View Filing Data

$ (13)

$ (26)

$ (19)

$ (16)

7,689

8,076

17,166

17,769

2,159

2,307

4,347

4,691

1,079

1,088

2,154

2,179

418

428

863

874

6,881

7,138

15,142

15,786

841

942

2,060

2,043

(403)

(367)

(800)

(732)

(6)

(13)

212

679

(197)

(329)

(134)

(728)

644

613

1,926

1,315

Equity in losses of unconsolidated affiliates

144

454

125

(6)

(5)

(12)

(11)

Net income attributable to noncontrolling interests

494

542

1,460

1,179

Net income (loss) attributable to common shareholders

484

539

1,391

1,125

Other comprehensive (loss) income, net of income taxes

Prior service benefit reclassified to periodic benefit cost

(16)

(17)

(32)

(33)

Actuarial loss reclassified to periodic benefit cost

123

Pension and non-pension postretirement benefit plan valuation adjustment

(1)

(39)

Unrealized (loss) gain on cash flow hedges

Unrealized (loss) gain on investments in unconsolidated affiliates

(2)

(4)

Unrealized gain (loss) on foreign currency translation

(5)

(6)

Other comprehensive income

117

Comprehensive income attributable to noncontrolling interests

515

586

1,463

1,296

Comprehensive income attributable to common shareholders/membership interest

$ 506

$ 582

$ 1,396

$ 1,240

Average shares of common stock outstanding:

Basic average shares of common stock outstanding

972

967

972

967

Assumed exercise and/or distributions of stock-based awards

Diluted average shares of common stock outstanding

^[1]

974

969

973

968

Earnings per average common share:

Basic earnings per average common share

$ 0.50

$ 0.56

$ 1.43

$ 1.16

Diluted earnings per average common share

$ 0.50

$ 0.56

$ 1.43

$ 1.16

Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount

$ 252

$ 273

$ 569

$ 671

4,210

4,579

9,506

10,090

1,117

1,247

2,185

2,425

149

171

299

331

409

466

814

914

129

134

264

272

4,096

4,298

9,059

9,515

147

282

480

629

(107)

(93)

(209)

(184)

(9)

(18)

171

601

(15)

(73)

374

(217)

202

209

854

412

Equity in losses of unconsolidated affiliates

301

(6)

(5)

(13)

(12)

Net income attributable to noncontrolling interests

118

181

540

368

Net income attributable to membership interest

108

178

472

314

Other comprehensive (loss) income, net of income taxes

Unrealized (loss) gain on cash flow hedges

(1)

Unrealized (loss) gain on investments in unconsolidated affiliates

(2)

(4)

Unrealized gain (loss) on foreign currency translation

(5)

(6)

Other comprehensive income

(1)

Comprehensive income attributable to noncontrolling interests

117

183

540

377

Comprehensive income attributable to common shareholders/membership interest

108

179

474

321

Commonwealth Edison Co [Member]

(14)

(17)

(42)

(12)

1,351

1,398

2,759

2,910

104

187

298

245

255

504

509

122

129

257

231

508

459

148

156

1,040

1,111

2,174

2,335

311

288

588

580

(86)

(82)

(171)

(168)

(3)

(7)

(79)

(81)

(159)

(163)

232

207

429

417

Other comprehensive (loss) income, net of income taxes

186

164

344

329

186

164

344

329

PECO Energy Co [Member]

(3)

(6)

655

653

1,554

1,518

162

153

349

387

164

149

510

526

1,187

1,249

145

127

367

269

(30)

(28)

(61)

(57)

(3)

(4)

(6)

(7)

(30)

(32)

(60)

(62)

115

307

207

(1)

(3)

Other comprehensive (loss) income, net of income taxes

102

270

210

Baltimore Gas and Electric Company [Member]

102

270

210

(4)

(17)

649

662

1,625

1,639

132

127

142

135

294

318

117

114

252

248

131

124

569

578

1,325

1,378

300

262

(29)

(25)

(58)

(51)

(24)

(21)

(47)

(42)

253

220

Other comprehensive (loss) income, net of income taxes

206

179

206

179

(3)

(7)

1,091

1,076

2,319

2,327

171

186

213

218

452

489

188

180

369

363

108

107

220

221

926

923

1,981

2,048

165

153

338

279

(67)

(65)

(131)

(128)

(53)

(54)

(104)

(106)

112

234

173

Other comprehensive (loss) income, net of income taxes

106

223

149

Comprehensive income attributable to common shareholders/membership interest

106

223

149

Potomac Electric Power Company [Member]

(1)

(10)

531

523

1,106

1,080

122

123

133

107

113

186

188

182

183

438

929

939

177

141

(34)

(32)

(68)

(63)

(27)

(24)

(54)

(47)

123

Other comprehensive (loss) income, net of income taxes

119

Delmarva Power and Light Company [Member]

119

287

289

667

673

243

247

550

582

117

(15)

(14)

(30)

(27)

(10)

(11)

(23)

(22)

Other comprehensive (loss) income, net of income taxes

Atlantic City Electric Company [Member]

(2)

(1)

(3)

274

265

547

575

246

240

498

526

(15)

(16)

(28)

(32)

(14)

(15)

(24)

(31)

Other comprehensive (loss) income, net of income taxes

Generation commodities and services

Revenue from Contract with Customer, Including Assessed Tax

3,959

4,305

8,938

9,417

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

2,289

2,277

5,493

5,566

Revenue from Contract with Customer, Including Assessed Tax

3,958

4,306

8,937

9,419

Rate-regulated utility revenues

2,289

2,277

5,493

5,566

Revenue from Contract with Customer, Including Assessed Tax

3,743

3,797

8,247

8,368

Electricity, US Regulated | Commonwealth Edison Co [Member]

936

1,038

2,285

2,476

Revenue from Contract with Customer, Including Assessed Tax

1,360

1,410

2,792

2,903

Electricity, US Regulated | PECO Energy Co [Member]

316

373

705

784

Revenue from Contract with Customer, Including Assessed Tax

567

556

1,188

1,189

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

124

161

275

361

Revenue from Contract with Customer, Including Assessed Tax

540

542

1,191

1,196

Electricity, US Regulated | Pepco Holdings LLC [Member]

131

135

322

327

Revenue from Contract with Customer, Including Assessed Tax

1,067

1,052

2,205

2,202

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

303

288

658

662

Revenue from Contract with Customer, Including Assessed Tax

531

1,090

1,067

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

209

224

Revenue from Contract with Customer, Including Assessed Tax

261

255

568

558

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

193

162

Revenue from Contract with Customer, Including Assessed Tax

275

265

547

576

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

125

122

257

277

Revenue from Contract with Customer, Including Assessed Tax

369

325

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

166

134

Revenue from Contract with Customer, Including Assessed Tax

118

405

448

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

116

155

Revenue from Contract with Customer, Including Assessed Tax

106

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

Revenue from Contract with Customer, Including Assessed Tax

106

$ 9

$ 12

$ 43

$ 53

[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 six months ended June 30, 2019 and approximately 2 million and 5 million for the three and six months ended June 30, 2018, respectively.

Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
Cash flows from operating activities
Net income	$ 1,460	$ 1,179
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization	2,922	3,000
Impairment of long-lived assets	9	41
Gain on sales of assets and businesses	(33)	(60)
Deferred income taxes and amortization of investment tax credits	284	(2)
Net fair value changes related to derivatives	107	151
Net realized and unrealized (gains) losses on NDT funds	(404)	80
Other non-cash operating activities	277	479
Changes in assets and liabilities:
Accounts receivable	618	(105)
Inventories	19	60
Accounts payable and accrued expenses	(924)	(342)
Option premiums received (paid), net	48	(36)
Collateral (posted) received, net	(311)	81
Income taxes	151	129
Pension and non-pension postretirement benefit contributions	(355)	(345)
Other assets and liabilities	(970)	(441)
Net cash flows provided by operating activities	2,898	3,869
Cash flows from investing activities
Capital expenditures	(3,572)	(3,807)
Proceeds from NDT fund sales	6,920	3,822
Investment in NDT funds	(6,847)	(3,924)
Acquisition of assets and businesses, net	0	(57)
Proceeds from sales of assets and businesses	14	89
Other investing activities	26	31
Net cash flows used in investing activities	(3,459)	(3,846)
Cash flows from financing activities
Changes in short-term borrowings	470	200
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	850	1,488
Retirement of long-term debt	(574)	(1,309)
Dividends paid on common stock	(704)	(666)
Proceeds from employee stock plans	75	27
Other financing activities	(34)	(50)
Net cash flows provided by (used in) financing activities	(42)	(185)
Increase (Decrease) in cash, cash equivalents and restricted cash	(603)	(162)
Cash, cash equivalents and restricted cash at beginning of period	1,781	1,190
Cash, cash equivalents and restricted cash at end of period	1,178	1,028
Supplemental Cash Flow Information
Increase (Decrease) in capital expenditures not paid	(133)	(283)
Change in PPE related to ARO update	301	47
Exelon Generation Co L L C [Member]
Cash flows from operating activities
Net income	540	368
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization	1,580	1,735
Impairment of long-lived assets	9	41
Gain on sales of assets and businesses	(33)	(54)
Deferred income taxes and amortization of investment tax credits	151	(149)
Net fair value changes related to derivatives	114	158
Net realized and unrealized (gains) losses on NDT funds	(404)	80
Other non-cash operating activities	(50)	85
Changes in assets and liabilities:
Accounts receivable	472	258
Receivables from and payables to affiliates, net	(18)	7
Inventories	32	34
Accounts payable and accrued expenses	(507)	(272)
Option premiums received (paid), net	48	(36)
Collateral (posted) received, net	(318)	91
Income taxes	321	58
Pension and non-pension postretirement benefit contributions	(158)	(129)
Other assets and liabilities	(351)	(212)
Net cash flows provided by operating activities	1,428	2,063
Cash flows from investing activities
Capital expenditures	(890)	(1,298)
Proceeds from NDT fund sales	6,920	3,822
Investment in NDT funds	(6,847)	(3,924)
Acquisition of assets and businesses, net	0	(57)
Proceeds from sales of assets and businesses	14	89
Changes in Exelon/PHI intercompany money pool	(179)	(185)
Other investing activities	8	4
Net cash flows used in investing activities	(974)	(1,549)
Cash flows from financing activities
Issuance of long-term debt	40	13
Retirement of long-term debt	(130)	(76)
Changes in Exelon/PHI intercompany money pool	(100)	(54)
Distributions to member	(449)	(377)
Other financing activities	(21)	(24)
Net cash flows provided by (used in) financing activities	(660)	(518)
Increase (Decrease) in cash, cash equivalents and restricted cash	(206)	(4)
Cash, cash equivalents and restricted cash at beginning of period	903	554
Cash, cash equivalents and restricted cash at end of period	697	550
Supplemental Cash Flow Information
Increase (Decrease) in capital expenditures not paid	(30)	(310)
Change in PPE related to ARO update	301	47
Commonwealth Edison Co [Member]
Cash flows from operating activities
Net income	344	329
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization	508	459
Deferred income taxes and amortization of investment tax credits	64	84
Other non-cash operating activities	87	117
Changes in assets and liabilities:
Accounts receivable	56	(133)
Receivables from and payables to affiliates, net	(16)	15
Inventories	(5)	5
Accounts payable and accrued expenses	(121)	(41)
Collateral (posted) received, net	11	(13)
Income taxes	43	(15)
Pension and non-pension postretirement benefit contributions	(68)	(39)
Other assets and liabilities	(236)	(166)
Net cash flows provided by operating activities	667	602
Cash flows from investing activities
Capital expenditures	(961)	(1,026)
Other investing activities	17	17
Net cash flows used in investing activities	(944)	(1,009)
Cash flows from financing activities
Changes in short-term borrowings	303	320
Issuance of long-term debt	400	800
Retirement of long-term debt	(300)	(700)
Contributions from parent	124	225
Dividends paid on common stock	(254)	(229)
Other financing activities	(10)	(10)
Net cash flows provided by (used in) financing activities	263	406
Increase (Decrease) in cash, cash equivalents and restricted cash	(14)	(1)
Cash, cash equivalents and restricted cash at beginning of period	330	144
Cash, cash equivalents and restricted cash at end of period	316	143
Supplemental Cash Flow Information
Increase (Decrease) in capital expenditures not paid	(77)	(22)
PECO Energy Co [Member]
Cash flows from operating activities
Net income	270	210
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization	164	149
Deferred income taxes and amortization of investment tax credits	8	(10)
Other non-cash operating activities	15	22
Changes in assets and liabilities:
Accounts receivable	39	(43)
Receivables from and payables to affiliates, net	(4)	(4)
Inventories	12	4
Accounts payable and accrued expenses	(31)	(18)
Income taxes	(11)	19
Pension and non-pension postretirement benefit contributions	(27)	(25)
Other assets and liabilities	(117)	(50)
Net cash flows provided by operating activities	318	254
Cash flows from investing activities
Capital expenditures	(447)	(411)
Other investing activities	4	5
Net cash flows used in investing activities	(443)	(406)
Cash flows from financing activities
Changes in short-term borrowings	0	50
Issuance of long-term debt	0	375
Retirement of long-term debt	0	(500)
Changes in Exelon/PHI intercompany money pool	52	233
Contributions from parent	145	41
Dividends paid on common stock	(180)	(293)
Other financing activities	(1)	(6)
Net cash flows provided by (used in) financing activities	16	(100)
Increase (Decrease) in cash, cash equivalents and restricted cash	(109)	(252)
Cash, cash equivalents and restricted cash at beginning of period	135	275
Cash, cash equivalents and restricted cash at end of period	26	23
Supplemental Cash Flow Information
Increase (Decrease) in capital expenditures not paid	33	(17)
Baltimore Gas and Electric Company [Member]
Cash flows from operating activities
Net income	206	179
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization	252	248
Deferred income taxes and amortization of investment tax credits	47	39
Other non-cash operating activities	41	27
Changes in assets and liabilities:
Accounts receivable	85	73
Receivables from and payables to affiliates, net	(14)	(4)
Inventories	5	5
Accounts payable and accrued expenses	(73)	(48)
Collateral (posted) received, net	(5)	0
Income taxes	(29)	(45)
Pension and non-pension postretirement benefit contributions	(42)	(49)
Other assets and liabilities	(21)	39
Net cash flows provided by operating activities	452	464
Cash flows from investing activities
Capital expenditures	(542)	(434)
Other investing activities	4	6
Net cash flows used in investing activities	(538)	(428)
Cash flows from financing activities
Changes in short-term borrowings	194	59
Dividends paid on common stock	(112)	(105)
Net cash flows provided by (used in) financing activities	82	(46)
Increase (Decrease) in cash, cash equivalents and restricted cash	(4)	(10)
Cash, cash equivalents and restricted cash at beginning of period	13	18
Cash, cash equivalents and restricted cash at end of period	9	8
Supplemental Cash Flow Information
Increase (Decrease) in capital expenditures not paid	24	10
Pepco Holdings LLC [Member]
Cash flows from operating activities
Net income	223	149
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization	369	363
Deferred income taxes and amortization of investment tax credits	2	14
Other non-cash operating activities	54	71
Changes in assets and liabilities:
Accounts receivable	(34)	(28)
Receivables from and payables to affiliates, net	(8)	4
Inventories	(25)	8
Accounts payable and accrued expenses	(25)	66
Income taxes	(12)	13
Pension and non-pension postretirement benefit contributions	(11)	(62)
Other assets and liabilities	(114)	(111)
Net cash flows provided by operating activities	419	487
Cash flows from investing activities
Capital expenditures	(698)	(629)
Other investing activities	2	2
Net cash flows used in investing activities	(696)	(627)
Cash flows from financing activities
Changes in short-term borrowings	(27)	(228)
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	(125)	(25)
Changes in Exelon/PHI intercompany money pool	3	7
Distributions to member	(216)	(109)
Contributions from member	283	235
Other financing activities	(4)	(7)
Net cash flows provided by (used in) financing activities	199	298
Increase (Decrease) in cash, cash equivalents and restricted cash	(78)	158
Cash, cash equivalents and restricted cash at beginning of period	186	95
Cash, cash equivalents and restricted cash at end of period	108	253
Supplemental Cash Flow Information
Increase (Decrease) in capital expenditures not paid	(74)	61
Potomac Electric Power Company [Member]
Cash flows from operating activities
Net income	119	85
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization	186	188
Deferred income taxes and amortization of investment tax credits	10	(8)
Other non-cash operating activities	8	24
Changes in assets and liabilities:
Accounts receivable	(36)	(31)
Receivables from and payables to affiliates, net	4	(11)
Inventories	(20)	2
Accounts payable and accrued expenses	(25)	77
Income taxes	(23)	3
Pension and non-pension postretirement benefit contributions	(6)	(11)
Other assets and liabilities	(40)	(91)
Net cash flows provided by operating activities	177	227
Cash flows from investing activities
Capital expenditures	(298)	(287)
Changes in Exelon/PHI intercompany money pool	(38)	0
Other investing activities	1	2
Net cash flows used in investing activities	(335)	(285)
Cash flows from financing activities
Changes in short-term borrowings	(40)	(26)
Issuance of long-term debt	260	100
Retirement of long-term debt	(117)	(7)
Contributions from parent	129	85
Dividends paid on common stock	(72)	(50)
Other financing activities	(3)	(4)
Net cash flows provided by (used in) financing activities	157	98
Increase (Decrease) in cash, cash equivalents and restricted cash	(1)	40
Cash, cash equivalents and restricted cash at beginning of period	53	40
Cash, cash equivalents and restricted cash at end of period	52	80
Supplemental Cash Flow Information
Increase (Decrease) in capital expenditures not paid	(18)	28
Delmarva Power and Light Company [Member]
Cash flows from operating activities
Net income	83	57
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization	91	88
Deferred income taxes and amortization of investment tax credits	(5)	9
Other non-cash operating activities	11	14
Changes in assets and liabilities:
Accounts receivable	15	18
Receivables from and payables to affiliates, net	(11)	(22)
Inventories	(3)	4
Accounts payable and accrued expenses	6	10
Income taxes	11	16
Pension and non-pension postretirement benefit contributions	(1)	0
Other assets and liabilities	(26)	22
Net cash flows provided by operating activities	171	216
Cash flows from investing activities
Capital expenditures	(160)	(166)
Other investing activities	1	1
Net cash flows used in investing activities	(159)	(165)
Cash flows from financing activities
Changes in short-term borrowings	0	(216)
Issuance of long-term debt	0	200
Retirement of long-term debt	0	(4)
Changes in Exelon/PHI intercompany money pool	38	0
Contributions from parent	0	150
Dividends paid on common stock	(70)	(40)
Other financing activities	0	(2)
Net cash flows provided by (used in) financing activities	(32)	88
Increase (Decrease) in cash, cash equivalents and restricted cash	(20)	139
Cash, cash equivalents and restricted cash at beginning of period	24	2
Cash, cash equivalents and restricted cash at end of period	4	141
Supplemental Cash Flow Information
Increase (Decrease) in capital expenditures not paid	(17)	17
Atlantic City Electric Company [Member]
Cash flows from operating activities
Net income	24	15
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization	71	69
Deferred income taxes and amortization of investment tax credits	2	6
Other non-cash operating activities	7	12
Changes in assets and liabilities:
Accounts receivable	(11)	(13)
Receivables from and payables to affiliates, net	(9)	(4)
Inventories	(1)	4
Accounts payable and accrued expenses	16	14
Income taxes	6	3
Pension and non-pension postretirement benefit contributions	0	(6)
Other assets and liabilities	(44)	(33)
Net cash flows provided by operating activities	61	67
Cash flows from investing activities
Capital expenditures	(227)	(170)
Other investing activities	0	(2)
Net cash flows used in investing activities	(227)	(172)
Cash flows from financing activities
Changes in short-term borrowings	13	14
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	(9)	(15)
Contributions from parent	155	0
Dividends paid on common stock	(24)	(19)
Other financing activities	(1)	0
Net cash flows provided by (used in) financing activities	159	105
Increase (Decrease) in cash, cash equivalents and restricted cash	(7)	0
Cash, cash equivalents and restricted cash at beginning of period	30	31
Cash, cash equivalents and restricted cash at end of period	23	31
Supplemental Cash Flow Information
Increase (Decrease) in capital expenditures not paid	$ (35)	$ 14

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

Jun. 30, 2019

Dec. 31, 2018

$ 735

$ 1,349

252

247

4,125

4,607

Mark-to-market derivative assets, current

1,008

1,256

526

804

Unamortized energy contract assets, current

258

334

1,412

1,351

1,194

1,222

Assets held for sale

880

904

1,218

1,238

11,655

13,360

78,030

76,707

Nuclear decommissioning trust funds

8,166

8,237

12,513

11,661

618

625

Mark-to-market derivative assets, noncurrent

6,677

537

452

Unamortized energy contract assets, noncurrent

362

372

3,038

1,575

31,911

29,599

^[1]

121,596

119,666

1,059

714

3,776

1,349

3,248

3,800

1,706

2,112

Mark-to-market derivative liabilities, current

403

644

163

475

Unamortized energy contract liabilities, current

145

149

Renewable energy credit obligation

298

344

Liabilities held for sale

764

777

1,367

1,035

12,934

11,404

Long-term debt to financing trusts

31,909

34,075

390

Deferred income taxes and unamortized investment tax credits

11,826

11,330

10,023

9,679

Pension obligations

3,720

3,988

Spent nuclear fuel obligation

2,007

1,928

1,186

1,171

Mark-to-market derivative liabilities, noncurrent

9,793

9,559

450

479

Unamortized energy contract liabilities, noncurrent

398

463

3,053

2,130

42,456

40,727

^[1]

87,689

86,596

19,209

19,116

Treasury stock, at cost

(123)

Accumulated other comprehensive loss, net

15,452

14,766

(2,990)

(2,995)

31,548

30,764

Noncontrolling Interests

2,359

2,306

Total equity

33,907

33,070

Variable Interest Entity, Consolidated, Assets, Pledged

121,596

119,666

9,526

9,667

Variable Interest Entity, Consolidated, Liabilities, No Recourse

3,568

3,548

575

750

122

153

2,528

2,941

Mark-to-market derivative assets, current

326

562

526

804

Receivable from Exelon/PHI intercompany money pool

159

173

179

Unamortized energy contract assets, current

201

251

984

963

Assets held for sale

880

904

849

883

7,376

8,433

23,810

23,981

Nuclear decommissioning trust funds

12,513

11,661

401

414

Mark-to-market derivative assets, noncurrent

533

452

Unamortized energy contract assets, noncurrent

1,506

1,421

361

371

Deferred income taxes

1,841

755

17,216

15,142

^[2]

48,402

47,556

2,733

906

1,517

1,847

767

898

122

139

Mark-to-market derivative liabilities, current

100

134

449

Unamortized energy contract liabilities, current

Renewable energy credit obligation

298

343

Liabilities held for sale

764

777

481

279

6,842

5,769

Long-term debt to affiliates

5,079

6,989

892

898

Deferred income taxes and unamortized investment tax credits

3,534

3,383

9,792

9,450

Spent nuclear fuel obligation

889

900

1,186

1,171

Payables to affiliates, noncurrent

2,928

2,606

Mark-to-market derivative liabilities, noncurrent

206

252

Unamortized energy contract liabilities, noncurrent

1,449

610

19,997

18,392

^[2]

32,810

32,048

Accumulated other comprehensive loss, net

3,746

3,724

(36)

(38)

Membership interest

9,525

9,518

Total members' equity

13,235

13,204

Noncontrolling Interests

2,357

2,304

Total equity

15,592

15,508

Variable Interest Entity, Consolidated, Assets, Pledged

48,402

47,556

9,503

9,634

Variable Interest Entity, Consolidated, Liabilities, No Recourse

3,513

3,480

Commonwealth Edison Co [Member]

135

528

539

268

320

Inventories, net

151

148

297

293

1,482

1,570

22,527

22,058

1,391

1,307

Receivable from affiliates, noncurrent

2,625

2,458

2,217

1,046

1,035

354

395

7,880

7,585

31,889

31,213

303

300

478

607

305

373

119

114

111

Mark-to-market derivative liabilities, current

186

293

126

1,632

1,925

Long-term debt to financing trusts

8,195

7,801

205

Deferred income taxes and unamortized investment tax credits

3,929

3,813

119

118

191

201

Mark-to-market derivative liabilities, noncurrent

6,322

6,050

244

223

592

630

11,397

11,035

21,429

20,966

Retained deficit unappropriated

1,588

Other paid-in capital

7,446

7,322

(1,639)

Retained earnings appropriated

3,065

2,976

10,460

10,247

31,889

31,213

PECO Energy Co [Member]

130

302

321

123

151

Prepaid utility taxes

658

782

8,940

8,610

508

460

Receivable from affiliates, noncurrent

470

389

371

349

1,404

1,250

11,002

10,642

375

370

102

113

175

784

809

Long-term debt to financing trusts

3,085

3,084

184

Deferred income taxes and unamortized investment tax credits

1,999

1,933

289

288

500

421

2,894

2,745

6,947

6,822

2,723

2,578

1,332

1,242

4,055

3,820

Baltimore Gas and Electric Company [Member]

11,002

10,642

278

353

Prepaid utility taxes

164

177

614

786

8,612

8,243

390

398

289

279

780

687

10,006

9,716

229

279

295

103

155

120

868

774

2,877

2,876

Deferred income taxes and unamortized investment tax credits

1,301

1,222

198

201

1,162

1,192

128

2,813

2,712

6,558

6,362

1,714

1,734

1,640

3,448

3,354

10,006

9,716

124

489

453

196

177

195

163

496

489

1,546

1,533

13,788

13,446

2,163

2,312

133

130

4,005

446

486

Deferred income taxes

360

7,120

7,005

^[3]

22,454

21,984

179

118

125

426

496

224

256

117

116

Unamortized energy contract liabilities, current

119

133

123

1,328

1,592

6,391

6,134

Deferred income taxes and unamortized investment tax credits

2,219

2,146

100

103

Unamortized energy contract liabilities, noncurrent

1,789

1,864

385

442

617

369

5,163

4,976

^[3]

12,882

12,702

Membership interest

9,503

9,220

Total members' equity

9,572

9,282

Total equity

9,572

9,282

Variable Interest Entity, Consolidated, Assets, Pledged

22,454

21,984

Variable Interest Entity, Consolidated, Liabilities, No Recourse

Potomac Electric Power Company [Member]

254

225

110

Receivable from Exelon/PHI intercompany money pool

Inventories, net

115

262

270

841

760

6,623

6,460

601

643

108

105

306

316

1,092

1,079

8,556

8,299

175

214

114

126

Merger related obligation

Current portion of DC PLUG obligation

517

628

2,852

2,704

Deferred income taxes and unamortized investment tax credits

1,114

1,064

782

822

313

275

2,271

2,227

5,640

5,559

1,765

1,636

1,151

1,104

2,916

2,740

Delmarva Power and Light Company [Member]

8,556

8,299

123

134

Renewable energy credits

300

336

3,893

3,821

224

231

178

186

490

431

4,683

4,588

106

111

398

375

1,404

1,403

Deferred income taxes and unamortized investment tax credits

644

628

586

606

113

1,359

1,301

3,161

3,079

914

608

595

1,522

1,509

Atlantic City Electric Company [Member]

4,683

4,588

112

Inventories, net

Prepaid utility taxes

299

240

3,093

2,966

374

386

494

493

^[4]

3,886

3,699

139

135

154

299

422

1,310

1,170

Deferred income taxes and unamortized investment tax credits

546

535

388

402

996

981

^[4]

2,605

2,573

1,134

979

147

1,281

1,126

Variable Interest Entity, Consolidated, Assets, Pledged

3,886

3,699

Variable Interest Entity, Consolidated, Liabilities, No Recourse

$ 51

$ 59

[1]	Exelon’s consolidated assets include $9,526 million and $9,667 million at June 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 $3,568 million and $3,548 million at June 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 $9,503 million and $9,634 million at June 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 $3,513 million and $3,480 million at June 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 $23 million and $33 million at June 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 $55 million and $69 million at June 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 $19 million and $23 million at June 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 $51 million and $59 million at June 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	Jun. 30, 2019	Dec. 31, 2018
Customer allowance for uncollectible accounts	$ 257	$ 283
Other allowance for uncollectible accounts	40	36
Accumulated depreciation and amortization	$ 24,266	$ 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	$ 96	$ 103
Other allowance for uncollectible accounts	1	1
Accumulated depreciation and amortization	12,902	12,206
Commonwealth Edison Co [Member]
Customer allowance for uncollectible accounts	59	61
Other allowance for uncollectible accounts	18	20
Accumulated depreciation and amortization	4,949	4,684
PECO Energy Co [Member]
Customer allowance for uncollectible accounts	53	53
Other allowance for uncollectible accounts	6	8
Accumulated depreciation and amortization	3,636	3,561
Baltimore Gas and Electric Company [Member]
Customer allowance for uncollectible accounts	14	16
Other allowance for uncollectible accounts	4	4
Accumulated depreciation and amortization	3,720	3,633
Pepco Holdings LLC [Member]
Customer allowance for uncollectible accounts	35	50
Other allowance for uncollectible accounts	11	3
Accumulated depreciation and amortization	1,032	841
Potomac Electric Power Company [Member]
Customer allowance for uncollectible accounts	13	20
Other allowance for uncollectible accounts	6	1
Accumulated depreciation and amortization	3,431	3,354
Delmarva Power and Light Company [Member]
Customer allowance for uncollectible accounts	10	12
Other allowance for uncollectible accounts	2	1
Accumulated depreciation and amortization	1,380	1,329
Atlantic City Electric Company [Member]
Customer allowance for uncollectible accounts	11	18
Other allowance for uncollectible accounts	3	1
Accumulated depreciation and amortization	$ 1,179	$ 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)
Distributions to member								(188)		(188)																(71)		(71)
Contributions from parent													113	0	113
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	1,179							368					329						210				179			149			85			57			15
Other comprehensive income (loss), net of income taxes	$ 117				115			9			7
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																(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)
Distributions to member								(189)		(189)																(38)		(38)
Contributions from parent													112	0	112				41	41	0	0				235	235		85	85		150	150
Other comprehensive income (loss), net of income taxes	$ 44				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
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)
Distributions to member								(225)		(225)																(128)		(128)
Contributions from parent													63	0	63				145	145	0	0				19	19		14	14					5	5
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	1,460							540					344						270				206			223			119			83			24
Other comprehensive income (loss), net of income taxes	$ 3				5			0			2
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	$ 31,548												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																(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
Sale of noncontrolling interests	0	0
Common stock dividends	(353)			(353)									(127)				(127)		(90)		(90)		(55)		(55)				(48)		(48)	(29)		(29)	(12)		(12)
Distributions to member								(224)		(224)																(88)		(88)
Contributions from parent													61	0	61				0	0	0	0				264	264		115	115					150	150
Other comprehensive income (loss), net of income taxes	$ 21				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	$ 31,548												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													$ 3,065			$ (186)	$ 186	$ 0

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

Significant Accounting Policies

6 Months Ended

Jun. 30, 2019

Accounting Policies [Abstract]

Significant Accounting Policies [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

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 June 30, 2019 and 2018 and for the three and six 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) carryforward 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 June 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 June 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 the entity’s current estimate of credit losses expected to be incurred over the life of the financial instrument. The standard does not make changes to the existing impairment models for non-financial assets such as fixed assets, intangibles and goodwill. 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. The Registrants are currently assessing the impacts of this standard.

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.

Business Description [Text Block]

Description of Business (All Registrants)



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 (All Registrants)

6 Months Ended

Jun. 30, 2019

Variable Interest Entity [Abstract]

Variable Interest Entity Disclosure (All Registrants)

Variable Interest Entities (All Registrants)

A VIE is a legal entity that possesses any of the following characteristics: an insufficient amount of equity at risk to finance its activities, equity owners who do not have the power to direct the significant activities of the entity (or have voting rights that are disproportionate to their ownership interest) or equity owners who do not have the obligation to absorb expected losses or the right to receive the expected residual returns of the entity. Companies are required to consolidate a VIE if they are its primary beneficiary, which is the enterprise that has the power to direct the activities that most significantly affect the entity’s economic performance.

At June 30, 2019 and December 31, 2018, Exelon, Generation, PHI and ACE collectively consolidated five VIEs or VIE groups for which the applicable Registrant was the primary beneficiary (see Consolidated Variable Interest Entities below). As of June 30, 2019 and December 31, 2018, Exelon and Generation collectively had significant interests in eight and seven, respectively, 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 Variable Interest Entities below).

