2023	5
Remaining Years	0
Total Minimum Future Lease Payments	25
Baltimore Gas and Electric Company [Member]
Operating Leases Future Minimum Payments Due [Line Items]
2019	35
2020	35
2021	33
2022	18
2023	3
Remaining Years	19
Total Minimum Future Lease Payments	143
Pepco Holdings LLC [Member]
Operating Leases Future Minimum Payments Due [Line Items]
2019	48
2020	46
2021	43
2022	42
2023	39
Remaining Years	159
Total Minimum Future Lease Payments	377
Potomac Electric Power Company [Member]
Operating Leases Future Minimum Payments Due [Line Items]
2019	11
2020	10
2021	9
2022	8
2023	8
Remaining Years	40
Total Minimum Future Lease Payments	86
Delmarva Power and Light Company [Member]
Operating Leases Future Minimum Payments Due [Line Items]
2019	14
2020	13
2021	12
2022	12
2023	10
Remaining Years	35
Total Minimum Future Lease Payments	96
Atlantic City Electric Company [Member]
Operating Leases Future Minimum Payments Due [Line Items]
2019	7
2020	6
2021	5
2022	5
2023	4
Remaining Years	5
Total Minimum Future Lease Payments	32
Real Estate Leases and Railroad Licenses [Member] \| Commonwealth Edison Co [Member]
Operating Leases Future Minimum Payments Due [Line Items]
Total Minimum Future Lease Payments	3
Real Estate Leases and Railroad Licenses [Member] \| PECO Energy Co [Member]
Operating Leases Future Minimum Payments Due [Line Items]
Total Minimum Future Lease Payments	5
Real Estate Leases and Railroad Licenses [Member] \| Baltimore Gas and Electric Company [Member]
Operating Leases Future Minimum Payments Due [Line Items]
Total Minimum Future Lease Payments	1
Real Estate Leases and Railroad Licenses [Member] \| Delmarva Power and Light Company [Member]
Operating Leases Future Minimum Payments Due [Line Items]
Total Minimum Future Lease Payments	1
Electrical Conduit System [Member] \| Baltimore Gas and Electric Company [Member]
Operating Leases Future Minimum Payments Due [Line Items]
2019	26
2020	28
2021	28
2022	$ 14

Leases Lessee - Supplemental Cash Flow Information Related to Leases (Details) $ in Millions	9 Months Ended
	Sep. 30, 2019 USD ($)
Supplemental Cash Flow Information [Line Items]
Operating cash flows from operating leases	$ 225
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	70
Exelon Generation Co L L C [Member]
Supplemental Cash Flow Information [Line Items]
Operating cash flows from operating leases	156
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	11
Commonwealth Edison Co [Member]
Supplemental Cash Flow Information [Line Items]
Operating cash flows from operating leases	2
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	6
PECO Energy Co [Member]
Supplemental Cash Flow Information [Line Items]
Operating cash flows from operating leases	0
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	0
Baltimore Gas and Electric Company [Member]
Supplemental Cash Flow Information [Line Items]
Operating cash flows from operating leases	32
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	1
Pepco Holdings LLC [Member]
Supplemental Cash Flow Information [Line Items]
Operating cash flows from operating leases	29
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	20
Potomac Electric Power Company [Member]
Supplemental Cash Flow Information [Line Items]
Operating cash flows from operating leases	7
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	7
Delmarva Power and Light Company [Member]
Supplemental Cash Flow Information [Line Items]
Operating cash flows from operating leases	6
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	9
Atlantic City Electric Company [Member]
Supplemental Cash Flow Information [Line Items]
Operating cash flows from operating leases	4
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	$ 4

Leases Lessor - Narrative (Details)	9 Months Ended
Leases Lessor - Narrative (Details)	Sep. 30, 2019
Contracted Generation [Member]
Lessor, Lease, Description [Line Items]
Lessor, Operating Lease, Description	●
Real Estate [Member]
Lessor, Lease, Description [Line Items]
Lessor, Operating Lease, Description	●
Minimum [Member]
Lessor, Lease, Description [Line Items]
Remaining lease terms	1 year
Options to extend the term	1 years
Maximum [Member]
Lessor, Lease, Description [Line Items]
Remaining lease terms	84 years
Options to extend the term	79 years
Exelon Generation Co L L C [Member] \| Contracted Generation [Member]
Lessor, Lease, Description [Line Items]
Lessor, Operating Lease, Description	●
Exelon Generation Co L L C [Member] \| Real Estate [Member]
Lessor, Lease, Description [Line Items]
Lessor, Operating Lease, Description	●
Exelon Generation Co L L C [Member] \| Minimum [Member]
Lessor, Lease, Description [Line Items]
Remaining lease terms	1 year
Options to extend the term	1 years
Exelon Generation Co L L C [Member] \| Maximum [Member]
Lessor, Lease, Description [Line Items]
Remaining lease terms	33 years
Options to extend the term	5 years
Commonwealth Edison Co [Member] \| Real Estate [Member]
Lessor, Lease, Description [Line Items]
Lessor, Operating Lease, Description	●
Commonwealth Edison Co [Member] \| Minimum [Member]
Lessor, Lease, Description [Line Items]
Remaining lease terms	1 year
Options to extend the term	5 years
Commonwealth Edison Co [Member] \| Maximum [Member]
Lessor, Lease, Description [Line Items]
Remaining lease terms	18 years
Options to extend the term	79 years
PECO Energy Co [Member] \| Real Estate [Member]
Lessor, Lease, Description [Line Items]
Lessor, Operating Lease, Description	●
PECO Energy Co [Member] \| Minimum [Member]
Lessor, Lease, Description [Line Items]
Remaining lease terms	1 year
Options to extend the term	5 years
PECO Energy Co [Member] \| Maximum [Member]
Lessor, Lease, Description [Line Items]
Remaining lease terms	84 years
Options to extend the term	50 years
Baltimore Gas and Electric Company [Member] \| Real Estate [Member]
Lessor, Lease, Description [Line Items]
Lessor, Operating Lease, Description	●
Baltimore Gas and Electric Company [Member] \| Minimum [Member]
Lessor, Lease, Description [Line Items]
Remaining lease terms	24 years
Baltimore Gas and Electric Company [Member] \| Maximum [Member]
Lessor, Lease, Description [Line Items]
Remaining lease terms	24 years
Pepco Holdings LLC [Member] \| Real Estate [Member]
Lessor, Lease, Description [Line Items]
Lessor, Operating Lease, Description	●
Pepco Holdings LLC [Member] \| Minimum [Member]
Lessor, Lease, Description [Line Items]
Remaining lease terms	1 year
Options to extend the term	5 years
Pepco Holdings LLC [Member] \| Maximum [Member]
Lessor, Lease, Description [Line Items]
Remaining lease terms	14 years
Options to extend the term	5 years
Potomac Electric Power Company [Member] \| Real Estate [Member]
Lessor, Lease, Description [Line Items]
Lessor, Operating Lease, Description	●
Potomac Electric Power Company [Member] \| Minimum [Member]
Lessor, Lease, Description [Line Items]
Remaining lease terms	2 years
Potomac Electric Power Company [Member] \| Maximum [Member]
Lessor, Lease, Description [Line Items]
Remaining lease terms	7 years
Delmarva Power and Light Company [Member] \| Real Estate [Member]
Lessor, Lease, Description [Line Items]
Lessor, Operating Lease, Description	●
Delmarva Power and Light Company [Member] \| Minimum [Member]
Lessor, Lease, Description [Line Items]
Remaining lease terms	13 years
Delmarva Power and Light Company [Member] \| Maximum [Member]
Lessor, Lease, Description [Line Items]
Remaining lease terms	14 years
Atlantic City Electric Company [Member] \| Real Estate [Member]
Lessor, Lease, Description [Line Items]
Lessor, Operating Lease, Description	●
Atlantic City Electric Company [Member] \| Minimum [Member]
Lessor, Lease, Description [Line Items]
Remaining lease terms	1 year
Atlantic City Electric Company [Member] \| Maximum [Member]
Lessor, Lease, Description [Line Items]
Remaining lease terms	3 years

Leases Lessor - Components of Operating Lease Income (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2019
Schedule of Operating Lease, Lease Income [Line Items]
Operating Lease Income	$ 30	$ 48
Variable Lease Income	80	209
Exelon Generation Co L L C [Member]
Schedule of Operating Lease, Lease Income [Line Items]
Operating Lease Income	29	44
Variable Lease Income	80	206
Commonwealth Edison Co [Member]
Schedule of Operating Lease, Lease Income [Line Items]
Operating Lease Income	0	0
Variable Lease Income	0	0
PECO Energy Co [Member]
Schedule of Operating Lease, Lease Income [Line Items]
Operating Lease Income	0	0
Variable Lease Income	0	0
Baltimore Gas and Electric Company [Member]
Schedule of Operating Lease, Lease Income [Line Items]
Operating Lease Income	0	0
Variable Lease Income	0	0
Pepco Holdings LLC [Member]
Schedule of Operating Lease, Lease Income [Line Items]
Operating Lease Income	1	3
Variable Lease Income	0	3
Potomac Electric Power Company [Member]
Schedule of Operating Lease, Lease Income [Line Items]
Operating Lease Income	0	0
Variable Lease Income	0	0
Delmarva Power and Light Company [Member]
Schedule of Operating Lease, Lease Income [Line Items]
Operating Lease Income	1	3
Variable Lease Income	0	3
Atlantic City Electric Company [Member]
Schedule of Operating Lease, Lease Income [Line Items]
Operating Lease Income	0	0
Variable Lease Income	$ 0	$ 0

Leases Lessor - Future Minimum Operating Lease Maturity Payments (Details) $ in Millions	Sep. 30, 2019 USD ($)
Schedule of Lessor, Operating Lease, Payments to be Received, Maturity [Line Items]
2019	$ 4
2020	51
2021	50
2022	50
2023	49
Remaining years	314
Total	518
Exelon Generation Co L L C [Member]
Schedule of Lessor, Operating Lease, Payments to be Received, Maturity [Line Items]
2019	3
2020	46
2021	45
2022	45
2023	45
Remaining years	271
Total	455
Commonwealth Edison Co [Member]
Schedule of Lessor, Operating Lease, Payments to be Received, Maturity [Line Items]
2019	0
2020	0
2021	0
2022	0
2023	0
Remaining years	1
Total	1
PECO Energy Co [Member]
Schedule of Lessor, Operating Lease, Payments to be Received, Maturity [Line Items]
2019	0
2020	0
2021	0
2022	0
2023	0
Remaining years	3
Total	3
Baltimore Gas and Electric Company [Member]
Schedule of Lessor, Operating Lease, Payments to be Received, Maturity [Line Items]
2019	0
2020	0
2021	0
2022	0
2023	0
Remaining years	1
Total	1
Pepco Holdings LLC [Member]
Schedule of Lessor, Operating Lease, Payments to be Received, Maturity [Line Items]
2019	1
2020	4
2021	4
2022	5
2023	4
Remaining years	38
Total	56
Potomac Electric Power Company [Member]
Schedule of Lessor, Operating Lease, Payments to be Received, Maturity [Line Items]
2019	0
2020	0
2021	1
2022	0
2023	0
Remaining years	0
Total	1
Delmarva Power and Light Company [Member]
Schedule of Lessor, Operating Lease, Payments to be Received, Maturity [Line Items]
2019	1
2020	3
2021	3
2022	4
2023	3
Remaining years	38
Total	52
Atlantic City Electric Company [Member]
Schedule of Lessor, Operating Lease, Payments to be Received, Maturity [Line Items]
2019	0
2020	0
2021	0
2022	0
2023	0
Remaining years	0
Total	$ 0