Consolidated Variable Interest Entities

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


•	energy related companies involved in distributed generation, backup generation and energy development


•	renewable energy project companies formed by Generation to build, own and operate renewable power facilities


•	certain retail power and gas companies for which Generation is the sole supplier of energy, and


•	CENG.

As of June 30, 2019 and December 31, 2018, Exelon's, PHI's and ACE's consolidated VIE consist of:


•	ACE Transition Funding (ATF), 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.

As of June 30, 2019 and December 31, 2018, ComEd, PECO, BGE, Pepco and DPL did not have any material consolidated VIEs.

Exelon and Generation provided the following support to their respective consolidated VIEs:


•	Operating and capital funding to the renewable energy project companies and there is limited recourse to Generation related to certain renewable energy project companies;


•	Approximately $6 million and $34 million as of June 30, 2019 and December 31, 2018, respectively, in credit support for the retail power and gas companies for which Generation is the sole supplier of energy.


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


•	under PPAs with CENG, Generation purchased or will purchase 50.01% of the available output generated by the CENG nuclear plants not subject to other contractual agreements from January 2015 through the end of the operating life of each respective plant.


•	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 16 — Commitments and Contingencies 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, and


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

As of June 30, 2019 and December 31, 2018, Exelon, PHI and ACE provided the following support to their respective consolidated VIE:

•

In the case of ATF, 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. During the three and six months ended June 30, 2019, ACE

transferred $3 million and $7 million to ATF, respectively. During the three and six months ended June 30, 2018, ACE transferred $6 million and $14 million to ATF, respectively.

For each of the consolidated VIEs, except as otherwise noted:


•	the assets of the VIEs are restricted and can only be used to settle obligations of the respective VIE;


•	Exelon, Generation, PHI and ACE did not provide any additional material financial support to the VIEs;


•	Exelon, Generation, PHI and ACE did not have any material contractual commitments or obligations to provide financial support to the VIEs; and


•	the creditors of the VIEs did not have recourse to Exelon’s, Generation’s, PHI's or ACE's general credit.

The carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in the Registrants' consolidated financial statements at June 30, 2019 and December 31, 2018 are as follows:



	June 30, 2019								December 31, 2018
	Exelon^(a)		Generation		PHI^(a)		ACE		Exelon^(a)		Generation		PHI^(a)		ACE
Current assets	$	649	$	646	$	3	$	2	$	938	$	931	$	7	$	4
Noncurrent assets	9,204		9,184		20		17		9,071		9,045		26		19
Total assets	$	9,853	$	9,830	$	23	$	19	$	10,009	$	9,976	$	33	$	23
Current liabilities	715		694		21		20		$	274	$	252	$	22	$	19
Noncurrent liabilities	2,861		2,827		34		31		3,280		3,233		47		40
Total liabilities	$	3,576	$	3,521	$	55	$	51	$	3,554	$	3,485	$	69	$	59

_________


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

Assets and Liabilities of Consolidated VIEs

Included within the balances above are assets and liabilities of certain consolidated VIEs for which the assets can only be used to settle obligations of those VIEs, and liabilities that creditors or beneficiaries do not have recourse to the general credit of the Registrants. As of June 30, 2019 and December 31, 2018, these assets and liabilities primarily consisted of the following:



	June 30, 2019								December 31, 2018
	Exelon^(a)		Generation		PHI^(a)		ACE		Exelon^(a)		Generation		PHI^(a)		ACE
Cash and cash equivalents	$	106	$	106	$	—	$	—	$	414	$	414	$	—	$	—
Restricted cash and cash equivalents	75		73		2		2		66		62		4		4
Accounts receivable, net
Customer	161		161		—		—		146		146		—		—
Other	39		39		—		—		23		23		—		—
Inventory, net
Materials and supplies	217		217		—		—		212		212		—		—
Other current assets	28		27		1		—		52		49		3		—
Total current assets	626		623		3		2		913		906		7		4
Property, plant and equipment, net	6,084		6,084		—		—		6,145		6,145		—		—
NDT funds	2,589		2,589		—		—		2,351		2,351		—		—
Other noncurrent assets	227		207		20		17		258		232		26		19
Total noncurrent assets	8,900		8,880		20		17		8,754		8,728		26		19
Total assets	$	9,526	$	9,503	$	23	$	19	$	9,667	$	9,634	$	33	$	23
Long-term debt due within one year	$	560	$	540	$	20	$	19	$	87	$	66	$	21	$	18
Accounts payable	89		89		—		—		96		96		—		—
Accrued expenses	52		51		1		1		72		72		1		1
Unamortized energy contract liabilities	11		11		—		—		15		15		—		—
Other current liabilities	3		3		—		—		3		3		—		—
Total current liabilities	715		694		21		20		273		252		22		19
Long-term debt	558		524		34		31		1,072		1,025		47		40
Asset retirement obligations	2,218		2,218		—		—		2,160		2,160		—		—
Unamortized energy contract liabilities	—		—		—		—		1		1		—		—
Other noncurrent liabilities	77		77		—		—		42		42		—		—
Total noncurrent liabilities	2,853		2,819		34		31		3,275		3,228		47		40
Total liabilities	$	3,568	$	3,513	$	55	$	51	$	3,548	$	3,480	$	69	$	59

_________


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

Unconsolidated Variable Interest Entities

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. Further, Exelon and Generation have not provided material debt or equity support, liquidity arrangements or performance guarantees associated with these commercial agreements.

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


•	Energy purchase and sale agreements with VIEs for which Generation has concluded that consolidation is not required.


•	Asset sale agreement with ZionSolutions, LLC and EnergySolutions, Inc. in which Generation has a variable interest but has concluded that consolidation is not required.


•	Equity investments in distributed energy companies for which Generation has concluded that consolidation is not required.

As of June 30, 2019 and December 31, 2018, the Utility Registrants did not have any material unconsolidated VIEs.

As of June 30, 2019 and December 31, 2018, Exelon and Generation had significant unconsolidated variable interests in eight and seven VIEs, respectively, for which Exelon or Generation, as applicable, was not the primary beneficiary; including certain equity investments and certain commercial agreements. Exelon and Generation only include unconsolidated VIEs that are individually material in the tables below. However, Exelon and Generation have several individually immaterial VIEs that in aggregate represent a total investment of $16 million and $12 million, as of June 30, 2019, and $15 million and $13 million as of December 31, 2018, respectively. These immaterial VIEs are equity and debt securities in energy development companies. As of June 30, 2019 and December 31, 2018, the maximum exposure to loss related to these securities included in Investments in Exelon’s and Generation’s Consolidated Balance Sheets is limited to $16 million and $12 million, and $15 million and $13 million, respectively. The risk of a loss was assessed to be remote and, accordingly, Exelon and Generation have not recognized a liability associated with any portion of the maximum exposure to loss.

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



June 30, 2019	Commercial Agreement VIEs		Equity Investment VIEs		Total
Total assets^(a)	$	603	$	453	$	1,056
Total liabilities^(a)	33		225		258
Exelon's ownership interest in VIE^(a)	—		203		203
Other ownership interests in VIE^(a)	571		25		596
Registrants’ maximum exposure to loss:
Carrying amount of equity method investments	—		203		203
Contract intangible asset	7		—		7



December 31, 2018	Commercial Agreement VIEs		Equity Investment VIEs		Total
Total assets^(a)	$	597	$	472	$	1,069
Total liabilities^(a)	37		222		259
Exelon's ownership interest in VIE^(a)	—		223		223
Other ownership interests in VIE^(a)	560		27		587
Registrants’ maximum exposure to loss:
Carrying amount of equity method investments	—		223		223
Contract intangible asset	7		—		7

_________


(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. In addition, there are no material agreements with, or commitments by, third parties that would affect the fair value or risk of their variable interests in these VIEs.

Mergers, Acquisitions and Dispositions (Exelon and Generation)	6 Months Ended
	Jun. 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 expect the loss on the sale, which will be recognized in the third quarter, to be 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 $863 million and $759 million of Assets and Liabilities held for sale, respectively, at June 30, 2019 and $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 six months ended June 30, 2018. In June 2018, additional proceeds were received, and a pre-tax gain was recorded within Gain on sales of assets and businesses in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.

Revenue from Contracts with Customers (All Registrants)

6 Months Ended

Jun. 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 June 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	(44		)	(44		)	38			115
Revenues recognized	53			53			(44		)	(131		)
Balance at June 30, 2019	$	196		$	196		$	21		$	26

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 June 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 June 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	$	274	$	275	$	93	$	68	$	248	$	958
Generation	355		343		118		72		248		1,136

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)

6 Months Ended

Jun. 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	1-4	2	4	N/A	3	N/A	N/A	N/A	N/A

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



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Operating lease costs	$	87	$	61	$	1	$	—	$	9	$	13	$	3	$	4	$	3
Variable lease costs	77		72		1		—		1		2		1		—		1
Short-term lease costs	3		3		—		—		—		—		—		—		—
Total lease costs ^(a)	$	167	$	136	$	2	$	—	$	10	$	15	$	4	$	4	$	4

__________


(a)	Excludes $16 million, $12 million, $4 million and $4 million of sublease income recorded at Exelon, Generation, PHI and DPL.

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



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Operating lease costs	$	155	$	107	$	2	$	—	$	17	$	23	$	6	$	7	$	4
Variable lease costs	150		140		1		—		1		4		1		1		1
Short-term lease costs	11		11		—		—		—		—		—		—		—
Total lease costs ^(a)	$	316	$	258	$	3	$	—	$	18	$	27	$	7	$	8	$	5

__________


(a)	Excludes $19 million, $14 million, $5 million and $5 million of sublease income recorded at Exelon, Generation, PHI and DPL.

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 June 30, 2019:



	Exelon^(a)		Generation^(a)		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Operating lease ROU assets
Other deferred debits and other assets	$	1,412	$	982	$	11	$	2	$	91	$	309	$	67	$	74	$	24

Operating lease liabilities
Other current liabilities	250		173		3		1		32		36		8		11		6
Other deferred credits and other liabilities	1,353		981		9		1		65		280		60		72		19
Total operating lease liabilities	$	1,603	$	1,154	$	12	$	2	$	97	$	316	$	68	$	83	$	25

__________


(a)	Exelon's and Generation's operating ROU assets and lease liabilities include $595 million and $744 million, respectively, related to contracted generation.

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



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Remaining lease term	9.9		10.6		4.9		4.4		5.4		9.2		9.7		9.6		5.2
Discount rate	4.6	%	4.8	%	3.1	%	3.4	%	3.6	%	4.1	%	3.8	%	3.9	%	3.5	%

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



Year	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
2019	$	149	$	104	$	2	$	1	$	17	$	23	$	6	$	5	$	4
2020	291		202		3		1		34		44		9		12		5
2021	246		161		3		—		31		42		9		12		5
2022	177		112		2		—		16		41		8		11		4
2023	141		99		1		—		—		39		8		10		3
Remaining years	1,051		834		2		—		19		196		43		52		6
Total	2,055		1,512		13		2		117		385		83		102		27
Interest	452		358		1		—		20		69		15		19		2
Total operating lease liabilities	$	1,603	$	1,154	$	12	$	2	$	97	$	316	$	68	$	83	$	25

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 six months ended June 30, 2019 were as follows:



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Operating cash flows from operating leases	$	142	$	101	$	2	$	—	$	16	$	19	$	5	$	4	$	3

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



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Operating leases	$	30	$	7	$	6	$	—	$	1	$	15	$	6	$	6	$	3

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 June 30, 2019 were as follows:



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Operating lease income	$	14	$	12	$	—	$	—	$	—	$	1	$	—	$	1	$	—
Variable lease income	77		74		—		—		—		3		—		3		—

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



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Operating lease income	$	18	$	15	$	—	$	—	$	—	$	2	$	—	$	2	$	—
Variable lease income	129		126		—		—		—		3		—		3		—

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



Year	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
2019	$	33	$	31	$	—	$	—	$	—	$	2	$	—	$	2	—
2020	51		46		—		—		—		4		—		3		—
2021	51		46		—		—		—		4		1		3		—
2022	50		45		—		—		—		5		—		4		—
2023	49		45		—		—		—		4		—		3		—
Remaining years	314		271		1		3		1		38		—		38		—
Total	$	548	$	484	$	1	$	3	$	1	$	57	$	1	$	53	$	—

Leases (All Registrants)

Regulatory Matters (All Registrants)

6 Months Ended

Jun. 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

__________


(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 Increase (Decrease)			Requested ROE		Expected Approval Timing
Pepco - Maryland (Electric)	January 15, 2019 (amended May 16, 2019)	$	27		10.3	%	Third quarter of 2019
ComEd - Illinois (Electric)^(a)	April 8, 2019	$	(6	)	8.91	%	December 2019
BGE - Maryland (Electric)	May 24, 2019	$	74		10.3	%	December 2019
BGE - Maryland (Natural Gas)	May 24, 2019	$	59		10.3	%	December 2019
Pepco - District of Columbia (Electric)^(b)	May 30, 2019	$	162		10.3	%	Second 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)	Reflects a three-year cumulative multi-year plan and total requested revenue requirement increases of $85 million, $40 million and $37 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 Increase (Decrease)			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 is not expected to have a material impact on PECO’s 2017, 2018, or 2019 annual transmission revenue requirements. A final order from FERC is not expected prior to the fourth quarter of 2019. 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.

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 $78 million, $52 million, $16 million, $10 million, $3 million, $5 million and $2 million, respectively, as of June 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 $88 million primarily due to an increase of $117 million in Energy Efficiency Costs, partially offset by a decrease of $38 million in Electric Distribution Formula Rate Annual Reconciliations.

BGE. Regulatory liabilities decreased $71 million primarily due to a decrease of $31 million in Deferred Income Taxes and $29 million in Removal Costs.

Pepco. Regulatory assets decreased $50 million primarily due to a decrease of $21 million in Electric Energy and Natural Gas Costs and $16 million in DC PLUG charge.

DPL. Regulatory liabilities decreased $36 million primarily due to a decrease of $21 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
June 30, 2019	$	61	$	5	$	—	$	48	$	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 $10 million for the three and six months ended June 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. Generation, CENG and the state’s answers and briefs were filed on March 30, 2018. On December 17, 2018, plaintiffs filed a reply brief introducing new arguments and new evidence. The State of New York filed a motion to strike on December 28, 2018. On January 4, 2019, Generation and CENG filed a motion to strike the new arguments and new evidence. The court must now decide whether or not to set the case for hearing.

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) with MDE for Conowingo, Generation continues to work with MDE and other stakeholders to resolve water quality licensing issues, including: (1) water quality, (2) fish habitat, and (3) sediment.

On April 27, 2018, the 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 in 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 violating MDE regulations, 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 proposed by MDE in April 2018. Exelon also continues to challenge the 401 Certification through the administrative process and in state and federal court. Exelon and Generation cannot predict the final outcome or its financial impact, if any, on Exelon or Generation.

As of June 30, 2019, $40 million of direct costs associated with Conowingo licensing efforts have been capitalized. See Note 4 — Regulatory Matters of the Exelon 2018 Form 10-K for additional information on Generation's operating license renewal efforts.

Impairment of Long-Lived Assets (Exelon and Generation)	6 Months Ended
Impairment of Long-Lived Assets (Exelon and Generation)	Jun. 30, 2019
Property, Plant and Equipment [Abstract]
Asset Impairment Charges [Text Block]	Impairment of Long-Lived Assets (Exelon and Generation) Registrants evaluate long-lived assets for recoverability whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. 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. Changes in those inputs could potentially result in material future impairments of the Registrants' long-lived assets. 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 June 30, 2019, Generation had approximately $740 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 $1,950 million of additional net long-lived assets as of June 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)

6 Months Ended

Jun. 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 programs 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 or about September 30, 2019. Generation filed the required market and regulatory notifications to shut down the plant and PJM approved the deactivation. On April 5, 2019, Generation filed the PSDAR with the NRC detailing the plans for TMI after its final shutdown.

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 in September 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 six months ended June 30, 2019 and 2018 are summarized in the table below.



	Three Months Ended June 30,				Six Months Ended June 30,
Income statement expense (pre-tax)	2019		2018		2019			2018
Depreciation and amortization^(a)
Accelerated depreciation	$	71	$	152	$	145		$	289
Accelerated nuclear fuel amortization	4		19		9			34
Operating and maintenance^(b)	—		2		(83		)	28
Total	$	75	$	173	$	71		$	351

_________


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


(b)	In 2019, primarily reflects decrease to estimated decommissioning costs for TMI. 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.

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. FERC has ordered ISO-NE to file long-term, market-based fuel security rules by October 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 July 15, 2019, FERC held a staff-led public meeting on the long-term, market-based fuel security proposal.

The following table provides the balance sheet amounts as of June 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 a decision to permanently cease generation operations in the absence of long-term market rule changes.



	June 30, 2019
Asset Balances
Materials and supplies inventory	$	30
Fuel inventory	11
Completed plant, net	896
Construction work in progress	4
Liability Balances
Asset retirement obligation	(1		)

Fair Value of Financial Assets and Liabilities (All Registrants)

6 Months Ended

Jun. 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 June 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.



	June 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	$	35,685	$	36,248	$	2,569	$	38,817	$	35,424	$	33,711	$	2,158	$	35,869
Generation	8,704		7,822		1,472		9,294		8,793		7,467		1,443		8,910
ComEd	8,195		9,222		—		9,222		8,101		8,390		—		8,390
PECO	3,085		3,415		50		3,465		3,084		3,157		50		3,207
BGE	2,877		3,197		—		3,197		2,876		2,950		—		2,950
PHI	6,509		5,823		1,047		6,870		6,259		5,436		665		6,101
Pepco	2,860		3,134		377		3,511		2,719		2,901		196		3,097
DPL	1,495		1,396		218		1,614		1,494		1,303		193		1,496
ACE	1,329		1,025		451		1,476		1,188		987		275		1,262
Long-Term Debt to Financing Trusts^(a)
Exelon	$	390	$	—	$	415	$	415	$	390	$	—	$	400	$	400
ComEd	205		—		209		209		205		—		209		209
PECO	184		—		206		206		184		—		191		191
SNF Obligation
Exelon	$	1,186	$	1,025	$	—	$	1,025	$	1,171	$	949	$	—	$	949
Generation	1,186		1,025		—		1,025		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 June 30, 2019 and December 31, 2018:



	Exelon										Generation
As of June 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)	$	648	$	—	$	—	$	—	$	648	$	323	$	—	$	—	$	—	$	323
NDT fund investments
Cash equivalents^(b)	1,241		90		—		—		1,331		1,241		90		—		—		1,331
Equities	3,123		1,638		—		1,328		6,089		3,123		1,638		—		1,328		6,089
Fixed income
Corporate debt	—		1,453		247		—		1,700		—		1,453		247		—		1,700
U.S. Treasury and agencies	1,589		134		—		—		1,723		1,589		134		—		—		1,723
Foreign governments	—		58		—		—		58		—		58		—		—		58
State and municipal debt	—		81		—		—		81		—		81		—		—		81
Other^(c)	—		19		—		955		974		—		19		—		955		974
Fixed income subtotal	1,589		1,745		247		955		4,536		1,589		1,745		247		955		4,536



	Exelon														Generation
As of June 30, 2019	Level 1			Level 2			Level 3			Not subject to leveling		Total			Level 1			Level 2			Level 3			Not subject to leveling		Total
Middle market lending	—			—			292			455		747			—			—			292			455		747
Private equity	—			—			—			379		379			—			—			—			379		379
Real estate	—			—			—			557		557			—			—			—			557		557
NDT fund investments subtotal^(d)	5,953			3,473			539			3,674		13,639			5,953			3,473			539			3,674		13,639
Rabbi trust investments
Cash equivalents	49			—			—			—		49			4			—			—			—		4
Mutual funds	73			—			—			—		73			23			—			—			—		23
Fixed income	—			13			—			—		13			—			—			—			—		—
Life insurance contracts	—			72			40			—		112			—			23			—			—		23
Rabbi trust investments subtotal	122			85			40			—		247			27			23			—			—		50
Commodity derivative assets
Economic hedges	505			2,148			1,875			—		4,528			505			2,148			1,875			—		4,528
Proprietary trading	—			44			139			—		183			—			44			139			—		183
Effect of netting and allocation of collateral^(e)(f)	(646		)	(2,042		)	(965		)	—		(3,653		)	(646		)	(2,042		)	(965		)	—		(3,653		)
Commodity derivative assets subtotal	(141		)	150			1,049			—		1,058			(141		)	150			1,049			—		1,058
Total assets	6,582			3,708			1,628			3,674		15,592			6,162			3,646			1,588			3,674		15,070
Liabilities
Commodity derivative liabilities
Economic hedges	(743		)	(2,539		)	(1,606		)	—		(4,888		)	(743		)	(2,539		)	(1,333		)	—		(4,615		)
Proprietary trading	—			(44		)	(71		)	—		(115		)	—			(44		)	(71		)	—		(115		)
Effect of netting and allocation of collateral^(e)(f)	743			2,438			1,228			—		4,409			743			2,438			1,228			—		4,409
Commodity derivative liabilities subtotal	—			(145		)	(449		)	—		(594		)	—			(145		)	(176		)	—		(321		)
Deferred compensation obligation	—			(137		)	—			—		(137		)	—			(36		)	—			—		(36		)
Total liabilities	—			(282		)	(449		)	—		(731		)	—			(181		)	(176		)	—		(357		)
Total net assets	$	6,582		$	3,426		$	1,179		$	3,674	$	14,861		$	6,162		$	3,465		$	1,412		$	3,674	$	14,713



	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 $447 million and $458 million at June 30, 2019 and December 31, 2018, respectively, and restricted cash of $83 million and $80 million at June 30, 2019 and December 31, 2018, respectively, and includes long-term restricted cash of $191 million and $185 million at June 30, 2019 and December 31, 2018, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. Generation excludes cash of $329 million and $283 million at June 30, 2019 and December 31, 2018, respectively, and restricted cash of $45 million and $39 million at June 30, 2019 and December 31, 2018, respectively.


(b)	Includes $75 million and $50 million of cash received from outstanding repurchase agreements at June 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 $827 million and $1,432 million at June 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 $141 million and $130 million at June 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 $97 million, $396 million and $263 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of June 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), $358 million and $(94) million represents variation margin on the exchanges as of June 30, 2019 and December 31, 2018, respectively.

As of June 30, 2019, Exelon and Generation have outstanding commitments to invest in fixed income, middle market lending, private equity and real estate investments of approximately $121 million, $84 million, $396 million, and $252 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 June 30, 2019. Changes were immaterial in fair value, cumulative adjustments and impairments for the three and six months ended June 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 June 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)	$	222	$	—		$	—		$	222		$	9	$	—		$	—	$	9		$	1	$	—		$	—	$	1
Rabbi trust investments
Mutual funds	—		—			—			—			7		—			—		7			7		—			—		7
Life insurance contracts	—		—			—			—			—		10			—		10			—		—			—		—
Rabbi trust investments subtotal	—		—			—			—			7		10			—		17			7		—			—		7
Total assets	222		—			—			222			16		10			—		26			8		—			—		8
Liabilities
Deferred compensation obligation	—		(7		)	—			(7		)	—		(8		)	—		(8		)	—		(5		)	—		(5		)
Mark-to-market derivative liabilities^(b)	—		—			(273		)	(273		)	—		—			—		—			—		—			—		—
Total liabilities	—		(7		)	(273		)	(280		)	—		(8		)	—		(8		)	—		(5		)	—		(5		)
Total net assets (liabilities)	$	222	$	(7	)	$	(273	)	$	(58	)	$	16	$	2		$	—	$	18		$	8	$	(5	)	$	—	$	3



	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 $65 million and $93 million at June 30, 2019 and December 31, 2018, respectively, and restricted cash of $29 million and $28 million at June 30, 2019 and December 31, 2018, respectively, and includes long-term restricted cash of $174 million and $166 million at June 30, 2019 and December 31, 2018, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. PECO excludes cash of $17 million and $24 million at June 30, 2019 and December 31, 2018, respectively. BGE excludes cash of $7 million at both June 30, 2019 and December 31, 2018, and restricted cash of $1 million and $2 million at June 30, 2019 and December 31, 2018, respectively.


(b)	The Level 3 balance consists of the current and noncurrent liability of $29 million and $244 million, respectively, at June 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 June 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)	$	87	$	—		$	—	$	87		$	147	$	—		$	—	$	147
Rabbi trust investments
Cash equivalents	44		—			—		44			42		—			—		42
Mutual funds	13		—			—		13			13		—			—		13
Fixed income	—		13			—		13			—		15			—		15
Life insurance contracts	—		23			40		63			—		22			38		60
Rabbi trust investments subtotal	57		36			40		133			55		37			38		130
Total assets	144		36			40		220			202		37			38		277
Liabilities
Deferred compensation obligation	—		(19		)	—		(19		)	—		(21		)	—		(21		)
Total liabilities	—		(19		)	—		(19		)	—		(21		)	—		(21		)
Total net assets	$	144	$	17		$	40	$	201		$	202	$	16		$	38	$	256



	Pepco										DPL								ACE
As of June 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)	$	40	$	—		$	—	$	40		$	1	$	—	$	—	$	1	$	19	$	—	$	—	$	19
Rabbi trust investments
Cash equivalents	43		—			—		43			—		—		—		—		—		—		—		—
Fixed income	—		3			—		3			—		—		—		—		—		—		—		—
Life insurance contracts	—		23			39		62			—		—		—		—		—		—		—		—
Rabbi trust investments subtotal	43		26			39		108			—		—		—		—		—		—		—		—
Total assets	83		26			39		148			1		—		—		1		19		—		—		19
Liabilities
Deferred compensation obligation	—		(2		)	—		(2		)	—		—		—		—		—		—		—		—
Total liabilities	—		(2		)	—		(2		)	—		—		—		—		—		—		—		—
Total net assets	$	83	$	24		$	39	$	146		$	1	$	—	$	—	$	1	$	19	$	—	$	—	$	19



	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 $21 million and $39 million at June 30, 2019 and December 31, 2018, respectively, and includes long-term restricted cash of $17 million and $19 million at June 30, 2019 and December 31, 2018, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. Pepco excludes cash of $12 million and $15 million at June 30, 2019 and December 31, 2018, respectively. DPL excludes cash of $3 million and $8 million at June 30, 2019 and December 31, 2018, respectively. ACE excludes cash of $4 million and $7 million at June 30, 2019 and December 31, 2018, respectively, and includes long-term restricted cash of $17 million and $19 million at June 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 six months ended June 30, 2019 and 2018:



	Exelon			Generation										ComEd				PHI and Pepco
Three Months Ended June 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 March 31, 2019	$	838		$	540		$	499			$	1,039		$	(240	)		$	39	$	—
Total realized / unrealized gains (losses)
Included in net income	275			2			272			^(a)	274			—				1		—
Included in noncurrent payables to affiliates	—			10			—				10			—				—		(10		)
Included in regulatory assets/liabilities	(23		)	—			—				—			(33		)	^(b)	—		10
Change in collateral	106			—			106				106			—				—		—
Purchases, sales, issuances and settlements
Purchases	51			40			11				51			—				—		—
Sales	(1		)	—			(1		)		(1		)	—				—		—
Settlements	(53		)	(53		)	—				(53		)	—				—		—
Transfers into Level 3	3			—			3			^(c)	3			—				—		—
Transfers out of Level 3	(17		)	—			(17		)	^(c)	(17		)	—				—		—
Balance at June 30, 2019	$	1,179		$	539		$	873			$	1,412		$	(273	)		$	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 June 30, 2019	$	339		$	1		$	337			$	338		$	—			$	1	$	—



	Exelon			Generation										ComEd				PHI and Pepco
Six Months Ended June 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	46			3			41			^(a)	44			—				2		—
Included in noncurrent payables to affiliates	—			21			—				21			—				—		(21		)
Included in regulatory assets	(3		)	—			—				—			(24		)	^(b)	—		21
Change in collateral	187			—			187				187			—				—		—
Purchases, sales, issuances and settlements
Purchases	110			42			68				110			—				—		—
Sales	(1		)	—			(1		)		(1		)	—				—		—
Settlements	(70		)	(70		)	—				(70		)	—				—		—
Transfers into Level 3	3			—			3			^(c)	3			—				—		—
Transfers out of Level 3	—			—			—			^(c)	—			—				—		—
Balance as of June 30, 2019	$	1,179		$	539		$	873			$	1,412		$	(273	)		$	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 June 30, 2019	$	191		$	3		$	186			$	189		$	—			$	2	$	—

__________


(a)	Includes a reduction for the reclassification of $65 million and $145 million of realized gains due to the settlement of derivative contracts for the three and six months ended June 30, 2019, respectively.

(b)

Includes $41 million of decreases in fair value and an increase for realized losses due to settlements of $8 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended June 30, 2019. Includes $37 million of increases in fair value and an increase for realized losses due to settlements of $13 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the six months ended June 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 June 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 March 31, 2018	$	1,283		$	609		$	918			$	1,527		$	(267	)		$	23	$	—
Total realized / unrealized gains (losses)
Included in net income	(112		)	—			(113		)	^(a)	(113		)	—				1		—
Included in noncurrent payables to affiliates	—			(3		)	—				(3		)	—				—		3
Included in regulatory assets	12			—			—				—			15			^(b)	—		(3		)
Change in collateral	(49		)	—			(49		)		(49		)	—				—		—
Purchases, sales, issuances and settlements
Purchases	30			17			13				30			—				—		—
Sales	(1		)	—			(1		)		(1		)	—				—		—
Settlements	(26		)	(38		)	—				(38		)	—				12		—
Transfers into Level 3	(15		)	—			(15		)	^(c)	(15		)	—				—		—
Transfers out of Level 3	(16		)	—			(16		)	^(c)	(16		)	—				—		—
Balance as of June 30, 2018	$	1,106		$	585		$	737			$	1,322		$	(252	)		$	36	$	—
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of June 30, 2018	$	3		$	(4	)	$	7			$	3		$	—			$	—	$	—



	Exelon			Generation										ComEd				PHI and Pepco
Six Months Ended June 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	74			1			71			^(a)	72			—				2		—
Included in noncurrent payables to affiliates	—			3			—				3			—				—		(3		)
Included in regulatory assets	7			—			—				—			4			^(b)	—		3
Change in collateral	57			—			57				57			—				—		—
Purchases, sales, issuances and settlements
Purchases	119			19			100				119			—				—		—
Sales	(4		)	—			(4		)		(4		)	—				—		—
Settlements	(74		)	(86		)	—				(86		)	—				12		—
Transfers into Level 3	(23		)	—			(23		)	^(c)	(23		)	—				—		—
Transfers out of Level 3	(16		)	—			(16		)	^(c)	(16		)	—				—		—
Balance as of June 30, 2018	$	1,106		$	585		$	737			$	1,322		$	(252	)		$	36	$	—
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of June 30, 2018	$	259		$	(4	)	$	263			$	259		$	—			$	—	$	—

__________


(a)	Includes a reduction for the reclassification of $120 million and $192 million of realized gains due to the settlement of derivative contracts for the three and six months ended June 30, 2018, respectively.

(b)

Includes $11 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 June 30, 2018. Includes $6 million of increases in fair value and an increase for realized losses due to settlements of $10 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the six months ended June 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 six months ended June 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 gains (losses) for the three months ended June 30, 2019	$	275	$	(3	)	$	1	$	2	$	275	$	(3	)	$	2	$	1
Total realized (losses) gains for the six months ended June 30, 2019	147		(106		)	2		3		147		(106		)	3		2
Total unrealized gains (losses) for the three months ended June 30, 2019	360		(23		)	1		1		360		(23		)	1		1
Total unrealized gains (losses) for the six months ended June 30, 2019	269		(83		)	2		3		269		(83		)	3		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 June 30, 2018	$	(191	)	$	78		$	1	$	—		$	(191	)	$	78		$	—		$	1
Total realized gains (losses) for the six months ended June 30, 2018	144			(73		)	2		2			144			(73		)	2			2
Total unrealized (losses) gains for the three months ended June 30, 2018	(71		)	78			—		(4		)	(71		)	78			(4		)	—
Total unrealized gains (losses) for the six months ended June 30, 2018	238			25			—		(3		)	238			25			(3		)	—

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



Type of trade	Fair Value at June 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)	$	542		$	443		Discounted Cash Flow	Forward power price	$10	-	$118	$12	-	$174
								Forward gas price	$1.54	-	$11.26	$0.78	-	$12.38
							Option Model	Volatility percentage	8%	-	384%	10%	-	277%

Mark-to-market derivatives — Proprietary trading (Exelon and Generation)^(a)(b)	$	68		$	56		Discounted Cash Flow	Forward power price	$10	-	$118	$14	-	$174

Mark-to-market derivatives (Exelon and ComEd)	$	(273	)	$	(249	)	Discounted Cash Flow	Forward heat rate^(c)	9x	-	10x	10x	-	11x
								Marketability reserve	4%	-	7%	4%	-	8%
								Renewable factor	88%	-	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 $263 million and $76 million as of June 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)

6 Months Ended

Jun. 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 June 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 Generation, ComEd and Exelon as of June 30, 2019 and December 31, 2018:



June 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)	$	526		$	2,910		$	122		$	218	$	(2,724	)	$	526		$	—
Mark-to-market derivative assets (noncurrent assets)	532			1,618			61			122		(1,269		)	532			—
Total mark-to-market derivative assets	1,058			4,528			183			340		(3,993		)	1,058			—
Mark-to-market derivative liabilities (current liabilities)	(157		)	(3,039		)	(78		)	265		2,724			(128		)	(29		)
Mark-to-market derivative liabilities (noncurrent liabilities)	(437		)	(1,576		)	(37		)	151		1,269			(193		)	(244		)
Total mark-to-market derivative liabilities	(594		)	(4,615		)	(115		)	416		3,993			(321		)	(273		)
Total mark-to-market derivative net assets (liabilities)	$	464		$	(87	)	$	68		$	756	$	—		$	737		$	(273	)



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), $358 million and $(94) million represents variation margin on the exchanges at June 30, 2019 and December 31, 2018 respectively.

Economic Hedges (Commodity Price Risk)

Generation. For the three and six months ended June 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 June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Income Statement Location	Gain (Loss)						Gain (Loss)
Operating revenues	$	40		$	(7	)	$	(10	)	$	(107	)
Purchased power and fuel	(114		)	96			(84		)	(70		)
Total Exelon and Generation	$	(74	)	$	89		$	(94	)	$	(177	)

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 June 30, 2019, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York and ERCOT reportable segments is 92%-95%, 70%-73% and 40%-43% 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 six months ended June 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 $1,373 million and $1,420 million at June 30, 2019 and December 31, 2018, respectively, for Exelon and $573 million and $620 million at June 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 $219 million and $268 million at June 30, 2019 and December 31, 2018, respectively.

The mark-to-market derivative assets and liabilities as of June 30, 2019 and December 31, 2018 and the mark-to-market gains and losses for the three and six months ended June 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 June 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 $70 million, $30 million, $32 million, $39 million, $15 million and $8 million as of June 30, 2019, respectively.



Rating as of June 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	$	859	$	12	$	847	2	$	249
Non-investment grade	30		11		19
No external ratings
Internally rated — investment grade	204		1		203
Internally rated — non-investment grade	117		11		106
Total	$	1,210	$	35	$	1,175	2	$	249



Net Credit Exposure by Type of Counterparty	As of June 30, 2019
Financial institutions	$	3
Investor-owned utilities, marketers, power producers	810
Energy cooperatives and municipalities	302
Other	60
Total	$	1,175

_________


(a)	As of June 30, 2019, credit collateral held from counterparties where Generation had credit exposure included $25 million of cash and $9 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 June 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	June 30, 2019			December 31, 2018
Gross fair value of derivative contracts containing this feature^(a)	$	(1,119	)	$	(1,723	)
Offsetting fair value of in-the-money contracts under master netting arrangements^(b)	824			1,105
Net fair value of derivative contracts containing this feature^(c)	$	(295	)	$	(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 June 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.



	June 30, 2019		December 31, 2018
Cash collateral posted	$	781	$	418
Letters of credit posted	228		367
Cash collateral held	64		47
Letters of credit held	21		44
Additional collateral required in the event of a credit downgrade below investment grade	1,513		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 June 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 June 30, 2019, they could have been required to post incremental collateral to its counterparties of $31 million, $31 million and $12 million, respectively.

Debt and Credit Agreements (All Registrants)

6 Months Ended

Jun. 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 June 30, 2019 and December 31, 2018. Generation and PECO had no commercial paper borrowings as of both June 30, 2019 and December 31, 2018.



	Outstanding Commercial Paper as of				Average Interest Rate on Commercial Paper Borrowings as of
Commercial Paper Issuer	June 30, 2019		December 31, 2018		June 30, 2019		December 31, 2018
Exelon	$	559	$	89	2.60	%	2.15	%
ComEd	303		—		2.59	%	2.14	%
BGE	229		35		2.58	%	2.18	%
PHI	27		54		2.61	%	2.15	%
PEPCO	—		40		2.62	%	2.24	%
DPL	—		—		2.55	%	2.07	%
ACE	27		14		2.61	%	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 six months ended June 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	$	2	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.
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	Repay existing indebtedness and for general corporate purposes
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 June 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 June 30, 2019, approximately $500 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 June 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 June 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)

6 Months Ended

Jun. 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 June 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	5.4	5.5	8.2	(1.2)	6.5	4.8	2.0	7.0	7.0
Qualified NDT fund income	5.1	16.2	—	—	—	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(0.7)	(1.9)	(0.2)	—	(0.1)	(0.2)	(0.1)	(0.2)	(0.3)
Plant basis differences	(1.7)	—	(0.6)	(5.9)	(1.5)	(1.7)	(2.1)	(0.3)	(2.2)
Production tax credits and other credits	(0.9)	(2.8)	—	—	(0.1)	—	—	—	—
Noncontrolling interests	0.1	0.4	—	—	—	—	—	—	—
Excess deferred tax amortization	(7.8)	—	(9.0)	(2.7)	(7.9)	(19.4)	(18.3)	(15.7)	(23.1)
Other	1.9	0.2	0.4	0.1	1.7	0.9	0.5	—	(2.4)
Effective income tax rate	22.4%	38.6%	19.8%	11.3%	19.6%	5.4%	3.0%	11.8%	—%



	Three Months Ended June 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	3.4	4.3	8.1	(3.4)	6.5	6.2	4.7	6.5	7.6
Qualified NDT fund income	0.2	0.5	—	—	—	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(0.9)	(2.4)	(0.2)	(0.1)	(0.2)	(0.2)	(0.1)	(0.3)	(0.3)
Plant basis differences	(3.0)	—	(0.1)	(17.2)	(0.7)	(1.2)	(2.0)	—	(0.2)
Production tax credits and other credits	(1.7)	(4.9)	(0.1)	—	—	—	—	—	—
Noncontrolling interests	(1.5)	(4.5)	—	—	—	—	—	—	—
Excess deferred tax amortization	(5.2)	—	(7.6)	(0.3)	(7.2)	(11.3)	(11.7)	(11.2)	(8.8)
Tax Cuts and Jobs Act of 2017	(1.3)	(1.7)	(0.7)	—	0.1	0.8	—	—	—
Other	(0.2)	(1.3)	0.4	(1.1)	0.8	(0.1)	(0.4)	0.1	0.7
Effective income tax rate	10.8%	11.0%	20.8%	(1.1)%	20.3%	15.2%	11.5%	16.1%	20.0%




	Six Months Ended June 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	4.4	3.6	8.2	0.2	6.4	4.7	2.0	6.7	6.9
Qualified NDT fund income	6.5	14.7	—	—	—	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(0.6)	(1.1)	(0.2)	—	(0.1)	(0.2)	(0.1)	(0.2)	(0.3)
Plant basis differences	(1.5)	—	(0.6)	(6.4)	(1.0)	(1.7)	(2.0)	(0.6)	(2.2)
Production tax credits and other credits	(0.8)	(1.8)	—	—	—	—	—	—	—
Noncontrolling interests	(0.3)	(0.8)	—	—	—	—	—	—	—
Excess deferred tax amortization	(5.8)	—	(8.8)	(2.6)	(7.9)	(19.4)	(18.1)	(15.6)	(23.4)
Other	0.7	(0.4)	0.2	(0.1)	0.2	0.3	0.5	0.4	2.0
Effective income tax rate	23.6%	35.2%	19.8%	12.1%	18.6%	4.7%	3.3%	11.7%	4.0%



	Six Months Ended June 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	3.8	3.4	8.1	(3.6)	6.4	5.5	3.7	6.4	7.2
Qualified NDT fund income	(0.1)	(0.4)	—	—	—	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(1.1)	(3.3)	(0.2)	(0.1)	(0.1)	(0.2)	(0.1)	(0.3)	(0.3)
Plant basis differences	(2.8)	—	—	(15.6)	(0.7)	(1.8)	(2.5)	(0.7)	(1.3)
Production tax credits and other credits	(2.3)	(7.2)	(0.1)	—	—	—	—	—	—
Noncontrolling interests	(1.1)	(3.5)	—	—	—	—	—	—	—
Excess deferred tax amortization	(5.6)	—	(7.5)	(2.7)	(8.2)	(11.0)	(12.1)	(9.4)	(8.8)
Tax Cuts and Jobs Act of 2017	(0.6)	(0.9)	(0.3)	—	—	0.5	—	—	—
Other	(1.7)	(1.3)	0.1	(0.4)	0.2	(0.1)	(0.4)	0.4	(1.1)
Effective income tax rate	9.5%	7.8%	21.1%	(1.4)%	18.6%	13.9%	9.6%	17.4%	16.7%

Accounting for Uncertainty in Income Taxes

The Registrants have the following unrecognized tax benefits as of June 30, 2019 and December 31, 2018:



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
June 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

As of June 30, 2019, Exelon, Generation, PHI and ACE have approximately $425 million, $411 million, $14 million and $14 million, respectively, of 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, and the outcomes of pending court cases. Of the above unrecognized tax benefits, Exelon and Generation have $411 million that, if recognized, would decrease the effective tax rate. The unrecognized tax benefits related to PHI and ACE, if

recognized, may be included in future regulated base rates and that portion would have no impact to the effective tax rate.

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)

6 Months Ended

Jun. 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 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 June 30, 2019:



Nuclear decommissioning ARO at December 31, 2018 ^(a)(b)	$	10,005
Accretion expense	243
Net increase due to changes in, and timing of, estimated future cash flows	232
Costs incurred related to decommissioning plants	(43		)
Nuclear decommissioning ARO at June 30, 2019 ^(a)(b)	$	10,437

_________


(a)	Includes $99 million and $22 million as the current portion of the ARO at June 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 $755 million and $772 million of ARO related to Oyster Creek which is classified as Liabilities held for sale in Exelon's and Generation's Consolidated Balance Sheets at June 30, 2019 and December 31, 2018, respectively. See Note 3 — Mergers, Acquisitions and Dispositions for additional information.

During the six months ended June 30, 2019, Exelon's and Generation’s total nuclear ARO increased by approximately $432 million, primarily reflecting the accretion of the ARO liability due to the passage of time and the impacts of ARO updates completed during first quarter 2019. The first quarter 2019 ARO update includes 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 in anticipation of its September 2019 shutdown date. Approximately $85 million of the TMI ARO adjustment resulted in a 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.

NDT Funds (Exelon and Generation)

Exelon and Generation had NDT funds totaling $13,498 million and $12,695 million at June 30, 2019 and December 31, 2018, respectively. The NDT funds include $857 million and $890 million at June 30, 2019 and December 31, 2018, respectively, related to Oyster Creek NDT funds which are 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 $127 million and $144 million for the current portion of the NDT funds at June 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)

6 Months Ended

Jun. 30, 2019

Retirement Benefits [Abstract]

Retirement Benefits (All Registrants)

Exelon sponsors defined benefit pension plans and other postretirement benefit plans for essentially all current employees. Substantially all non-union employees and electing union employees hired on or after January 1, 2001 participate in cash balance pension plans. Effective January 1, 2009, substantially all newly-hired union-represented employees participate in cash balance pension plans. Effective February 1, 2018, most newly-hired Generation and BSC non-represented employees are not eligible for pension benefits and will instead be eligible to receive an enhanced non-discretionary employer contribution in an Exelon defined contribution savings plan. Effective January 1, 2018, most newly-hired non-represented employees are not eligible for OPEB benefits and employees represented by Local 614 are not eligible for retiree health care benefits.

Effective January 1, 2019, Exelon merged the Exelon Corporation Cash Balance Pension Plan (CBPP) into the Exelon Corporation Retirement Program (ECRP). The merging of the plans 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 Other Postretirement Benefits

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 other postretirement benefit 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 six months ended June 30, 2019 and 2018.



	Pension Benefits Three Months Ended June 30,						Other Postretirement Benefits Three Months Ended June 30,
	2019			2018			2019			2018
Components of net periodic benefit cost:
Service cost	$	89		$	102		$	24		$	28
Interest cost	221			200			47			44
Expected return on assets	(306		)	(313		)	(38		)	(43		)
Amortization of:
Prior service benefit	—			—			(44		)	(47		)
Actuarial loss	103			157			10			16
Settlement charges	—			1			—			—
Net periodic benefit cost	$	107		$	147		$	(1	)	$	(2	)




	Pension Benefits Six Months Ended June 30,						Other Postretirement Benefits Six Months Ended June 30,
	2019			2018			2019			2018
Components of net periodic benefit cost:
Service cost	$	178		$	202		$	47		$	56
Interest cost	442			401			94			88
Expected return on assets	(612		)	(626		)	(77		)	(87		)
Amortization of:
Prior service cost (benefit)	—			1			(89		)	(93		)
Actuarial loss	206			314			23			33
Settlement charges	—			1			—			—
Net periodic benefit cost	$	214		$	293		$	(2	)	$	(3	)

The amounts below represent Exelon's, Generation's, ComEd's, PECO's, BGE's, PHI's, Pepco's, DPL's, and ACE's pension and postretirement benefit plan costs. For Exelon, the service cost component is included in Operating and maintenance expense and Property, plant and equipment, net, for the three and six months ended June 30, 2019 and 2018, while the non-service cost components are included in Other, net and Regulatory assets for the three and six months ended June 30, 2019 and 2018. For the Registrants other than Exelon, the service cost and non-service cost components are included in Operating and maintenance expense and Property, plant and equipment, net in their consolidated financial statements for the three and six months ended June 30, 2019 and 2018.



	Three Months Ended June 30,				Six Months Ended June 30,
Pension and Other Postretirement Benefit Costs	2019		2018		2019		2018
Exelon	$	106	$	145	$	212	$	290
Generation	31		51		62		100
ComEd	23		44		47		88
PECO	3		5		5		10
BGE	16		15		30		30
PHI	24		17		48		34
Pepco	6		3		12		8
DPL	4		2		8		3
ACE	4		3		8		6

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 six months ended June 30, 2019 and 2018, respectively.



	Three Months Ended June 30,				Six Months Ended June 30,
Savings Plan Matching Contributions	2019		2018		2019		2018
Exelon	$	33	$	50	$	64	$	82
Generation	14		28		28		43
ComEd	9		8		16		15
PECO	2		2		5		4
BGE	2		2		4		4
PHI	3		3		6		6
Pepco	1		1		2		2
DPL	1		1		1		1
ACE	—		—		1		1

Changes in Accumulated Other Comprehensive Income (Exelon and Generation)

6 Months Ended

Jun. 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 and Generation)

The following tables present changes in accumulated other comprehensive income (loss) (AOCI) by component for the six months ended June 30, 2019 and 2018:



Six Months Ended June 30, 2019	Losses on Cash Flow Hedges			Pension and Non-Pension Postretirement Benefit Plan Items			Foreign Currency Items			AOCI of Investments in Unconsolidated Affiliates			Total
Exelon^(a)
Beginning balance	$	(2	)	$	(2,960	)	$	(33	)	$	—		$	(2,995	)
OCI before reclassifications	—			(39		)	4			(2		)	(37		)
Amounts reclassified from AOCI^(b)	—			42			—			—			42
Net current-period OCI	—			3			4			(2		)	5
Ending balance	$	(2	)	$	(2,957	)	$	(29	)	$	(2	)	$	(2,990	)
Generation^(a)
Beginning balance	$	(4	)	$	—		$	(33	)	$	(1	)	$	(38	)
OCI before reclassifications	—			—			4			(2		)	2
Amounts reclassified from AOCI	—			—			—			—			—
Net current-period OCI	—			—			4			(2		)	2
Ending balance	$	(4	)	$	—		$	(29	)	$	(3	)	$	(36	)



Six Months Ended June 30, 2018	Gains (Losses) on Cash Flow Hedges			Unrealized gains (losses) on Marketable Securities			Pension and Non-Pension Postretirement Benefit Plan Items				Foreign Currency Items			AOCI of Investments in Unconsolidated Affiliates			Total
Exelon^(a)
Beginning balance	$	(14	)	$	10		$	(2,998	)	^(d)	$	(23	)	$	(1	)	$	(3,026	)
OCI before reclassifications	13			—			20				(6		)	1			28
Amounts reclassified from AOCI^(b)	(1		)	—			88				—			—			87
Net current-period OCI	12			—			108				(6		)	1			115
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard^(c)	—			(10		)	—				—			—			(10		)
Ending balance	$	(2	)	$	—		$	(2,890	)		$	(29	)	$	—		$	(2,921	)
Generation^(a)
Beginning balance	$	(16	)	$	3		$	—			$	(23	)	$	(1	)	$	(37	)
OCI before reclassifications	13			—			—				(6		)	1			8
Amounts reclassified from AOCI	(1		)	—			—				—			—			(1		)
Net current-period OCI	12			—			—				(6		)	1			7
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard^(c)	—			(3		)	—				—			—			(3		)
Ending balance	$	(4	)	$	—		$	—			$	(29	)	$	—		$	(33	)

_________


(a)	All amounts are net of tax and noncontrolling interests. Amounts in parenthesis represent a decrease in AOCI.


(b)	See next tables for details about these reclassifications.

(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 and $3 million for Exelon and Generation, respectively. The amounts reclassified related to Rabbi Trusts. See Note 1 — Significant Accounting Policies of the Exelon 2018 Form 10-K for additional information.

(d)

Exelon early adopted the new standard Reclassification of Certain Tax Effects from AOCI. The standard was adopted retrospectively as of December 31, 2017, which resulted in an increase to Exelon’s Retained earnings and Accumulated other comprehensive loss of $539 million, primarily related to deferred income taxes associated with Exelon’s pension and OPEB obligations. See Note 1 — Significant Accounting Policies of the Exelon 2018 Form 10-K for additional information.

ComEd, PECO, BGE, PHI, Pepco, DPL and ACE did not have any reclassifications out of AOCI to Net income during the three and six months ended June 30, 2019 and 2018. The following tables present amounts reclassified out of AOCI to Net income for Exelon during the three and six months ended June 30, 2019 and 2018.

Three Months Ended June 30, 2019



Details about AOCI components	Items reclassified out of AOCI^(a)			Affected line item in the Statement of Operations and Comprehensive Income
	Exelon
Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)	$	22
Actuarial losses^(b)	(49		)
	(27		)	Total before tax
	7			Tax benefit
	$	(20	)	Net of tax

Six Months Ended June 30, 2019



Details about AOCI components	Items reclassified out of AOCI^(a)			Affected line item in the Statement of Operations and Comprehensive Income
	Exelon
Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)	$	44
Actuarial losses^(b)	(100		)
	(56		)	Total before tax
	14			Tax benefit
	$	(42	)	Net of tax

Three Months Ended June 30, 2018



Details about AOCI components	Items reclassified out of AOCI^(a)			Affected line item in the Statement of Operations and Comprehensive Income
	Exelon
Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)	$	23
Actuarial losses^(b)	(83		)
	(60		)	Total before tax
	16			Tax benefit
	$	(44	)	Net of tax

Six Months Ended June 30, 2018



Details about AOCI components	Items reclassified out of AOCI^(a)			Affected line item in the Statement of Operations and Comprehensive Income
	Exelon
Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)	$	46
Actuarial losses^(b)	(166		)
	(120		)	Total before tax
	32			Tax benefit
	$	(88	)	Net of tax

_________


(a)	Amounts in parenthesis represent a decrease in net income.


(b)	This AOCI component is included in the computation of net periodic pension and OPEB cost. See Note 14 — Retirement Benefits for additional information.

The following table presents income tax benefit (expense) allocated to each component of other comprehensive income (loss) during the three and six months ended June 30, 2019 and 2018:



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Exelon
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	$	6		$	6		$	12		$	12
Actuarial loss reclassified to periodic benefit cost	(13		)	(22		)	(26		)	(44		)
Pension and non-pension postretirement benefit plans valuation adjustment	—			1			14			(6		)
Change in unrealized loss on cash flow hedges	—			(1		)	—			(4		)
Change in unrealized gain (loss) on investments in unconsolidated affiliates	1			—			1			(1		)
Total	$	(6	)	$	(16	)	$	1		$	(43	)

Generation
Change in unrealized gain (loss) on cash flow hedges	$	—		$	(1	)	$	—		$	(4	)
Change in unrealized gain (loss) on investments in unconsolidated affiliates	1			—			1			(1		)
Total	$	1		$	(1	)	$	1		$	(5	)

Commitments and Contingencies (All Registrants)

6 Months Ended

Jun. 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). The merger of Exelon and PHI was approved in Delaware, New Jersey, Maryland and the District of Columbia. Exelon and PHI agreed to certain commitments including where applicable: customer rate credits, funding for energy efficiency and delivery system modernization programs, a green sustainability fund, workforce development initiatives, charitable contributions, renewable

generation and other required commitments. In addition, the orders approving the merger in Delaware, New Jersey, and Maryland include a “most favored nation” provision which, generally, requires allocation of merger benefits proportionally across all the jurisdictions.

The following amounts represent total commitment costs for Exelon, PHI, Pepco, DPL and ACE that have been recorded since the acquisition date and the remaining obligations as of June 30, 2019:



Description	Expected Payment Period	Exelon		PHI		Pepco		DPL		ACE
Rate credits	2016 - 2021	$	264	$	264	$	91	$	72	$	101
Energy efficiency	2016 - 2021	117		—		—		—		—
Charitable contributions	2016 - 2026	50		50		28		12		10
Delivery system modernization	Q2 2017	22		—		—		—		—
Green sustainability fund	Q2 2017	14		—		—		—		—
Workforce development	2016 - 2020	17		—		—		—		—
Other		29		6		1		5		—
Total commitments		$	513	$	320	$	120	$	89	$	111
Remaining commitments		$	116	$	86	$	69	$	11	$	6

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 June 30, 2019, 27 MWs of new generation were developed and Exelon and Generation have incurred costs of $102 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.

Pursuant to the various jurisdictions' merger approval conditions, over specified periods Pepco, DPL and ACE are not permitted to reduce employment levels due to involuntary attrition associated with the merger integration process and have made other commitments regarding hiring and relocation of positions.

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



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Letters of credit	$	1,315	$	1,283	$	7	$	—	$	9	$	10	$	10	$	—	$	—
Surety bonds^(a)	1,492		1,271		52		9		17		39		31		4		3
Financing trust guarantees	378		—		200		178		—		—		—		—		—
Guaranteed lease residual values^(b)	26		—		—		—		—		26		9		11		7
Total commercial commitments	$	3,211	$	2,554	$	259	$	187	$	26	$	75	$	50	$	15	$	10

_________


(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, $23 million of which is a guarantee by Pepco, $28 million by DPL and $17 million by ACE. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.

Nuclear Insurance (Exelon and Generation). Generation is subject to liability, property damage and other risks associated with major incidents at any of its nuclear stations. Generation has mitigated its financial exposure to these risks through insurance and other industry risk-sharing provisions.

The Price-Anderson Act was enacted to ensure the availability of funds for public liability claims arising from an incident at any of the U.S. licensed nuclear facilities and also to limit the liability of nuclear reactor owners for such claims from any single incident. As of June 30, 2019, the current liability limit per incident is $13.9 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors. Changes to account for the effects of inflation occur at least once every five years with the last adjustment effective November 1, 2018. In accordance with the Price-Anderson Act, Generation maintains financial protection at levels equal to the amount of liability insurance available from private sources through the purchase of private nuclear energy liability insurance for public liability claims that could arise in the event of an incident. Effective January 1, 2017, the required amount of nuclear energy liability insurance purchased is $450 million for each operating site. Claims exceeding that amount are covered through mandatory participation in a financial protection pool, as required by the Price Anderson-Act, which provides the additional $13.5 billion per incident in funds available for public liability claims. Participation in this secondary financial protection pool requires the operator of each reactor to fund its proportionate share of costs for any single incident that exceeds the primary layer of financial protection. Exelon’s share of this secondary layer would be approximately $2.9 billion, however any amounts payable under this secondary layer would be capped at $434 million per year.

In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay public liability claims exceeding the $13.9 billion limit for a single incident.

As part of the execution of the NOSA on April 1, 2014, Generation executed an Indemnity Agreement pursuant to which Generation agreed to indemnify EDF and its affiliates against third-party claims that may arise from any future nuclear incident (as defined in the Price-Anderson Act) in connection with the CENG nuclear plants or their operations. Exelon guarantees Generation’s obligations under this indemnity. See Note 2 — Variable Interest Entities of the Exelon 2018 Form 10-K for additional information on Generation’s operations relating to CENG.

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

NEIL may declare distributions to its members as a result of favorable operating experience. In recent years NEIL has made distributions to its members, but Generation cannot predict the level of future distributions or if they will continue at all.

Premiums paid to NEIL by its members are also subject to a potential assessment for adverse loss experience in the form of a retrospective premium obligation. NEIL has never assessed this retrospective premium since its formation in 1973, and Generation cannot predict the level of future assessments if any. The current maximum aggregate annual retrospective premium obligation for Generation is approximately $334 million. NEIL requires its members to maintain an investment grade credit rating or to ensure collectability of their annual retrospective premium obligation by providing a financial guarantee, letter of credit, deposit premium, or some other means of assurance.

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

For its insured losses, Generation is self-insured to the extent that losses are within the policy deductible or exceed the amount of insurance maintained. Uninsured losses and other expenses, to the extent not recoverable from insurers or the nuclear industry, could also be borne by Generation. Any such losses could have a material adverse effect on Exelon’s and Generation’s financial condition, results of operations and cash flows.

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 42 sites, 21 of which have been remediated and approved by the Illinois EPA or the U.S. EPA and 21 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 2023.


•	PECO has identified 26 sites, 17 of which have been remediated in accordance with applicable PA DEP regulatory requirements and 9 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 identified 13 sites, 9 of which have been remediated and approved by the MDE and 4 that require some level of remediation and/or ongoing activity. BGE expects the majority of the remediation at these sites to continue through at least 2019.


•	DPL has identified 3 sites, for 2 of which remediation has been completed and approved by the MDE or the Delaware Department of Natural Resources and Environmental Control. The remaining site is 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. See Note 6 — Regulatory Matters for additional information regarding the associated regulatory assets. 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 June 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:



June 30, 2019	Total environmental investigation and remediation reserve		Portion of total related to MGP investigation and remediation
Exelon	$	482	$	345
Generation	107		—
ComEd	318		318
PECO	25		24
BGE	5		3
PHI	27		—
Pepco	24		—
DPL	1		—
ACE	1		—



December 31, 2018	Total environmental investigation and remediation reserve		Portion of total related to MGP investigation and remediation
Exelon	$	496	$	356
Generation	108		—
ComEd	329		327
PECO	27		25
BGE	5		4
PHI	27		—
Pepco	25		—
DPL	1		—
ACE	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 August 2019 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.

Commencing in February 2012, a number of lawsuits have been filed in the U.S. District Court for the Eastern District of Missouri. Among the defendants were Exelon, Generation and ComEd, all of which were subsequently dismissed from the case, as well as Cotter, which remains a defendant. The suits allege that individuals living in the North St. Louis area developed some form of cancer or other serious illness due to Cotter's negligent or reckless conduct in processing, transporting, storing, handling and/or disposing of radioactive materials. Plaintiffs are asserting public liability claims under the Price-Anderson Act. Their state law claims for negligence, strict liability, emotional distress, and medical monitoring have been dismissed. In the event of a finding of liability against Cotter, it is probable that Generation would be financially responsible due to its indemnification responsibilities of Cotter described above. The court has dismissed a number of the lawsuits as untimely, which has been upheld on appeal. Cotter and the remaining plaintiffs have engaged in settlement discussions pursuant to court-ordered mediation. During the second quarter of 2018, Generation determined a loss was probable based on the advancement of settlement proceedings and recorded an immaterial liability.

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. That generating facility was deactivated in June 2012 and plant structure demolition was completed in July 2015. 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. The RI/FS will form the basis for the remedial actions for the Benning Road site and for the Anacostia River sediment associated with the site. The Consent Decree does not obligate Pepco or Pepco Energy Services to pay for or perform any remediation work, but it is anticipated that DOEE will look to Pepco and Pepco Energy Services to assume responsibility for cleanup of any conditions in the river that are determined to be attributable to past activities at the Benning Road site. Pursuant to Exelon's March 23, 2016 acquisition of PHI, Pepco Energy Services was transferred to Generation.

Since 2013, Pepco and Pepco Energy Services (now Generation) 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 an 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.

Upon DOEE’s approval of the final RI and FS Reports, Pepco and Generation will have satisfied their obligations under the Consent Decree. At that point, DOEE will prepare a Proposed Plan regarding further response actions. After considering public comment on the Proposed Plan, DOEE will issue a Record of Decision identifying any further response actions determined to be necessary. PHI, Pepco and Generation have determined that a loss associated with this matter is probable and have accrued an estimated liability, which is included in the table above.

Anacostia River Tidal Reach (Exelon, PHI and Pepco). Contemporaneous with the Benning RI/FS being performed by Pepco and Generation, DOEE and certain federal agencies have been conducting a separate RI/FS focused on the entire tidal reach of the Anacostia River extending from just north of the Maryland-D.C. boundary line to the confluence of the Anacostia and Potomac Rivers. In March 2016, DOEE released a draft of the river-wide RI Report for public review and comment. 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 addressing the entire tidal reach of the river 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 RI/FS. Pepco responded that it will participate in the Consultative Working Group, but its participation is not an acceptance of any financial responsibility beyond the work that will be performed at the Benning Road site described above. In April 2018, DOEE released a draft remedial investigation report for public review and comment. Pepco submitted written comments to the draft RI and participated in a public hearing. Pepco continues outreach efforts as appropriate to the agencies, governmental officials, community organizations and other key stakeholders. In May 2018 the District of Columbia Council extended the deadline for completion of the Record of Decision from June 30, 2018 until December 31, 2019. An appropriate liability for Pepco’s share of investigation costs has been accrued and is included in the table above. Although Pepco has determined that it is probable that costs for remediation will be incurred, Pepco cannot estimate the reasonably possible range of loss at this time and no liability has been accrued for those future costs. A draft Feasibility Study of potential remedies and their estimated costs is being prepared by the agencies and is expected later in 2019, at which time Pepco will likely be in a better position to estimate the range of loss.

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 Trustees responsible for those resources to restore them to their condition before injury from the environmental contaminants. If natural resources are not restored, then compensation for the injury can be sought from the party responsible for the release of the contaminants. 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 June 30, 2019 and December 31, 2018, Generation had recorded estimated liabilities of approximately $84 million and $79 million, respectively, in total for asbestos-related bodily injury claims. As of June 30, 2019, approximately $24 million of this amount related to 244 open claims presented to Generation, while the remaining $60 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.

There is a reasonable possibility that Exelon may have additional exposure to estimated future asbestos-related bodily injury claims in excess of the amount accrued and the increases 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 2019, could be material to Generation’s results of operations and cash flows.