Regulatory Matters - Narrative (Details) - USD ($) $ in Millions							3 Months Ended		7 Months Ended	9 Months Ended
	Oct. 29, 2019	Jul. 22, 2019	May 23, 2019	Apr. 18, 2019	Feb. 28, 2019	May 01, 2017	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2017	Sep. 30, 2019	Sep. 30, 2018
Regulatory Matters Additional Narrative Information [Line Items]
Payments to Acquire Property, Plant, and Equipment							$ 1,687	$ 1,690		$ 5,259	$ 5,497
Maximum [Member] \| One-Time Revenue Adjustment [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Amount of Impairment to Carrying Amount of Regulatory Assets							80			80
PECO Energy Co [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount						$ 22
Public Utilities, Requested Equity Capital Structure, Percentage		10.35%				11.00%
Revenue										8	6
Payments to Acquire Property, Plant, and Equipment										675	615
Increase (Decrease) in Regulatory Assets										62
Commonwealth Edison Co [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount			$ 51							5
Revenue			$ (2)							(16)
Payments to Acquire Property, Plant, and Equipment										1,413	1,540
Increase (Decrease) in Regulatory Assets										122
Commonwealth Edison Co [Member] \| Maximum [Member] \| One-Time Revenue Adjustment [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Amount of Impairment to Carrying Amount of Regulatory Assets							52			52
Baltimore Gas and Electric Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount										(19)
Revenue										(23)
Payments to Acquire Property, Plant, and Equipment										842	667
Increase (Decrease) in Regulatory Liabilities										(90)
Baltimore Gas and Electric Company [Member] \| Maximum [Member] \| One-Time Revenue Adjustment [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Amount of Impairment to Carrying Amount of Regulatory Assets							16			16
Pepco Holdings LLC [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Payments to Acquire Property, Plant, and Equipment										1,006	988
Pepco Holdings LLC [Member] \| Maximum [Member] \| One-Time Revenue Adjustment [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Amount of Impairment to Carrying Amount of Regulatory Assets							12			12
Potomac Electric Power Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount										26
Revenue										11
Payments to Acquire Property, Plant, and Equipment										455	475
Increase (Decrease) in Regulatory Assets										(84)
Increase (Decrease) in Regulatory Liabilities										(71)
Potomac Electric Power Company [Member] \| Maximum [Member] \| One-Time Revenue Adjustment [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Amount of Impairment to Carrying Amount of Regulatory Assets							4			4
Atlantic City Electric Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount										9
Revenue										(2)
Payments to Acquire Property, Plant, and Equipment				$ 96	$ 338					300	247
Increase (Decrease) in Regulatory Liabilities										(30)
Atlantic City Electric Company [Member] \| Maximum [Member] \| One-Time Revenue Adjustment [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Amount of Impairment to Carrying Amount of Regulatory Assets							2			2
Delmarva Power and Light Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount										16
Revenue										(1)
Payments to Acquire Property, Plant, and Equipment										245	254
Increase (Decrease) in Regulatory Liabilities										(42)
Delmarva Power and Light Company [Member] \| Maximum [Member] \| One-Time Revenue Adjustment [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Amount of Impairment to Carrying Amount of Regulatory Assets							6			6
Exelon Generation Co L L C [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Payments to Acquire Property, Plant, and Equipment										1,282	1,660
Deferred Income Tax Charge [Member] \| PECO Energy Co [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Increase (Decrease) in Regulatory Assets										95
Deferred Income Tax Charge [Member] \| Baltimore Gas and Electric Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Increase (Decrease) in Regulatory Liabilities										(40)
Deferred Income Tax Charge [Member] \| Potomac Electric Power Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Increase (Decrease) in Regulatory Liabilities										(73)
Deferred Income Tax Charge [Member] \| Atlantic City Electric Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Increase (Decrease) in Regulatory Liabilities										(32)
Deferred Income Tax Charge [Member] \| Delmarva Power and Light Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Increase (Decrease) in Regulatory Liabilities										(29)
Removal Costs [Member] \| Baltimore Gas and Electric Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Increase (Decrease) in Regulatory Liabilities										(43)
Clean Energy Legislation [Member] \| Exelon Generation Co L L C [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Competitive businesses other revenues							$ 21			$ 31
Nuclear Plant [Member] \| Exelon Generation Co L L C [Member] \| Salem [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Interest, percentage							42.59%			42.59%
Generation commodities and services
Regulatory Matters Additional Narrative Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax							$ 4,499	4,971		$ 13,436	14,387
Generation commodities and services \| Exelon Generation Co L L C [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax							4,499	$ 4,970		13,436	$ 14,389
Generation commodities and services \| Zero Emission Standard [Member] \| Exelon Generation Co L L C [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									$ 150
License and Service [Member] \| Conowingo [Member]
Regulatory Matters Additional Narrative Information [Line Items]
License Costs							41			41
License and Service [Member] \| Conowingo [Member] \| Subsequent Event [Member] \| Maximum [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Environmental Remediation Expense	$ 14
License and Service [Member] \| Conowingo [Member] \| Subsequent Event [Member] \| Minimum [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Environmental Remediation Expense	11
License and Service [Member] \| Conowingo [Member] \| Exelon Generation Co L L C [Member]
Regulatory Matters Additional Narrative Information [Line Items]
License Costs							$ 41			41
License and Service [Member] \| Conowingo [Member] \| Exelon Generation Co L L C [Member] \| Subsequent Event [Member] \| Maximum [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Environmental Remediation Expense	14
License and Service [Member] \| Conowingo [Member] \| Exelon Generation Co L L C [Member] \| Subsequent Event [Member] \| Minimum [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Environmental Remediation Expense	$ 11
Energy Efficiency Costs [Member] \| PECO Energy Co [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Increase (Decrease) in Regulatory Assets										(34)
Energy Efficiency Costs [Member] \| Commonwealth Edison Co [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Increase (Decrease) in Regulatory Assets										186
Renewable Energy Program [Member] \| Commonwealth Edison Co [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Increase (Decrease) in Regulatory Assets										32
Electric Distribution Formula Rate Annual Reconciliations [Member] \| Commonwealth Edison Co [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Increase (Decrease) in Regulatory Assets										(97)
Under Recovered Energy and Natural Gas Costs [Member] \| Potomac Electric Power Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Increase (Decrease) in Regulatory Assets										(39)
Under Recovered Energy and Natural Gas Costs [Member] \| Delmarva Power and Light Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Increase (Decrease) in Regulatory Liabilities										(10)
DC PLUG Charge [Member] \| Potomac Electric Power Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Increase (Decrease) in Regulatory Assets										(26)
Advanced Metering Infrastructure Legacy Meter Costs [Member] \| Potomac Electric Power Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Increase (Decrease) in Regulatory Assets										$ (14)

Regulatory Matters Schedule of Completed Rate Cases (Details) (Details) - USD ($) $ in Millions														9 Months Ended	12 Months Ended
	Aug. 12, 2019	May 24, 2019	May 23, 2019	Apr. 08, 2019	Mar. 13, 2019	Jan. 15, 2019	Jan. 04, 2019	Dec. 20, 2018	Dec. 04, 2018	Nov. 19, 2018	Jun. 08, 2018	Apr. 16, 2018	Mar. 29, 2018	Sep. 30, 2019	Dec. 31, 2018
Commonwealth Edison Co [Member]
Regulatory Matters Completed Rate Cases [Line Items]
Requested Revenue Requirement Increase (Decrease)			$ 53											$ 21
Approved Return on Equity, Percentage														11.50%	10.91%
Commonwealth Edison Co [Member] \| Electric Distribution [Member]
Regulatory Matters Completed Rate Cases [Line Items]
Requested Revenue Requirement Increase (Decrease)				$ (6)								$ (23)		$ 57
Approved Revenue Requirement Increase (Decrease)									$ (24)						$ (63)
Approved Return on Equity, Percentage									8.69%
PECO Energy Co [Member] \| Electricity [Member]
Regulatory Matters Completed Rate Cases [Line Items]
Requested Revenue Requirement Increase (Decrease)													$ 82
Approved Revenue Requirement Increase (Decrease)								$ 25
Baltimore Gas and Electric Company [Member]
Regulatory Matters Completed Rate Cases [Line Items]
Requested Revenue Requirement Increase (Decrease)														$ (10)
Approved Return on Equity, Percentage														10.50%
Baltimore Gas and Electric Company [Member] \| Electric Distribution [Member]
Regulatory Matters Completed Rate Cases [Line Items]
Requested Revenue Requirement Increase (Decrease)		$ 74
Baltimore Gas and Electric Company [Member] \| Gas Distribution [Member]
Regulatory Matters Completed Rate Cases [Line Items]
Requested Revenue Requirement Increase (Decrease)		$ 59									$ 61
Approved Revenue Requirement Increase (Decrease)							$ 43
Approved Return on Equity, Percentage							9.80%
Atlantic City Electric Company [Member]
Regulatory Matters Completed Rate Cases [Line Items]
Requested Revenue Requirement Increase (Decrease)														$ 11
Approved Return on Equity, Percentage														10.50%
Atlantic City Electric Company [Member] \| Electric Distribution [Member]
Regulatory Matters Completed Rate Cases [Line Items]
Requested Revenue Requirement Increase (Decrease)										$ 122
Approved Revenue Requirement Increase (Decrease)					$ 70
Approved Return on Equity, Percentage					9.60%
Potomac Electric Power Company [Member]
Regulatory Matters Completed Rate Cases [Line Items]
Requested Revenue Requirement Increase (Decrease)														$ 15
Approved Return on Equity, Percentage														10.50%
MARYLAND \| Potomac Electric Power Company [Member] \| Electric Distribution [Member]
Regulatory Matters Completed Rate Cases [Line Items]
Requested Revenue Requirement Increase (Decrease)						$ 27
Approved Revenue Requirement Increase (Decrease)	$ 10
Approved Return on Equity, Percentage	9.60%

Regulatory Matters Schedule of Pending Rate Cases (Details) (Details) - USD ($) $ in Millions												9 Months Ended	12 Months Ended
	Oct. 25, 2019	Aug. 12, 2019	May 30, 2019	May 24, 2019	May 23, 2019	Apr. 08, 2019	Jan. 15, 2019	Jan. 04, 2019	Dec. 04, 2018	Jun. 08, 2018	Apr. 16, 2018	Sep. 30, 2019	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2018
Potomac Electric Power Company [Member]
Regulatory Matters Pending Rate Cases [Line Items]
Requested Revenue Requirement Increase (Decrease), Amended												$ 26
Requested Revenue Requirement Increase (Decrease)												15
Commonwealth Edison Co [Member]
Regulatory Matters Pending Rate Cases [Line Items]
Requested Revenue Requirement Increase (Decrease), Amended					$ 51							5
Requested Revenue Requirement Increase (Decrease)					$ 53							21
Requested Return on Equity, Percentage					8.91%
Baltimore Gas and Electric Company [Member]
Regulatory Matters Pending Rate Cases [Line Items]
Requested Revenue Requirement Increase (Decrease), Amended												(19)
Requested Revenue Requirement Increase (Decrease)												(10)
Electric Distribution [Member] \| Commonwealth Edison Co [Member]
Regulatory Matters Pending Rate Cases [Line Items]
Requested Revenue Requirement Increase (Decrease)						$ (6)					$ (23)	$ 57
Requested Return on Equity, Percentage						8.91%
Approved Revenue Requirement Increase (Decrease)									$ (24)							$ (63)
Requested Return on Distribution Rate Base, Percentage					6.53%											6.53%
Electric Distribution [Member] \| Baltimore Gas and Electric Company [Member]
Regulatory Matters Pending Rate Cases [Line Items]
Requested Revenue Requirement Increase (Decrease)				$ 74
Requested Return on Equity, Percentage				10.30%
Electric Distribution [Member] \| Baltimore Gas and Electric Company [Member] \| Subsequent Event [Member]
Regulatory Matters Pending Rate Cases [Line Items]
Requested Revenue Requirement Increase (Decrease)	$ 18
Requested Return on Equity, Percentage	4500000000.00%
Gas Distribution [Member] \| Baltimore Gas and Electric Company [Member]
Regulatory Matters Pending Rate Cases [Line Items]
Requested Revenue Requirement Increase (Decrease)				$ 59						$ 61
Requested Return on Equity, Percentage				10.30%
Approved Revenue Requirement Increase (Decrease)								$ 43
MARYLAND \| Electric Distribution [Member] \| Potomac Electric Power Company [Member]
Regulatory Matters Pending Rate Cases [Line Items]
Requested Revenue Requirement Increase (Decrease)							$ 27
Approved Revenue Requirement Increase (Decrease)		$ 10
DISTRICT OF COLUMBIA \| Electric Distribution [Member] \| Potomac Electric Power Company [Member]
Regulatory Matters Pending Rate Cases [Line Items]
Requested Revenue Requirement Increase (Decrease)			$ 160
Requested Return on Equity, Percentage			10.30%
DISTRICT OF COLUMBIA \| Forecast [Member] \| Electric Distribution [Member] \| Potomac Electric Power Company [Member]
Regulatory Matters Pending Rate Cases [Line Items]
Requested Revenue Requirement Increase (Decrease)													$ 36	$ 40	$ 84