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)

6 Months Ended

Jun. 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 June 30, 2019
Utility taxes^(a)	$	209	$	32	$	55	$	30	$	21	$	71	$	67	$	4	$	—
Property	148		68		9		4		37		30		21		8		1
Payroll	61		30		7		4		4		7		2		1		1

Three Months Ended June 30, 2018
Utility taxes^(a)	$	218	$	29	$	60	$	30	$	21	$	78	$	73	$	5	$	—
Property	135		65		8		4		34		24		15		8		1
Payroll	65		34		7		4		4		6		2		1		1

Six Months Ended June 30, 2019
Utility taxes^(a)	$	432	$	58	$	118	$	63	$	48	$	145	$	136	$	9	$	—
Property	296		138		15		8		75		60		43		16		1
Payroll	127		64		14		7		8		14		3		2		2

Six Months Ended June 30, 2018
Utility taxes^(a)	$	452	$	60	$	121	$	63	$	47	$	161	$	151	$	10	$	—
Property	271		134		15		7		69		46		29		16		1
Payroll	133		68		14		8		8		14		3		2		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 June 30, 2019
Decommissioning-related activities:
Net realized income on NDT funds^(a)
Regulatory agreement units	$	77		$	77		$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-regulatory agreement units	230			230			—		—		—		—		—		—		—
Net unrealized (losses) gains on NDT funds
Regulatory agreement units	98			98			—		—		—		—		—		—		—
Non-regulatory agreement units	(98		)	(98		)	—		—		—		—		—		—		—
Regulatory offset to NDT fund-related activities^(b)	(141		)	(141		)	—		—		—		—		—		—		—
Decommissioning-related activities	166			166			—		—		—		—		—		—		—
AFUDC — Equity	21			—			4		3		5		9		6		1		2
Non-service net periodic benefit cost	5			—			—		—		—		—		—		—		—

Three Months Ended June 30, 2018
Decommissioning-related activities:
Net realized income on NDT funds^(a)
Regulatory agreement units	$	216		$	216		$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-regulatory agreement units	143			143			—		—		—		—		—		—		—
Net unrealized losses on NDT funds
Regulatory agreement units	(194		)	(194		)	—		—		—		—		—		—		—
Non-regulatory agreement units	(120		)	(120		)	—		—		—		—		—		—		—
Regulatory offset to NDT fund-related activities^(b)	(23		)	(23		)	—		—		—		—		—		—		—
Decommissioning-related activities	22			22			—		—		—		—		—		—		—
AFUDC — Equity	13			—			2		—		4		7		6		1		—
Non-service net periodic benefit cost	(11		)	—			—		—		—		—		—		—		—



	Other, Net
	Exelon			Generation			ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Six Months Ended June 30, 2019
Decommissioning-related activities:
Net realized income on NDT funds^(a)
Regulatory agreement units	$	131		$	131		$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-regulatory agreement units	283			283			—		—		—		—		—		—		—
Net unrealized gains on NDT funds
Regulatory agreement units	476			476			—		—		—		—		—		—		—
Non-regulatory agreement units	182			182			—		—		—		—		—		—		—
Regulatory offset to NDT fund-related activities^(b)	(487		)	(487		)	—		—		—		—		—		—		—
Decommissioning-related activities	585			585			—		—		—		—		—		—		—
AFUDC — Equity	43			—			9		6		10		18		12		2		4
Non-service net periodic benefit cost	10			—			—		—		—		—		—		—		—

Six Months Ended June 30, 2018
Decommissioning-related activities:
Net realized income on NDT funds^(a)
Regulatory agreement units	$	262		$	262		$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-regulatory agreement units	199			199			—		—		—		—		—		—		—
Net unrealized losses on NDT funds
Regulatory agreement units	(268		)	(268		)	—		—		—		—		—		—		—
Non-regulatory agreement units	(215		)	(215		)	—		—		—		—		—		—		—
Regulatory offset to NDT fund-related activities^(b)	(1		)	(1		)	—		—		—		—		—		—		—
Decommissioning-related activities	(23		)	(23		)	—		—		—		—		—		—		—
AFUDC — Equity	31			—			8		2		8		13		12		1		—
Non-service net periodic benefit cost	(21		)	—			—		—		—		—		—		—		—

_________


(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
Six Months Ended June 30, 2019
Property, plant and equipment^(a)	$	1,859	$	789	$	439	$	149	$	173	$	266	$	117	$	71	$	57
Amortization of regulatory assets^(a)	266		—		69		15		79		103		69		20		14
Amortization of intangible assets, net^(a)	29		25		—		—		—		—		—		—		—
Amortization of energy contract assets and liabilities^(b)	5		5		—		—		—		—		—		—		—
Nuclear fuel^(c)	513		513		—		—		—		—		—		—		—
ARO accretion^(d)	250		248		—		—		—		—		—		—		—
Total depreciation, amortization and accretion	$	2,922	$	1,580	$	508	$	164	$	252	$	369	$	186	$	91	$	71

Six Months Ended June 30, 2018
Property, plant and equipment^(a)	$	1,873	$	890	$	406	$	135	$	164	$	236	$	107	$	64	$	47
Amortization of regulatory assets^(a)	278		—		53		14		84		127		81		24		22
Amortization of intangible assets, net^(a)	28		24		—		—		—		—		—		—		—
Amortization of energy contract assets and liabilities^(b)	10		10		—		—		—		—		—		—		—
Nuclear fuel^(c)	569		569		—		—		—		—		—		—		—
ARO accretion^(d)	242		242		—		—		—		—		—		—		—
Total depreciation, amortization and accretion	$	3,000	$	1,735	$	459	$	149	$	248	$	363	$	188	$	88	$	69

_________


(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
Six Months Ended June 30, 2019
Pension and non-pension postretirement benefit costs	$	212		$	62		$	47	$	5	$	29	$	48		$	12		$	8		$	8
Provision for uncollectible accounts	45			12			16		10		4		3			2			1			—
Other decommissioning-related activity^(a)	(260		)	(261		)	—		—		—		—			—			—			—
Energy-related options^(b)	43			43			—		—		—		—			—			—			—
Amortization of rate stabilization deferral	(10		)	—			—		—		—		(10		)	(8		)	(2		)	—
Discrete impacts from EIMA and FEJA^(c)	24			—			24		—		—		—			—			—			—
Long-term incentive plan	35			—			—		—		—		—			—			—			—
Amortization of operating ROU asset	115			78			1		—		15		17			4			5			2

Six Months Ended June 30, 2018
Pension and non-pension postretirement benefit costs	$	290		$	100		$	88	$	10	$	29	$	34		$	8		$	3		$	6
Provision for uncollectible accounts	77			28			18		11		5		15			7			2			5
Other decommissioning-related activity^(a)	(61		)	(61		)	—		—		—		—			—			—			—
Energy-related options^(b)	(7		)	(7		)	—		—		—		—			—			—			—
Amortization of rate stabilization deferral	13			—			—		—		—		13			10			3			—
Discrete impacts from EIMA and FEJA^(c)	14			—			14		—		—		—			—			—			—
Long-term incentive plan	51			—			—		—		—		—			—			—			—

_______

(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
June 30, 2019
Cash and cash equivalents	$	735	$	575	$	65	$	20	$	8	$	54	$	18	$	3	$	4
Restricted cash	252		122		77		6		1		37		34		1		2
Restricted cash included in other long-term assets	191		—		174		—		—		17		—		—		17
Total cash, cash equivalents and restricted cash	$	1,178	$	697	$	316	$	26	$	9	$	108	$	52	$	4	$	23

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

June 30, 2018
Cash and cash equivalents	$	694	$	420	$	30	$	18	$	7	$	195	$	47	$	141	$	6
Restricted cash	206		130		5		5		1		38		33		—		5
Restricted cash included in other long-term assets	128		—		108		—		—		20		—		—		20
Total cash, cash equivalents and restricted cash	$	1,028	$	550	$	143	$	23	$	8	$	253	$	80	$	141	$	31

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
June 30, 2019	$	1,352	$	703	$	218	$	121	$	115	$	195	$	107	$	47	$	41
December 31, 2018	1,656		965		223		114		168		186		97		59		30



	Accrued expenses
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
June 30, 2019
Compensation-related accruals^(a)	$	767	$	292	$	117	$	52	$	41	$	72	$	23	$	15	$	10
Taxes accrued	446		304		65		14		21		75		54		13		9
Interest accrued	340		76		109		33		40		50		24		8		13

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.

Significant Accounting Policies (Policies)

6 Months Ended

Jun. 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) carryforward 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)

6 Months Ended

Jun. 30, 2019

Variable Interest Entity [Abstract]

Schedule of Variable Interest Entities



	June 30, 2019								December 31, 2018
	Exelon^(a)		Generation		PHI^(a)		ACE		Exelon^(a)		Generation		PHI^(a)		ACE
Current assets	$	649	$	646	$	3	$	2	$	938	$	931	$	7	$	4
Noncurrent assets	9,204		9,184		20		17		9,071		9,045		26		19
Total assets	$	9,853	$	9,830	$	23	$	19	$	10,009	$	9,976	$	33	$	23
Current liabilities	715		694		21		20		$	274	$	252	$	22	$	19
Noncurrent liabilities	2,861		2,827		34		31		3,280		3,233		47		40
Total liabilities	$	3,576	$	3,521	$	55	$	51	$	3,554	$	3,485	$	69	$	59

_________

(a)

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

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



	June 30, 2019								December 31, 2018
	Exelon^(a)		Generation		PHI^(a)		ACE		Exelon^(a)		Generation		PHI^(a)		ACE
Cash and cash equivalents	$	106	$	106	$	—	$	—	$	414	$	414	$	—	$	—
Restricted cash and cash equivalents	75		73		2		2		66		62		4		4
Accounts receivable, net
Customer	161		161		—		—		146		146		—		—
Other	39		39		—		—		23		23		—		—
Inventory, net
Materials and supplies	217		217		—		—		212		212		—		—
Other current assets	28		27		1		—		52		49		3		—
Total current assets	626		623		3		2		913		906		7		4
Property, plant and equipment, net	6,084		6,084		—		—		6,145		6,145		—		—
NDT funds	2,589		2,589		—		—		2,351		2,351		—		—
Other noncurrent assets	227		207		20		17		258		232		26		19
Total noncurrent assets	8,900		8,880		20		17		8,754		8,728		26		19
Total assets	$	9,526	$	9,503	$	23	$	19	$	9,667	$	9,634	$	33	$	23
Long-term debt due within one year	$	560	$	540	$	20	$	19	$	87	$	66	$	21	$	18
Accounts payable	89		89		—		—		96		96		—		—
Accrued expenses	52		51		1		1		72		72		1		1
Unamortized energy contract liabilities	11		11		—		—		15		15		—		—
Other current liabilities	3		3		—		—		3		3		—		—
Total current liabilities	715		694		21		20		273		252		22		19
Long-term debt	558		524		34		31		1,072		1,025		47		40
Asset retirement obligations	2,218		2,218		—		—		2,160		2,160		—		—
Unamortized energy contract liabilities	—		—		—		—		1		1		—		—
Other noncurrent liabilities	77		77		—		—		42		42		—		—
Total noncurrent liabilities	2,853		2,819		34		31		3,275		3,228		47		40
Total liabilities	$	3,568	$	3,513	$	55	$	51	$	3,548	$	3,480	$	69	$	59

_________

(a)

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

VIE - Summary of Unconsolidated VIEs [Table Text Block]



June 30, 2019	Commercial Agreement VIEs		Equity Investment VIEs		Total
Total assets^(a)	$	603	$	453	$	1,056
Total liabilities^(a)	33		225		258
Exelon's ownership interest in VIE^(a)	—		203		203
Other ownership interests in VIE^(a)	571		25		596
Registrants’ maximum exposure to loss:
Carrying amount of equity method investments	—		203		203
Contract intangible asset	7		—		7



December 31, 2018	Commercial Agreement VIEs		Equity Investment VIEs		Total
Total assets^(a)	$	597	$	472	$	1,069
Total liabilities^(a)	37		222		259
Exelon's ownership interest in VIE^(a)	—		223		223
Other ownership interests in VIE^(a)	560		27		587
Registrants’ maximum exposure to loss:
Carrying amount of equity method investments	—		223		223
Contract intangible asset	7		—		7

_________

(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.

- Definition

Tabular disclosure of the significant judgments and assumptions made in determining whether a variable interest (as defined) held by the entity requires the variable interest entity (VIE) (as defined) to be consolidated and (or) disclose information about its involvement with the VIE, individually or in aggregate (as applicable); the nature of restrictions, if any, on the consolidated VIE's assets and on the settlement of its liabilities reported by an entity in its statement of financial position, including the carrying amounts of such assets and liabilities; the nature of, and changes in, the risks associated with involvement in the VIE; how involvement with the VIE affects the entity's financial position, financial performance, and cash flows; the lack of recourse if creditors (or beneficial interest holders) of the consolidated VIE have no recourse to the general credit of the primary beneficiary (if applicable); the terms of arrangements, giving consideration to both explicit arrangements and implicit variable interests, if any, that could require the entity to provide financial support to the VIE, including events or circumstances that could expose the entity to a loss; the methodology used by the entity for determining whether or not it is the primary beneficiary of the variable interest entity; the significant factors considered and judgments made in determining that the power to direct the activities of a VIE that most significantly impact the VIE's economic performance are shared (as defined); the carrying amounts and classification of assets and liabilities of the VIE included in the statement of financial position; the entity's maximum exposure to loss, if any, as a result of its involvement with the VIE, including how the maximum exposure is determined and significant sources of the entity's exposure to the VIE; a comparison of the carrying amounts of the assets and liabilities and the entity's maximum exposure to loss; information about any liquidity arrangements, guarantees, and (or) other commitments by third parties that may affect the fair value or risk of the entity's variable interest in the VIE; whether or not the entity has provided financial support or other support (explicitly or implicitly) to the VIE that it was not previously contractually required to provide or whether the entity intends to provide that support, including the type and amount of the support and the primary reasons for providing the support; and supplemental information the entity determines necessary to provide.

+ References + Details

Revenue from Contracts with Customers (Tables)

6 Months Ended

Jun. 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 June 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	(44		)	(44		)	38			115
Revenues recognized	53			53			(44		)	(131		)
Balance at June 30, 2019	$	196		$	196		$	21		$	26

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



	2019		2020		2021		2022		2023 and thereafter		Total
Exelon	$	274	$	275	$	93	$	68	$	248	$	958
Generation	355		343		118		72		248		1,136

Leases (Tables)

6 Months Ended

Jun. 30, 2019

Leases [Abstract]

Components of Lease Cost [Table Text Block]

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



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Operating lease costs	$	87	$	61	$	1	$	—	$	9	$	13	$	3	$	4	$	3
Variable lease costs	77		72		1		—		1		2		1		—		1
Short-term lease costs	3		3		—		—		—		—		—		—		—
Total lease costs ^(a)	$	167	$	136	$	2	$	—	$	10	$	15	$	4	$	4	$	4

__________


(a)	Excludes $16 million, $12 million, $4 million and $4 million of sublease income recorded at Exelon, Generation, PHI and DPL.

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



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Operating lease costs	$	155	$	107	$	2	$	—	$	17	$	23	$	6	$	7	$	4
Variable lease costs	150		140		1		—		1		4		1		1		1
Short-term lease costs	11		11		—		—		—		—		—		—		—
Total lease costs ^(a)	$	316	$	258	$	3	$	—	$	18	$	27	$	7	$	8	$	5

__________

(a)

Excludes $19 million, $14 million, $5 million and $5 million of sublease income recorded at Exelon, Generation, PHI and DPL.

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



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Remaining lease term	9.9		10.6		4.9		4.4		5.4		9.2		9.7		9.6		5.2
Discount rate	4.6	%	4.8	%	3.1	%	3.4	%	3.6	%	4.1	%	3.8	%	3.9	%	3.5	%

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	$	1,412	$	982	$	11	$	2	$	91	$	309	$	67	$	74	$	24

Operating lease liabilities
Other current liabilities	250		173		3		1		32		36		8		11		6
Other deferred credits and other liabilities	1,353		981		9		1		65		280		60		72		19
Total operating lease liabilities	$	1,603	$	1,154	$	12	$	2	$	97	$	316	$	68	$	83	$	25

__________

(a)

Exelon's and Generation's operating ROU assets and lease liabilities include $595 million and $744 million, respectively, related to contracted generation.

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

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



Year	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
2019	$	149	$	104	$	2	$	1	$	17	$	23	$	6	$	5	$	4
2020	291		202		3		1		34		44		9		12		5
2021	246		161		3		—		31		42		9		12		5
2022	177		112		2		—		16		41		8		11		4
2023	141		99		1		—		—		39		8		10		3
Remaining years	1,051		834		2		—		19		196		43		52		6
Total	2,055		1,512		13		2		117		385		83		102		27
Interest	452		358		1		—		20		69		15		19		2
Total operating lease liabilities	$	1,603	$	1,154	$	12	$	2	$	97	$	316	$	68	$	83	$	25

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 six months ended June 30, 2019 were as follows:



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Operating cash flows from operating leases	$	142	$	101	$	2	$	—	$	16	$	19	$	5	$	4	$	3

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



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Operating leases	$	30	$	7	$	6	$	—	$	1	$	15	$	6	$	6	$	3

Components of Operating Lease Income [Table Text Block]

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



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Operating lease income	$	14	$	12	$	—	$	—	$	—	$	1	$	—	$	1	$	—
Variable lease income	77		74		—		—		—		3		—		3		—

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



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Operating lease income	$	18	$	15	$	—	$	—	$	—	$	2	$	—	$	2	$	—
Variable lease income	129		126		—		—		—		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 June 30, 2019 were as follows:



Year	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
2019	$	33	$	31	$	—	$	—	$	—	$	2	$	—	$	2	—
2020	51		46		—		—		—		4		—		3		—
2021	51		46		—		—		—		4		1		3		—
2022	50		45		—		—		—		5		—		4		—
2023	49		45		—		—		—		4		—		3		—
Remaining years	314		271		1		3		1		38		—		38		—
Total	$	548	$	484	$	1	$	3	$	1	$	57	$	1	$	53	$	—

Regulatory Matters (Tables)

6 Months Ended

Jun. 30, 2019

Regulated Operations [Abstract]

Public Utilities General Disclosures [Table Text Block]



	Exelon		ComEd^(a)		PECO		BGE^(b)		PHI		Pepco^(c)		DPL^(c)		ACE
June 30, 2019	$	61	$	5	$	—	$	48	$	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)

6 Months Ended

Jun. 30, 2019

Property, Plant and Equipment [Abstract]

Income statement expense (pre-tax)



	Three Months Ended June 30,				Six Months Ended June 30,
Income statement expense (pre-tax)	2019		2018		2019			2018
Depreciation and amortization^(a)
Accelerated depreciation	$	71	$	152	$	145		$	289
Accelerated nuclear fuel amortization	4		19		9			34
Operating and maintenance^(b)	—		2		(83		)	28
Total	$	75	$	173	$	71		$	351

_________


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


(b)	In 2019, primarily reflects decrease to estimated decommissioning costs for TMI. 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.

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



	June 30, 2019
Asset Balances
Materials and supplies inventory	$	30
Fuel inventory	11
Completed plant, net	896
Construction work in progress	4
Liability Balances
Asset retirement obligation	(1		)

Fair Value of Financial Assets and Liabilities (Tables)

6 Months Ended

Jun. 30, 2019

Fair Value Disclosures [Abstract]

Fair Value of Financial Liabilities Recorded at Amortized Cost



	June 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	$	35,685	$	36,248	$	2,569	$	38,817	$	35,424	$	33,711	$	2,158	$	35,869
Generation	8,704		7,822		1,472		9,294		8,793		7,467		1,443		8,910
ComEd	8,195		9,222		—		9,222		8,101		8,390		—		8,390
PECO	3,085		3,415		50		3,465		3,084		3,157		50		3,207
BGE	2,877		3,197		—		3,197		2,876		2,950		—		2,950
PHI	6,509		5,823		1,047		6,870		6,259		5,436		665		6,101
Pepco	2,860		3,134		377		3,511		2,719		2,901		196		3,097
DPL	1,495		1,396		218		1,614		1,494		1,303		193		1,496
ACE	1,329		1,025		451		1,476		1,188		987		275		1,262
Long-Term Debt to Financing Trusts^(a)
Exelon	$	390	$	—	$	415	$	415	$	390	$	—	$	400	$	400
ComEd	205		—		209		209		205		—		209		209
PECO	184		—		206		206		184		—		191		191
SNF Obligation
Exelon	$	1,186	$	1,025	$	—	$	1,025	$	1,171	$	949	$	—	$	949
Generation	1,186		1,025		—		1,025		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										Generation
As of June 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)	$	648	$	—	$	—	$	—	$	648	$	323	$	—	$	—	$	—	$	323
NDT fund investments
Cash equivalents^(b)	1,241		90		—		—		1,331		1,241		90		—		—		1,331
Equities	3,123		1,638		—		1,328		6,089		3,123		1,638		—		1,328		6,089
Fixed income
Corporate debt	—		1,453		247		—		1,700		—		1,453		247		—		1,700
U.S. Treasury and agencies	1,589		134		—		—		1,723		1,589		134		—		—		1,723
Foreign governments	—		58		—		—		58		—		58		—		—		58
State and municipal debt	—		81		—		—		81		—		81		—		—		81
Other^(c)	—		19		—		955		974		—		19		—		955		974
Fixed income subtotal	1,589		1,745		247		955		4,536		1,589		1,745		247		955		4,536



	Exelon														Generation
As of June 30, 2019	Level 1			Level 2			Level 3			Not subject to leveling		Total			Level 1			Level 2			Level 3			Not subject to leveling		Total
Middle market lending	—			—			292			455		747			—			—			292			455		747
Private equity	—			—			—			379		379			—			—			—			379		379
Real estate	—			—			—			557		557			—			—			—			557		557
NDT fund investments subtotal^(d)	5,953			3,473			539			3,674		13,639			5,953			3,473			539			3,674		13,639
Rabbi trust investments
Cash equivalents	49			—			—			—		49			4			—			—			—		4
Mutual funds	73			—			—			—		73			23			—			—			—		23
Fixed income	—			13			—			—		13			—			—			—			—		—
Life insurance contracts	—			72			40			—		112			—			23			—			—		23
Rabbi trust investments subtotal	122			85			40			—		247			27			23			—			—		50
Commodity derivative assets
Economic hedges	505			2,148			1,875			—		4,528			505			2,148			1,875			—		4,528
Proprietary trading	—			44			139			—		183			—			44			139			—		183
Effect of netting and allocation of collateral^(e)(f)	(646		)	(2,042		)	(965		)	—		(3,653		)	(646		)	(2,042		)	(965		)	—		(3,653		)
Commodity derivative assets subtotal	(141		)	150			1,049			—		1,058			(141		)	150			1,049			—		1,058
Total assets	6,582			3,708			1,628			3,674		15,592			6,162			3,646			1,588			3,674		15,070
Liabilities
Commodity derivative liabilities
Economic hedges	(743		)	(2,539		)	(1,606		)	—		(4,888		)	(743		)	(2,539		)	(1,333		)	—		(4,615		)
Proprietary trading	—			(44		)	(71		)	—		(115		)	—			(44		)	(71		)	—		(115		)
Effect of netting and allocation of collateral^(e)(f)	743			2,438			1,228			—		4,409			743			2,438			1,228			—		4,409
Commodity derivative liabilities subtotal	—			(145		)	(449		)	—		(594		)	—			(145		)	(176		)	—		(321		)
Deferred compensation obligation	—			(137		)	—			—		(137		)	—			(36		)	—			—		(36		)
Total liabilities	—			(282		)	(449		)	—		(731		)	—			(181		)	(176		)	—		(357		)
Total net assets	$	6,582		$	3,426		$	1,179		$	3,674	$	14,861		$	6,162		$	3,465		$	1,412		$	3,674	$	14,713



	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 $75 million and $50 million of cash received from outstanding repurchase agreements at June 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), $358 million and $(94) million represents variation margin on the exchanges as of June 30, 2019 and December 31, 2018, respectively.

Valuation Techniques Used to Determine Net Asset Value

ComEd, PECO and BGE



	ComEd											PECO										BGE
As of June 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)	$	222	$	—		$	—		$	222		$	9	$	—		$	—	$	9		$	1	$	—		$	—	$	1
Rabbi trust investments
Mutual funds	—		—			—			—			7		—			—		7			7		—			—		7
Life insurance contracts	—		—			—			—			—		10			—		10			—		—			—		—
Rabbi trust investments subtotal	—		—			—			—			7		10			—		17			7		—			—		7
Total assets	222		—			—			222			16		10			—		26			8		—			—		8
Liabilities
Deferred compensation obligation	—		(7		)	—			(7		)	—		(8		)	—		(8		)	—		(5		)	—		(5		)
Mark-to-market derivative liabilities^(b)	—		—			(273		)	(273		)	—		—			—		—			—		—			—		—
Total liabilities	—		(7		)	(273		)	(280		)	—		(8		)	—		(8		)	—		(5		)	—		(5		)
Total net assets (liabilities)	$	222	$	(7	)	$	(273	)	$	(58	)	$	16	$	2		$	—	$	18		$	8	$	(5	)	$	—	$	3



	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 $29 million and $244 million, respectively, at June 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 June 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)	$	87	$	—		$	—	$	87		$	147	$	—		$	—	$	147
Rabbi trust investments
Cash equivalents	44		—			—		44			42		—			—		42
Mutual funds	13		—			—		13			13		—			—		13
Fixed income	—		13			—		13			—		15			—		15
Life insurance contracts	—		23			40		63			—		22			38		60
Rabbi trust investments subtotal	57		36			40		133			55		37			38		130
Total assets	144		36			40		220			202		37			38		277
Liabilities
Deferred compensation obligation	—		(19		)	—		(19		)	—		(21		)	—		(21		)
Total liabilities	—		(19		)	—		(19		)	—		(21		)	—		(21		)
Total net assets	$	144	$	17		$	40	$	201		$	202	$	16		$	38	$	256



	Pepco										DPL								ACE
As of June 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)	$	40	$	—		$	—	$	40		$	1	$	—	$	—	$	1	$	19	$	—	$	—	$	19
Rabbi trust investments
Cash equivalents	43		—			—		43			—		—		—		—		—		—		—		—
Fixed income	—		3			—		3			—		—		—		—		—		—		—		—
Life insurance contracts	—		23			39		62			—		—		—		—		—		—		—		—
Rabbi trust investments subtotal	43		26			39		108			—		—		—		—		—		—		—		—
Total assets	83		26			39		148			1		—		—		1		19		—		—		19
Liabilities
Deferred compensation obligation	—		(2		)	—		(2		)	—		—		—		—		—		—		—		—
Total liabilities	—		(2		)	—		(2		)	—		—		—		—		—		—		—		—
Total net assets	$	83	$	24		$	39	$	146		$	1	$	—	$	—	$	1	$	19	$	—	$	—	$	19



	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

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 six months ended June 30, 2019 and 2018:



	Exelon			Generation										ComEd				PHI and Pepco
Three Months Ended June 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 March 31, 2019	$	838		$	540		$	499			$	1,039		$	(240	)		$	39	$	—
Total realized / unrealized gains (losses)
Included in net income	275			2			272			^(a)	274			—				1		—
Included in noncurrent payables to affiliates	—			10			—				10			—				—		(10		)
Included in regulatory assets/liabilities	(23		)	—			—				—			(33		)	^(b)	—		10
Change in collateral	106			—			106				106			—				—		—
Purchases, sales, issuances and settlements
Purchases	51			40			11				51			—				—		—
Sales	(1		)	—			(1		)		(1		)	—				—		—
Settlements	(53		)	(53		)	—				(53		)	—				—		—
Transfers into Level 3	3			—			3			^(c)	3			—				—		—
Transfers out of Level 3	(17		)	—			(17		)	^(c)	(17		)	—				—		—
Balance at June 30, 2019	$	1,179		$	539		$	873			$	1,412		$	(273	)		$	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 June 30, 2019	$	339		$	1		$	337			$	338		$	—			$	1	$	—



	Exelon			Generation										ComEd				PHI and Pepco
Six Months Ended June 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	46			3			41			^(a)	44			—				2		—
Included in noncurrent payables to affiliates	—			21			—				21			—				—		(21		)
Included in regulatory assets	(3		)	—			—				—			(24		)	^(b)	—		21
Change in collateral	187			—			187				187			—				—		—
Purchases, sales, issuances and settlements
Purchases	110			42			68				110			—				—		—
Sales	(1		)	—			(1		)		(1		)	—				—		—
Settlements	(70		)	(70		)	—				(70		)	—				—		—
Transfers into Level 3	3			—			3			^(c)	3			—				—		—
Transfers out of Level 3	—			—			—			^(c)	—			—				—		—
Balance as of June 30, 2019	$	1,179		$	539		$	873			$	1,412		$	(273	)		$	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 June 30, 2019	$	191		$	3		$	186			$	189		$	—			$	2	$	—

__________


(a)	Includes a reduction for the reclassification of $65 million and $145 million of realized gains due to the settlement of derivative contracts for the three and six months ended June 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 June 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 March 31, 2018	$	1,283		$	609		$	918			$	1,527		$	(267	)		$	23	$	—
Total realized / unrealized gains (losses)
Included in net income	(112		)	—			(113		)	^(a)	(113		)	—				1		—
Included in noncurrent payables to affiliates	—			(3		)	—				(3		)	—				—		3
Included in regulatory assets	12			—			—				—			15			^(b)	—		(3		)
Change in collateral	(49		)	—			(49		)		(49		)	—				—		—
Purchases, sales, issuances and settlements
Purchases	30			17			13				30			—				—		—
Sales	(1		)	—			(1		)		(1		)	—				—		—
Settlements	(26		)	(38		)	—				(38		)	—				12		—
Transfers into Level 3	(15		)	—			(15		)	^(c)	(15		)	—				—		—
Transfers out of Level 3	(16		)	—			(16		)	^(c)	(16		)	—				—		—
Balance as of June 30, 2018	$	1,106		$	585		$	737			$	1,322		$	(252	)		$	36	$	—
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of June 30, 2018	$	3		$	(4	)	$	7			$	3		$	—			$	—	$	—



	Exelon			Generation										ComEd				PHI and Pepco
Six Months Ended June 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	74			1			71			^(a)	72			—				2		—
Included in noncurrent payables to affiliates	—			3			—				3			—				—		(3		)
Included in regulatory assets	7			—			—				—			4			^(b)	—		3
Change in collateral	57			—			57				57			—				—		—
Purchases, sales, issuances and settlements
Purchases	119			19			100				119			—				—		—
Sales	(4		)	—			(4		)		(4		)	—				—		—
Settlements	(74		)	(86		)	—				(86		)	—				12		—
Transfers into Level 3	(23		)	—			(23		)	^(c)	(23		)	—				—		—
Transfers out of Level 3	(16		)	—			(16		)	^(c)	(16		)	—				—		—
Balance as of June 30, 2018	$	1,106		$	585		$	737			$	1,322		$	(252	)		$	36	$	—
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of June 30, 2018	$	259		$	(4	)	$	263			$	259		$	—			$	—	$	—

__________


(a)	Includes a reduction for the reclassification of $120 million and $192 million of realized gains due to the settlement of derivative contracts for the three and six months ended June 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 gains (losses) for the three months ended June 30, 2019	$	275	$	(3	)	$	1	$	2	$	275	$	(3	)	$	2	$	1
Total realized (losses) gains for the six months ended June 30, 2019	147		(106		)	2		3		147		(106		)	3		2
Total unrealized gains (losses) for the three months ended June 30, 2019	360		(23		)	1		1		360		(23		)	1		1
Total unrealized gains (losses) for the six months ended June 30, 2019	269		(83		)	2		3		269		(83		)	3		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 June 30, 2018	$	(191	)	$	78		$	1	$	—		$	(191	)	$	78		$	—		$	1
Total realized gains (losses) for the six months ended June 30, 2018	144			(73		)	2		2			144			(73		)	2			2
Total unrealized (losses) gains for the three months ended June 30, 2018	(71		)	78			—		(4		)	(71		)	78			(4		)	—
Total unrealized gains (losses) for the six months ended June 30, 2018	238			25			—		(3		)	238			25			(3		)	—

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 June 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)	$	542		$	443		Discounted Cash Flow	Forward power price	$10	-	$118	$12	-	$174
								Forward gas price	$1.54	-	$11.26	$0.78	-	$12.38
							Option Model	Volatility percentage	8%	-	384%	10%	-	277%

Mark-to-market derivatives — Proprietary trading (Exelon and Generation)^(a)(b)	$	68		$	56		Discounted Cash Flow	Forward power price	$10	-	$118	$14	-	$174

Mark-to-market derivatives (Exelon and ComEd)	$	(273	)	$	(249	)	Discounted Cash Flow	Forward heat rate^(c)	9x	-	10x	10x	-	11x
								Marketability reserve	4%	-	7%	4%	-	8%
								Renewable factor	88%	-	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 $263 million and $76 million as of June 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)

6 Months Ended

Jun. 30, 2019

Derivative Instruments, Gain (Loss) [Line Items]

Summary of the derivative fair value

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



June 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)	$	526		$	2,910		$	122		$	218	$	(2,724	)	$	526		$	—
Mark-to-market derivative assets (noncurrent assets)	532			1,618			61			122		(1,269		)	532			—
Total mark-to-market derivative assets	1,058			4,528			183			340		(3,993		)	1,058			—
Mark-to-market derivative liabilities (current liabilities)	(157		)	(3,039		)	(78		)	265		2,724			(128		)	(29		)
Mark-to-market derivative liabilities (noncurrent liabilities)	(437		)	(1,576		)	(37		)	151		1,269			(193		)	(244		)
Total mark-to-market derivative liabilities	(594		)	(4,615		)	(115		)	416		3,993			(321		)	(273		)
Total mark-to-market derivative net assets (liabilities)	$	464		$	(87	)	$	68		$	756	$	—		$	737		$	(273	)



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), $358 million and $(94) million represents variation margin on the exchanges at June 30, 2019 and December 31, 2018 respectively.