Regulatory Matters - Annual Electric Transmission Fillings (Details) - USD ($) $ in Millions		3 Months Ended	9 Months Ended	12 Months Ended
	May 23, 2019	Sep. 30, 2019	Sep. 30, 2019	Dec. 31, 2018
Commonwealth Edison Co [Member]
Public Utilities, General Disclosures [Line Items]
Initial Revenue Requirement Increase (Decrease)	$ 53		$ 21
Annual Reconciliation Increase (Decrease)	(2)		(16)
Total Revenue Requirement Increase (Decrease)	$ 51		$ 5
Allowed Return on Rate Base, Percentage			8.21%
Allowed Return on Equity, Percentage			11.50%	10.91%
Cap on Equity Component of Rate of Return on Common Equity in Federal Energy Regulatory Committee Complaint			55.00%
Baltimore Gas and Electric Company [Member]
Public Utilities, General Disclosures [Line Items]
Initial Revenue Requirement Increase (Decrease)			$ (10)
Annual Reconciliation Increase (Decrease)			(23)
Total Revenue Requirement Increase (Decrease)			$ (19)
Allowed Return on Rate Base, Percentage			7.35%
Allowed Return on Equity, Percentage			10.50%
Proposed Capital Expenditure			$ 14
Potomac Electric Power Company [Member]
Public Utilities, General Disclosures [Line Items]
Initial Revenue Requirement Increase (Decrease)			15
Annual Reconciliation Increase (Decrease)			11
Total Revenue Requirement Increase (Decrease)			$ 26
Allowed Return on Rate Base, Percentage			7.75%
Allowed Return on Equity, Percentage			10.50%
Delmarva Power and Light Company [Member]
Public Utilities, General Disclosures [Line Items]
Initial Revenue Requirement Increase (Decrease)			$ 17
Annual Reconciliation Increase (Decrease)			(1)
Total Revenue Requirement Increase (Decrease)			$ 16
Allowed Return on Rate Base, Percentage			7.14%
Allowed Return on Equity, Percentage			10.50%
Atlantic City Electric Company [Member]
Public Utilities, General Disclosures [Line Items]
Initial Revenue Requirement Increase (Decrease)			$ 11
Annual Reconciliation Increase (Decrease)			(2)
Total Revenue Requirement Increase (Decrease)			$ 9
Allowed Return on Rate Base, Percentage			7.79%
Allowed Return on Equity, Percentage			10.50%
Clean Energy Legislation [Member] \| Exelon Generation Co L L C [Member]
Public Utilities, General Disclosures [Line Items]
Other Operating Income		$ 21	$ 31

Regulatory Matters Energy Efficiency Formula Rate (Details) - Commonwealth Edison Co [Member] - USD ($) $ in Millions					9 Months Ended	12 Months Ended
	May 23, 2019	Apr. 08, 2019	Dec. 04, 2018	Apr. 16, 2018	Sep. 30, 2019	Dec. 31, 2018
Schedule of Energy Efficiency Formula Rate Updates [Line Items]
Initial Revenue Requirement Increase (Decrease)	$ 53				$ 21
Annual Reconciliation Increase (Decrease)	(2)				(16)
Total Revenue Requirement Increase (Decrease)	$ 51				$ 5
Requested Return on Equity, Percentage	8.91%
Allowed Return on Equity, Percentage					11.50%	10.91%
Allowed Return on Rate Base, Percentage					8.21%
Electric Distribution [Member]
Schedule of Energy Efficiency Formula Rate Updates [Line Items]
Initial Revenue Requirement Increase (Decrease)		$ (6)		$ (23)	$ 57
Requested Return on Distribution Rate Base, Percentage	6.53%					6.53%
Requested Return on Equity, Percentage		8.91%
Allowed Return on Equity, Percentage			8.69%
Allowed Return on Rate Base, Percentage						7.49%

Regulatory Matters - Capitalized Ratemaking Amount Not Recognized (Details) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Public Utility, Property, Plant and Equipment [Line Items]
Public Utilities, Amount of Allowance for Earnings on Equity Capitalized for Rate Making Purposes	$ 59	$ 65
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	4	8
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	47	49
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	8	8
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	5	5
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	3	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

Asset Impairments - Narrative (Details) $ in Millions	3 Months Ended		9 Months Ended
Asset Impairments - Narrative (Details) $ in Millions	Sep. 30, 2019 USD ($)	Sep. 30, 2018 USD ($)	Sep. 30, 2019 USD ($) MW	Sep. 30, 2018 USD ($)
Property, Plant and Equipment [Line Items]
Net Income (Loss) Attributable to Noncontrolling Interest	$ (12)	$ 67	$ 56	$ 121
Deferred Income Taxes and Tax Credits			412	97
Impairment of long-lived assets			174	49
Exelon Generation Co L L C [Member]
Property, Plant and Equipment [Line Items]
Net Income (Loss) Attributable to Noncontrolling Interest	(13)	$ 66	56	120
Deferred Income Taxes and Tax Credits			201	(278)
Impairment of long-lived assets			174	$ 49
Antelope Valley [Member]
Property, Plant and Equipment [Line Items]
Long-lived assets	730		730
Impairment of long-lived assets			$ 0
Antelope Valley [Member] \| Exelon Generation Co L L C [Member]
Property, Plant and Equipment [Line Items]
Capacity Of Facility Of Company Owned Solar Distribution Generation Facilities \| MW			242
Long-lived assets	730		$ 730
Impairment of long-lived assets			0
ExGen Renewables IV, LLC [Member]
Property, Plant and Equipment [Line Items]
Long-lived assets	1,930		1,930
ExGen Renewables IV, LLC [Member] \| Exelon Generation Co L L C [Member]
Property, Plant and Equipment [Line Items]
Long-lived assets	1,930		$ 1,930
Certain Distributed Energy Companies [Member]
Property, Plant and Equipment [Line Items]
Equity Method Investment, Other than Temporary Impairment	164
Net Income (Loss) Attributable to Noncontrolling Interest	96
Deferred Income Taxes and Tax Credits	(46)
Income (Loss) from Equity Method Investments	(15)
Certain Distributed Energy Companies [Member] \| Exelon Generation Co L L C [Member]
Property, Plant and Equipment [Line Items]
Equity Method Investment, Other than Temporary Impairment	164
Net Income (Loss) Attributable to Noncontrolling Interest	96
Deferred Income Taxes and Tax Credits	(46)
Income (Loss) from Equity Method Investments	$ (15)

Early Plant Retirements - Narrative (Details)	Sep. 30, 2019
Salem [Member] \| Nuclear Plant [Member] \| Exelon Generation Co L L C [Member]
Property, Plant and Equipment [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share	42.59%

Early Plant Retirements - Pretax Expense (Details) - Facility Closing [Member] - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Three Mile Island [Member]
Accelerated depreciation	$ 71		$ 216
Accelerated nuclear fuel amortization	3		13
Operating and maintenance	39		(44)
Restructuring and Related Cost, Incurred Cost	113		185
TMI,OysterCreek [Member]
Accelerated depreciation		$ 152		$ 441
Accelerated nuclear fuel amortization		18		52
Operating and maintenance		4		32
Restructuring and Related Cost, Incurred Cost		174		525
Exelon Generation Co L L C [Member] \| Three Mile Island [Member]
Accelerated depreciation	71		216
Accelerated nuclear fuel amortization	3		13
Operating and maintenance	39		(44)
Restructuring and Related Cost, Incurred Cost	$ 113		$ 185
Exelon Generation Co L L C [Member] \| TMI,OysterCreek [Member]
Accelerated depreciation		152		441
Accelerated nuclear fuel amortization		18		52
Operating and maintenance		4		32
Restructuring and Related Cost, Incurred Cost		$ 174		$ 525

Early Plant Retirements - Implications of Potential Early Plant Retirement on Balance Sheet (Details) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Implications of Potential Early Plant Retirement [Line Items]
Completed plant, net	$ 78,593	$ 76,707
Mystic Generating Station [Member] \| Facility Closing [Member]
Implications of Potential Early Plant Retirement [Line Items]
Materials and supplies inventory	31
Fuel inventory	5
Completed plant, net	889
Construction work in progress	7
Asset retirement obligation	(2)
Exelon Generation Co L L C [Member]
Implications of Potential Early Plant Retirement [Line Items]
Completed plant, net	23,591	$ 23,981
Exelon Generation Co L L C [Member] \| Mystic Generating Station [Member] \| Facility Closing [Member]
Implications of Potential Early Plant Retirement [Line Items]
Materials and supplies inventory	31
Fuel inventory	5
Completed plant, net	889
Construction work in progress	7
Asset retirement obligation	$ (2)

Fair Value of Financial Assets and Liabilities - Narrative (Details) $ in Millions	Sep. 30, 2019 USD ($)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity Securities without Readily Determinable Fair Value, Amount	$ 75
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	75
Fixed Income Securities [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	93
Fixed Income Securities [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	93
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	241
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	241
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	383
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	383
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	388
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	$ 388

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, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Fair Value, Inputs, Level 3 [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Beginning Balance	$ 1,179	$ 1,106	$ 907	$ 966
Total realized / unrealized gains (losses)
Included in net income	(171)	(259)	(125)	(186)
Included in noncurrent payables to affiliates	0	0	0
Included in regulatory assets	4	(11)	1	(3)
Change in collateral	41	(44)	227	14
Purchases, sales, issuances and settlements
Purchases	53	96	163	215
Sales	(22)		(23)	(3)
Settlements	(18)	(29)	(88)	(103)
Transfers into Level 3	1	3	5	(21)
Transfers out of Level 3	(11)	(6)	(11)	(23)
Ending Balance	1,056	856	1,056	856
Fair Value, Asset, Recurring Basis, Still Held, Unrealized Gain (Loss)	(18)	(105)	173	154
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)	4	(32)
Included in regulatory assets	11	(4)	32	0
Change in collateral	0		0	0
Purchases, sales, issuances and settlements
Purchases	0	0	0	0
Sales	0		0	0
Settlements	0	0	0	0
Transfers into Level 3	0	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	153	155	298	347
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	1,412	1,322	1,118	1,200
Total realized / unrealized gains (losses)
Included in net income	(171)	(260)	(127)	(189)
Included in noncurrent payables to affiliates	11	(4)	32
Included in regulatory assets	0	0	0	0
Change in collateral	41	(44)	227	14
Purchases, sales, issuances and settlements
Purchases	53	96	163	215
Sales	(22)		(23)	(3)
Settlements	(18)	(29)	(88)	(115)
Transfers into Level 3	1	3	5	(21)
Transfers out of Level 3	(11)	(6)	(11)	(23)
Ending Balance	1,296	1,078	1,296	1,078
Fair Value, Asset, Recurring Basis, Still Held, Unrealized Gain (Loss)	(18)	(105)	171	154
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	539	585	543	648
Total realized / unrealized gains (losses)
Included in net income	2	(1)	5	(1)
Included in noncurrent payables to affiliates	11	(4)	32
Included in regulatory assets	0	0	0	0
Change in collateral	0	0	0	0
Purchases, sales, issuances and settlements
Purchases	1	15	43	34
Sales	(21)		(21)	0
Settlements	(18)	(29)	(88)	(115)
Transfers into Level 3	0	0	0	0
Transfers out of Level 3	0	0	0	0
Ending Balance	514	566	514	566
Fair Value, Asset, Recurring Basis, Still Held, Unrealized Gain (Loss)	2	(1)	5	(5)
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	873	737	575	552
Total realized / unrealized gains (losses)
Included in net income	(173)	(259)	(132)	(188)
Included in noncurrent payables to affiliates	0	0	0
Included in regulatory assets	0	0		0
Change in collateral	41	(44)	227	14
Purchases, sales, issuances and settlements
Purchases	52	81	120	181
Sales	(1)		(2)	(3)
Settlements	0	0	0	0
Transfers into Level 3	1	3	5	(21)
Transfers out of Level 3	(11)	(6)	(11)	(23)
Ending Balance	782	512	782	512
Fair Value, Asset, Recurring Basis, Still Held, Unrealized Gain (Loss)	(20)	(104)	166	159
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)	4	3	17	12
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	(273)	(252)	(249)	(256)
Total realized / unrealized gains (losses)
Included in net income	0	0	0	0
Included in noncurrent payables to affiliates	0	0	0
Included in regulatory assets	(7)	(7)	(31)	(3)
Change in collateral	0	0	0	0
Purchases, sales, issuances and settlements
Purchases	0	0	0	0
Sales	0		0	0
Settlements	0	0	0	0
Transfers into Level 3	0	0	0	0
Transfers out of Level 3	0	0	0	0
Ending Balance	(280)	(259)	(280)	(259)
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)	(7)	4	(31)	(9)
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	40	36	38	22
Total realized / unrealized gains (losses)
Included in net income	0	1	2	3
Included in noncurrent payables to affiliates	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
Settlements	0	0	0	12
Transfers into Level 3	0	0	0	0
Transfers out of Level 3	0	0	0	0
Ending Balance	40	37	40	37
Fair Value, Asset, Recurring Basis, Still Held, Unrealized Gain (Loss)	0	0	2	0
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	40	36	38	22
Total realized / unrealized gains (losses)
Included in net income	0	1	2	3
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	0	0	12
Transfers into Level 3	0	0	0	0
Transfers out of Level 3	0	0	0
Ending Balance	40	37	40	37
Fair Value, Asset, Recurring Basis, Still Held, Unrealized Gain (Loss)	$ 0	$ 0	$ 2	$ 0

Fair Value of Financial Assets and Liabilities - Fair Value Inputs Assets Quantitative Information (Details)	9 Months Ended	12 Months Ended
	Sep. 30, 2019 USD ($)	Dec. 31, 2018 USD ($)
Fair Value, Inputs, Level 3 [Member]
Derivatives Fair Value Footnotes [Abstract]
Cash Collateral Posted	$ 304,000,000	$ 76,000,000
Fair Value, Inputs, Level 3 [Member] \| Economic Hedges [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	411,000,000	443,000,000
Fair Value, Inputs, Level 3 [Member] \| Derivative [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	$ (280,000,000)	$ (249,000,000)
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	11	12
Forward gas price assets	1.36	0.78
Forward heat rate	900.00%	1000.00%
Derivative Asset (Liability) Net, Measurement Input	0.04	0.04
Fair Value Inputs Renewable Factor	87.00%	86.00%
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	167	174
Forward gas price assets	10.82	12.38
Forward heat rate	1000.00%	1100.00%
Derivative Asset (Liability) Net, Measurement Input	0.07	0.08
Fair Value Inputs Renewable Factor	119.00%	120.00%
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	0.09	0.10
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	2.00	2.77
Fair Value, Inputs, Level 3 [Member] \| Proprietary Trading [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	$ 67,000,000	$ 56,000,000
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	17	14
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	167	174
Exelon Generation Co L L C [Member]
Derivatives Fair Value Footnotes [Abstract]
Cash Collateral Posted	$ 18,000,000
Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 3 [Member]
Derivatives Fair Value Footnotes [Abstract]
Cash Collateral Posted	304,000,000	$ 76,000,000
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	$ 411,000,000	$ 443,000,000
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	11	12
Forward gas price assets	1.36	0.78
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	167	174
Forward gas price assets	10.82	12.38
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	0.09	0.10
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	2	2.77
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	$ 67,000,000	$ 56,000,000
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	17	14
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	167	174
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	$ (280,000,000)	$ (249,000,000)
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]
Forward heat rate	900.00%	1000.00%
Derivative Asset (Liability) Net, Measurement Input	0.04	0.04
Fair Value Inputs Renewable Factor	87.00%	86.00%
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]
Forward heat rate	1000.00%	1100.00%
Derivative Asset (Liability) Net, Measurement Input	0.07	0.08
Fair Value Inputs Renewable Factor	119.00%	120.00%

Derivative Financial Instruments - Summary of Derivative Fair Value Balances (Details) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Derivative [Line Items]
Mark-to-market derivatives assets	$ 601	$ 804
Derivative Asset, Noncurrent	487	452
Derivative Liability, Current	(239)	(475)
Derivative Liability, Noncurrent	(416)	(479)
Commodity Contract [Member]
Derivative [Line Items]
Mark-to-market derivatives assets	602	801
Derivative Asset, Noncurrent	483	445
Total mark-to-market derivative assets	1,085	1,246
Derivative Liability, Current	(224)	(473)
Derivative Liability, Noncurrent	(394)	(474)
Total mark-to-market derivative liabilities	(618)	(947)
Total mark-to-market derivative net assets (liabilities)	467	299
Exelon Generation Co L L C [Member]
Derivative [Line Items]
Mark-to-market derivatives assets	602	804
Derivative Asset, Noncurrent	483	452
Derivative Liability, Current	(212)	(449)
Derivative Liability, Noncurrent	(163)	(252)
Exelon Generation Co L L C [Member] \| Commodity Contract [Member]
Derivative [Line Items]
Mark-to-market derivatives assets	602	801
Derivative Asset, Noncurrent	483	445
Total mark-to-market derivative assets	1,085	1,246
Derivative Liability, Current	(197)	(447)
Derivative Liability, Noncurrent	(141)	(251)
Total mark-to-market derivative liabilities	(338)	(698)
Total mark-to-market derivative net assets (liabilities)	747	548
Commonwealth Edison Co [Member]
Derivative [Line Items]
Derivative Liability, Current	(27)	(26)
Derivative Liability, Noncurrent	(253)	(223)
Collateral [Member] \| Exelon Generation Co L L C [Member] \| Commodity Contract [Member]
Derivative [Line Items]
Mark-to-market derivatives assets	212	121
Derivative Asset, Noncurrent	104	51
Total mark-to-market derivative assets	316	172
Derivative Liability, Current	249	125
Derivative Liability, Noncurrent	156	60
Total mark-to-market derivative liabilities	405	185
Total mark-to-market derivative net assets (liabilities)	721	357
Netting [Member] \| Exelon Generation Co L L C [Member] \| Commodity Contract [Member]
Derivative [Line Items]
Mark-to-market derivatives assets	(2,205)	(2,930)
Derivative Asset, Noncurrent	(1,074)	(913)
Total mark-to-market derivative assets	(3,279)	(3,843)
Derivative Liability, Current	2,205	2,931
Derivative Liability, Noncurrent	1,074	912
Total mark-to-market derivative liabilities	3,279	3,843
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 derivatives assets	2,452	3,505
Derivative Asset, Noncurrent	1,386	1,266
Total mark-to-market derivative assets	3,838	4,771
Derivative Liability, Current	(2,550)	(3,429)
Derivative Liability, Noncurrent	(1,324)	(1,203)
Total mark-to-market derivative liabilities	(3,874)	(4,632)
Total mark-to-market derivative net assets (liabilities)	(36)	139
Not Designated as Hedging Instrument, Economic Hedge [Member] \| Commonwealth Edison Co [Member] \| Commodity Contract [Member]
Derivative [Line Items]
Mark-to-market derivatives assets	0	0
Derivative Asset, Noncurrent	0	0
Total mark-to-market derivative assets	0	0
Derivative Liability, Current	(27)	(26)
Derivative Liability, Noncurrent	(253)	(223)
Total mark-to-market derivative liabilities	(280)	(249)
Total mark-to-market derivative net assets (liabilities)	(280)	(249)
Not Designated as Hedging Instrument [Member] \| Exelon Generation Co L L C [Member] \| Commodity Contract [Member]
Derivative [Line Items]
Mark-to-market derivatives assets	143	105
Derivative Asset, Noncurrent	67	41
Total mark-to-market derivative assets	210	146
Derivative Liability, Current	(101)	(74)
Derivative Liability, Noncurrent	(47)	(20)
Total mark-to-market derivative liabilities	(148)	(94)
Total mark-to-market derivative net assets (liabilities)	62	52
Designated as Hedging Instrument [Member] \| Exelon Generation Co L L C [Member] \| Other Current Assets [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Amount Offset Against Collateral	$ 306	$ (94)

Derivative Financial Instruments - Summary of Economic Hedges (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives			$ (96)	$ (67)
Exelon Generation Co L L C [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives			(102)	(73)
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	$ 31	$ 74	(62)	(103)
Not Designated as Hedging Instrument, Economic Hedge [Member] \| Commodity Contract [Member] \| Operating Revenue [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	76	8	65	(99)
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	$ (45)	$ 66	$ (127)	$ (4)

Derivative Financial Instruments - Summary of Credit Risk Exposure (Details) - Exelon Generation Co L L C [Member] $ in Millions	Sep. 30, 2019 USD ($)
Derivative [Line Items]
Cash Collateral Posted	$ 18
Financial institutions	1
Investor-owned utilities, marketers and power producers	875
Energy Cooperatives And Municipalities	255
Other	35
Letters Of Credit Posted	55
Total Exposure Before Credit Collateral [Member]
Derivative [Line Items]
Investment grade	693
Non-investment grade	74
No external ratings - internally rated - investment grade	297
No external ratings - internally rated - non-investment grade	175
Total	1,239
Credit Collateral [Member]
Derivative [Line Items]
Investment grade	10
Non-investment grade	38
No external ratings - internally rated - investment grade	1
No external ratings - internally rated - non-investment grade	24
Total	73
Net Exposure [Member]
Derivative [Line Items]
Investment grade	683
Non-investment grade	36
No external ratings - internally rated - investment grade	296
No external ratings - internally rated - non-investment grade	151
Total	1,166
Number Of Counterparties Greater Than Ten Percent Of Net Exposure [Member]
Derivative [Line Items]
Investment grade	0
Non-investment grade
No external ratings - internally rated - investment grade
No external ratings - internally rated - non-investment grade
Total	0
Net Exposure Of Counterparties Greater Than Ten Percent Of Net Exposure [Member]
Derivative [Line Items]
Investment grade	0
Non-investment grade
No external ratings - internally rated - investment grade
No external ratings - internally rated - non-investment grade
Total	$ 0

Derivative Financial Instruments - Summary of Credit Risk Related Contingent Features (Details) - Exelon Generation Co L L C [Member] - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Derivative [Line Items]
Aggregate fair value of derivatives with credit-risk-related contingent features	$ (1,249)	$ (1,723)
Offsetting fair value of in-the-money contracts under master netting agreements	947	1,105
Net liability position after contractual right of offset	$ (302)	$ (618)

Derivative Financial Instruments - Narrative (Details) MWh in Millions, $ in Millions	1 Months Ended	9 Months Ended
	Jun. 30, 2012 MWh	Sep. 30, 2019 USD ($)	Dec. 31, 2018 USD ($)
Derivative [Line Items]
Incremental Collateral For Loss Of Investment Grade Credit Rating		$ 1,481	$ 2,104
Exelon Generation Co L L C [Member]
Derivative [Line Items]
Incremental Collateral For Loss Of Investment Grade Credit Rating		1,481	2,104
Commonwealth Edison Co [Member]
Derivative [Line Items]
Long-term Purchase Commitment, Minimum Energy Volume Required \| MWh	1.3
Delmarva Power and Light Company [Member]
Derivative [Line Items]
Incremental Collateral For Loss Of Investment Grade Credit Rating		11
Baltimore Gas and Electric Company [Member]
Derivative [Line Items]
Incremental Collateral For Loss Of Investment Grade Credit Rating		26
PECO Energy Co [Member]
Derivative [Line Items]
Incremental Collateral For Loss Of Investment Grade Credit Rating		$ 28
Minimum [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Expected Generation Hedged In Next Twelve Months		96.00%
Expected Generation Hedged In Year Two		84.00%
Expected generation Hedged In Year Three		54.00%
Maximum [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Expected Generation Hedged In Next Twelve Months		99.00%
Expected Generation Hedged In Year Two		87.00%
Expected generation Hedged In Year Three		57.00%
Commonwealth Edison Co Affiliate [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Net receivable from electric utility		$ 68
PECO Energy Co Affiliate [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Net receivable from affiliated electric and gas utility		30
Baltimore Gas And Electric Company Affiliate [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Net receivable from affiliated electric and gas utility		32
Potomac Electric Power Company [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Net receivable from electric utility		39
Delmarva Power and Light Company [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Net receivable from electric utility		15
Atlantic City Electric Company [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Net receivable from electric utility		8
Not Designated as Hedging Instrument, Economic Hedge [Member] \| Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount		1,371	1,420
Not Designated as Hedging Instrument, Economic Hedge [Member] \| Interest Rate Swap [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Derivative, Notional Amount		571	620
Not Designated as Hedging Instrument, Economic Hedge [Member] \| Foreign Exchange Contract [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Derivative, Notional Amount		$ 257	$ 268

Derivative Financial Instruments Derivative Financial Instruments - Summary of Cash Collateral and Letters of Credit (Details) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Collateral, Right to Reclaim Cash	$ 787	$ 418
Derivative, Collateral, Right to Reclaim Securities	273	367
Derivative, Collateral, Obligation to Return Cash	96	47
Derivative, Collateral, Obligation to Return Securities	58	44
Incremental Collateral For Loss Of Investment Grade Credit Rating	1,481	2,104
Exelon Generation Co L L C [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Collateral, Right to Reclaim Cash	787	418
Derivative, Collateral, Right to Reclaim Securities	273	367
Derivative, Collateral, Obligation to Return Cash	96	47
Derivative, Collateral, Obligation to Return Securities	58	44
Incremental Collateral For Loss Of Investment Grade Credit Rating	$ 1,481	$ 2,104

Debt and Credit Agreements - Narrative (Details) $ in Millions	9 Months Ended
	Sep. 30, 2019 USD ($)
Corporate, Non-Segment [Member]
Debt Instrument [Line Items]
Short-term Bank Loans and Notes Payable	$ 500
Debt Instrument, Interest Rate Terms	LIBOR plus 0.95%
Exelon Generation Co L L C [Member] \| Line of Credit [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 100
DOE Project Financing, 2.82% January 5, 2037 [Member] \| Non Recourse Debt [Member]
Debt Instrument [Line Items]
Long-term Line of Credit	646
Non-Recourse Debt	495
DOE Project Financing, 2.82% January 5, 2037 [Member] \| Exelon Generation Co L L C [Member] \| Non Recourse Debt [Member]
Debt Instrument [Line Items]
Long-term Line of Credit	646
Non-Recourse Debt	495
ExGenRenewablesIVNov2024 [Member] \| Non Recourse Debt [Member]
Debt Instrument [Line Items]
Long-term Line of Credit	850
Non-Recourse Debt	796
ExGenRenewablesIVNov2024 [Member] \| Exelon Generation Co L L C [Member] \| Non Recourse Debt [Member]
Debt Instrument [Line Items]
Long-term Line of Credit	850
Non-Recourse Debt	$ 796