Derivative Instruments, Gain (Loss) [Table Text Block]

For the three and six months ended June 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 June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Income Statement Location	Gain (Loss)						Gain (Loss)
Operating revenues	$	40		$	(7	)	$	(10	)	$	(107	)
Purchased power and fuel	(114		)	96			(84		)	(70		)
Total Exelon and Generation	$	(74	)	$	89		$	(94	)	$	(177	)

Credit-Risk Related Contingent



Rating as of June 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	$	859	$	12	$	847	2	$	249
Non-investment grade	30		11		19
No external ratings
Internally rated — investment grade	204		1		203
Internally rated — non-investment grade	117		11		106
Total	$	1,210	$	35	$	1,175	2	$	249



Net Credit Exposure by Type of Counterparty	As of June 30, 2019
Financial institutions	$	3
Investor-owned utilities, marketers, power producers	810
Energy cooperatives and municipalities	302
Other	60
Total	$	1,175

_________

(a)

As of June 30, 2019, credit collateral held from counterparties where Generation had credit exposure included $25 million of cash and $9 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	June 30, 2019			December 31, 2018
Gross fair value of derivative contracts containing this feature^(a)	$	(1,119	)	$	(1,723	)
Offsetting fair value of in-the-money contracts under master netting arrangements^(b)	824			1,105
Net fair value of derivative contracts containing this feature^(c)	$	(295	)	$	(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]



	June 30, 2019		December 31, 2018
Cash collateral posted	$	781	$	418
Letters of credit posted	228		367
Cash collateral held	64		47
Letters of credit held	21		44
Additional collateral required in the event of a credit downgrade below investment grade	1,513		2,104

Debt and Credit Agreements (Tables)

6 Months Ended

Jun. 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	June 30, 2019		December 31, 2018		June 30, 2019		December 31, 2018
Exelon	$	559	$	89	2.60	%	2.15	%
ComEd	303		—		2.59	%	2.14	%
BGE	229		35		2.58	%	2.18	%
PHI	27		54		2.61	%	2.15	%
PEPCO	—		40		2.62	%	2.24	%
DPL	—		—		2.55	%	2.07	%
ACE	27		14		2.61	%	2.21	%

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

During the six months ended June 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	$	2	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.
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	Repay existing indebtedness and for general corporate purposes
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)

6 Months Ended

Jun. 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 June 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	5.4	5.5	8.2	(1.2)	6.5	4.8	2.0	7.0	7.0
Qualified NDT fund income	5.1	16.2	—	—	—	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(0.7)	(1.9)	(0.2)	—	(0.1)	(0.2)	(0.1)	(0.2)	(0.3)
Plant basis differences	(1.7)	—	(0.6)	(5.9)	(1.5)	(1.7)	(2.1)	(0.3)	(2.2)
Production tax credits and other credits	(0.9)	(2.8)	—	—	(0.1)	—	—	—	—
Noncontrolling interests	0.1	0.4	—	—	—	—	—	—	—
Excess deferred tax amortization	(7.8)	—	(9.0)	(2.7)	(7.9)	(19.4)	(18.3)	(15.7)	(23.1)
Other	1.9	0.2	0.4	0.1	1.7	0.9	0.5	—	(2.4)
Effective income tax rate	22.4%	38.6%	19.8%	11.3%	19.6%	5.4%	3.0%	11.8%	—%



	Three Months Ended June 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	3.4	4.3	8.1	(3.4)	6.5	6.2	4.7	6.5	7.6
Qualified NDT fund income	0.2	0.5	—	—	—	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(0.9)	(2.4)	(0.2)	(0.1)	(0.2)	(0.2)	(0.1)	(0.3)	(0.3)
Plant basis differences	(3.0)	—	(0.1)	(17.2)	(0.7)	(1.2)	(2.0)	—	(0.2)
Production tax credits and other credits	(1.7)	(4.9)	(0.1)	—	—	—	—	—	—
Noncontrolling interests	(1.5)	(4.5)	—	—	—	—	—	—	—
Excess deferred tax amortization	(5.2)	—	(7.6)	(0.3)	(7.2)	(11.3)	(11.7)	(11.2)	(8.8)
Tax Cuts and Jobs Act of 2017	(1.3)	(1.7)	(0.7)	—	0.1	0.8	—	—	—
Other	(0.2)	(1.3)	0.4	(1.1)	0.8	(0.1)	(0.4)	0.1	0.7
Effective income tax rate	10.8%	11.0%	20.8%	(1.1)%	20.3%	15.2%	11.5%	16.1%	20.0%




	Six Months Ended June 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	4.4	3.6	8.2	0.2	6.4	4.7	2.0	6.7	6.9
Qualified NDT fund income	6.5	14.7	—	—	—	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(0.6)	(1.1)	(0.2)	—	(0.1)	(0.2)	(0.1)	(0.2)	(0.3)
Plant basis differences	(1.5)	—	(0.6)	(6.4)	(1.0)	(1.7)	(2.0)	(0.6)	(2.2)
Production tax credits and other credits	(0.8)	(1.8)	—	—	—	—	—	—	—
Noncontrolling interests	(0.3)	(0.8)	—	—	—	—	—	—	—
Excess deferred tax amortization	(5.8)	—	(8.8)	(2.6)	(7.9)	(19.4)	(18.1)	(15.6)	(23.4)
Other	0.7	(0.4)	0.2	(0.1)	0.2	0.3	0.5	0.4	2.0
Effective income tax rate	23.6%	35.2%	19.8%	12.1%	18.6%	4.7%	3.3%	11.7%	4.0%



	Six Months Ended June 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	3.8	3.4	8.1	(3.6)	6.4	5.5	3.7	6.4	7.2
Qualified NDT fund income	(0.1)	(0.4)	—	—	—	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(1.1)	(3.3)	(0.2)	(0.1)	(0.1)	(0.2)	(0.1)	(0.3)	(0.3)
Plant basis differences	(2.8)	—	—	(15.6)	(0.7)	(1.8)	(2.5)	(0.7)	(1.3)
Production tax credits and other credits	(2.3)	(7.2)	(0.1)	—	—	—	—	—	—
Noncontrolling interests	(1.1)	(3.5)	—	—	—	—	—	—	—
Excess deferred tax amortization	(5.6)	—	(7.5)	(2.7)	(8.2)	(11.0)	(12.1)	(9.4)	(8.8)
Tax Cuts and Jobs Act of 2017	(0.6)	(0.9)	(0.3)	—	—	0.5	—	—	—
Other	(1.7)	(1.3)	0.1	(0.4)	0.2	(0.1)	(0.4)	0.4	(1.1)
Effective income tax rate	9.5%	7.8%	21.1%	(1.4)%	18.6%	13.9%	9.6%	17.4%	16.7%

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

The Registrants have the following unrecognized tax benefits as of June 30, 2019 and December 31, 2018:



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
June 30, 2019	$	448	$	411	$	—	$	—	$	—	$	45	$	—	$	—	$	14
December 31, 2018	$	477	$	408	$	2	$	—	$	—	$	45	$	—	$	—	$	14

Nuclear Decommissioning (Tables)

6 Months Ended

Jun. 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 June 30, 2019:



Nuclear decommissioning ARO at December 31, 2018 ^(a)(b)	$	10,005
Accretion expense	243
Net increase due to changes in, and timing of, estimated future cash flows	232
Costs incurred related to decommissioning plants	(43		)
Nuclear decommissioning ARO at June 30, 2019 ^(a)(b)	$	10,437

_________


(a)	Includes $99 million and $22 million as the current portion of the ARO at June 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 $755 million and $772 million of ARO related to Oyster Creek which is classified as Liabilities held for sale in Exelon's and Generation's Consolidated Balance Sheets at June 30, 2019 and December 31, 2018, respectively. See Note 3 — Mergers, Acquisitions and Dispositions for additional information.

^[1]

[1]	Includes $99 million and $22 million as the current portion of the ARO at June 30, 2019 and December 31, 2018, respectively, which is included in Other current liabilities in Exelon’s and Generation’s Consolidated Balance Sheets.

Retirement Benefits (Tables)

6 Months Ended

Jun. 30, 2019

Retirement Benefits [Abstract]

Calculation of Net Periodic Benefit Costs



	Pension Benefits Three Months Ended June 30,						Other Postretirement Benefits Three Months Ended June 30,
	2019			2018			2019			2018
Components of net periodic benefit cost:
Service cost	$	89		$	102		$	24		$	28
Interest cost	221			200			47			44
Expected return on assets	(306		)	(313		)	(38		)	(43		)
Amortization of:
Prior service benefit	—			—			(44		)	(47		)
Actuarial loss	103			157			10			16
Settlement charges	—			1			—			—
Net periodic benefit cost	$	107		$	147		$	(1	)	$	(2	)




	Pension Benefits Six Months Ended June 30,						Other Postretirement Benefits Six Months Ended June 30,
	2019			2018			2019			2018
Components of net periodic benefit cost:
Service cost	$	178		$	202		$	47		$	56
Interest cost	442			401			94			88
Expected return on assets	(612		)	(626		)	(77		)	(87		)
Amortization of:
Prior service cost (benefit)	—			1			(89		)	(93		)
Actuarial loss	206			314			23			33
Settlement charges	—			1			—			—
Net periodic benefit cost	$	214		$	293		$	(2	)	$	(3	)

Allocated Portion of Pension and Postretirement Benefit Costs



	Three Months Ended June 30,				Six Months Ended June 30,
Pension and Other Postretirement Benefit Costs	2019		2018		2019		2018
Exelon	$	106	$	145	$	212	$	290
Generation	31		51		62		100
ComEd	23		44		47		88
PECO	3		5		5		10
BGE	16		15		30		30
PHI	24		17		48		34
Pepco	6		3		12		8
DPL	4		2		8		3
ACE	4		3		8		6

Defined Contribution Savings Plans



	Three Months Ended June 30,				Six Months Ended June 30,
Savings Plan Matching Contributions	2019		2018		2019		2018
Exelon	$	33	$	50	$	64	$	82
Generation	14		28		28		43
ComEd	9		8		16		15
PECO	2		2		5		4
BGE	2		2		4		4
PHI	3		3		6		6
Pepco	1		1		2		2
DPL	1		1		1		1
ACE	—		—		1		1

Changes in Accumulated Other Comprehensive Income (Tables)

6 Months Ended

Jun. 30, 2019

Changes in Accumulated Other Comprehensive Income [Abstract]

Schedule of Accumulated Other Comprehensive Income (Loss)

The following tables present changes in accumulated other comprehensive income (loss) (AOCI) by component for the six months ended June 30, 2019 and 2018:



Six Months Ended June 30, 2019	Losses on Cash Flow Hedges			Pension and Non-Pension Postretirement Benefit Plan Items			Foreign Currency Items			AOCI of Investments in Unconsolidated Affiliates			Total
Exelon^(a)
Beginning balance	$	(2	)	$	(2,960	)	$	(33	)	$	—		$	(2,995	)
OCI before reclassifications	—			(39		)	4			(2		)	(37		)
Amounts reclassified from AOCI^(b)	—			42			—			—			42
Net current-period OCI	—			3			4			(2		)	5
Ending balance	$	(2	)	$	(2,957	)	$	(29	)	$	(2	)	$	(2,990	)
Generation^(a)
Beginning balance	$	(4	)	$	—		$	(33	)	$	(1	)	$	(38	)
OCI before reclassifications	—			—			4			(2		)	2
Amounts reclassified from AOCI	—			—			—			—			—
Net current-period OCI	—			—			4			(2		)	2
Ending balance	$	(4	)	$	—		$	(29	)	$	(3	)	$	(36	)



Six Months Ended June 30, 2018	Gains (Losses) on Cash Flow Hedges			Unrealized gains (losses) on Marketable Securities			Pension and Non-Pension Postretirement Benefit Plan Items				Foreign Currency Items			AOCI of Investments in Unconsolidated Affiliates			Total
Exelon^(a)
Beginning balance	$	(14	)	$	10		$	(2,998	)	^(d)	$	(23	)	$	(1	)	$	(3,026	)
OCI before reclassifications	13			—			20				(6		)	1			28
Amounts reclassified from AOCI^(b)	(1		)	—			88				—			—			87
Net current-period OCI	12			—			108				(6		)	1			115
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard^(c)	—			(10		)	—				—			—			(10		)
Ending balance	$	(2	)	$	—		$	(2,890	)		$	(29	)	$	—		$	(2,921	)
Generation^(a)
Beginning balance	$	(16	)	$	3		$	—			$	(23	)	$	(1	)	$	(37	)
OCI before reclassifications	13			—			—				(6		)	1			8
Amounts reclassified from AOCI	(1		)	—			—				—			—			(1		)
Net current-period OCI	12			—			—				(6		)	1			7
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard^(c)	—			(3		)	—				—			—			(3		)
Ending balance	$	(4	)	$	—		$	—			$	(29	)	$	—		$	(33	)

_________


(a)	All amounts are net of tax and noncontrolling interests. Amounts in parenthesis represent a decrease in AOCI.


(b)	See next tables for details about these reclassifications.

(c)

(d)

Reclassification out of Accumulated Other Comprehensive Income

Three Months Ended June 30, 2019



Details about AOCI components	Items reclassified out of AOCI^(a)			Affected line item in the Statement of Operations and Comprehensive Income
	Exelon
Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)	$	22
Actuarial losses^(b)	(49		)
	(27		)	Total before tax
	7			Tax benefit
	$	(20	)	Net of tax

Six Months Ended June 30, 2019



Details about AOCI components	Items reclassified out of AOCI^(a)			Affected line item in the Statement of Operations and Comprehensive Income
	Exelon
Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)	$	44
Actuarial losses^(b)	(100		)
	(56		)	Total before tax
	14			Tax benefit
	$	(42	)	Net of tax

Three Months Ended June 30, 2018



Details about AOCI components	Items reclassified out of AOCI^(a)			Affected line item in the Statement of Operations and Comprehensive Income
	Exelon
Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)	$	23
Actuarial losses^(b)	(83		)
	(60		)	Total before tax
	16			Tax benefit
	$	(44	)	Net of tax

Six Months Ended June 30, 2018



Details about AOCI components	Items reclassified out of AOCI^(a)			Affected line item in the Statement of Operations and Comprehensive Income
	Exelon
Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)	$	46
Actuarial losses^(b)	(166		)
	(120		)	Total before tax
	32			Tax benefit
	$	(88	)	Net of tax

_________


(a)	Amounts in parenthesis represent a decrease in net income.

(b)

This AOCI component is included in the computation of net periodic pension and OPEB cost. See Note 14 — Retirement Benefits for additional information.

Schedule Of Other Comprehensive Income Loss Tax

The following table presents income tax benefit (expense) allocated to each component of other comprehensive income (loss) during the three and six months ended June 30, 2019 and 2018:



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Exelon
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	$	6		$	6		$	12		$	12
Actuarial loss reclassified to periodic benefit cost	(13		)	(22		)	(26		)	(44		)
Pension and non-pension postretirement benefit plans valuation adjustment	—			1			14			(6		)
Change in unrealized loss on cash flow hedges	—			(1		)	—			(4		)
Change in unrealized gain (loss) on investments in unconsolidated affiliates	1			—			1			(1		)
Total	$	(6	)	$	(16	)	$	1		$	(43	)

Generation
Change in unrealized gain (loss) on cash flow hedges	$	—		$	(1	)	$	—		$	(4	)
Change in unrealized gain (loss) on investments in unconsolidated affiliates	1			—			1			(1		)
Total	$	1		$	(1	)	$	1		$	(5	)

Commitments and Contingencies (Tables)

6 Months Ended

Jun. 30, 2019

Commitments And Contingencies Tables Disclosure [Line Items]

Other Commitments

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



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Letters of credit	$	1,315	$	1,283	$	7	$	—	$	9	$	10	$	10	$	—	$	—
Surety bonds^(a)	1,492		1,271		52		9		17		39		31		4		3
Financing trust guarantees	378		—		200		178		—		—		—		—		—
Guaranteed lease residual values^(b)	26		—		—		—		—		26		9		11		7
Total commercial commitments	$	3,211	$	2,554	$	259	$	187	$	26	$	75	$	50	$	15	$	10

_________


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

(b)

The following amounts represent total commitment costs for Exelon, PHI, Pepco, DPL and ACE that have been recorded since the acquisition date and the remaining obligations as of June 30, 2019:



Description	Expected Payment Period	Exelon		PHI		Pepco		DPL		ACE
Rate credits	2016 - 2021	$	264	$	264	$	91	$	72	$	101
Energy efficiency	2016 - 2021	117		—		—		—		—
Charitable contributions	2016 - 2026	50		50		28		12		10
Delivery system modernization	Q2 2017	22		—		—		—		—
Green sustainability fund	Q2 2017	14		—		—		—		—
Workforce development	2016 - 2020	17		—		—		—		—
Other		29		6		1		5		—
Total commitments		$	513	$	320	$	120	$	89	$	111
Remaining commitments		$	116	$	86	$	69	$	11	$	6

Accrued environmental liabilities



June 30, 2019	Total environmental investigation and remediation reserve		Portion of total related to MGP investigation and remediation
Exelon	$	482	$	345
Generation	107		—
ComEd	318		318
PECO	25		24
BGE	5		3
PHI	27		—
Pepco	24		—
DPL	1		—
ACE	1		—



December 31, 2018	Total environmental investigation and remediation reserve		Portion of total related to MGP investigation and remediation
Exelon	$	496	$	356
Generation	108		—
ComEd	329		327
PECO	27		25
BGE	5		4
PHI	27		—
Pepco	25		—
DPL	1		—
ACE	1		—

Supplemental Financial Information (Tables)

6 Months Ended

Jun. 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 June 30, 2019
Utility taxes^(a)	$	209	$	32	$	55	$	30	$	21	$	71	$	67	$	4	$	—
Property	148		68		9		4		37		30		21		8		1
Payroll	61		30		7		4		4		7		2		1		1

Three Months Ended June 30, 2018
Utility taxes^(a)	$	218	$	29	$	60	$	30	$	21	$	78	$	73	$	5	$	—
Property	135		65		8		4		34		24		15		8		1
Payroll	65		34		7		4		4		6		2		1		1

Six Months Ended June 30, 2019
Utility taxes^(a)	$	432	$	58	$	118	$	63	$	48	$	145	$	136	$	9	$	—
Property	296		138		15		8		75		60		43		16		1
Payroll	127		64		14		7		8		14		3		2		2

Six Months Ended June 30, 2018
Utility taxes^(a)	$	452	$	60	$	121	$	63	$	47	$	161	$	151	$	10	$	—
Property	271		134		15		7		69		46		29		16		1
Payroll	133		68		14		8		8		14		3		2		2

_________

(a)

Schedule of Other Nonoperating Income, by Component



	Other, Net
	Exelon			Generation			ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Three Months Ended June 30, 2019
Decommissioning-related activities:
Net realized income on NDT funds^(a)
Regulatory agreement units	$	77		$	77		$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-regulatory agreement units	230			230			—		—		—		—		—		—		—
Net unrealized (losses) gains on NDT funds
Regulatory agreement units	98			98			—		—		—		—		—		—		—
Non-regulatory agreement units	(98		)	(98		)	—		—		—		—		—		—		—
Regulatory offset to NDT fund-related activities^(b)	(141		)	(141		)	—		—		—		—		—		—		—
Decommissioning-related activities	166			166			—		—		—		—		—		—		—
AFUDC — Equity	21			—			4		3		5		9		6		1		2
Non-service net periodic benefit cost	5			—			—		—		—		—		—		—		—

Three Months Ended June 30, 2018
Decommissioning-related activities:
Net realized income on NDT funds^(a)
Regulatory agreement units	$	216		$	216		$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-regulatory agreement units	143			143			—		—		—		—		—		—		—
Net unrealized losses on NDT funds
Regulatory agreement units	(194		)	(194		)	—		—		—		—		—		—		—
Non-regulatory agreement units	(120		)	(120		)	—		—		—		—		—		—		—
Regulatory offset to NDT fund-related activities^(b)	(23		)	(23		)	—		—		—		—		—		—		—
Decommissioning-related activities	22			22			—		—		—		—		—		—		—
AFUDC — Equity	13			—			2		—		4		7		6		1		—
Non-service net periodic benefit cost	(11		)	—			—		—		—		—		—		—		—



	Other, Net
	Exelon			Generation			ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Six Months Ended June 30, 2019
Decommissioning-related activities:
Net realized income on NDT funds^(a)
Regulatory agreement units	$	131		$	131		$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-regulatory agreement units	283			283			—		—		—		—		—		—		—
Net unrealized gains on NDT funds
Regulatory agreement units	476			476			—		—		—		—		—		—		—
Non-regulatory agreement units	182			182			—		—		—		—		—		—		—
Regulatory offset to NDT fund-related activities^(b)	(487		)	(487		)	—		—		—		—		—		—		—
Decommissioning-related activities	585			585			—		—		—		—		—		—		—
AFUDC — Equity	43			—			9		6		10		18		12		2		4
Non-service net periodic benefit cost	10			—			—		—		—		—		—		—		—

Six Months Ended June 30, 2018
Decommissioning-related activities:
Net realized income on NDT funds^(a)
Regulatory agreement units	$	262		$	262		$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-regulatory agreement units	199			199			—		—		—		—		—		—		—
Net unrealized losses on NDT funds
Regulatory agreement units	(268		)	(268		)	—		—		—		—		—		—		—
Non-regulatory agreement units	(215		)	(215		)	—		—		—		—		—		—		—
Regulatory offset to NDT fund-related activities^(b)	(1		)	(1		)	—		—		—		—		—		—		—
Decommissioning-related activities	(23		)	(23		)	—		—		—		—		—		—		—
AFUDC — Equity	31			—			8		2		8		13		12		1		—
Non-service net periodic benefit cost	(21		)	—			—		—		—		—		—		—		—

_________


(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
Six Months Ended June 30, 2019
Property, plant and equipment^(a)	$	1,859	$	789	$	439	$	149	$	173	$	266	$	117	$	71	$	57
Amortization of regulatory assets^(a)	266		—		69		15		79		103		69		20		14
Amortization of intangible assets, net^(a)	29		25		—		—		—		—		—		—		—
Amortization of energy contract assets and liabilities^(b)	5		5		—		—		—		—		—		—		—
Nuclear fuel^(c)	513		513		—		—		—		—		—		—		—
ARO accretion^(d)	250		248		—		—		—		—		—		—		—
Total depreciation, amortization and accretion	$	2,922	$	1,580	$	508	$	164	$	252	$	369	$	186	$	91	$	71

Six Months Ended June 30, 2018
Property, plant and equipment^(a)	$	1,873	$	890	$	406	$	135	$	164	$	236	$	107	$	64	$	47
Amortization of regulatory assets^(a)	278		—		53		14		84		127		81		24		22
Amortization of intangible assets, net^(a)	28		24		—		—		—		—		—		—		—
Amortization of energy contract assets and liabilities^(b)	10		10		—		—		—		—		—		—		—
Nuclear fuel^(c)	569		569		—		—		—		—		—		—		—
ARO accretion^(d)	242		242		—		—		—		—		—		—		—
Total depreciation, amortization and accretion	$	3,000	$	1,735	$	459	$	149	$	248	$	363	$	188	$	88	$	69

_________


(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
Six Months Ended June 30, 2019
Pension and non-pension postretirement benefit costs	$	212		$	62		$	47	$	5	$	29	$	48		$	12		$	8		$	8
Provision for uncollectible accounts	45			12			16		10		4		3			2			1			—
Other decommissioning-related activity^(a)	(260		)	(261		)	—		—		—		—			—			—			—
Energy-related options^(b)	43			43			—		—		—		—			—			—			—
Amortization of rate stabilization deferral	(10		)	—			—		—		—		(10		)	(8		)	(2		)	—
Discrete impacts from EIMA and FEJA^(c)	24			—			24		—		—		—			—			—			—
Long-term incentive plan	35			—			—		—		—		—			—			—			—
Amortization of operating ROU asset	115			78			1		—		15		17			4			5			2

Six Months Ended June 30, 2018
Pension and non-pension postretirement benefit costs	$	290		$	100		$	88	$	10	$	29	$	34		$	8		$	3		$	6
Provision for uncollectible accounts	77			28			18		11		5		15			7			2			5
Other decommissioning-related activity^(a)	(61		)	(61		)	—		—		—		—			—			—			—
Energy-related options^(b)	(7		)	(7		)	—		—		—		—			—			—			—
Amortization of rate stabilization deferral	13			—			—		—		—		13			10			3			—
Discrete impacts from EIMA and FEJA^(c)	14			—			14		—		—		—			—			—			—
Long-term incentive plan	51			—			—		—		—		—			—			—			—

_______

(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
June 30, 2019
Cash and cash equivalents	$	735	$	575	$	65	$	20	$	8	$	54	$	18	$	3	$	4
Restricted cash	252		122		77		6		1		37		34		1		2
Restricted cash included in other long-term assets	191		—		174		—		—		17		—		—		17
Total cash, cash equivalents and restricted cash	$	1,178	$	697	$	316	$	26	$	9	$	108	$	52	$	4	$	23

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

June 30, 2018
Cash and cash equivalents	$	694	$	420	$	30	$	18	$	7	$	195	$	47	$	141	$	6
Restricted cash	206		130		5		5		1		38		33		—		5
Restricted cash included in other long-term assets	128		—		108		—		—		20		—		—		20
Total cash, cash equivalents and restricted cash	$	1,028	$	550	$	143	$	23	$	8	$	253	$	80	$	141	$	31

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
June 30, 2019	$	1,352	$	703	$	218	$	121	$	115	$	195	$	107	$	47	$	41
December 31, 2018	1,656		965		223		114		168		186		97		59		30



	Accrued expenses
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
June 30, 2019
Compensation-related accruals^(a)	$	767	$	292	$	117	$	52	$	41	$	72	$	23	$	15	$	10
Taxes accrued	446		304		65		14		21		75		54		13		9
Interest accrued	340		76		109		33		40		50		24		8		13

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

6 Months Ended

Jun. 30, 2019

Segment Reporting [Abstract]

Analysis and reconciliation of reportable segment information

An analysis and reconciliation of the Registrants’ reportable segment information to the respective information in the consolidated financial statements for the three and six months ended June 30, 2019 and 2018 is as follows:

Three Months Ended June 30, 2019 and 2018



	Generation^(a)		ComEd		PECO		BGE		PHI		Other^(b)		Intersegment Eliminations			Exelon
Operating revenues^(c):
2019
Competitive businesses electric revenues	$	3,718	$	—	$	—	$	—	$	—	$	—	$	(250	)	$	3,468
Competitive businesses natural gas revenues	333		—		—		—		—		—		—			333
Competitive businesses other revenues	159		—		—		—		—		—		(1		)	158
Rate-regulated electric revenues	—		1,351		566		540		1,063		—		(8		)	3,512
Rate-regulated natural gas revenues	—		—		89		109		24		—		(4		)	218
Shared service and other revenues	—		—		—		—		4		484		(488		)	—
Total operating revenues	$	4,210	$	1,351	$	655	$	649	$	1,091	$	484	$	(751	)	$	7,689



	Generation^(a)		ComEd		PECO			BGE		PHI		Other^(b)			Intersegment Eliminations			Exelon
2018
Competitive businesses electric revenues	$	3,939	$	—	$	—		$	—	$	—	$	—		$	(270	)	$	3,669
Competitive businesses natural gas revenues	489		—		—			—		—		—			—			489
Competitive businesses other revenues	151		—		—			—		—		—			(4		)	147
Rate-regulated electric revenues	—		1,398		560			548		1,045		—			(9		)	3,542
Rate-regulated natural gas revenues	—		—		93			114		28		—			(5		)	230
Shared service and other revenues	—		—		—			—		3		487			(491		)	(1		)
Total operating revenues	$	4,579	$	1,398	$	653		$	662	$	1,076	$	487		$	(779	)	$	8,076
Intersegment revenues^(d):
2019	$	252	$	5	$	2		$	6	$	3	$	482		$	(750	)	$	—
2018	273		5		2			6		3		487			(776		)	—
Depreciation and amortization:
2019	$	409	$	257	$	83		$	117	$	188	$	25		$	—		$	1,079
2018	466		231		74			114		180		23			—			1,088
Operating expenses:
2019	$	4,096	$	1,040	$	510		$	569	$	926	$	484		$	(744	)	$	6,881
2018	4,298		1,111		526			578		923		492			(790		)	7,138
Interest expense, net:
2019	$	116	$	89	$	33		$	29	$	67	$	75		$	—		$	409
2018	102		85		32			25		65		64			—			373
Income (loss) before income taxes:
2019	$	202	$	232	$	115		$	56	$	112	$	(73	)	$	—		$	644
2018	209		207		95			64		99		(61		)	—			613
Income Taxes:
2019	$	78	$	46	$	13		$	11	$	6	$	(10	)	$	—		$	144
2018	23		43		(1		)	13		15		(27		)	—			66
Net income (loss):
2019	$	118	$	186	$	102		$	45	$	106	$	(63	)	$	—		$	494
2018	181		164		96			51		84		(34		)	—			542
Capital Expenditures
2019	$	383	$	459	$	225		$	284	$	340	$	11		$	—		$	1,702
2018	670		495		194			210		371		(13		)	—			1,927

__________

(a)

Intersegment revenues for Generation in 2019 include revenue from sales to PECO of $35 million, sales to BGE of $57 million, sales to Pepco of $52 million, sales to DPL of $12 million and sales to ACE of $5 million in the Mid-Atlantic region, and sales to ComEd of $89 million in the Midwest region, which eliminate upon consolidation. Intersegment revenues for Generation in 2018 include revenue from sales to PECO of $25 million, sales to BGE of $63 million, sales to Pepco of $46 million, sales to DPL of $30 million and sales to ACE of $6 million in the Mid-Atlantic region, and sales to ComEd of $103 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	$	531	$	261	$	274	$	—		$	(3	)	$	1,063
Rate-regulated natural gas revenues	—		24		—		—			—			24
Shared service and other revenues	—		2		—		97			(95		)	4
Total operating revenues	$	531	$	287	$	274	$	97		$	(98	)	$	1,091
2018
Rate-regulated electric revenues	$	523	$	261	$	265	$	—		$	(4	)	$	1,045
Rate-regulated natural gas revenues	—		28		—		—			—			28
Shared service and other revenues	—		—		—		108			(105		)	3
Total operating revenues	$	523	$	289	$	265	$	108		$	(109	)	$	1,076
Intersegment revenues:
2019	$	1	$	2	$	1	$	98		$	(99	)	$	3
2018	2		2		1		107			(109		)	3
Depreciation and amortization:
2019	$	93	$	45	$	40	$	10		$	—		$	188
2018	92		43		36		9			—			180
Operating expenses:
2019	$	438	$	243	$	246	$	100		$	(101	)	$	926
2018	438		247		240		110			(112		)	923
Interest expense, net:
2019	$	34	$	15	$	15	$	3		$	—		$	67
2018	32		14		16		3			—			65
Income (loss) before income taxes:
2019	$	66	$	34	$	14	$	106		$	(108	)	$	112
2018	61		31		10		85			(88		)	99
Income Taxes:
2019	$	2	$	4	$	—	$	—		$	—		$	6
2018	7		5		2		1			—			15
Net income (loss):
2019	$	64	$	30	$	14	$	(5	)	$	3		$	106
2018	54		26		8		(7		)	3			84
Capital Expenditures
2019	$	154	$	82	$	99	$	5		$	—		$	340
2018	160		101		107		3			—			371

__________


(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.