Debt and Credit Agreements - Commercial Paper Borrowings (Details) - Commercial Paper [Member] - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Short-term Debt [Line Items]
Outstanding Commercial Paper	$ 519	$ 89
Average Interest Rate on Commercial Paper Borrowings	2.50%	2.15%
Exelon Generation Co L L C [Member]
Short-term Debt [Line Items]
Outstanding Commercial Paper	$ 0	$ 0
Commonwealth Edison Co [Member]
Short-term Debt [Line Items]
Outstanding Commercial Paper	$ 387	$ 0
Average Interest Rate on Commercial Paper Borrowings	2.51%	2.14%
PECO Energy Co [Member]
Short-term Debt [Line Items]
Outstanding Commercial Paper	$ 0	$ 0
Baltimore Gas and Electric Company [Member]
Short-term Debt [Line Items]
Outstanding Commercial Paper	$ 0	$ 35
Average Interest Rate on Commercial Paper Borrowings	2.49%	2.18%
Pepco Holdings LLC [Member]
Short-term Debt [Line Items]
Outstanding Commercial Paper	$ 132	$ 54
Average Interest Rate on Commercial Paper Borrowings	2.52%	2.15%
Potomac Electric Power Company [Member]
Short-term Debt [Line Items]
Outstanding Commercial Paper	$ 12	$ 40
Average Interest Rate on Commercial Paper Borrowings	2.61%	2.24%
Delmarva Power and Light Company [Member]
Short-term Debt [Line Items]
Outstanding Commercial Paper	$ 57	$ 0
Average Interest Rate on Commercial Paper Borrowings	2.42%	2.07%
Atlantic City Electric Company [Member]
Short-term Debt [Line Items]
Outstanding Commercial Paper	$ 63	$ 14
Average Interest Rate on Commercial Paper Borrowings	2.57%	2.21%

Debt and Credit Agreements - Issuance of Long-Term Debt (Details) $ in Millions	Sep. 30, 2019 USD ($)
Exelon Generation Co L L C [Member] \| EEPF395Aug2020 [Member] \| Notes Payable, Other Payables [Member]
Debt Instrument [Line Items]
Interest Rate	3.95%
Debt Instrument, Face Amount	$ 4
Exelon Generation Co L L C [Member] \| EEPF346May2020 [Member] \| Notes Payable, Other Payables [Member]
Debt Instrument [Line Items]
Interest Rate	3.46%
Debt Instrument, Face Amount	$ 39
Commonwealth Edison Co [Member] \| FMB400Mar2049 [Member] \| First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Interest Rate	4.00%
Debt Instrument, Face Amount	$ 400
PECO Energy Co [Member] \| FRMB300Sep2049 [Member] \| First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Interest Rate	3.00%
Debt Instrument, Face Amount	$ 325
Baltimore Gas and Electric Company [Member] \| SN320Sep2049 [Member] \| Senior Notes [Member]
Debt Instrument [Line Items]
Interest Rate	3.20%
Debt Instrument, Face Amount	$ 400
Potomac Electric Power Company [Member] \| FMB345Jun2029 [Member] \| First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Interest Rate	3.45%
Debt Instrument, Face Amount	$ 150
Potomac Electric Power Company [Member] \| Medco170Sep2022 [Member] \| Tax-exempt Money Market Funds [Member]
Debt Instrument [Line Items]
Interest Rate	1.70%
Debt Instrument, Face Amount	$ 110
Atlantic City Electric Company [Member] \| FMB350May2029 [Member] \| First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Interest Rate	3.50%
Debt Instrument, Face Amount	$ 100
Atlantic City Electric Company [Member] \| FMB414May2049 [Member] \| First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Interest Rate	4.14%
Debt Instrument, Face Amount	$ 50

Income Taxes - Narrative (Details) - USD ($) $ in Millions		3 Months Ended			9 Months Ended
Income Taxes - Narrative (Details) - USD ($) $ in Millions	Jun. 05, 2019	Sep. 30, 2019	Mar. 31, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Income Tax Additional Narrative Information [Line Items]
Unrecognized Tax Benefits, Period Increase (Decrease)			$ (33)
Effective income tax rate		15.60%		14.50%	20.70%	11.60%
Exelon Generation Co L L C [Member]
Income Tax Additional Narrative Information [Line Items]
Effective income tax rate		17.40%		20.10%	28.60%	13.80%
Commonwealth Edison Co [Member]
Income Tax Additional Narrative Information [Line Items]
Unrecognized Tax Benefits, Period Increase (Decrease)			$ (2)
Effective income tax rate		18.40%		21.20%	19.30%	21.10%
PECO Energy Co [Member]
Income Tax Additional Narrative Information [Line Items]
Effective income tax rate		9.10%		(1.60%)	11.10%	(1.50%)
Baltimore Gas and Electric Company [Member]
Income Tax Additional Narrative Information [Line Items]
Effective income tax rate		17.90%		22.20%	18.40%	19.60%
Pepco Holdings LLC [Member]
Income Tax Additional Narrative Information [Line Items]
Effective income tax rate		6.90%		2.10%	5.70%	7.70%
Potomac Electric Power Company [Member]
Income Tax Additional Narrative Information [Line Items]
Effective income tax rate		4.90%		(2.30%)	4.00%	3.90%
Delmarva Power and Light Company [Member]
Income Tax Additional Narrative Information [Line Items]
Effective income tax rate		13.20%		13.20%	12.10%	15.90%
Atlantic City Electric Company [Member]
Income Tax Additional Narrative Information [Line Items]
Effective income tax rate		3.10%		11.60%	2.20%	13.60%
ILLINOIS
Income Tax Additional Narrative Information [Line Items]
Effective income tax rate	10.49%				9.50%

Income Taxes - Reconciliation to Effective Tax Rate (Details)	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
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%	(1.20%)	5.10%	1.70%
Qualified nuclear decommissioning trust fund income	3.20%	2.40%	5.30%	0.90%
Amortization of investment tax credit, including deferred taxes on basis difference	(4.10%)	(0.60%)	(1.90%)	(0.90%)
Plant basis differences	(1.70%)	(2.50%)	(1.60%)	(2.70%)
Production tax credits and other credits	(1.20%)	(1.20%)	(1.00%)	(1.80%)
Noncontrolling interests	(2.20%)	(1.10%)	(1.00%)	(1.10%)
Excess deferred tax amortization	(6.50%)	(6.80%)	(6.00%)	(6.10%)
Tax Cuts and Jobs Act of 2017		1.30%		0.20%
Other	0.70%	3.20%	0.80%	0.40%
Effective income tax rate	15.60%	14.50%	20.70%	11.60%
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	5.20%	(9.00%)	4.20%	(2.60%)
Qualified nuclear decommissioning trust fund income	7.10%	5.80%	11.90%	2.60%
Amortization of investment tax credit, including deferred taxes on basis difference	(8.90%)	(1.10%)	(4.00%)	(2.20%)
Plant basis differences	0.00%	0.00%	0.00%	0.00%
Production tax credits and other credits	(2.70%)	(2.90%)	(2.10%)	(5.10%)
Noncontrolling interests	(4.80%)	(2.80%)	(2.30%)	(3.20%)
Excess deferred tax amortization	0.00%	0.00%	0.00%	0.00%
Tax Cuts and Jobs Act of 2017		3.50%		1.30%
Other	0.50%	5.60%	(0.10%)	2.00%
Effective income tax rate	17.40%	20.10%	28.60%	13.80%
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	8.10%	8.30%	8.20%	8.20%
Qualified nuclear decommissioning trust fund income	0.00%	0.00%	0.00%	0.00%
Amortization of investment tax credit, including deferred taxes on basis difference	(0.20%)	(0.20%)	(0.20%)	(0.20%)
Plant basis differences	(1.00%)	(0.30%)	(0.70%)	(0.10%)
Production tax credits and other credits	0.00%	(0.10%)	0.00%	(0.10%)
Noncontrolling interests	0.00%	0.00%	0.00%	0.00%
Excess deferred tax amortization	(9.90%)	(7.80%)	(9.20%)	(7.60%)
Tax Cuts and Jobs Act of 2017		0.00%		(0.20%)
Other	0.40%	0.30%	0.20%	0.10%
Effective income tax rate	18.40%	21.20%	19.30%	21.10%
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	(0.30%)	(3.60%)	0.00%	(3.60%)
Qualified nuclear decommissioning trust fund income	0.00%	0.00%	0.00%	0.00%
Amortization of investment tax credit, including deferred taxes on basis difference	0.00%	(0.10%)	0.00%	(0.10%)
Plant basis differences	(7.50%)	(15.20%)	(6.80%)	(15.40%)
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	(3.60%)	(4.60%)	(2.90%)	(3.40%)
Tax Cuts and Jobs Act of 2017		0.00%		0.00%
Other	(0.50%)	0.90%	(0.20%)	0.00%
Effective income tax rate	9.10%	(1.60%)	11.10%	(1.50%)
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	6.30%	7.30%	6.40%	6.60%
Qualified nuclear decommissioning trust fund income	0.00%	0.00%	0.00%	0.00%
Amortization of investment tax credit, including deferred taxes on basis difference	(0.10%)	0.00%	(0.10%)	(0.10%)
Plant basis differences	(1.10%)	(0.80%)	(1.10%)	(0.70%)
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	(8.00%)	(7.90%)	(7.90%)	(8.10%)
Tax Cuts and Jobs Act of 2017		0.00%		0.00%
Other	(0.20%)	2.60%	0.10%	0.90%
Effective income tax rate	17.90%	22.20%	18.40%	19.60%
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	4.80%	0.20%	4.80%	2.70%
Qualified nuclear decommissioning trust fund income	0.00%	0.00%	0.00%	0.00%
Amortization of investment tax credit, including deferred taxes on basis difference	(0.20%)	(0.20%)	(0.20%)	(0.20%)
Plant basis differences	(1.80%)	(2.00%)	(1.80%)	(1.90%)
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	(17.70%)	(17.70%)	(18.60%)	(14.50%)
Tax Cuts and Jobs Act of 2017		0.20%		0.30%
Other	0.80%	0.60%	0.50%	0.30%
Effective income tax rate	6.90%	2.10%	5.70%	7.70%
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	1.90%	1.00%	2.00%	2.40%
Qualified nuclear decommissioning trust fund income	0.00%	0.00%	0.00%	0.00%
Amortization of investment tax credit, including deferred taxes on basis difference	(0.10%)	(0.10%)	(0.10%)	(0.10%)
Plant basis differences	(2.60%)	(3.40%)	(2.30%)	(2.90%)
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	(16.30%)	(21.20%)	(17.30%)	(16.50%)
Tax Cuts and Jobs Act of 2017		0.10%		0.00%
Other	1.00%	0.30%	0.70%	0.00%
Effective income tax rate	4.90%	(2.30%)	4.00%	3.90%
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	6.60%	6.60%	6.70%	6.50%
Qualified nuclear decommissioning trust fund income	0.00%	0.00%	0.00%	0.00%
Amortization of investment tax credit, including deferred taxes on basis difference	(0.20%)	(0.30%)	(0.20%)	(0.30%)
Plant basis differences	(0.60%)	(0.70%)	(0.60%)	(0.70%)
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	(13.50%)	(14.00%)	(15.00%)	(11.00%)
Tax Cuts and Jobs Act of 2017		0.00%		0.00%
Other	(0.10%)	0.60%	0.20%	0.40%
Effective income tax rate	13.20%	13.20%	12.10%	15.90%
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	6.90%	7.30%	6.90%	7.30%
Qualified nuclear decommissioning trust fund income	0.00%	0.00%	0.00%	0.00%
Amortization of investment tax credit, including deferred taxes on basis difference	(0.30%)	(0.30%)	(0.30%)	(0.30%)
Plant basis differences	(1.90%)	(1.30%)	(2.00%)	(1.30%)
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	(23.30%)	(15.40%)	(23.40%)	(14.00%)
Tax Cuts and Jobs Act of 2017		0.00%		0.00%
Other	0.70%	0.30%	0.00%	0.90%
Effective income tax rate	3.10%	11.60%	2.20%	13.60%

Income Taxes - Accounting for Uncertainty in Income Taxes (Details) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Income Tax Contingency [Line Items]
Unrecognized Tax Benefits	$ 448	$ 477
Exelon Generation Co L L C [Member]
Income Tax Contingency [Line Items]
Unrecognized Tax Benefits	411	408
Commonwealth Edison Co [Member]
Income Tax Contingency [Line Items]
Unrecognized Tax Benefits	0	2
Pepco Holdings LLC [Member]
Income Tax Contingency [Line Items]
Unrecognized Tax Benefits	45	45
Atlantic City Electric Company [Member]
Income Tax Contingency [Line Items]
Unrecognized Tax Benefits	$ 14	$ 14

Income Taxes Income Taxes - Reasonably possible the total amount of unrecognized tax benefits could significantly increase or decrease within 12 months after the reporting date (Details) $ in Millions	Sep. 30, 2019 USD ($)
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Decrease in Unrecognized Tax Benefits is Reasonably Possible	$ 425
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	411
Exelon Generation Co L L C [Member]
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Decrease in Unrecognized Tax Benefits is Reasonably Possible	411
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	411
Pepco Holdings LLC [Member]
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Decrease in Unrecognized Tax Benefits is Reasonably Possible	14
Atlantic City Electric Company [Member]
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Decrease in Unrecognized Tax Benefits is Reasonably Possible	$ 14