Six Months Ended June 30, 2019 and 2018



	Generation^(a)		ComEd		PECO		BGE		PHI		Other^(b)		Intersegment Eliminations			Exelon
Operating revenues^(c):
2019
Competitive businesses electric revenues	$	8,052	$	—	$	—	$	—	$	—	$	—	$	(565	)	$	7,487
Competitive businesses natural gas revenues	1,214		—		—		—		—		—		(1		)	1,213
Competitive businesses other revenues	240		—		—		—		—		—		(2		)	238
Rate-regulated electric revenues	—		2,759		1,185		1,198		2,218		—		(17		)	7,343
Rate-regulated natural gas revenues	—		—		369		427		95		—		(8		)	883
Shared service and other revenues	—		—		—		—		6		940		(944		)	2
Total operating revenues	$	9,506	$	2,759	$	1,554	$	1,625	$	2,319	$	940	$	(1,537	)	$	17,166
2018
Competitive businesses electric revenues	$	8,448	$	—	$	—	$	—	$	—	$	—	$	(663	)	$	7,785
Competitive businesses natural gas revenues	1,444		—		—		—		—		—		(8		)	1,436
Competitive businesses other revenues	198		—		—		—		—		—		(2		)	196
Rate-regulated electric revenues	—		2,910		1,193		1,206		2,214		—		(27		)	7,496
Rate-regulated natural gas revenues	—		—		325		433		106		—		(9		)	855
Shared service and other revenues	—		—		—		—		7		940		(946		)	1
Total operating revenues	$	10,090	$	2,910	$	1,518	$	1,639	$	2,327	$	940	$	(1,655	)	$	17,769
Shared service and other revenues
Intersegment revenues^(d):
2019	$	568	$	9	$	3	$	12	$	7	$	935	$	(1,534	)	$	—
2018	672		19		3		12		7		937		(1,650		)	—
Depreciation and amortization:
2019	$	814	$	508	$	164	$	252	$	369	$	47	$	—		$	2,154
2018	914		459		149		248		363		46		—			2,179
Operating expenses:
2019	$	9,059	$	2,174	$	1,187	$	1,325	$	1,981	$	942	$	(1,526	)	$	15,142
2018	9,515		2,335		1,249		1,378		2,048		936		(1,675		)	15,786
Interest expense, net:
2019	$	227	$	178	$	67	$	58	$	131	$	152	$	—		$	813
2018	202		175		64		51		128		125		—			745



	Generation^(a)		ComEd		PECO			BGE		PHI		Other^(b)			Intersegment Eliminations			Exelon
Income (loss) before income taxes:
2019	$	854	$	429	$	307		$	253	$	234	$	(151	)	$	—		$	1,926
2018	412		417		207			220		173		(114		)	—			1,315
Income Taxes:
2019	$	301	$	85	$	37		$	47	$	11	$	(27	)	$	—		$	454
2018	32		88		(3		)	41		24		(57		)	—			125
Net income (loss):
2019	$	540	$	344	$	270		$	206	$	223	$	(123	)	$	—		$	1,460
2018	368		329		210			179		149		(56		)	—			1,179
Capital Expenditures
2019	$	890	$	961	$	447		$	542	$	698	$	34		$	—		$	3,572
2018	1,298		1,026		411			434		629		9			—			3,807
Total assets:
June 30, 2019	$	48,402	$	31,889	$	11,002		$	10,006	$	22,454	$	8,142		$	(10,299	)	$	121,596
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 $80 million, sales to BGE of $133 million, sales to Pepco of $122 million, sales to DPL of $35 million and sales to ACE of $13 million in the Mid-Atlantic region, and sales to ComEd of $183 million in the Midwest region, which eliminate upon consolidation. Intersegment revenues for Generation in 2018 include revenue from sales to PECO of $61 million, sales to BGE of $128 million, sales to Pepco of $98 million, sales to DPL of $76 million and sales to ACE of $12 million in the Mid-Atlantic region, and sales to ComEd of $297 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	$	1,106	$	572	$	547	$	—		$	(7	)	$	2,218
Rate-regulated natural gas revenues	—		95		—		—			—			95
Shared service and other revenues	—		—		—		205			(199		)	6
Total operating revenues	$	1,106	$	667	$	547	$	205		$	(206	)	$	2,319
2018
Rate-regulated electric revenues	$	1,080	$	567	$	575	$	—		$	(8	)	$	2,214
Rate-regulated natural gas revenues	—		106		—		—			—			106
Shared service and other revenues	—		—		—		221			(214		)	7
Total operating revenues	$	1,080	$	673	$	575	$	221		$	(222	)	$	2,327
Intersegment revenues:
2019	$	3	$	3	$	1	$	205		$	(205	)	$	7
2018	3		4		2		220			(222		)	7
Depreciation and amortization:
2019	$	186	$	91	$	71	$	20		$	1		$	369
2018	188		88		69		19			(1		)	363
Operating expenses:
2019	$	929	$	550	$	498	$	208		$	(204	)	$	1,981
2018	939		582		526		224			(223		)	2,048
Interest expense, net:
2019	$	68	$	30	$	28	$	5		$	—		$	131
2018	63		27		32		5			1			128
Income (loss) before income taxes:
2019	$	123	$	94	$	25	$	219		$	(227	)	$	234
2018	94		69		18		149			(157		)	173
Income Taxes:
2019	$	4	$	11	$	1	$	(4	)	$	(1	)	$	11
2018	9		12		3		—			—			24
Net income (loss):
2019	$	119	$	83	$	24	$	(10	)	$	7		$	223
2018	85		57		15		(15		)	7			149
Capital Expenditures
2019	$	298	$	160	$	227	$	13		$	—		$	698
2018	287		166		170		6			—			629
Total assets:
June 30, 2019	$	8,556	$	4,683	$	3,886	$	11,168		$	(5,839	)	$	22,454
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

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 June 30, 2019
	Revenues from external parties^(a)						Intersegment revenues			Total Revenues
	Contracts with customers		Other^(b)		Total		Intersegment revenues			Total Revenues
Mid-Atlantic	$	1,162	$	21	$	1,183	$	6		$	1,189
Midwest	974		68		1,042		(8		)	1,034
New York	373		17		390		—			390
ERCOT	178		47		225		4			229
Other Power Regions	814		64		878		(17		)	861
Total Competitive Businesses Electric Revenues	3,501		217		3,718		(15		)	3,703
Competitive Businesses Natural Gas Revenues	177		156		333		15			348
Competitive Businesses Other Revenues^(c)	108		51		159		—			159
Total Generation Consolidated Operating Revenues	$	3,786	$	424	$	4,210	$	—		$	4,210



	Three Months Ended June 30, 2018
	Revenues from external customers(a)							Intersegment revenues			Total Revenues
	Contracts with customers		Other(b)			Total		Intersegment revenues			Total Revenues
Mid-Atlantic	$	1,220	$	58		$	1,278	$	4		$	1,282
Midwest	1,062		73			1,135		(5		)	1,130
New York	392		(2		)	390		2			392
ERCOT	165		111			276		1			277
Other Power Regions	761		99			860		(39		)	821
Total Competitive Businesses Electric Revenues	3,600		339			3,939		(37		)	3,902
Competitive Businesses Natural Gas Revenues	295		194			489		37			526
Competitive Businesses Other Revenues^(c)	125		26			151		—			151
Total Generation Consolidated Operating Revenues	$	4,020	$	559		$	4,579	$	—		$	4,579

__________


(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 $38 million and losses of $5 million in 2019 and 2018, respectively, and elimination of intersegment revenues.

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



	Three Months Ended June 30, 2019							Three Months Ended June 30, 2018
	RNF from external customers^(a)		Intersegment RNF			Total RNF		RNF from external customers^(a)		Intersegment RNF			Total RNF
Mid-Atlantic	$	644	$	8		$	652	$	722	$	13		$	735
Midwest	738		(8		)	730		770		2			772
New York	250		3			253		259		7			266
ERCOT	80		(1		)	79		129		(47		)	82
Other Power Regions	154		(20		)	134		229		(43		)	186
Total Revenues net of purchased power and fuel for Reportable Segments	1,866		(18		)	1,848		2,109		(68		)	2,041
Other^(b)	52		18			70		190		68			258
Total Generation Revenues net of purchased power and fuel expense	$	1,918	$	—		$	1,918	$	2,299	$	—		$	2,299

__________


(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 $74 million and gains of $90 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 $5 million decrease and $20 million decrease to RNF in 2019 and 2018, respectively, and the elimination of intersegment RNF.

Competitive Business Revenues (Generation):



	Six Months Ended June 30, 2019
	Revenues from external parties^(a)							Intersegment Revenues			Total Revenues
	Contracts with customers		Other^(b)			Total		Intersegment Revenues			Total Revenues
Mid-Atlantic	$	2,448	$	(2	)	$	2,446	$	(1	)	$	2,445
Midwest	2,030		126			2,156		(14		)	2,142
New York	781		1			782		—			782
ERCOT	307		126			433		8			441
Other Power Regions	1,976		259			2,235		(21		)	2,214
Total Competitive Businesses Electric Revenues	7,542		510			8,052		(28		)	8,024
Competitive Businesses Natural Gas Revenues	763		451			1,214		28			1,242
Competitive Businesses Other Revenues^(c)	230		10			240		—			240
Total Generation Consolidated Operating Revenues	$	8,535	$	971		$	9,506	$	—		$	9,506



	Six Months Ended June 30, 2018
	Revenues from external customers^(a)							Intersegment revenues			Total Revenues
	Contracts with customers		Other^(b)			Total		Intersegment revenues			Total Revenues
Mid-Atlantic	$	2,574	$	138		$	2,712	$	10		$	2,722
Midwest	2,336		143			2,479		(4		)	2,475
New York	831		(31		)	800		1			801
ERCOT	315		169			484		2			486
Other Power Regions	1,696		277			1,973		(71		)	1,902
Total Competitive Businesses Electric Revenues	7,752		696			8,448		(62		)	8,386
Competitive Businesses Natural Gas Revenues	816		628			1,444		62			1,506
Competitive Businesses Other Revenues^(c)	258		(60		)	198		—			198
Total Generation Consolidated Operating Revenues	$	8,826	$	1,264		$	10,090	$	—		$	10,090

__________


(a)	Includes all wholesale and retail electric sales to third parties and affiliated sales to the Utility Registrants.


(b)	Includes revenues from derivatives and leases.


(c)	Other represents activities not allocated to a region. See text above for a description of included activities. Includes unrealized mark-to-market losses of $14 million and $102 million in 2019 and 2018, respectively, and elimination of intersegment revenues.

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



	Six Months Ended June 30, 2019							Six Months Ended June 30, 2018
	RNF from external customers^(a)		Intersegment RNF			Total RNF		RNF from external customers^(a)		Intersegment RNF			Total RNF
Mid-Atlantic	$	1,324	$	10		$	1,334	$	1,558	$	28		$	1,586
Midwest	1,506		(6		)	1,500		1,617		14			1,631
New York	512		7			519		541		8			549
ERCOT	178		(24		)	154		235		(117		)	118
Other Power Regions	328		(36		)	292		511		(87		)	424
Total Revenues net of purchased power and fuel expense for Reportable Segments	3,848		(49		)	3,799		4,462		(154		)	4,308
Other^(b)	161		49			210		55		154			209
Total Generation Revenues net of purchased power and fuel expense	$	4,009	$	—		$	4,009	$	4,517	$	—		$	4,517

__________


(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 $102 million and $175 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 $9 million and $34 million decrease to RNF in 2019 and 2018, respectively, and the elimination of intersegment RNF.

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

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



	Three Months Ended June 30, 2019
Revenues from contracts with customers	ComEd			PECO			BGE		PHI			Pepco			DPL		ACE
Rate-regulated electric revenues
Residential	$	647		$	343		$	282	$	494		$	224		$	135	$	135
Small commercial & industrial	349			99			59		120			35			44		41
Large commercial & industrial	127			52			109		278			207			25		46
Public authorities & electric railroads	10			7			6		16			8			4		4
Other^(a)	227			62			82		159			56			54		50
Total rate-regulated electric revenues^(b)	$	1,360		$	563		$	538	$	1,067		$	530		$	262	$	276
Rate-regulated natural gas revenues
Residential	$	—		$	49		$	60	$	11		$	—		$	11	$	—
Small commercial & industrial	—			33			11		7			—			7		—
Large commercial & industrial	—			—			23		2			—			2		—
Transportation	—			6			—		3			—			3		—
Other^(c)	—			1			7		1			—			1		—
Total rate-regulated natural gas revenues^(d)	$	—		$	89		$	101	$	24		$	—		$	24	$	—
Total rate-regulated revenues from contracts with customers	$	1,360		$	652		$	639	$	1,091		$	530		$	286	$	276

Other revenues
Revenues from alternative revenue programs	$	(14	)	$	(3	)	$	6	$	(3	)	$	(1	)	$	—	$	(2	)
Other rate-regulated electric revenues^(e)	5			6			3		3			2			1		—
Other rate-regulated natural gas revenues^(e)	—			—			1		—			—			—		—
Total other revenues	$	(9	)	$	3		$	10	$	—		$	1		$	1	$	(2	)
Total rate-regulated revenues for reportable segments	$	1,351		$	655		$	649	$	1,091		$	531		$	287	$	274



	Three Months Ended June 30, 2018
Revenues from contracts with customers	ComEd			PECO		BGE			PHI			Pepco			DPL		ACE
Rate-regulated electric revenues
Residential	$	699		$	338	$	295		$	505		$	228		$	142	$	135
Small commercial & industrial	357			97		60			115			33			44		38
Large commercial & industrial	127			52		101			282			212			25		45
Public authorities & electric railroads	12			6		7			16			9			3		4
Other^(a)	213			60		78			133			49			41		44
Total rate-regulated electric revenues^(b)	$	1,408		$	553	$	541		$	1,051		$	531		$	255	$	266
Rate-regulated natural gas revenues
Residential	$	—		$	62	$	74		$	13		$	—		$	13	$	—
Small commercial & industrial	—			25		13			8			—			8		—
Large commercial & industrial	—			—		23			1			—			1		—
Transportation	—			5		—			4			—			4		—
Other^(c)	—			1		12			2			—			2		—
Total rate-regulated natural gas revenues^(d)	$	—		$	93	$	122		$	28		$	—		$	28	$	—
Total rate-regulated revenues from contracts with customers	$	1,408		$	646	$	663		$	1,079		$	531		$	283	$	266

Other revenues
Revenues from alternative revenue programs	$	(17	)	$	2	$	(4	)	$	(7	)	$	(10	)	$	4	$	(1	)
Other rate-regulated electric revenues^(e)	7			5		3			4			2			2		—
Other rate-regulated natural gas revenues^(e)	—			—		—			—			—			—		—
Total other revenues	$	(10	)	$	7	$	(1	)	$	(3	)	$	(8	)	$	6	$	(1	)
Total rate-regulated revenues for reportable segments	$	1,398		$	653	$	662		$	1,076		$	523		$	289	$	265

__________


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


(b)	Includes operating revenues from affiliates of $5 million, $1 million, $1 million, $3 million, $1 million, $2 million and $1 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2019 and $5 million, $2 million, $2 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 2018.

(e)

Includes late payment charge revenues.

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



	Six Months Ended June 30, 2019
Revenues from contracts with customers	ComEd			PECO			BGE		PHI		Pepco		DPL		ACE
Rate-regulated electric revenues
Residential	$	1,356		$	752		$	667	$	1,073	$	480	$	320	$	273
Small commercial & industrial	709			195			129		241		73		93		75
Large commercial & industrial	259			100			219		545		411		49		85
Public authorities & electric railroads	23			14			13		31		17		7		7
Other^(a)	442			123			160		317		108		101		108
Total rate-regulated electric revenues^(b)	2,789			1,184			1,188		2,207		1,089		570		548
Rate-regulated natural gas revenues
Residential	—			247			279		55		—		55		—
Small commercial & industrial	—			105			46		26		—		26		—
Large commercial & industrial	—			1			73		3		—		3		—
Transportation	—			13			—		7		—		7		—
Other^(c)	—			3			13		4		—		4		—
Total rate-regulated natural gas revenues^(d)	—			369			411		95		—		95		—
Total rate-regulated revenues from contracts with customers	2,789			1,553			1,599		2,302		1,089		665		548

Other revenues
Revenues from alternative revenue programs	(42		)	(6		)	17		12		13		1		(1		)
Other rate-regulated electric revenues^(e)	12			7			6		5		4		1		—
Other rate-regulated natural gas revenues^(e)	—			—			3		—		—		—		—
Total other revenues	(30		)	1			26		17		17		2		(1		)
Total rate-regulated revenues for reportable segments	$	2,759		$	1,554		$	1,625	$	2,319	$	1,106	$	667	$	547



	Six Months Ended June 30, 2018
Revenues from contracts with customers	ComEd			PECO		BGE			PHI		Pepco		DPL		ACE
Rate-regulated electric revenues
Residential	$	1,416		$	741	$	688		$	1,114	$	486	$	333	$	295
Small commercial & industrial	741			198		128			230		65		90		75
Large commercial & industrial	280			110		207			541		402		48		91
Public authorities & electric railroads	25			14		14			30		16		7		7
Other^(a)	444			122		156			289		98		82		110
Total rate-regulated electric revenues^(b)	2,906			1,185		1,193			2,204		1,067		560		578
Rate-regulated natural gas revenues
Residential	—			223		298			60		—		60		—
Small commercial & industrial	—			87		47			26		—		26		—
Large commercial & industrial	—			1		70			5		—		5		—
Transportation	—			11		—			9		—		9		—
Other^(c)	—			3		40			6		—		6		—
Total rate-regulated natural gas revenues^(d)	—			325		455			106		—		106		—
Total rate-regulated revenues from contracts with customers	2,906			1,510		1,648			2,310		1,067		666		578

Other revenues
Revenues from alternative revenue programs	(12		)	1		(17		)	12		10		5		(3		)
Other rate-regulated electric revenues^(e)	16			7		6			5		3		2		—
Other rate-regulated natural gas revenues^(e)	—			—		2			—		—		—		—
Total other revenues	4			8		(9		)	17		13		7		(3		)
Total rate-regulated revenues for reportable segments	$	2,910		$	1,518	$	1,639		$	2,327	$	1,080	$	673	$	575

__________


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


(b)	Includes operating revenues from affiliates of $9 million, $2 million, $1 million, $7 million, $3 million, $3 million and $1 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2019 and $19 million, $3 million, $3 million, $7 million $3 million, $4 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 $1 million and $9 million at PECO and BGE, respectively, in 2019 and less than $1 million and $9 million at PECO and BGE, respectively, in 2018,

(e)

Includes late payment charge revenues.

Variable Interest Entities - Narrative (Details) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019 USD ($) VIE	Jun. 30, 2018 USD ($)	Jun. 30, 2019 USD ($) VIE	Jun. 30, 2018 USD ($)	Dec. 31, 2018 USD ($) VIE	Apr. 01, 2014 USD ($)
Variable Interest Entity [Line Items]
Number Of Variable Interest Entities Consolidated \| VIE	5		5		5
Number of Variable Interest Entities not consolidated by equity holders \| VIE	8		8		7
Guarantor Obligations, Maximum Exposure, Undiscounted	$ 68		$ 68
Variable Interest Entity, Nonconsolidated, Carrying Amount, Assets and Liabilities, Net	16		16		$ 15
Variable Interest Entity, Reporting Entity Involvement, Maximum Loss Exposure, Amount	$ 16		$ 16		$ 15
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]
Variable Interest Entity [Line Items]
Number Of Variable Interest Entities Consolidated \| VIE	3		3		3
Number of Variable Interest Entities not consolidated by equity holders \| VIE	8		8		7
Guarantor Obligations, Current Carrying Value	$ 6		$ 6		$ 34
Variable Interest Entity, Nonconsolidated, Carrying Amount, Assets and Liabilities, Net	12		12		13
Variable Interest Entity, Reporting Entity Involvement, Maximum Loss Exposure, Amount	12		12		$ 13
Exelon Generation Co L L C [Member] \| CENG [Member]
Variable Interest Entity [Line Items]
Guarantor Obligations, Current Carrying Value	$ 688		$ 688
Equity Method Investment, Ownership Percentage	50.01%		50.01%
Due from Affiliates						$ 400
Atlantic City Electric Company [Member]
Variable Interest Entity [Line Items]
Number Of Variable Interest Entities Consolidated \| VIE	1		1		1
Guarantor Obligations, Maximum Exposure, Undiscounted	$ 17		$ 17
Atlantic City Electric Company [Member] \| ATF [Member]
Variable Interest Entity [Line Items]
Cash Remitted To VIE	$ 3	$ 6	$ 7	$ 14
Pepco Holdings LLC [Member]
Variable Interest Entity [Line Items]
Number Of Variable Interest Entities Consolidated \| VIE	1		1		1
Investments [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity, Reporting Entity Involvement, Maximum Loss Exposure, Amount	$ 203		$ 203		$ 223
Investments [Member] \| Exelon Generation Co L L C [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity, Reporting Entity Involvement, Maximum Loss Exposure, Amount	203		203		223
Finite-Lived Intangible Assets [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity, Reporting Entity Involvement, Maximum Loss Exposure, Amount	7		7		7
Finite-Lived Intangible Assets [Member] \| Exelon Generation Co L L C [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity, Reporting Entity Involvement, Maximum Loss Exposure, Amount	$ 7		$ 7		$ 7

Variable Interest Entities - Carrying Amounts and Classification of Consolidated VIE Assets and Liabilities (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Variable Interest Entity [Line Items]
Current assets	$ 649	$ 938
Noncurrent assets	9,204	9,071
Total assets	9,853	10,009
Current liabilities	715	274
Noncurrent liabilities	2,861	3,280
Total liabilities	3,576	3,554
Exelon Generation Co L L C [Member]
Variable Interest Entity [Line Items]
Current assets	646	931
Noncurrent assets	9,184	9,045
Total assets	9,830	9,976
Current liabilities	694	252
Noncurrent liabilities	2,827	3,233
Total liabilities	3,521	3,485
Pepco Holdings LLC [Member]
Variable Interest Entity [Line Items]
Current assets	3	7
Noncurrent assets	20	26
Total assets	23	33
Current liabilities	21	22
Noncurrent liabilities	34	47
Total liabilities	55	69
Atlantic City Electric Company [Member]
Variable Interest Entity [Line Items]
Current assets	2	4
Noncurrent assets	17	19
Total assets	19	23
Current liabilities	20	19
Noncurrent liabilities	31	40
Total liabilities	$ 51	$ 59

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

Jun. 30, 2019

Dec. 31, 2018

Jun. 30, 2018

Dec. 31, 2017

$ 735

$ 1,349

$ 694

$ 898

252

247

206

207

4,125

4,607

1,008

1,256

1,412

1,351

1,218

1,238

11,655

13,360

78,030

76,707

12,513

11,661

3,038

1,575

^[1]

121,596

119,666

3,776

1,349

3,248

3,800

1,706

2,112

145

149

1,367

1,035

12,934

11,404

31,909

34,075

10,023

9,679

398

463

3,053

2,130

Variable Interest Entity, Primary Beneficiary [Member]

^[1]

87,689

86,596

106

414

161

146

217

212

626

913

6,084

6,145

2,589

2,351

227

258

8,900

8,754

9,526

9,667

560

715

273

558

1,072

2,218

2,160

2,853

3,275

3,568

3,548

575

750

420

416

122

153

130

138

2,528

2,941

326

562

984

963

849

883

7,376

8,433

23,810

23,981

12,513

11,661

1,841

755

^[2]

48,402

47,556

2,733

906

1,517

1,847

767

898

481

279

6,842

5,769

5,079

6,989

9,792

9,450

1,449

610

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

^[2]

32,810

32,048

106

414

161

146

217

212

623

906

6,084

6,145

2,589

2,351

207

232

8,880

8,728

9,503

9,634

540

694

252

524

1,025

2,218

2,160

2,819

3,228

3,513

3,480

124

195

489

453

196

177

195

163

1,546

1,533

13,788

13,446

360

^[3]

22,454

21,984

118

125

426

496

224

256

119

133

123

1,328

1,592

6,391

6,134

385

442

617

369

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

^[3]

12,882

12,702

Atlantic City Electric Company [Member]

$ 5

$ 6

112

299

240

3,093

2,966

^[4]

3,886

3,699

135

154

299

422

1,310

1,170

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

^[4]

2,605

2,573

$ 51

$ 59

[1]	Exelon’s consolidated assets include $9,526 million and $9,667 million at June 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 $3,568 million and $3,548 million at June 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 $9,503 million and $9,634 million at June 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 $3,513 million and $3,480 million at June 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 $23 million and $33 million at June 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 $55 million and $69 million at June 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 $19 million and $23 million at June 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 $51 million and $59 million at June 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	Jun. 30, 2019	Dec. 31, 2018
Variable Interest Entity [Line Items]
Total assets	$ 1,056	$ 1,069
Total liabilities	258	259
Exelon's ownership interest in VIE	203	223
Other ownership interests in VIE	596	587
Registrants' maximum exposure to loss	16	15
Carrying amount of equity method investments
Variable Interest Entity [Line Items]
Registrants' maximum exposure to loss	203	223
Contract intangible asset
Variable Interest Entity [Line Items]
Registrants' maximum exposure to loss	7	7
Commercial Agreement Variable Interest Entities [Member]
Variable Interest Entity [Line Items]
Total assets	603	597
Total liabilities	33	37
Exelon's ownership interest in VIE	0	0
Other ownership interests in VIE	571	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
Commercial Agreement Variable Interest Entities [Member] \| Contract intangible asset
Variable Interest Entity [Line Items]
Registrants' maximum exposure to loss	7	7
Equity Investment VIE [Member]
Variable Interest Entity [Line Items]
Total assets	453	472
Total liabilities	225	222
Exelon's ownership interest in VIE	203	223
Other ownership interests in VIE	25	27
Equity Investment VIE [Member] \| Carrying amount of equity method investments
Variable Interest Entity [Line Items]
Registrants' maximum exposure to loss	203	223
Equity Investment VIE [Member] \| Contract intangible asset
Variable Interest Entity [Line Items]
Registrants' maximum exposure to loss	0	0
Exelon Generation Co L L C [Member]
Variable Interest Entity [Line Items]
Total assets	1,056	1,069
Total liabilities	258	259
Exelon's ownership interest in VIE	203	223
Other ownership interests in VIE	596	587
Registrants' maximum exposure to loss	12	13
Exelon Generation Co L L C [Member] \| Carrying amount of equity method investments
Variable Interest Entity [Line Items]
Registrants' maximum exposure to loss	203	223
Exelon Generation Co L L C [Member] \| Contract intangible asset
Variable Interest Entity [Line Items]
Registrants' maximum exposure to loss	7	7
Exelon Generation Co L L C [Member] \| Commercial Agreement Variable Interest Entities [Member]
Variable Interest Entity [Line Items]
Total assets	603	597
Total liabilities	33	37
Exelon's ownership interest in VIE	0	0
Other ownership interests in VIE	571	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] \| Commercial Agreement Variable Interest Entities [Member] \| Contract intangible asset
Variable Interest Entity [Line Items]
Registrants' maximum exposure to loss	7	7
Exelon Generation Co L L C [Member] \| Equity Investment VIE [Member]
Variable Interest Entity [Line Items]
Total assets	453	472
Total liabilities	225	222
Exelon's ownership interest in VIE	203	223
Other ownership interests in VIE	25	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	203	223
Exelon Generation Co L L C [Member] \| Equity Investment VIE [Member] \| Contract intangible asset
Variable Interest Entity [Line Items]
Registrants' maximum exposure to loss	$ 0	$ 0

Mergers, Acquisitions and Dispositions - Acquisitions Narrative (Details) - USD ($) $ in Millions		6 Months Ended
	Apr. 04, 2018	Jun. 30, 2019	Jun. 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
	Feb. 28, 2018	Jun. 30, 2019	Sep. 30, 2018	Dec. 31, 2018
Business Dispositions [Line Items]
Assets held for sale		$ 880		$ 904
Liabilities held for sale		764		777
Exelon Generation Co L L C [Member]
Business Dispositions [Line Items]
Assets held for sale		880		904
Liabilities held for sale		764		777
Oyster Creek [Member]
Business Dispositions [Line Items]
Assets held for sale		863		897
Liabilities held for sale		759		777
Asset Retirement Obligation Revision Of Estimate In Operating And Maintenance Expense		9	$ 84
Oyster Creek [Member] \| Exelon Generation Co L L C [Member]
Business Dispositions [Line Items]
Assets held for sale		863		897
Liabilities held for sale		759		$ 777
Asset Retirement Obligation Revision Of Estimate In Operating And Maintenance Expense		$ 9	$ 84
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

Revenue from Contracts with Customers - Change in Contract with Customer, Asset and Liability (Details) - USD ($) $ in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2019	Dec. 31, 2018	Dec. 31, 2017
Change in Contract with Customer, Asset and Liability [Line Items]
Contract Assets	$ 196	$ 187	$ 283
Contract Liabilities	21	27	35
Consideration (received) due, contract assets	(44)	(146)
Consideration received (due), contract liabilities	38	179
Revenues recognized, contract assets	53	50
Revenues recognized, contract liabilities	(44)	(187)
Exelon Generation Co L L C [Member]
Change in Contract with Customer, Asset and Liability [Line Items]
Contract Assets	196	187	283
Contract Liabilities	26	42	$ 35
Consideration (received) due, contract assets	(44)	(146)
Consideration received (due), contract liabilities	115	465
Revenues recognized, contract assets	53	50
Revenues recognized, contract liabilities	$ (131)	$ (458)

Leases Components of Lease Cost (Details) $ in Millions	3 Months Ended	6 Months Ended
Leases Components of Lease Cost (Details) $ in Millions	Jun. 30, 2019 USD ($)	Jun. 30, 2019 USD ($)
Schedule of Components of Lease Cost [Line Items]
Operating Lease Costs	$ 87	$ 155
Variable Lease Costs	77	150
Short-term Lease Costs	3	11
Total Lease Costs	167	316
Sublease Income	$ 16	$ 19
Operating Lease, Weighted Average Remaining Lease Term	9 years 10 months 24 days	9 years 10 months 24 days
Operating Lease Weighted Average Discount Rate, Percent	4.60%	4.60%
Exelon Generation Co L L C [Member]
Schedule of Components of Lease Cost [Line Items]
Operating Lease Costs	$ 61	$ 107
Variable Lease Costs	72	140
Short-term Lease Costs	3	11
Total Lease Costs	136	258
Sublease Income	$ 12	$ 14
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	1	1
Short-term Lease Costs	0	0
Total Lease Costs	$ 2	$ 3
Operating Lease, Weighted Average Remaining Lease Term	4 years 10 months 24 days	4 years 10 months 24 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	$ 0
Variable Lease Costs	0	0
Short-term Lease Costs	0	0
Total Lease Costs	$ 0	$ 0
Operating Lease, Weighted Average Remaining Lease Term	4 years 4 months 24 days	4 years 4 months 24 days
Operating Lease Weighted Average Discount Rate, Percent	3.40%	3.40%
Baltimore Gas and Electric Company [Member]
Schedule of Components of Lease Cost [Line Items]
Operating Lease Costs	$ 9	$ 17
Variable Lease Costs	1	1
Short-term Lease Costs	0	0
Total Lease Costs	$ 10	$ 18
Operating Lease, Weighted Average Remaining Lease Term	5 years 4 months 24 days	5 years 4 months 24 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	$ 13	$ 23
Variable Lease Costs	2	4
Short-term Lease Costs	0	0
Total Lease Costs	15	27
Sublease Income	$ 4	$ 5
Operating Lease, Weighted Average Remaining Lease Term	9 years 2 months 12 days	9 years 2 months 12 days
Operating Lease Weighted Average Discount Rate, Percent	4.10%	4.10%
Potomac Electric Power Company [Member]
Schedule of Components of Lease Cost [Line Items]
Operating Lease Costs	$ 3	$ 6
Variable Lease Costs	1	1
Short-term Lease Costs	0	0
Total Lease Costs	$ 4	$ 7
Operating Lease, Weighted Average Remaining Lease Term	9 years 8 months 12 days	9 years 8 months 12 days
Operating Lease Weighted Average Discount Rate, Percent	3.80%	3.80%
Delmarva Power and Light Company [Member]
Schedule of Components of Lease Cost [Line Items]
Operating Lease Costs	$ 4	$ 7
Variable Lease Costs	0	1
Short-term Lease Costs	0	0
Total Lease Costs	4	8
Sublease Income	$ 4	$ 5
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	3.90%	3.90%
Atlantic City Electric Company [Member]
Schedule of Components of Lease Cost [Line Items]
Operating Lease Costs	$ 3	$ 4
Variable Lease Costs	1	1
Short-term Lease Costs	0	0
Total Lease Costs	$ 4	$ 5
Operating Lease, Weighted Average Remaining Lease Term	5 years 2 months 12 days	5 years 2 months 12 days
Operating Lease Weighted Average Discount Rate, Percent	3.50%	3.50%

Leases Lessee Future Minimum Operating Lease Maturity Payments (Details) $ in Millions	Jun. 30, 2019 USD ($)
Schedule of Lessee, Operating Lease, Liability, Maturity [Line Items]
2019	$ 149
2020	291
2021	246
2022	177
2023	141
Remaining Years	1,051
Total	2,055
Interest	452
Total Operating Lease Liabilities	1,603
Exelon Generation Co L L C [Member]
Schedule of Lessee, Operating Lease, Liability, Maturity [Line Items]
2019	104
2020	202
2021	161
2022	112
2023	99
Remaining Years	834
Total	1,512
Interest	358
Total Operating Lease Liabilities	1,154
Commonwealth Edison Co [Member]
Schedule of Lessee, Operating Lease, Liability, Maturity [Line Items]
2019	2
2020	3
2021	3
2022	2
2023	1
Remaining Years	2
Total	13
Interest	1
Total Operating Lease Liabilities	12
PECO Energy Co [Member]
Schedule of Lessee, Operating Lease, Liability, Maturity [Line Items]
2019	1
2020	1
2021	0
2022	0
2023	0
Remaining Years	0
Total	2
Interest	0
Total Operating Lease Liabilities	2
Baltimore Gas and Electric Company [Member]
Schedule of Lessee, Operating Lease, Liability, Maturity [Line Items]
2019	17
2020	34
2021	31
2022	16
2023	0
Remaining Years	19
Total	117
Interest	20
Total Operating Lease Liabilities	97
Pepco Holdings LLC [Member]
Schedule of Lessee, Operating Lease, Liability, Maturity [Line Items]
2019	23
2020	44
2021	42
2022	41
2023	39
Remaining Years	196
Total	385
Interest	69
Total Operating Lease Liabilities	316
Potomac Electric Power Company [Member]
Schedule of Lessee, Operating Lease, Liability, Maturity [Line Items]
2019	6
2020	9
2021	9
2022	8
2023	8
Remaining Years	43
Total	83
Interest	15
Total Operating Lease Liabilities	68
Delmarva Power and Light Company [Member]
Schedule of Lessee, Operating Lease, Liability, Maturity [Line Items]
2019	5
2020	12
2021	12
2022	11
2023	10
Remaining Years	52
Total	102
Interest	19
Total Operating Lease Liabilities	83
Atlantic City Electric Company [Member]
Schedule of Lessee, Operating Lease, Liability, Maturity [Line Items]
2019	4
2020	5
2021	5
2022	4
2023	3
Remaining Years	6
Total	27
Interest	2
Total Operating Lease Liabilities	$ 25

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 Supplemental Cash Flow Information Related to Leases (Details) $ in Millions	6 Months Ended
	Jun. 30, 2019 USD ($)
Supplemental Cash Flow Information [Line Items]
Operating cash flows from operating leases	$ 142
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	30
Exelon Generation Co L L C [Member]
Supplemental Cash Flow Information [Line Items]
Operating cash flows from operating leases	101
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	7
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	16
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	19
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	15
Potomac Electric Power Company [Member]
Supplemental Cash Flow Information [Line Items]
Operating cash flows from operating leases	5
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	6
Delmarva Power and Light 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	6
Atlantic City Electric Company [Member]
Supplemental Cash Flow Information [Line Items]
Operating cash flows from operating leases	3
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	$ 3

Leases Lessor - Narrative (Details)	6 Months Ended
Leases Lessor - Narrative (Details)	Jun. 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 Components of Operating Lease Income (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2019
Schedule of Operating Lease, Lease Income [Line Items]
Operating Lease Income	$ 14	$ 18
Variable Lease Income	77	129
Exelon Generation Co L L C [Member]
Schedule of Operating Lease, Lease Income [Line Items]
Operating Lease Income	12	15
Variable Lease Income	74	126
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	2
Variable Lease Income	3	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	2
Variable Lease Income	3	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	Jun. 30, 2019 USD ($)
Schedule of Lessor, Operating Lease, Payments to be Received, Maturity [Line Items]
2019	$ 33
2020	51
2021	51
2022	50
2023	49
Remaining years	314
Total	548
Exelon Generation Co L L C [Member]
Schedule of Lessor, Operating Lease, Payments to be Received, Maturity [Line Items]
2019	31
2020	46
2021	46
2022	45
2023	45
Remaining years	271
Total	484
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	2
2020	4
2021	4
2022	5
2023	4
Remaining years	38
Total	57
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	2
2020	3
2021	3
2022	4
2023	3
Remaining years	38
Total	53
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		6 Months Ended		7 Months Ended
	Jul. 22, 2019	May 23, 2019	Apr. 18, 2019	Feb. 28, 2019	May 01, 2017	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2017
Regulatory Matters Additional Narrative Information [Line Items]
Payments to Acquire Property, Plant, and Equipment						$ 1,702	$ 1,927	$ 3,572	$ 3,807
Maximum [Member] \| One-Time Revenue Adjustment [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Amount of Impairment to Carrying Amount of Regulatory Assets						78		78
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					11.00%
Revenue								8	6
Payments to Acquire Property, Plant, and Equipment								447	411
PECO Energy Co [Member] \| Subsequent Event [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Public Utilities, Requested Equity Capital Structure, Percentage	10.35%
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								961	1,026
Increase (Decrease) in Regulatory Assets								88
Public Utilities, Requested Return on Equity, Percentage		8.91%
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								542	434
Increase (Decrease) in Regulatory Liabilities								71
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								698	629
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						10		10
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								298	287
Increase (Decrease) in Regulatory Assets								(50)
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						3		3
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								160	166
Increase (Decrease) in Regulatory Liabilities								36
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						5		5
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				227	170
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
Exelon Generation Co L L C [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Payments to Acquire Property, Plant, and Equipment								890	1,298
Deferred Income Tax Charge [Member] \| Baltimore Gas and Electric Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Increase (Decrease) in Regulatory Liabilities								31
Deferred Income Tax Charge [Member] \| Delmarva Power and Light Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Increase (Decrease) in Regulatory Liabilities								21
Removal Costs [Member] \| Baltimore Gas and Electric Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Increase (Decrease) in Regulatory Liabilities								29
Clean Energy Legislation [Member] \| Exelon Generation Co L L C [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Competitive businesses other revenues						$ 10		$ 10
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						$ 3,959	4,305	$ 8,938	9,417
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						$ 3,958	$ 4,306	8,937	$ 9,419
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] \| Exelon Generation Co L L C [Member]
Regulatory Matters Additional Narrative Information [Line Items]
License Costs								40
Energy Efficiency Costs [Member] \| Commonwealth Edison Co [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Increase (Decrease) in Regulatory Assets								117
Electric Distribution Formula Rate Annual Reconciliations [Member] \| Commonwealth Edison Co [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Increase (Decrease) in Regulatory Assets								(38)
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								(21)
DC PLUG Charge [Member] \| Potomac Electric Power Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Increase (Decrease) in Regulatory Assets								$ (16)

Regulatory Matters Schedule of Completed Rate Cases (Details) (Details) - USD ($) $ in Millions												6 Months Ended	12 Months Ended
	May 24, 2019	May 23, 2019	Apr. 08, 2019	Mar. 13, 2019	Jan. 04, 2019	Dec. 20, 2018	Dec. 04, 2018	Nov. 19, 2018	Jun. 08, 2018	Apr. 16, 2018	Mar. 29, 2018	Jun. 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%

Regulatory Matters Schedule of Pending Rate Cases (Details) (Details) - USD ($) $ in Millions										6 Months Ended	12 Months Ended
	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	Jun. 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%
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), Amended					$ 27
Requested Return on Equity, Percentage					10.30%
DISTRICT OF COLUMBIA \| Electric Distribution [Member] \| Potomac Electric Power Company [Member]
Regulatory Matters Pending Rate Cases [Line Items]
Requested Revenue Requirement Increase (Decrease)	$ 162
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)											$ 37	$ 40	$ 85

Regulatory Matters - Annual Electric Transmission Fillings (Details) - USD ($) $ in Millions		3 Months Ended	6 Months Ended	12 Months Ended
	May 23, 2019	Jun. 30, 2019	Jun. 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		$ 10	$ 10
Other Operating Income		$ 10	$ 10

Regulatory Matters Energy Efficiency Formula Rate (Details) - Commonwealth Edison Co [Member] - USD ($) $ in Millions					6 Months Ended	12 Months Ended
	May 23, 2019	Apr. 08, 2019	Dec. 04, 2018	Apr. 16, 2018	Jun. 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	Jun. 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	$ 61	$ 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	5	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	48	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

Impairment of Long-Lived Assets - Narrative (Details) $ in Millions	6 Months Ended
	Jun. 30, 2019 USD ($) MW	Jun. 30, 2018 USD ($)
Property, Plant and Equipment [Line Items]
Impairment of long-lived assets	$ 9	$ 41
Exelon Generation Co L L C [Member]
Property, Plant and Equipment [Line Items]
Impairment of long-lived assets	9	$ 41
Antelope Valley [Member]
Property, Plant and Equipment [Line Items]
Long-lived assets	740
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	$ 740
Impairment of long-lived assets	0
ExGen Renewables IV, LLC [Member]
Property, Plant and Equipment [Line Items]
Long-lived assets	1,950
ExGen Renewables IV, LLC [Member] \| Exelon Generation Co L L C [Member]
Property, Plant and Equipment [Line Items]
Long-lived assets	$ 1,950

Early Plant Retirements - Narrative (Details)	Jun. 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		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Three Mile Island [Member]
Accelerated depreciation	$ 71		$ 145
Accelerated nuclear fuel amortization	4		9
Operating and maintenance	0		(83)
Restructuring and Related Cost, Incurred Cost	75		71
TMI,OysterCreek [Member]
Accelerated depreciation		$ 152		$ 289
Accelerated nuclear fuel amortization		19		34
Operating and maintenance		2		28
Restructuring and Related Cost, Incurred Cost		173		351
Exelon Generation Co L L C [Member] \| Three Mile Island [Member]
Accelerated depreciation	71		145
Accelerated nuclear fuel amortization	4		9
Operating and maintenance	0		(83)
Restructuring and Related Cost, Incurred Cost	$ 75		$ 71
Exelon Generation Co L L C [Member] \| TMI,OysterCreek [Member]
Accelerated depreciation		152		289
Accelerated nuclear fuel amortization		19		34
Operating and maintenance		2		28
Restructuring and Related Cost, Incurred Cost		$ 173		$ 351

Early Plant Retirements - Implications of Potential Early Plant Retirement on Balance Sheet (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Implications of Potential Early Plant Retirement [Line Items]
Completed plant, net	$ 78,030	$ 76,707
Mystic Generating Station [Member] \| Facility Closing [Member]
Implications of Potential Early Plant Retirement [Line Items]
Materials and supplies inventory	30
Fuel inventory	11
Completed plant, net	896
Construction work in progress	4
Asset retirement obligation	(1)
Exelon Generation Co L L C [Member]
Implications of Potential Early Plant Retirement [Line Items]
Completed plant, net	23,810	$ 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	30
Fuel inventory	11
Completed plant, net	896
Construction work in progress	4
Asset retirement obligation	$ (1)

Fair Value of Financial Assets and Liabilities - Narrative (Details) $ in Millions	Jun. 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	121
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	121
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	84
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	84
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	396
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	396
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	252
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	$ 252

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		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018	Mar. 31, 2019	Dec. 31, 2018	Mar. 31, 2018	Dec. 31, 2017
Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value								$ 0
Fair Value, Inputs, Level 3 [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value	$ 1,179	$ 1,106	$ 1,179	$ 1,106	$ 838	$ 907	$ 1,283	966
Total realized / unrealized gains (losses)
Included in net income	275	(112)	46	74
Included in noncurrent payables to affiliates	0	0	0	0
Included in regulatory assets	(23)	12	(3)	7
Change in collateral	106	(49)	187	57
Purchases, sales, issuances and settlements
Purchases	51	30	110	119
Sales	(1)	(1)	(1)	(4)
Settlements	(53)	(26)	(70)	(74)
Transfers into Level 3	3	(15)	3	(23)
Transfers out of Level 3	(17)	(16)	0	16
Fair Value, Asset, Recurring Basis, Still Held, Unrealized Gain (Loss)	339	3	191	259
Fair Value, Inputs, Level 3 [Member] \| Consolidation, Eliminations [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value	0	0	0	0	0	0	0
Total realized / unrealized gains (losses)
Included in net income	0	0	0	0
Included in noncurrent payables to affiliates	(10)	3	(21)	(3)
Included in regulatory assets	10	(3)	21	3
Change in collateral	0		0	0
Purchases, sales, issuances and settlements
Purchases	0	0	0	0
Sales	0	0	0	0
Settlements	0	0	0	0
Transfers into Level 3	0	0	0	0
Transfers out of Level 3	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	65	120	145	192
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]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value	1,412	1,322	1,412	1,322	1,039	1,118	1,527	1,200
Total realized / unrealized gains (losses)
Included in net income	274	(113)	44	72
Included in noncurrent payables to affiliates	10	(3)	21	3
Included in regulatory assets	0	0	0	0
Change in collateral	106	(49)	187	57
Purchases, sales, issuances and settlements
Purchases	51	30	110	119
Sales	(1)	(1)	(1)	(4)
Settlements	(53)	(38)	(70)	(86)
Transfers into Level 3	3	(15)	3	(23)
Transfers out of Level 3	(17)	(16)	0	(16)
Fair Value, Asset, Recurring Basis, Still Held, Unrealized Gain (Loss)	338	3	189	259
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]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value	539	585	539	585	540	543	609	648
Total realized / unrealized gains (losses)
Included in net income	2	0	3	1
Included in noncurrent payables to affiliates	10	(3)	21	3
Included in regulatory assets		0		0
Change in collateral	0	0	0	0
Purchases, sales, issuances and settlements
Purchases	40	17	42	19
Sales	0	0	0	0
Settlements	(53)	(38)	(70)	(86)
Transfers into Level 3	0	0	0	0
Transfers out of Level 3	0	0	0	0
Fair Value, Asset, Recurring Basis, Still Held, Unrealized Gain (Loss)	1	(4)	3	(4)
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]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value	873	737	873	737	499	575	918	552
Total realized / unrealized gains (losses)
Included in net income	272	(113)	41	71
Included in noncurrent payables to affiliates	0	0	0	0
Included in regulatory assets		0		0
Change in collateral	106	(49)	187	57
Purchases, sales, issuances and settlements
Purchases	11	13	68	100
Sales	(1)	(1)	(1)	(4)
Settlements	0	0	0	0
Transfers into Level 3	3	(15)	3	(23)
Transfers out of Level 3	(17)	(16)	0	(16)
Fair Value, Asset, Recurring Basis, Still Held, Unrealized Gain (Loss)	337	7	186	263
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)	8	13	4	10
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]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value	(273)	(252)	(273)	(252)	(240)	(249)	(267)	(256)
Total realized / unrealized gains (losses)
Included in net income	0	0	0	0
Included in noncurrent payables to affiliates	0	0	0	0
Included in regulatory assets	(33)	15	(24)	4
Change in collateral	0	0	0	0
Purchases, sales, issuances and settlements
Purchases	0	0	0	0
Sales	0	0	0	0
Settlements	0	0	0	0
Transfers into Level 3	0	0	0	0
Transfers out of Level 3	0	0	0	0
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)	(41)	37	(11)	6
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]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value	40	36	40	36	39	38	23	22
Total realized / unrealized gains (losses)
Included in net income	1	1	2	2
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	12	0	12
Transfers into Level 3	0	0	0	0
Transfers out of Level 3	0	0	0	0
Fair Value, Asset, Recurring Basis, Still Held, Unrealized Gain (Loss)	1	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]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value	40	36	40	36	$ 39	$ 38	$ 23	$ 22
Total realized / unrealized gains (losses)
Included in net income	1	1	2	2
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	12	0	12
Transfers into Level 3	0	0	0	0
Transfers out of Level 3	0	0	0
Fair Value, Asset, Recurring Basis, Still Held, Unrealized Gain (Loss)	$ 1	$ 0	$ 2	$ 0

Fair Value of Financial Assets and Liabilities - Fair Value Inputs Assets Quantitative Information (Details)	6 Months Ended	12 Months Ended
	Jun. 30, 2019 USD ($)	Dec. 31, 2018 USD ($)
Derivatives Fair Value Footnotes [Abstract]
Cash Collateral Posted	$ 25,000,000
Fair Value, Inputs, Level 3 [Member]
Derivatives Fair Value Footnotes [Abstract]
Cash Collateral Posted	263,000,000	$ 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	542,000,000	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	(273,000,000)	(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	10	12
Forward gas price assets	$ 1.54	$ 0.78
Derivative Asset (Liability) Net, Measurement Input	0.04	0.04
Forward heat rate	900.00%	1000.00%
Fair Value Inputs Renewable Factor	88.00%	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	$ 118	$ 174
Forward gas price assets	$ 11.26	$ 12.38
Derivative Asset (Liability) Net, Measurement Input	0.07	0.08
Forward heat rate	1000.00%	1100.00%
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	0.08	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	3.84	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	$ 68,000,000	$ 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	10	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	118	174
Exelon Generation Co L L C [Member]
Derivatives Fair Value Footnotes [Abstract]
Cash Collateral Posted	781,000,000	418,000,000
Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 3 [Member]
Derivatives Fair Value Footnotes [Abstract]
Cash Collateral Posted	263,000,000	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	542,000,000	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	10	12
Forward gas price assets	1.54	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	118	174
Forward gas price assets	$ 11.26	$ 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	0.08	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	3.84	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	$ 68,000,000	$ 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	10	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	118	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	$ (273,000,000)	$ (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]
Derivative Asset (Liability) Net, Measurement Input	0.04	0.04
Forward heat rate	900.00%	1000.00%
Fair Value Inputs Renewable Factor	88.00%	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]
Derivative Asset (Liability) Net, Measurement Input	0.07	0.08
Forward heat rate	1000.00%	1100.00%
Fair Value Inputs Renewable Factor	119.00%	120.00%

Derivative Financial Instruments - Summary of Derivative Fair Value Balances (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Derivative [Line Items]
Mark-to-market derivatives assets	$ 526	$ 804
Derivative Asset, Noncurrent	537	452
Derivative Liability, Current	(163)	(475)
Derivative Liability, Noncurrent	(450)	(479)
Commodity Contract [Member]
Derivative [Line Items]
Mark-to-market derivatives assets	526	801
Derivative Asset, Noncurrent	532	445
Total mark-to-market derivative assets	1,058	1,246
Derivative Liability, Current	(157)	(473)
Derivative Liability, Noncurrent	(437)	(474)
Total mark-to-market derivative liabilities	(594)	(947)
Total mark-to-market derivative net assets (liabilities)	464	299
Exelon Generation Co L L C [Member]
Derivative [Line Items]
Mark-to-market derivatives assets	526	804
Derivative Asset, Noncurrent	533	452
Derivative Liability, Current	(134)	(449)
Derivative Liability, Noncurrent	(206)	(252)
Exelon Generation Co L L C [Member] \| Commodity Contract [Member]
Derivative [Line Items]
Mark-to-market derivatives assets	526	801
Derivative Asset, Noncurrent	532	445
Total mark-to-market derivative assets	1,058	1,246
Derivative Liability, Current	(128)	(447)
Derivative Liability, Noncurrent	(193)	(251)
Total mark-to-market derivative liabilities	(321)	(698)
Total mark-to-market derivative net assets (liabilities)	737	548
Commonwealth Edison Co [Member]
Derivative [Line Items]
Derivative Liability, Current	(29)	(26)
Derivative Liability, Noncurrent	(244)	(223)
Collateral [Member] \| Exelon Generation Co L L C [Member] \| Commodity Contract [Member]
Derivative [Line Items]
Mark-to-market derivatives assets	218	121
Derivative Asset, Noncurrent	122	51
Total mark-to-market derivative assets	340	172
Derivative Liability, Current	265	125
Derivative Liability, Noncurrent	151	60
Total mark-to-market derivative liabilities	416	185
Total mark-to-market derivative net assets (liabilities)	756	357
Netting [Member] \| Exelon Generation Co L L C [Member] \| Commodity Contract [Member]
Derivative [Line Items]
Mark-to-market derivatives assets	(2,724)	(2,930)
Derivative Asset, Noncurrent	(1,269)	(913)
Total mark-to-market derivative assets	(3,993)	(3,843)
Derivative Liability, Current	2,724	2,931
Derivative Liability, Noncurrent	1,269	912
Total mark-to-market derivative liabilities	3,993	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	2,910	3,505
Derivative Asset, Noncurrent	1,618	1,266
Total mark-to-market derivative assets	4,528	4,771
Derivative Liability, Current	(3,039)	(3,429)
Derivative Liability, Noncurrent	(1,576)	(1,203)
Total mark-to-market derivative liabilities	(4,615)	(4,632)
Total mark-to-market derivative net assets (liabilities)	(87)	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	(29)	(26)
Derivative Liability, Noncurrent	(244)	(223)
Total mark-to-market derivative liabilities	(273)	(249)
Total mark-to-market derivative net assets (liabilities)	(273)	(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	122	105
Derivative Asset, Noncurrent	61	41
Total mark-to-market derivative assets	183	146
Derivative Liability, Current	(78)	(74)
Derivative Liability, Noncurrent	(37)	(20)
Total mark-to-market derivative liabilities	(115)	(94)
Total mark-to-market derivative net assets (liabilities)	68	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	$ 358	$ (94)

Derivative Financial Instruments - Summary of Economic Hedges (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives			$ (107)	$ (151)
Exelon Generation Co L L C [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives			(114)	(158)
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	$ (74)	$ 89	(94)	(177)
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	40	(7)	(10)	(107)
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	$ (114)	$ 96	$ (84)	$ (70)

Derivative Financial Instruments - Summary of Proprietary Trading Activities (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	$ (107)	$ (151)
Exelon Generation Co L L C [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	$ (114)	$ (158)

Derivative Financial Instruments - Summary of Credit Risk Exposure (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Derivative [Line Items]
Cash Collateral Posted	$ 25
Letters Of Credit Posted	9
Exelon Generation Co L L C [Member]
Derivative [Line Items]
Cash Collateral Posted	781	$ 418
Financial institutions	3
Investor-owned utilities, marketers and power producers	810
Energy Cooperatives And Municipalities	302
Other	60
Letters Of Credit Posted	228	$ 367
Exelon Generation Co L L C [Member] \| Total Exposure Before Credit Collateral [Member]
Derivative [Line Items]
Investment grade	859
Non-investment grade	30
No external ratings - internally rated - investment grade	204
No external ratings - internally rated - non-investment grade	117
Total	1,210
Exelon Generation Co L L C [Member] \| Credit Collateral [Member]
Derivative [Line Items]
Investment grade	12
Non-investment grade	11
No external ratings - internally rated - investment grade	1
No external ratings - internally rated - non-investment grade	11
Total	35
Exelon Generation Co L L C [Member] \| Net Exposure [Member]
Derivative [Line Items]
Investment grade	847
Non-investment grade	19
No external ratings - internally rated - investment grade	203
No external ratings - internally rated - non-investment grade	106
Total	1,175
Exelon Generation Co L L C [Member] \| Number Of Counterparties Greater Than Ten Percent Of Net Exposure [Member]
Derivative [Line Items]
Investment grade	2
Non-investment grade
No external ratings - internally rated - investment grade
No external ratings - internally rated - non-investment grade
Total	2
Exelon Generation Co L L C [Member] \| Net Exposure Of Counterparties Greater Than Ten Percent Of Net Exposure [Member]
Derivative [Line Items]
Investment grade	249
Non-investment grade
No external ratings - internally rated - investment grade
No external ratings - internally rated - non-investment grade
Total	$ 249

Derivative Financial Instruments - Summary of Credit Risk Related Contingent Features (Details) - Exelon Generation Co L L C [Member] - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Derivative [Line Items]
Aggregate fair value of derivatives with credit-risk-related contingent features	$ (1,119)	$ (1,723)
Offsetting fair value of in-the-money contracts under master netting agreements	824	1,105
Net liability position after contractual right of offset	$ (295)	$ (618)

Derivative Financial Instruments - Narrative (Details) $ in Millions	1 Months Ended	6 Months Ended
	Jun. 30, 2012 MWh	Jun. 30, 2019 USD ($)	Dec. 31, 2018 USD ($)
Exelon Generation Co L L C [Member]
Derivative [Line Items]
Incremental Collateral For Loss Of Investment Grade Credit Rating		$ 1,513	$ 2,104
Commonwealth Edison Co [Member]
Derivative [Line Items]
Long-term Purchase Commitment, Minimum Energy Volume Required \| MWh	1,300,000
Delmarva Power and Light Company [Member]
Derivative [Line Items]
Incremental Collateral For Loss Of Investment Grade Credit Rating		12
Baltimore Gas and Electric Company [Member]
Derivative [Line Items]
Incremental Collateral For Loss Of Investment Grade Credit Rating		31
PECO Energy Co [Member]
Derivative [Line Items]
Incremental Collateral For Loss Of Investment Grade Credit Rating		$ 31
Minimum [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Expected Generation Hedged In Next Twelve Months		92.00%
Expected Generation Hedged In Year Two		70.00%
Expected generation Hedged In Year Three		40.00%
Maximum [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Expected Generation Hedged In Next Twelve Months		95.00%
Expected Generation Hedged In Year Two		73.00%
Expected generation Hedged In Year Three		43.00%
Commonwealth Edison Co Affiliate [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Net receivable from electric utility		$ 70
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		1,373	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		573	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		$ 219	$ 268

Derivative Financial Instruments Derivative Financial Instruments - Summary of Cash Collateral and Letters of Credit (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Derivative Instruments, Gain (Loss) [Line Items]
Cash Collateral Posted	$ 25
Letters Of Credit Posted	9
Exelon Generation Co L L C [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Cash Collateral Posted	781	$ 418
Letters Of Credit Posted	228	367
Cash Collateral Held	64	47
Letters Of Credit Held	21	44
Incremental Collateral For Loss Of Investment Grade Credit Rating	$ 1,513	$ 2,104

Debt and Credit Agreements - Narrative (Details) $ in Millions	6 Months Ended
	Jun. 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	500
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	500
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	Jun. 30, 2019	Dec. 31, 2018
Short-term Debt [Line Items]
Outstanding Commercial Paper	$ 559	$ 89
Average Interest Rate on Commercial Paper Borrowings	2.60%	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	$ 303	$ 0
Average Interest Rate on Commercial Paper Borrowings	2.59%	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	$ 229	$ 35
Average Interest Rate on Commercial Paper Borrowings	2.58%	2.18%
Pepco Holdings LLC [Member]
Short-term Debt [Line Items]
Outstanding Commercial Paper	$ 27	$ 54
Average Interest Rate on Commercial Paper Borrowings	2.61%	2.15%
Potomac Electric Power Company [Member]
Short-term Debt [Line Items]
Outstanding Commercial Paper	$ 0	$ 40
Average Interest Rate on Commercial Paper Borrowings	2.62%	2.24%
Delmarva Power and Light Company [Member]
Short-term Debt [Line Items]
Outstanding Commercial Paper	$ 0	$ 0
Average Interest Rate on Commercial Paper Borrowings	2.55%	2.07%
Atlantic City Electric Company [Member]
Short-term Debt [Line Items]
Outstanding Commercial Paper	$ 27	$ 14
Average Interest Rate on Commercial Paper Borrowings	2.61%	2.21%

Debt and Credit Agreements - Issuance of Long-Term Debt (Details) $ in Millions	Jun. 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	$ 2
Exelon Generation Co L L C [Member] \| EEPF346Aug2020 [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
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			6 Months Ended
Income Taxes - Narrative (Details) - USD ($) $ in Millions	Jan. 01, 2021	Jun. 30, 2019	Mar. 31, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Income Tax Additional Narrative Information [Line Items]
Unrecognized Tax Benefits, Period Increase (Decrease)			$ (33)
Decrease in Unrecognized Tax Benefits is Reasonably Possible		$ 425			$ 425
Unrecognized tax benefits that if recognized would affect the effective tax rate		$ 411			$ 411
Effective income tax rate		22.40%		10.80%	23.60%	9.50%
Exelon Generation Co L L C [Member]
Income Tax Additional Narrative Information [Line Items]
Decrease in Unrecognized Tax Benefits is Reasonably Possible		$ 411			$ 411
Unrecognized tax benefits that if recognized would affect the effective tax rate		$ 411			$ 411
Effective income tax rate		38.60%		11.00%	35.20%	7.80%
Commonwealth Edison Co [Member]
Income Tax Additional Narrative Information [Line Items]
Unrecognized Tax Benefits, Period Increase (Decrease)			$ (2)
Effective income tax rate		19.80%		20.80%	19.80%	21.10%
PECO Energy Co [Member]
Income Tax Additional Narrative Information [Line Items]
Effective income tax rate		11.30%		(1.10%)	12.10%	(1.40%)
Baltimore Gas and Electric Company [Member]
Income Tax Additional Narrative Information [Line Items]
Effective income tax rate		19.60%		20.30%	18.60%	18.60%
Pepco Holdings LLC [Member]
Income Tax Additional Narrative Information [Line Items]
Decrease in Unrecognized Tax Benefits is Reasonably Possible		$ 14			$ 14
Effective income tax rate		5.40%		15.20%	4.70%	13.90%
Potomac Electric Power Company [Member]
Income Tax Additional Narrative Information [Line Items]
Effective income tax rate		3.00%		11.50%	3.30%	9.60%
Delmarva Power and Light Company [Member]
Income Tax Additional Narrative Information [Line Items]
Effective income tax rate		11.80%		16.10%	11.70%	17.40%
Atlantic City Electric Company [Member]
Income Tax Additional Narrative Information [Line Items]
Decrease in Unrecognized Tax Benefits is Reasonably Possible		$ 14			$ 14
Effective income tax rate		0.00%		20.00%	4.00%	16.70%
ILLINOIS
Income Tax Additional Narrative Information [Line Items]
Effective income tax rate					9.50%
Subsequent Event [Member] \| ILLINOIS
Income Tax Additional Narrative Information [Line Items]
Effective income tax rate	10.49%