Income Taxes Income Taxes - Other Income Tax Matters (Details) - State and Local Jurisdiction [Member]	3 Months Ended
	Sep. 30, 2019 USD ($)
Schedule of Components of Income Tax Expense (Benefit) [Line Items]
Increase (Decrease) in Deferred Income Taxes	$ 23
Increase (Decrease) in Income Taxes	23
Exelon Generation Co L L C [Member]
Schedule of Components of Income Tax Expense (Benefit) [Line Items]
Increase (Decrease) in Deferred Income Taxes	9
Increase (Decrease) in Income Taxes	$ 9

Nuclear Decommissioning - Narrative (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Mar. 31, 2019	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2018
Nuclear Decommissioning Additional Narrative Information [Line Items]
Asset Retirement Obligation, Period Increase (Decrease)	$ 280		$ (235)
Asset Retirement Obligation, Revision of Estimate	(300)	$ 330		$ 20
Decommissioning Fund Investments	12,706		12,706		$ 11,661
Assets held for sale	18		18		904
Exelon Generation Co L L C [Member]
Nuclear Decommissioning Additional Narrative Information [Line Items]
Asset Retirement Obligation, Period Increase (Decrease)	280		(235)
Asset Retirement Obligation, Revision of Estimate	(300)	330		0
Decommissioning Fund Investments	12,706		12,706		11,661
Assets held for sale	18		18		904
Potomac Electric Power Company [Member]
Nuclear Decommissioning Additional Narrative Information [Line Items]
Asset Retirement Obligation, Revision of Estimate				$ 22
Nuclear Decommissioning [Member]
Nuclear Decommissioning Additional Narrative Information [Line Items]
Asset Retirement Obligation, Revision of Estimate			211
Nuclear Decommissioning [Member] \| Exelon Generation Co L L C [Member]
Nuclear Decommissioning Additional Narrative Information [Line Items]
Asset Retirement Obligation, Revision of Estimate			211
Three Mile Island [Member]
Nuclear Decommissioning Additional Narrative Information [Line Items]
Asset Retirement Obligation, Period Increase (Decrease)		(110)
Three Mile Island [Member] \| Exelon Generation Co L L C [Member]
Nuclear Decommissioning Additional Narrative Information [Line Items]
Asset Retirement Obligation, Period Increase (Decrease)		(110)
Assets, Total [Member]
Nuclear Decommissioning Additional Narrative Information [Line Items]
Decommissioning Fund Investments	12,862		12,862		12,695
Assets, Total [Member] \| Exelon Generation Co L L C [Member]
Nuclear Decommissioning Additional Narrative Information [Line Items]
Decommissioning Fund Investments	12,862		12,862		12,695
Nuclear Decommissioning Trust Fund Investments [Member] \| Oyster Creek [Member]
Nuclear Decommissioning Additional Narrative Information [Line Items]
Assets held for sale					890
Nuclear Decommissioning Trust Fund Investments [Member] \| Oyster Creek [Member] \| Exelon Generation Co L L C [Member]
Nuclear Decommissioning Additional Narrative Information [Line Items]
Assets held for sale					890
Other Current Assets [Member]
Nuclear Decommissioning Additional Narrative Information [Line Items]
Decommissioning Fund Investments	156		156		144
Other Current Assets [Member] \| Exelon Generation Co L L C [Member]
Nuclear Decommissioning Additional Narrative Information [Line Items]
Decommissioning Fund Investments	156		$ 156		$ 144
Operating Expense [Member]
Nuclear Decommissioning Additional Narrative Information [Line Items]
Asset Retirement Obligation, Revision of Estimate	(65)
Operating Expense [Member] \| Exelon Generation Co L L C [Member]
Nuclear Decommissioning Additional Narrative Information [Line Items]
Asset Retirement Obligation, Revision of Estimate	$ (65)
Operating Expense [Member] \| Three Mile Island [Member]
Nuclear Decommissioning Additional Narrative Information [Line Items]
Asset Retirement Obligation, Revision of Estimate		(85)
Operating Expense [Member] \| Three Mile Island [Member] \| Exelon Generation Co L L C [Member]
Nuclear Decommissioning Additional Narrative Information [Line Items]
Asset Retirement Obligation, Revision of Estimate		$ (85)

Nuclear Decommissioning - Rollforward of Nuclear Decommissioning ARO (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Mar. 31, 2019	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2018
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Accretion expense			$ 371	$ 367
Asset Retirement Obligation, Revision of Estimate	$ (300)	$ 330		20
Liabilities held for sale	11		11		$ 777
Nuclear Decommissioning [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Nuclear decommissioning ARO, beginning balance		10,005	10,005
Asset Retirement Obligation, Liabilities Settled			(755)
Accretion expense			361
Asset Retirement Obligation, Revision of Estimate			211
Costs incurred related to decommissioning plants			(52)
Nuclear decommissioning ARO, ending balance	9,770		9,770
Current portion of ARO	127		127		22
Exelon Generation Co L L C [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Accretion expense			371	365
Asset Retirement Obligation, Revision of Estimate	(300)	330		$ 0
Liabilities held for sale	11		11		777
Exelon Generation Co L L C [Member] \| Nuclear Decommissioning [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Nuclear decommissioning ARO, beginning balance		10,005	10,005
Asset Retirement Obligation, Liabilities Settled			(755)
Accretion expense			361
Asset Retirement Obligation, Revision of Estimate			211
Costs incurred related to decommissioning plants			(52)
Nuclear decommissioning ARO, ending balance	9,770		9,770
Current portion of ARO	127		$ 127		22
Nuclear Decommissioning Asset Retirement Obligation [Member] \| Oyster Creek [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Liabilities held for sale					772
Nuclear Decommissioning Asset Retirement Obligation [Member] \| Exelon Generation Co L L C [Member] \| Oyster Creek [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Liabilities held for sale					$ 772
Operating Expense [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset Retirement Obligation, Revision of Estimate	(65)
Operating Expense [Member] \| Three Mile Island [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset Retirement Obligation, Revision of Estimate		(85)
Operating Expense [Member] \| Exelon Generation Co L L C [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset Retirement Obligation, Revision of Estimate	$ (65)
Operating Expense [Member] \| Exelon Generation Co L L C [Member] \| Three Mile Island [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset Retirement Obligation, Revision of Estimate		$ (85)

Retirement Benefits - Narrative (Details) $ in Millions	3 Months Ended	9 Months Ended
Retirement Benefits - Narrative (Details) $ in Millions	Sep. 30, 2019 USD ($)	Sep. 30, 2019 USD ($)
Defined Benefit Plan Disclosure [Line Items]
Increase (Decrease) in Obligation, Pension Benefits	$ 75
Increase (Decrease) in Obligation, Other Postretirement Benefits	36
Accumulated Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss), after Tax	(39)	$ (39)
Defined Benefit Plan Amounts Recognized In Regulatory Assets Before Tax	53
Defined Benefit Plan Amounts Recognized In Regulatory Liabilities Before Tax	$ (5)
Pension Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected return on assets		7.00%
Discount rate		4.31%
Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected return on assets		6.67%
Discount rate		4.30%

Retirement Benefits - Calculation of Net Periodic Benefit Cost (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Amortization of:
Net periodic benefit cost	$ 2	$ 12	$ (8)	$ 33
Pension Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	89	100	267	303
Interest cost	221	201	663	602
Expected return on assets	(306)	(312)	(918)	(939)
Amortization of:
Prior service cost (benefit)	0	0	0	1
Actuarial loss	104	158	310	472
Settlement charges	7	0	7	1
Contractual Termination Benefits	1	0	1	0
Net periodic benefit cost	116	147	330	440
Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	23	28	70	84
Interest cost	47	43	141	131
Expected return on assets	(38)	(43)	(115)	(130)
Amortization of:
Prior service cost (benefit)	(45)	(47)	(134)	(140)
Actuarial loss	11	18	34	50
Settlement charges	0	0	0	0
Contractual Termination Benefits	0	0	0	0
Net periodic benefit cost	$ (2)	$ (1)	$ (4)	$ (5)

Retirement Benefits - Defined Contribution Savings Plans (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Defined Benefit Plan Disclosure [Line Items]
Savings Plan Matching Contributions	$ 36	$ 44	$ 101	$ 126
Exelon Generation Co L L C [Member]
Defined Benefit Plan Disclosure [Line Items]
Savings Plan Matching Contributions	14	23	41	65
Commonwealth Edison Co [Member]
Defined Benefit Plan Disclosure [Line Items]
Savings Plan Matching Contributions	9	8	26	23
PECO Energy Co [Member]
Defined Benefit Plan Disclosure [Line Items]
Savings Plan Matching Contributions	2	2	7	7
Baltimore Gas and Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Savings Plan Matching Contributions	4	2	9	5
Pepco Holdings LLC [Member]
Defined Benefit Plan Disclosure [Line Items]
Savings Plan Matching Contributions	4	4	8	10
Potomac Electric Power Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Savings Plan Matching Contributions	1	1	2	2
Delmarva Power and Light Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Savings Plan Matching Contributions	1	1	2	2
Atlantic City Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Savings Plan Matching Contributions	$ 1	$ 1	$ 1	$ 2

Changes in Accumulated Other Comprehensive Income - Schedule of Changes in AOCI (Details) - USD ($) $ in Millions	3 Months Ended						9 Months Ended
	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Sep. 30, 2019	Sep. 30, 2018
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	$ 33,907	$ 33,704	$ 33,070	$ 32,839	$ 32,565	$ 32,187	$ 33,070	$ 32,187
Beginning Balance			30,764				30,764
Other comprehensive income	30			52			33	169
Ending balance	34,352	33,907	33,704	33,388	32,839	32,565	34,352	33,388
Ending Balance	32,023						32,023
Gains (Losses) on Cash Flow Hedges
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	(2)		(2)	(2)		(14)	(2)	(14)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	0			0			0	11
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	0			0			0	1
Other comprehensive income	0			0			0	12
Ending balance	(2)	(2)		(2)	(2)		(2)	(2)
Gains (Losses) on Cash Flow Hedges \| Accounting Standards Update 2016-01 [Member]
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard(c)								0
Unrealized Gains (Losses) on Marketable Securities
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance						10		10
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax								0
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax								0
Other comprehensive income								0
Ending balance				0				0
Unrealized Gains (Losses) on Marketable Securities \| Accounting Standards Update 2016-01 [Member]
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard(c)								(10)
Pension and Non-Pension Postretirement Benefit Plan Items
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	(2,957)		(2,960)	(2,890)		(2,998)	(2,960)	(2,998)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	6			5			(32)	22
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	21			45			62	136
Other comprehensive income	27			50			30	158
Ending balance	(2,930)	(2,957)		(2,840)	(2,890)		(2,930)	(2,840)
Pension and Non-Pension Postretirement Benefit Plan Items \| Accounting Standards Update 2016-01 [Member]
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard(c)								0
Foreign Currency Items
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	(29)		(33)	(29)		(23)	(33)	(23)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	(2)			2			2	(4)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	0			0			0	0
Other comprehensive income	(2)			2			2	(4)
Ending balance	(31)	(29)		(27)	(29)		(31)	(27)
Foreign Currency Items \| Accounting Standards Update 2016-01 [Member]
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard(c)								0
AOCI of Investments in Unconsolidated Affiliates
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	(2)		0	0		(1)	0	(1)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	0			0			(2)	1
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	2			0			2	0
Other comprehensive income	2			0			0	1
Ending balance	0	(2)		0	0		0	0
AOCI of Investments in Unconsolidated Affiliates \| Accounting Standards Update 2016-01 [Member]
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard(c)								0
Total
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	(2,990)	(3,012)	(2,995)	(2,921)	(2,965)	(3,026)	(2,995)	(3,026)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	4			7			(32)	30
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	23			45			64	137
Other comprehensive income	27	22	(17)	52	44	71	32	167
Ending balance	$ (2,963)	$ (2,990)	$ (3,012)	$ (2,869)	$ (2,921)	$ (2,965)	$ (2,963)	(2,869)
Total \| Accounting Standards Update 2016-01 [Member]
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard(c)								$ (10)

Changes in Accumulated Other Comprehensive Income - Components of Other Comprehensive Income (Loss) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Prior service costs
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), Tax	$ 6	$ 6	$ 18	$ 18
Actuarial losses
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), Tax	(13)	(21)	(39)	(65)
Pension and Non-Pension Postretirement Benefit Plan Items
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), Tax	$ 0	$ (2)	$ 14	$ (8)

Commitments and Contingencies - Narrative (Details) $ in Millions		9 Months Ended	12 Months Ended
	Mar. 23, 2016 USD ($) MW	Sep. 30, 2019 USD ($) MGPSite Open_claim MW	Dec. 31, 2022 MW	Dec. 31, 2018 USD ($) MW	Dec. 31, 2017 MW
Commitments And Contingencies Additional Narrative Information [Line Items]
Other Commitment		$ 3,113
Accrual for Environmental Loss Contingencies, Gross		507		$ 496
Exelon Generation Co L L C [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Other Commitment		2,476
Accrual for Environmental Loss Contingencies, Gross		107		108
Liability for Asbestos and Environmental Claims, Gross		83		79
Commonwealth Edison Co [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Other Commitment		$ 257
Mgp Site Contingency Monitoring Count \| MGPSite		21
Accrual for Environmental Loss Contingencies, Gross		$ 328		329
PECO Energy Co [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Other Commitment		$ 187
Mgp Site Contingency Monitoring Count \| MGPSite		8
Accrual for Environmental Loss Contingencies, Gross		$ 20		27
Baltimore Gas and Electric Company [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Other Commitment		$ 25
Mgp Site Contingency Monitoring Count \| MGPSite		4
Accrual for Environmental Loss Contingencies, Gross		$ 3		5
Pepco Holdings LLC [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Other Commitment		61
Accrual for Environmental Loss Contingencies, Gross		49		27
Potomac Electric Power Company [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Other Commitment		36
Accrual for Environmental Loss Contingencies, Gross		47		25
Delmarva Power and Light Company [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Other Commitment		$ 16
Mgp Site Contingency 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		$ 25
Open Asbestos Related Personal Injury Claims \| Open_claim		257
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		$ 58
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]
Commitments And Contingencies Additional Narrative Information [Line Items]
Accrual for Environmental Loss Contingencies, Gross		280
West Lake [Member] \| Exelon Generation Co L L C [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Accrual for Environmental Loss Contingencies, Gross		20
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	$ 127	$ 107
Other Non-Financial Commitment \| MW		27
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		$ 107
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
Subsequent Event [Member] \| Wind Assets [Member] \| Pepco Holdings Inc [Member] \| Delmarva Power and Light Company [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Purchase Commitment \| MW			40

Commitments and Contingencies - Merger Commitment (Details) $ in Millions	Sep. 30, 2019 USD ($)
Other Commitments [Line Items]
Other Commitment	$ 3,113
Pepco Holdings LLC [Member]
Other Commitments [Line Items]
Other Commitment	61
Potomac Electric Power Company [Member]
Other Commitments [Line Items]
Other Commitment	36
Delmarva Power and Light Company [Member]
Other Commitments [Line Items]
Other Commitment	16
Atlantic City Electric Company [Member]
Other Commitments [Line Items]
Other Commitment	10
Pepco Holdings Inc [Member]
Other Commitments [Line Items]
Other Commitment	513
Pepco Holdings Inc [Member] \| Remaining commitment
Other Commitments [Line Items]
Other Commitment	112
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	82
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	67
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	9
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	$ 6

Supplemental Financial Information - Utility Taxes (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Supplemental Statement of Operations Information [Line Items]
Utility taxes	$ 241	$ 253	$ 672	$ 705
Property	148	145	444	416
Payroll	57	58	185	191
Exelon Generation Co L L C [Member]
Supplemental Statement of Operations Information [Line Items]
Utility taxes	29	32	87	92
Property	66	70	205	204
Payroll	28	31	92	99
Commonwealth Edison Co [Member]
Supplemental Statement of Operations Information [Line Items]
Utility taxes	66	67	183	188
Property	7	7	22	22
Payroll	7	6	21	20
PECO Energy Co [Member]
Supplemental Statement of Operations Information [Line Items]
Utility taxes	38	39	102	102
Property	5	4	12	12
Payroll	3	3	11	11
Baltimore Gas and Electric Company [Member]
Supplemental Statement of Operations Information [Line Items]
Utility taxes	21	23	68	70
Property	39	37	114	106
Payroll	4	4	13	12
Pepco Holdings LLC [Member]
Supplemental Statement of Operations Information [Line Items]
Utility taxes	86	92	231	253
Property	31	26	91	71
Payroll	6	5	20	19
Potomac Electric Power Company [Member]
Supplemental Statement of Operations Information [Line Items]
Utility taxes	81	87	217	238
Property	21	16	64	45
Payroll	2	1	5	5
Delmarva Power and Light Company [Member]
Supplemental Statement of Operations Information [Line Items]
Utility taxes	5	5	14	15
Property	9	9	25	24
Payroll	1	1	3	3
Atlantic City Electric Company [Member]
Supplemental Statement of Operations Information [Line Items]
Utility taxes	0	0	0	0
Property	0	0	2	2
Payroll	$ 1	$ 1	$ 2	$ 2

Supplemental Financial Information - Operations (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Decommissioning-Related Activities [Abstract]
Net realized income on NDT funds - Regulatory agreement units	$ 67	$ 214	$ 197	$ 476
Net realized income on NDT funds - Non-regulatory agreement units	33	58	316	257
Net unrealized (losses) gains on NDT funds - Regulatory agreement units	89	(66)	565	(335)
Net unrealized (losses) gains on NDT funds - Non-regulatory agreement units	55	72	236	(143)
Regulatory offset to NDT fund-related activities	(125)	(110)	(611)	(110)
Decommissioning-related activities	119	168	703	145
AFUDC - Equity	22	16	64	47
Non-service net periodic benefit cost	(2)	(12)	8	(33)
Exelon Generation Co L L C [Member]
Decommissioning-Related Activities [Abstract]
Net realized income on NDT funds - Regulatory agreement units	67	214	197	476
Net realized income on NDT funds - Non-regulatory agreement units	33	58	316	257
Net unrealized (losses) gains on NDT funds - Regulatory agreement units	89	(66)	565	(335)
Net unrealized (losses) gains on NDT funds - Non-regulatory agreement units	55	72	236	(143)
Regulatory offset to NDT fund-related activities	(125)	(110)	(611)	(110)
Decommissioning-related activities	119	168	703	145
AFUDC - Equity	0	0	0	0
Commonwealth Edison Co [Member]
Decommissioning-Related Activities [Abstract]
AFUDC - Equity	4	4	13	12
PECO Energy Co [Member]
Decommissioning-Related Activities [Abstract]
AFUDC - Equity	3	1	9	3
Baltimore Gas and Electric Company [Member]
Decommissioning-Related Activities [Abstract]
AFUDC - Equity	6	5	16	13
Pepco Holdings LLC [Member]
Decommissioning-Related Activities [Abstract]
AFUDC - Equity	9	6	26	19
Potomac Electric Power Company [Member]
Decommissioning-Related Activities [Abstract]
AFUDC - Equity	7	6	18	17
Delmarva Power and Light Company [Member]
Decommissioning-Related Activities [Abstract]
AFUDC - Equity	1	0	3	2
Atlantic City Electric Company [Member]
Decommissioning-Related Activities [Abstract]
AFUDC - Equity	$ 1	$ 0	$ 4	$ 0

Supplemental Financial Information - Cash Flow (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Mar. 31, 2019	Sep. 30, 2019	Sep. 30, 2018
Depreciation, Amortization and Accretion [Abstract]
Property, plant and equipment			$ 2,803	$ 2,829
Amortization of regulatory assets			390	412
Amortization of intangible assets, net			44	43
Amortization of energy contract assets and liabilities			14	8
Nuclear fuel			771	852
ARO accretion			371	367
Total depreciation, amortization and accretion			4,393	4,511
Other Non-Cash Operating Activities [Abstract]
Pension and non-pension postretirement benefit costs			324	435
Provision for uncollectible accounts			89	133
Other decommissioning-related activity			(400)	(39)
Energy-related options			21	4
Amortization of rate stabilization deferral			(8)	0
Discrete impacts from EIMA and FEJA			80	27
Long-term incentive plan			33	84
Amortization of operating ROU asset			193
Change in environmental liabilities			23
Asset retirement costs	$ (300)	$ 330		20
Exelon Generation Co L L C [Member]
Depreciation, Amortization and Accretion [Abstract]
Property, plant and equipment			1,184	1,347
Amortization of regulatory assets			0	0
Amortization of intangible assets, net			37	36
Amortization of energy contract assets and liabilities			14	8
Nuclear fuel			771	852
ARO accretion			371	365
Total depreciation, amortization and accretion			2,377	2,608
Other Non-Cash Operating Activities [Abstract]
Pension and non-pension postretirement benefit costs			98	151
Provision for uncollectible accounts			20	38
Other decommissioning-related activity			(400)	(39)
Energy-related options			21	4
Amortization of rate stabilization deferral			0	0
Amortization of operating ROU asset			138
Change in environmental liabilities			0
Asset retirement costs	$ (300)	$ 330		0
Commonwealth Edison Co [Member]
Depreciation, Amortization and Accretion [Abstract]
Property, plant and equipment			661	613
Amortization of regulatory assets			106	83
Amortization of intangible assets, net			0	0
ARO accretion			0	0
Total depreciation, amortization and accretion			767	696
Other Non-Cash Operating Activities [Abstract]
Pension and non-pension postretirement benefit costs			70	133
Provision for uncollectible accounts			26	30
Amortization of rate stabilization deferral			0	0
Discrete impacts from EIMA and FEJA			80	27
Amortization of operating ROU asset			2
Change in environmental liabilities			0
Asset retirement costs				0
PECO Energy Co [Member]
Depreciation, Amortization and Accretion [Abstract]
Property, plant and equipment			225	204
Amortization of regulatory assets			22	20
Amortization of intangible assets, net			0	0
ARO accretion			0	0
Total depreciation, amortization and accretion			247	224
Other Non-Cash Operating Activities [Abstract]
Pension and non-pension postretirement benefit costs			9	14
Provision for uncollectible accounts			22	25
Amortization of rate stabilization deferral			0	0
Amortization of operating ROU asset			0
Change in environmental liabilities			0
Asset retirement costs				0
Baltimore Gas and Electric Company [Member]
Depreciation, Amortization and Accretion [Abstract]
Property, plant and equipment			263	249
Amortization of regulatory assets			105	109
Amortization of intangible assets, net			0	0
ARO accretion			0	0
Total depreciation, amortization and accretion			368	358
Other Non-Cash Operating Activities [Abstract]
Pension and non-pension postretirement benefit costs			45	43
Provision for uncollectible accounts			5	6
Amortization of rate stabilization deferral			0	0
Amortization of operating ROU asset			23
Change in environmental liabilities			0
Asset retirement costs				0
Pepco Holdings LLC [Member]
Depreciation, Amortization and Accretion [Abstract]
Property, plant and equipment			405	355
Amortization of regulatory assets			157	200
Amortization of intangible assets, net			0	0
ARO accretion			0	0
Total depreciation, amortization and accretion			562	555
Other Non-Cash Operating Activities [Abstract]
Pension and non-pension postretirement benefit costs			71	51
Provision for uncollectible accounts			16	32
Amortization of rate stabilization deferral			(8)	0
Amortization of operating ROU asset			26
Change in environmental liabilities			23
Asset retirement costs				20
Potomac Electric Power Company [Member]
Depreciation, Amortization and Accretion [Abstract]
Property, plant and equipment			178	161
Amortization of regulatory assets			103	125
Amortization of intangible assets, net			0	0
ARO accretion			0	0
Total depreciation, amortization and accretion			281	286
Other Non-Cash Operating Activities [Abstract]
Pension and non-pension postretirement benefit costs			19	10
Provision for uncollectible accounts			7	12
Amortization of rate stabilization deferral			(9)	0
Amortization of operating ROU asset			6
Change in environmental liabilities			23
Asset retirement costs				22
Delmarva Power and Light Company [Member]
Depreciation, Amortization and Accretion [Abstract]
Property, plant and equipment			109	97
Amortization of regulatory assets			29	38
Amortization of intangible assets, net			0	0
ARO accretion			0	0
Total depreciation, amortization and accretion			138	135
Other Non-Cash Operating Activities [Abstract]
Pension and non-pension postretirement benefit costs			11	5
Provision for uncollectible accounts			2	6
Amortization of rate stabilization deferral			1	0
Amortization of operating ROU asset			7
Change in environmental liabilities			0
Asset retirement costs				(1)
Atlantic City Electric Company [Member]
Depreciation, Amortization and Accretion [Abstract]
Property, plant and equipment			89	70
Amortization of regulatory assets			25	37
Amortization of intangible assets, net			0	0
ARO accretion			0	0
Total depreciation, amortization and accretion			114	107
Other Non-Cash Operating Activities [Abstract]
Pension and non-pension postretirement benefit costs			12	10
Provision for uncollectible accounts			6	14
Amortization of rate stabilization deferral			0	0
Amortization of operating ROU asset			4
Change in environmental liabilities			$ 0
Asset retirement costs				$ (1)

Supplemental Financial Information - Balance Sheet (Details) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018	Sep. 30, 2018	Dec. 31, 2017
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]
Cash and cash equivalents	$ 1,683	$ 1,349	$ 1,918	$ 898
Restricted cash	309	247	240	207
Restricted cash included in other long-term assets	186	185	163	85
Total cash, cash equivalents and restricted cash	2,178	1,781	2,321	1,190
Receivables [Abstract]
Unbilled customer revenues	1,256	1,656
Accrued Expenses [Abstract]
Compensation-related accruals	880	1,191
Taxes accrued	431	412
Interest accrued	421	334
Exelon Generation Co L L C [Member]
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]
Cash and cash equivalents	1,019	750	1,187	416
Restricted cash	126	153	152	138
Restricted cash included in other long-term assets	0	0	0	0
Total cash, cash equivalents and restricted cash	1,145	903	1,339	554
Receivables [Abstract]
Unbilled customer revenues	676	965
Accrued Expenses [Abstract]
Compensation-related accruals	336	479
Taxes accrued	247	226
Interest accrued	106	77
Commonwealth Edison Co [Member]
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]
Cash and cash equivalents	76	135	124	76
Restricted cash	124	29	12	5
Restricted cash included in other long-term assets	171	166	144	63
Total cash, cash equivalents and restricted cash	371	330	280	144
Receivables [Abstract]
Unbilled customer revenues	212	223
Accrued Expenses [Abstract]
Compensation-related accruals	133	187
Taxes accrued	56	71
Interest accrued	62	105
PECO Energy Co [Member]
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]
Cash and cash equivalents	224	130	102	271
Restricted cash	6	5	5	4
Restricted cash included in other long-term assets	0	0	0	0
Total cash, cash equivalents and restricted cash	230	135	107	275
Receivables [Abstract]
Unbilled customer revenues	102	114
Accrued Expenses [Abstract]
Compensation-related accruals	48	49
Taxes accrued	13	28
Interest accrued	33	33
Baltimore Gas and Electric Company [Member]
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]
Cash and cash equivalents	130	7	113	17
Restricted cash	1	6	3	1
Restricted cash included in other long-term assets	0	0	0	0
Total cash, cash equivalents and restricted cash	131	13	116	18
Receivables [Abstract]
Unbilled customer revenues	103	168
Accrued Expenses [Abstract]
Compensation-related accruals	63	68
Taxes accrued	64	46
Interest accrued	36	39
Pepco Holdings LLC [Member]
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]
Cash and cash equivalents	99	124	153	30
Restricted cash	38	43	42	42
Restricted cash included in other long-term assets	15	19	19	23
Total cash, cash equivalents and restricted cash	152	186	214	95
Receivables [Abstract]
Unbilled customer revenues	163	186
Accrued Expenses [Abstract]
Compensation-related accruals	86	99
Taxes accrued	80	74
Interest accrued	78	50
Potomac Electric Power Company [Member]
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]
Cash and cash equivalents	18	16	12	5
Restricted cash	34	37	35	35
Restricted cash included in other long-term assets	0	0	0	0
Total cash, cash equivalents and restricted cash	52	53	47	40
Receivables [Abstract]
Unbilled customer revenues	91	97
Accrued Expenses [Abstract]
Compensation-related accruals	26	29
Taxes accrued	61	58
Interest accrued	37	25
Delmarva Power and Light Company [Member]
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]
Cash and cash equivalents	11	23	110	2
Restricted cash	0	1	0	0
Restricted cash included in other long-term assets	0	0	0	0
Total cash, cash equivalents and restricted cash	11	24	110	2
Receivables [Abstract]
Unbilled customer revenues	38	59
Accrued Expenses [Abstract]
Compensation-related accruals	17	19
Taxes accrued	17	4
Interest accrued	20	8
Atlantic City Electric Company [Member]
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]
Cash and cash equivalents	13	7	11	2
Restricted cash	3	4	7	6
Restricted cash included in other long-term assets	15	19	19	23
Total cash, cash equivalents and restricted cash	31	30	$ 37	$ 31
Receivables [Abstract]
Unbilled customer revenues	34	30
Accrued Expenses [Abstract]
Compensation-related accruals	13	12
Taxes accrued	3	5
Interest accrued	$ 19	$ 12

Segment Information - Narrative (Details)	9 Months Ended
Segment Information - Narrative (Details)	Sep. 30, 2019 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, 2019

Jun. 30, 2019

Mar. 31, 2019

Sep. 30, 2018

Jun. 30, 2018

Mar. 31, 2018

Sep. 30, 2019

Sep. 30, 2018

Dec. 31, 2018

$ 8,929

$ 9,403

$ 26,096

$ 27,170

1,083

1,105

3,237

3,284

7,559

8,252

22,703

24,036

Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest

409

393

1,221

1,138

1,102

947

3,028

2,263

172

137

626

262

760

$ 494

$ 966

800

$ 542

$ 636

2,220

1,979

1,687

1,690

5,259

5,497

^[1]

122,738

$ 119,666

1,380

1,361

3,700

3,688

Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest

203

191

436

363

189

106

117

187

412

336

1,006

988

^[2]

22,576

21,984

4,774

5,278

14,280

15,368

Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest

275

308

844

979

501

389

1,355

800

388

110

244

$ 118

$ 422

300

$ 181

$ 186

784

667

1,282

1,660

Operating Segments [Member]

^[3]

47,984

47,556

194

139

432

335

8,929

9,403

26,096

27,170

760

800

2,220

1,979

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

122,738

119,666

Revenue from Contract with Customer, Including Assessed Tax

(9)

(5)

Intersegment Eliminations [Member]

(1)

(4)

(763)

(780)

(2,296)

(2,436)

(764)

(779)

(2,300)

(2,430)

(759)

(790)

(2,291)

(2,467)

Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest

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

(10,085)

(9,800)

(92)

(104)

(298)

(328)

(93)

(105)

(298)

(327)

(94)

(104)

(298)

(324)

Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest

(195)

(182)

(422)

(339)

(1)

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

(5,738)

(5,421)

195

140

436

339

4,774

5,278

14,280

15,368

407

468

1,221

1,383

4,274

4,961

13,333

14,475

Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest

109

101

336

305

501

389

1,355

800

388

110

244

300

784

667

392

362

1,282

1,660

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

47,984

47,556

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

275

308

844

981

1,583

1,598

4,342

4,508

259

237

767

696

1,256

1,275

3,431

3,610

Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest

268

261

245

674

663

130

140

200

193

544

523

452

514

1,413

1,540

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

32,326

31,213

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

778

757

2,333

2,275

247

224

595

603

1,783

1,853

Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest

100

154

124

461

331

(2)

(5)

140

126

410

336

228

204

675

615

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

11,379

10,642

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

703

731

2,327

2,369

116

110

368

358

612

628

1,936

2,005

Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest

320

301

261

242

300

233

842

667

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

10,304

9,716

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

1,380

1,361

3,700

3,688

193

192

562

555

1,124

1,116

3,106

3,165

Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest

197

193

203

191

436

363

189

187

412

336

308

359

1,006

988

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

22,576

21,984

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

642

628

1,748

1,708

281

286

515

516

1,444

1,454

Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest

100

103

226

181

(2)

217

174

157

188

455

475

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

8,603

8,299

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

319

328

987

1,001

138

135

268

277

820

859

Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest

132

107

116

245

254

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

4,724

4,588

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

419

406

966

981

114

107

340

322

838

847

Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest

300

247

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

3,916

3,699

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

474

458

1,410

1,398

457

459

1,405

1,395

Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest

231

205

(68)

(83)

(218)

(195)

(13)

(27)

(70)

(68)

(69)

(191)

(125)

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

8,254

8,355

103

297

326

105

302

329

Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest

192

179

411

326

(8)

(1)

(8)

(9)

(19)

(15)

(7)

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

11,071

$ 10,819

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

474

456

1,410

1,392

Generation Mid Atlantic [Member]

103

297

325

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

1,364

1,456

3,809

4,179

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

123

Generation Mid Atlantic [Member] | PotomacElectricPowerCompanyAffiliate [Member] | Exelon Generation Co L L C [Member]

199

198

Generation Mid Atlantic [Member] | DelmarvaPowerandLightCompanyAffiliate [Member] | Exelon Generation Co L L C [Member]

188

143

Generation Mid Atlantic [Member] | AtlanticCityElectricCompanyAffiliate [Member] | Exelon Generation Co L L C [Member]

103

Generation Mid Atlantic [Member] | Operating Segments [Member]

Generation Mid Atlantic [Member] | Intersegment Eliminations [Member]

1,361

1,449

3,807

4,162

Generation Midwest [Member]

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

1,082

1,117

3,224

3,593

Generation Midwest [Member] | Operating Segments [Member]

122

266

419

Generation Midwest [Member] | Intersegment Eliminations [Member]

1,099

1,121

3,255

3,601

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

(17)

(4)

(31)

(8)

Revenue from Contract with Customer, Including Assessed Tax

266

397

1,479

1,831

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

Revenue from Contract with Customer, Including Assessed Tax

(8)

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

Revenue from Contract with Customer, Including Assessed Tax

265

397

1,479

1,839

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

Revenue from Contract with Customer, Including Assessed Tax

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

Revenue from Contract with Customer, Including Assessed Tax

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

Revenue from Contract with Customer, Including Assessed Tax

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

Revenue from Contract with Customer, Including Assessed Tax

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

Revenue from Contract with Customer, Including Assessed Tax

Electricity, US Regulated | Pepco Holdings LLC [Member]

Revenue from Contract with Customer, Including Assessed Tax

1,365

1,340

3,570

3,541

Electricity, US Regulated | Operating Segments [Member]

Revenue from Contract with Customer, Including Assessed Tax

4,268

4,270

11,609

11,766

Electricity, US Regulated | Intersegment Eliminations [Member]

Revenue from Contract with Customer, Including Assessed Tax

(7)

(25)

(34)

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

Revenue from Contract with Customer, Including Assessed Tax

(3)

(4)

(10)

(12)

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

Revenue from Contract with Customer, Including Assessed Tax

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

Revenue from Contract with Customer, Including Assessed Tax

1,583

1,598

4,342

4,508

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

Revenue from Contract with Customer, Including Assessed Tax

716

700

1,901

1,893

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

Revenue from Contract with Customer, Including Assessed Tax

619

645

1,817

1,850

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

Revenue from Contract with Customer, Including Assessed Tax

1,357

1,334

3,574

3,549

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

Revenue from Contract with Customer, Including Assessed Tax

642

628

1,748

1,708

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

Revenue from Contract with Customer, Including Assessed Tax

299

304

871

872

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

Revenue from Contract with Customer, Including Assessed Tax

419

406

966

981

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

Revenue from Contract with Customer, Including Assessed Tax

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

Revenue from Contract with Customer, Including Assessed Tax

(1)

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

Revenue from Contract with Customer, Including Assessed Tax

4,039

4,435

11,525

12,221

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

Revenue from Contract with Customer, Including Assessed Tax

(275)

(306)

(840)

(969)

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

Revenue from Contract with Customer, Including Assessed Tax

4,314

4,741

12,365

13,190

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

Revenue from Contract with Customer, Including Assessed Tax

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

Revenue from Contract with Customer, Including Assessed Tax

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

Revenue from Contract with Customer, Including Assessed Tax

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

Revenue from Contract with Customer, Including Assessed Tax

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

Revenue from Contract with Customer, Including Assessed Tax

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

Revenue from Contract with Customer, Including Assessed Tax

115

129

Natural Gas, US Regulated | Operating Segments [Member]

Revenue from Contract with Customer, Including Assessed Tax

163

162

1,046

1,017

Natural Gas, US Regulated | Intersegment Eliminations [Member]

Revenue from Contract with Customer, Including Assessed Tax

(3)

(5)

(12)

(13)

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

Revenue from Contract with Customer, Including Assessed Tax

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

Revenue from Contract with Customer, Including Assessed Tax

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

Revenue from Contract with Customer, Including Assessed Tax

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

Revenue from Contract with Customer, Including Assessed Tax

432

382

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

Revenue from Contract with Customer, Including Assessed Tax

510

519

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

Revenue from Contract with Customer, Including Assessed Tax

116

129

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

Revenue from Contract with Customer, Including Assessed Tax

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

Revenue from Contract with Customer, Including Assessed Tax

116

129

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

Revenue from Contract with Customer, Including Assessed Tax

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

Revenue from Contract with Customer, Including Assessed Tax

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

Revenue from Contract with Customer, Including Assessed Tax

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

Revenue from Contract with Customer, Including Assessed Tax

(1)

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

Revenue from Contract with Customer, Including Assessed Tax

(478)

(461)

(1,415)

(1,408)

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

Revenue from Contract with Customer, Including Assessed Tax

(89)

(100)

(288)

(316)

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

Revenue from Contract with Customer, Including Assessed Tax

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

Revenue from Contract with Customer, Including Assessed Tax

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

Revenue from Contract with Customer, Including Assessed Tax

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

Revenue from Contract with Customer, Including Assessed Tax

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

Revenue from Contract with Customer, Including Assessed Tax

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

Revenue from Contract with Customer, Including Assessed Tax

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

Revenue from Contract with Customer, Including Assessed Tax

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

Revenue from Contract with Customer, Including Assessed Tax

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

Revenue from Contract with Customer, Including Assessed Tax

474

458

1,410

1,398

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