Income Taxes - Reconciliation to Effective Tax Rate (Details)	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 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	5.40%	3.40%	4.40%	3.80%
Qualified nuclear decommissioning trust fund income	5.10%	0.20%	6.50%	(0.10%)
Amortization of investment tax credit, including deferred taxes on basis difference	(0.70%)	(0.90%)	(0.60%)	(1.10%)
Plant basis differences	(1.70%)	(3.00%)	(1.50%)	(2.80%)
Production tax credits and other credits	(0.90%)	(1.70%)	(0.80%)	(2.30%)
Noncontrolling interests	0.10%	(1.50%)	(0.30%)	(1.10%)
Excess deferred tax amortization	(7.80%)	(5.20%)	(5.80%)	(5.60%)
Tax Cuts and Jobs Act of 2017		(1.30%)		(0.60%)
Other	1.90%	(0.20%)	0.70%	(1.70%)
Effective income tax rate	22.40%	10.80%	23.60%	9.50%
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	5.50%	4.30%	3.60%	3.40%
Qualified nuclear decommissioning trust fund income	16.20%	0.50%	14.70%	(0.40%)
Amortization of investment tax credit, including deferred taxes on basis difference	(1.90%)	(2.40%)	(1.10%)	(3.30%)
Plant basis differences	0.00%	0.00%	0.00%	0.00%
Production tax credits and other credits	(2.80%)	(4.90%)	(1.80%)	(7.20%)
Noncontrolling interests	0.40%	(4.50%)	(0.80%)	(3.50%)
Excess deferred tax amortization	0.00%	0.00%	0.00%	0.00%
Tax Cuts and Jobs Act of 2017		(1.70%)		(0.90%)
Other	0.20%	(1.30%)	(0.40%)	(1.30%)
Effective income tax rate	38.60%	11.00%	35.20%	7.80%
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	8.20%	8.10%	8.20%	8.10%
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	(0.60%)	(0.10%)	(0.60%)	0.00%
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	(9.00%)	(7.60%)	(8.80%)	(7.50%)
Tax Cuts and Jobs Act of 2017		(0.70%)		(0.30%)
Other	0.40%	0.40%	0.20%	0.10%
Effective income tax rate	19.80%	20.80%	19.80%	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	(1.20%)	(3.40%)	0.20%	(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	(5.90%)	(17.20%)	(6.40%)	(15.60%)
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	(2.70%)	(0.30%)	(2.60%)	(2.70%)
Tax Cuts and Jobs Act of 2017		0.00%		0.00%
Other	0.10%	(1.10%)	(0.10%)	(0.40%)
Effective income tax rate	11.30%	(1.10%)	12.10%	(1.40%)
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	6.50%	6.50%	6.40%	6.40%
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%)	(0.20%)	(0.10%)	(0.10%)
Plant basis differences	(1.50%)	(0.70%)	(1.00%)	(0.70%)
Production tax credits and other credits	(0.10%)	0.00%	0.00%	0.00%
Noncontrolling interests	0.00%	0.00%	0.00%	0.00%
Excess deferred tax amortization	(7.90%)	(7.20%)	(7.90%)	(8.20%)
Tax Cuts and Jobs Act of 2017		0.10%		0.00%
Other	1.70%	0.80%	0.20%	0.20%
Effective income tax rate	19.60%	20.30%	18.60%	18.60%
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%	6.20%	4.70%	5.50%
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%)	(0.20%)	(0.20%)	(0.20%)
Plant basis differences	(1.70%)	(1.20%)	(1.70%)	(1.80%)
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	(19.40%)	(11.30%)	(19.40%)	(11.00%)
Tax Cuts and Jobs Act of 2017		0.80%		0.50%
Other	0.90%	(0.10%)	0.30%	(0.10%)
Effective income tax rate	5.40%	15.20%	4.70%	13.90%
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	2.00%	4.70%	2.00%	3.70%
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	(0.10%)	(0.10%)	(0.10%)	(0.10%)
Plant basis differences	(2.10%)	(2.00%)	(2.00%)	(2.50%)
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	(18.30%)	(11.70%)	(18.10%)	(12.10%)
Tax Cuts and Jobs Act of 2017		0.00%		0.00%
Other	0.50%	(0.40%)	0.50%	(0.40%)
Effective income tax rate	3.00%	11.50%	3.30%	9.60%
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	7.00%	6.50%	6.70%	6.40%
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	(0.20%)	(0.30%)	(0.20%)	(0.30%)
Plant basis differences	(0.30%)	0.00%	(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	(15.70%)	(11.20%)	(15.60%)	(9.40%)
Tax Cuts and Jobs Act of 2017		0.00%		0.00%
Other	0.00%	0.10%	0.40%	0.40%
Effective income tax rate	11.80%	16.10%	11.70%	17.40%
Atlantic City Electric Company [Member]
Effective Income Tax Rate Reconciliation, Percent [Abstract]
U.S. Federal statutory rate	21.00%	21.00%	21.00%	21.00%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	7.00%	7.60%	6.90%	7.20%
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	(0.30%)	(0.30%)	(0.30%)	(0.30%)
Plant basis differences	(2.20%)	(0.20%)	(2.20%)	(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	(23.10%)	(8.80%)	(23.40%)	(8.80%)
Tax Cuts and Jobs Act of 2017		0.00%		0.00%
Other	(2.40%)	0.70%	2.00%	(1.10%)
Effective income tax rate	0.00%	20.00%	4.00%	16.70%

Income Taxes - Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	Jun. 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
PECO Energy Co [Member]
Income Tax Contingency [Line Items]
Unrecognized Tax Benefits	0	0
Baltimore Gas and Electric Company [Member]
Income Tax Contingency [Line Items]
Unrecognized Tax Benefits	0	0
Pepco Holdings LLC [Member]
Income Tax Contingency [Line Items]
Unrecognized Tax Benefits	45	45
Potomac Electric Power Company [Member]
Income Tax Contingency [Line Items]
Unrecognized Tax Benefits	0	0
Delmarva Power and Light Company [Member]
Income Tax Contingency [Line Items]
Unrecognized Tax Benefits	0	0
Atlantic City Electric Company [Member]
Income Tax Contingency [Line Items]
Unrecognized Tax Benefits	$ 14	$ 14

Nuclear Decommissioning - Narrative (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended
	Mar. 31, 2019	Jun. 30, 2019	Dec. 31, 2018
Nuclear Decommissioning Additional Narrative Information [Line Items]
Asset Retirement Obligation, Period Increase (Decrease)		$ 432
Asset Retirement Obligation, Revision of Estimate	$ 330
Decommissioning Fund Investments		12,513	$ 11,661
Assets held for sale		880	904
Exelon Generation Co L L C [Member]
Nuclear Decommissioning Additional Narrative Information [Line Items]
Asset Retirement Obligation, Period Increase (Decrease)		432
Asset Retirement Obligation, Revision of Estimate	330
Decommissioning Fund Investments		12,513	11,661
Assets held for sale		880	904
Nuclear Decommissioning [Member]
Nuclear Decommissioning Additional Narrative Information [Line Items]
Asset Retirement Obligation, Revision of Estimate		232
Nuclear Decommissioning [Member] \| Exelon Generation Co L L C [Member]
Nuclear Decommissioning Additional Narrative Information [Line Items]
Asset Retirement Obligation, Revision of Estimate		232
Three Mile Island [Member]
Nuclear Decommissioning Additional Narrative Information [Line Items]
Asset Retirement Obligation, Period Increase (Decrease)	(110)
Asset Retirement Obligation Revision Of Estimate In Operating And Maintenance Expense	(85)
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)
Asset Retirement Obligation Revision Of Estimate In Operating And Maintenance Expense	$ (85)
Assets, Total [Member]
Nuclear Decommissioning Additional Narrative Information [Line Items]
Decommissioning Fund Investments		13,498	12,695
Assets, Total [Member] \| Exelon Generation Co L L C [Member]
Nuclear Decommissioning Additional Narrative Information [Line Items]
Decommissioning Fund Investments		13,498	12,695
Nuclear Decommissioning Trust Fund Investments [Member] \| Oyster Creek [Member]
Nuclear Decommissioning Additional Narrative Information [Line Items]
Assets held for sale		857	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		857	890
Other Current Assets [Member]
Nuclear Decommissioning Additional Narrative Information [Line Items]
Decommissioning Fund Investments		127	144
Other Current Assets [Member] \| Exelon Generation Co L L C [Member]
Nuclear Decommissioning Additional Narrative Information [Line Items]
Decommissioning Fund Investments		$ 127	$ 144

Nuclear Decommissioning - Rollforward of Nuclear Decommissioning ARO (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended
	Mar. 31, 2019	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2018
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Accretion expense		$ 250	$ 242
Asset Retirement Obligation, Revision of Estimate	$ 330
Liabilities held for sale		764		$ 777
Nuclear Decommissioning [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Nuclear decommissioning ARO, beginning balance	10,005	10,005
Accretion expense		243
Asset Retirement Obligation, Revision of Estimate		232
Costs incurred related to decommissioning plants		(43)
Nuclear decommissioning ARO, ending balance		10,437
Current portion of ARO		99		22
Exelon Generation Co L L C [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Accretion expense		248	$ 242
Asset Retirement Obligation, Revision of Estimate	330
Liabilities held for sale		764		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
Accretion expense		243
Asset Retirement Obligation, Revision of Estimate		232
Costs incurred related to decommissioning plants		(43)
Nuclear decommissioning ARO, ending balance		10,437
Current portion of ARO		99		22
Nuclear Decommissioning Asset Retirement Obligation [Member] \| Oyster Creek [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Liabilities held for sale		755		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		$ 755		$ 772

Retirement Benefits - Narrative (Details) $ in Millions	3 Months Ended	6 Months Ended
Retirement Benefits - Narrative (Details) $ in Millions	Jun. 30, 2019 USD ($)	Jun. 30, 2019 USD ($)
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		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Amortization of:
Net periodic benefit cost	$ (5)	$ 11	$ (10)	$ 21
Pension Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	89	102	178	202
Interest cost	221	200	442	401
Expected return on assets	(306)	(313)	(612)	(626)
Amortization of:
Prior service cost (benefit)	0	0	0	1
Actuarial loss	103	157	206	314
Settlement charges	0	1	0	1
Net periodic benefit cost	107	147	214	293
Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	24	28	47	56
Interest cost	47	44	94	88
Expected return on assets	(38)	(43)	(77)	(87)
Amortization of:
Prior service cost (benefit)	(44)	(47)	(89)	(93)
Actuarial loss	10	16	23	33
Settlement charges	0	0	0	0
Net periodic benefit cost	$ (1)	$ (2)	$ (2)	$ (3)

Retirement Benefits - Defined Contribution Savings Plans (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Defined Benefit Plan Disclosure [Line Items]
Savings Plan Matching Contributions	$ 33	$ 50	$ 64	$ 82
Exelon Generation Co L L C [Member]
Defined Benefit Plan Disclosure [Line Items]
Savings Plan Matching Contributions	14	28	28	43
Commonwealth Edison Co [Member]
Defined Benefit Plan Disclosure [Line Items]
Savings Plan Matching Contributions	9	8	16	15
PECO Energy Co [Member]
Defined Benefit Plan Disclosure [Line Items]
Savings Plan Matching Contributions	2	2	5	4
Baltimore Gas and Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Savings Plan Matching Contributions	2	2	4	4
Pepco Holdings LLC [Member]
Defined Benefit Plan Disclosure [Line Items]
Savings Plan Matching Contributions	3	3	6	6
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	1	1
Atlantic City Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Savings Plan Matching Contributions	$ 0	$ 0	$ 1	$ 1

Changes in Accumulated Other Comprehensive Income - Schedule of Changes in AOCI (Details) - USD ($) $ in Millions	3 Months Ended				6 Months Ended
	Jun. 30, 2019	Mar. 31, 2019	Jun. 30, 2018	Mar. 31, 2018	Jun. 30, 2019	Jun. 30, 2018
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	$ 33,704	$ 33,070	$ 32,565	$ 32,187	$ 33,070	$ 32,187
Beginning Balance		30,764			30,764
Other comprehensive income	21		44		3	117
Ending balance	33,907	33,704	32,839	32,565	33,907	32,839
Ending Balance	31,548				31,548
Tax Cuts and Jobs Act, Reclassification from AOCI to Retained Earnings						539
Gains (Losses) on Cash Flow Hedges
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance		(2)		(14)	(2)	(14)
OCI before reclassifications					0	13
Amounts reclassified from AOCI					0	(1)
Other comprehensive income					0	12
Ending balance	(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
OCI before reclassifications						0
Amounts reclassified from AOCI						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		(2,960)		(2,998)	(2,960)	(2,998)
OCI before reclassifications					(39)	20
Amounts reclassified from AOCI	20		44		42	88
Other comprehensive income					3	108
Ending balance	(2,957)		(2,890)		(2,957)	(2,890)
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		(33)		(23)	(33)	(23)
OCI before reclassifications					4	(6)
Amounts reclassified from AOCI					0	0
Other comprehensive income					4	(6)
Ending balance	(29)		(29)		(29)	(29)
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		0		(1)	0	(1)
OCI before reclassifications					(2)	1
Amounts reclassified from AOCI					0	0
Other comprehensive income					(2)	1
Ending balance	(2)		0		(2)	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	(3,012)	(2,995)	(2,965)	(3,026)	(2,995)	(3,026)
OCI before reclassifications					(37)	28
Amounts reclassified from AOCI					42	87
Other comprehensive income	22	(17)	44	71	5	115
Ending balance	(2,990)	(3,012)	(2,921)	(2,965)	(2,990)	(2,921)
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)
Exelon Generation Co L L C [Member]
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning Balance	15,696	15,508	15,958	15,959	15,508	15,959
Other comprehensive income	(1)	1	2	7	0	9
Ending Balance	15,592	15,696	15,939	15,958	15,592	15,939
Exelon Generation Co L L C [Member] \| Gains (Losses) on Cash Flow Hedges
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning Balance		(4)		(16)	(4)	(16)
OCI before reclassifications					0	13
Amounts reclassified from AOCI					0	(1)
Other comprehensive income					0	12
Ending Balance	(4)		(4)		(4)	(4)
Exelon Generation Co L L C [Member] \| 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
Exelon Generation Co L L C [Member] \| Unrealized Gains (Losses) on Marketable Securities
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning Balance				3		3
OCI before reclassifications						0
Amounts reclassified from AOCI						0
Other comprehensive income						0
Ending Balance			0			0
Exelon Generation Co L L C [Member] \| 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)						(3)
Exelon Generation Co L L C [Member] \| Pension and Non-Pension Postretirement Benefit Plan Items
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning Balance		0		0	0	0
OCI before reclassifications					0	0
Amounts reclassified from AOCI					0	0
Other comprehensive income					0	0
Ending Balance	0		0		0	0
Exelon Generation Co L L C [Member] \| 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
Exelon Generation Co L L C [Member] \| Foreign Currency Items
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning Balance		(33)		(23)	(33)	(23)
OCI before reclassifications					4	(6)
Amounts reclassified from AOCI					0	0
Other comprehensive income					4	(6)
Ending Balance	(29)		(29)		(29)	(29)
Exelon Generation Co L L C [Member] \| 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
Exelon Generation Co L L C [Member] \| AOCI of Investments in Unconsolidated Affiliates
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning Balance		(1)		(1)	(1)	(1)
OCI before reclassifications					(2)	1
Amounts reclassified from AOCI					0	0
Other comprehensive income					(2)	1
Ending Balance	(3)		0		(3)	0
Exelon Generation Co L L C [Member] \| 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
Exelon Generation Co L L C [Member] \| Total
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning Balance	(36)	(38)	(34)	(37)	(38)	(37)
OCI before reclassifications					2	8
Amounts reclassified from AOCI					0	(1)
Other comprehensive income	0	2	1	6	2	7
Ending Balance	$ (36)	$ (36)	$ (33)	$ (34)	$ (36)	(33)
Exelon Generation Co L L C [Member] \| 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)						$ (3)

Changes in Accumulated Other Comprehensive Income - Reclassification out of Accumulated Other Comprehensive Income (Details) - USD ($) $ in Millions	3 Months Ended			6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Mar. 31, 2018	Jun. 30, 2019	Jun. 30, 2018
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income Tax Expense (Benefit)	$ 144	$ 66		$ 454	$ 125
Amortization of pension and other postretirement benefit plan items			$ 4
Gains (Losses) on Cash Flow Hedges
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Amounts reclassified from AOCI				0	1
Prior service costs
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Amortization of pension and other postretirement benefit plan items	22	23		44	46
Actuarial losses
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Amortization of pension and other postretirement benefit plan items	(49)	(83)		(100)	(166)
Pension and Non-Pension Postretirement Benefit Plan Items
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Amortization of pension and other postretirement benefit plan items	(27)	(60)		(56)	(120)
Tax benefit	7	16		14	32
Amounts reclassified from AOCI	$ (20)	$ (44)		$ (42)	$ (88)

Changes in Accumulated Other Comprehensive Income - Components of Other Comprehensive Income (Loss) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), Tax	$ (6)	$ (16)	$ 1	$ (43)
Prior service costs
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), Tax	6	6	12	12
Actuarial losses
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), Tax	(13)	(22)	(26)	(44)
Pension and Non-Pension Postretirement Benefit Plan Items
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), Tax	0	1	14	(6)
Gains (Losses) on Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), Tax	0	(1)	0	(4)
Unrealized Gains (Losses) on Marketable Securities
Accumulated Other Comprehensive Income (Loss) [Line Items]
Change in unrealized gains (losses) on investments in unconsolidated affiliates	1	0	1	(1)
Exelon Generation Co L L C [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), Tax	1	(1)	1	(5)
Exelon Generation Co L L C [Member] \| Gains (Losses) on Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), Tax	0	(1)	0	(4)
Exelon Generation Co L L C [Member] \| Unrealized Gains (Losses) on Marketable Securities
Accumulated Other Comprehensive Income (Loss) [Line Items]
Change in unrealized gains (losses) on investments in unconsolidated affiliates	$ 1	$ 0	$ 1	$ (1)

Commitments and Contingencies - Narrative (Details) $ in Millions		6 Months Ended	12 Months Ended
	Mar. 23, 2016 USD ($) MW	Jun. 30, 2019 USD ($) 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		$ 3,211
Accrual for Environmental Loss Contingencies, Gross		482		$ 496
Exelon Generation Co L L C [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Other Commitment		2,554
Accrued Insurance, Current		13,900
Loss Contingency, Undiscounted Amount of Insurance-related Assessment Liability		450
Maximum liability per nuclear incident		13,500
Prepaid Reinsurance Premiums		334
Estimated Insurance Recoveries		3,200
Accrual for Environmental Loss Contingencies, Gross		107		108
Liability for Asbestos and Environmental Claims, Gross		84		79
Commonwealth Edison Co [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Other Commitment		$ 259
Mgp Site Contingency Approved Cleanup Count \| MGPSite		42
Mgp Site Contingency Count \| MGPSite		21
Mgp Site Contingency Monitoring Count \| MGPSite		21
Accrual for Environmental Loss Contingencies, Gross		$ 318		329
PECO Energy Co [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Other Commitment		$ 187
Mgp Site Contingency Approved Cleanup Count \| MGPSite		26
Mgp Site Contingency Count \| MGPSite		17
Mgp Site Contingency Monitoring Count \| MGPSite		9
Accrual for Environmental Loss Contingencies, Gross		$ 25		27
Baltimore Gas and Electric Company [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Other Commitment		$ 26
Mgp Site Contingency Approved Cleanup Count \| MGPSite		13
Mgp Site Contingency Count \| MGPSite		9
Mgp Site Contingency Monitoring Count \| MGPSite		4
Accrual for Environmental Loss Contingencies, Gross		$ 5		5
Pepco Holdings LLC [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Other Commitment		75
Accrual for Environmental Loss Contingencies, Gross		27		27
Potomac Electric Power Company [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Other Commitment		50
Accrual for Environmental Loss Contingencies, Gross		24		25
Delmarva Power and Light Company [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Other Commitment		$ 15
Mgp Site Contingency Approved Cleanup Count \| MGPSite		3
Mgp Site Contingency Count \| MGPSite		2
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		$ 24
Open Asbestos Related Personal Injury Claims \| Open_claim		244
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		$ 60
Nuclear Insurance Premiums [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Nuclear financial protection pool value		2,900
Nuclear Insurance Premiums [Member] \| Maximum [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Nuclear financial protection pool value		434
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 Non-Financial Commitment \| MW		27
Other Commitment	$ 127	$ 102
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		$ 102
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

Supplemental Financial Information - Utility Taxes (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Supplemental Statement of Operations Information [Line Items]
Utility taxes	$ 209	$ 218	$ 432	$ 452
Property	148	135	296	271
Payroll	61	65	127	133
Exelon Generation Co L L C [Member]
Supplemental Statement of Operations Information [Line Items]
Utility taxes	32	29	58	60
Property	68	65	138	134
Payroll	30	34	64	68
Commonwealth Edison Co [Member]
Supplemental Statement of Operations Information [Line Items]
Utility taxes	55	60	118	121
Property	9	8	15	15
Payroll	7	7	14	14
PECO Energy Co [Member]
Supplemental Statement of Operations Information [Line Items]
Utility taxes	30	30	63	63
Property	4	4	8	7
Payroll	4	4	7	8
Baltimore Gas and Electric Company [Member]
Supplemental Statement of Operations Information [Line Items]
Utility taxes	21	21	48	47
Property	37	34	75	69
Payroll	4	4	8	8
Pepco Holdings LLC [Member]
Supplemental Statement of Operations Information [Line Items]
Utility taxes	71	78	145	161
Property	30	24	60	46
Payroll	7	6	14	14
Potomac Electric Power Company [Member]
Supplemental Statement of Operations Information [Line Items]
Utility taxes	67	73	136	151
Property	21	15	43	29
Payroll	2	2	3	3
Delmarva Power and Light Company [Member]
Supplemental Statement of Operations Information [Line Items]
Utility taxes	4	5	9	10
Property	8	8	16	16
Payroll	1	1	2	2
Atlantic City Electric Company [Member]
Supplemental Statement of Operations Information [Line Items]
Utility taxes	0	0	0	0
Property	1	1	1	1
Payroll	$ 1	$ 1	$ 2	$ 2

Supplemental Financial Information - Operations (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Decommissioning-Related Activities [Abstract]
Net realized income on NDT funds - Regulatory agreement units	$ 77	$ 216	$ 131	$ 262
Net realized income on NDT funds - Non-regulatory agreement units	230	143	283	199
Net unrealized (losses) gains on NDT funds - Regulatory agreement units	98	(194)	476	(268)
Net unrealized (losses) gains on NDT funds - Non-regulatory agreement units	(98)	(120)	182	(215)
Regulatory offset to NDT fund-related activities	(141)	(23)	(487)	(1)
Decommissioning-related activities	166	22	585	(23)
AFUDC - Equity	21	13	43	31
Non-service net periodic benefit cost	5	(11)	10	(21)
Exelon Generation Co L L C [Member]
Decommissioning-Related Activities [Abstract]
Net realized income on NDT funds - Regulatory agreement units	77	216	131	262
Net realized income on NDT funds - Non-regulatory agreement units	230	143	283	199
Net unrealized (losses) gains on NDT funds - Regulatory agreement units	98	(194)	476	(268)
Net unrealized (losses) gains on NDT funds - Non-regulatory agreement units	(98)	(120)	182	(215)
Regulatory offset to NDT fund-related activities	(141)	(23)	(487)	(1)
Decommissioning-related activities	166	22	585	(23)
AFUDC - Equity	0	0	0	0
Commonwealth Edison Co [Member]
Decommissioning-Related Activities [Abstract]
AFUDC - Equity	4	2	9	8
PECO Energy Co [Member]
Decommissioning-Related Activities [Abstract]
AFUDC - Equity	3	0	6	2
Baltimore Gas and Electric Company [Member]
Decommissioning-Related Activities [Abstract]
AFUDC - Equity	5	4	10	8
Pepco Holdings LLC [Member]
Decommissioning-Related Activities [Abstract]
AFUDC - Equity	9	7	18	13
Potomac Electric Power Company [Member]
Decommissioning-Related Activities [Abstract]
AFUDC - Equity	6	6	12	12
Delmarva Power and Light Company [Member]
Decommissioning-Related Activities [Abstract]
AFUDC - Equity	1	1	2	1
Atlantic City Electric Company [Member]
Decommissioning-Related Activities [Abstract]
AFUDC - Equity	$ 2	$ 0	$ 4	$ 0

Supplemental Financial Information - Cash Flow (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
Depreciation, Amortization and Accretion [Abstract]
Property, plant and equipment	$ 1,859	$ 1,873
Amortization of regulatory assets	266	278
Amortization of intangible assets, net	29	28
Amortization of energy contract assets and liabilities	5	10
Nuclear fuel	513	569
ARO accretion	250	242
Total depreciation, amortization and accretion	2,922	3,000
Other Non-Cash Operating Activities [Abstract]
Pension and non-pension postretirement benefit costs	212	290
Provision for uncollectible accounts	45	77
Other decommissioning-related activity	(260)	(61)
Energy-related options	43	(7)
Amortization of rate stabilization deferral	(10)	13
Discrete impacts from EIMA and FEJA	24	14
Long-term incentive plan	35	51
Amortization of operating ROU asset	115
Exelon Generation Co L L C [Member]
Depreciation, Amortization and Accretion [Abstract]
Property, plant and equipment	789	890
Amortization of regulatory assets	0	0
Amortization of intangible assets, net	25	24
Amortization of energy contract assets and liabilities	5	10
Nuclear fuel	513	569
ARO accretion	248	242
Total depreciation, amortization and accretion	1,580	1,735
Other Non-Cash Operating Activities [Abstract]
Pension and non-pension postretirement benefit costs	62	100
Provision for uncollectible accounts	12	28
Other decommissioning-related activity	(261)	(61)
Energy-related options	43	(7)
Amortization of rate stabilization deferral	0	0
Amortization of operating ROU asset	78
Commonwealth Edison Co [Member]
Depreciation, Amortization and Accretion [Abstract]
Property, plant and equipment	439	406
Amortization of regulatory assets	69	53
Amortization of intangible assets, net	0	0
ARO accretion	0	0
Total depreciation, amortization and accretion	508	459
Other Non-Cash Operating Activities [Abstract]
Pension and non-pension postretirement benefit costs	47	88
Provision for uncollectible accounts	16	18
Amortization of rate stabilization deferral	0	0
Discrete impacts from EIMA and FEJA	24	14
Amortization of operating ROU asset	1
PECO Energy Co [Member]
Depreciation, Amortization and Accretion [Abstract]
Property, plant and equipment	149	135
Amortization of regulatory assets	15	14
Amortization of intangible assets, net	0	0
ARO accretion	0	0
Total depreciation, amortization and accretion	164	149
Other Non-Cash Operating Activities [Abstract]
Pension and non-pension postretirement benefit costs	5	10
Provision for uncollectible accounts	10	11
Amortization of rate stabilization deferral	0	0
Amortization of operating ROU asset	0
Baltimore Gas and Electric Company [Member]
Depreciation, Amortization and Accretion [Abstract]
Property, plant and equipment	173	164
Amortization of regulatory assets	79	84
Amortization of intangible assets, net	0	0
ARO accretion	0	0
Total depreciation, amortization and accretion	252	248
Other Non-Cash Operating Activities [Abstract]
Pension and non-pension postretirement benefit costs	29	29
Provision for uncollectible accounts	4	5
Amortization of rate stabilization deferral	0	0
Amortization of operating ROU asset	15
Pepco Holdings LLC [Member]
Depreciation, Amortization and Accretion [Abstract]
Property, plant and equipment	266	236
Amortization of regulatory assets	103	127
Amortization of intangible assets, net	0	0
ARO accretion	0	0
Total depreciation, amortization and accretion	369	363
Other Non-Cash Operating Activities [Abstract]
Pension and non-pension postretirement benefit costs	48	34
Provision for uncollectible accounts	3	15
Amortization of rate stabilization deferral	(10)	13
Amortization of operating ROU asset	17
Potomac Electric Power Company [Member]
Depreciation, Amortization and Accretion [Abstract]
Property, plant and equipment	117	107
Amortization of regulatory assets	69	81
Amortization of intangible assets, net	0	0
ARO accretion	0	0
Total depreciation, amortization and accretion	186	188
Other Non-Cash Operating Activities [Abstract]
Pension and non-pension postretirement benefit costs	12	8
Provision for uncollectible accounts	2	7
Amortization of rate stabilization deferral	(8)	10
Amortization of operating ROU asset	4
Delmarva Power and Light Company [Member]
Depreciation, Amortization and Accretion [Abstract]
Property, plant and equipment	71	64
Amortization of regulatory assets	20	24
Amortization of intangible assets, net	0	0
ARO accretion	0	0
Total depreciation, amortization and accretion	91	88
Other Non-Cash Operating Activities [Abstract]
Pension and non-pension postretirement benefit costs	8	3
Provision for uncollectible accounts	1	2
Amortization of rate stabilization deferral	(2)	3
Amortization of operating ROU asset	5
Atlantic City Electric Company [Member]
Depreciation, Amortization and Accretion [Abstract]
Property, plant and equipment	57	47
Amortization of regulatory assets	14	22
Amortization of intangible assets, net	0	0
ARO accretion	0	0
Total depreciation, amortization and accretion	71	69
Other Non-Cash Operating Activities [Abstract]
Pension and non-pension postretirement benefit costs	8	6
Provision for uncollectible accounts	0	5
Amortization of rate stabilization deferral	0	$ 0
Amortization of operating ROU asset	$ 2

Supplemental Financial Information - Balance Sheet (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018	Jun. 30, 2018	Dec. 31, 2017
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]
Cash and cash equivalents	$ 735	$ 1,349	$ 694	$ 898
Restricted cash	252	247	206	207
Restricted cash included in other long-term assets	191	185	128	85
Total cash, cash equivalents and restricted cash	1,178	1,781	1,028	1,190
Receivables [Abstract]
Unbilled customer revenues	1,352	1,656
Accrued Expenses [Abstract]
Compensation-related accruals	767	1,191
Taxes accrued	446	412
Interest accrued	340	334
Exelon Generation Co L L C [Member]
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]
Cash and cash equivalents	575	750	420	416
Restricted cash	122	153	130	138
Restricted cash included in other long-term assets	0	0	0	0
Total cash, cash equivalents and restricted cash	697	903	550	554
Receivables [Abstract]
Unbilled customer revenues	703	965
Accrued Expenses [Abstract]
Compensation-related accruals	292	479
Taxes accrued	304	226
Interest accrued	76	77
Commonwealth Edison Co [Member]
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]
Cash and cash equivalents	65	135	30	76
Restricted cash	77	29	5	5
Restricted cash included in other long-term assets	174	166	108	63
Total cash, cash equivalents and restricted cash	316	330	143	144
Receivables [Abstract]
Unbilled customer revenues	218	223
Accrued Expenses [Abstract]
Compensation-related accruals	117	187
Taxes accrued	65	71
Interest accrued	109	105
PECO Energy Co [Member]
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]
Cash and cash equivalents	20	130	18	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	26	135	23	275
Receivables [Abstract]
Unbilled customer revenues	121	114
Accrued Expenses [Abstract]
Compensation-related accruals	52	49
Taxes accrued	14	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	8	7	7	17
Restricted cash	1	6	1	1
Restricted cash included in other long-term assets	0	0	0	0
Total cash, cash equivalents and restricted cash	9	13	8	18
Receivables [Abstract]
Unbilled customer revenues	115	168
Accrued Expenses [Abstract]
Compensation-related accruals	41	68
Taxes accrued	21	46
Interest accrued	40	39
Pepco Holdings LLC [Member]
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]
Cash and cash equivalents	54	124	195	30
Restricted cash	37	43	38	42
Restricted cash included in other long-term assets	17	19	20	23
Total cash, cash equivalents and restricted cash	108	186	253	95
Receivables [Abstract]
Unbilled customer revenues	195	186
Accrued Expenses [Abstract]
Compensation-related accruals	72	99
Taxes accrued	75	74
Interest accrued	50	50
Potomac Electric Power Company [Member]
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]
Cash and cash equivalents	18	16	47	5
Restricted cash	34	37	33	35
Restricted cash included in other long-term assets	0	0	0	0
Total cash, cash equivalents and restricted cash	52	53	80	40
Receivables [Abstract]
Unbilled customer revenues	107	97
Accrued Expenses [Abstract]
Compensation-related accruals	23	29
Taxes accrued	54	58
Interest accrued	24	25
Delmarva Power and Light Company [Member]
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]
Cash and cash equivalents	3	23	141	2
Restricted cash	1	1	0	0
Restricted cash included in other long-term assets	0	0	0	0
Total cash, cash equivalents and restricted cash	4	24	141	2
Receivables [Abstract]
Unbilled customer revenues	47	59
Accrued Expenses [Abstract]
Compensation-related accruals	15	19
Taxes accrued	13	4
Interest accrued	8	8
Atlantic City Electric Company [Member]
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]
Cash and cash equivalents	4	7	6	2
Restricted cash	2	4	5	6
Restricted cash included in other long-term assets	17	19	20	23
Total cash, cash equivalents and restricted cash	23	30	$ 31	$ 31
Receivables [Abstract]
Unbilled customer revenues	41	30
Accrued Expenses [Abstract]
Compensation-related accruals	10	12
Taxes accrued	9	5
Interest accrued	$ 13	$ 12

Segment Information - Narrative (Details)	6 Months Ended
Segment Information - Narrative (Details)	Jun. 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

6 Months Ended

Jun. 30, 2019

Mar. 31, 2019

Jun. 30, 2018

Mar. 31, 2018

Jun. 30, 2019

Jun. 30, 2018

Dec. 31, 2018

$ 7,689

$ 8,076

$ 17,166

$ 17,769

1,079

1,088

2,154

2,179

6,881

7,138

15,142

15,786

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

409

373

813

745

644

613

1,926

1,315

144

454

125

494

$ 966

542

$ 636

1,460

1,179

1,702

1,927

3,572

3,807

^[1]

121,596

$ 119,666

1,091

1,076

2,319

2,327

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

112

234

173

106

117

223

149

698

629

^[2]

22,454

21,984

4,210

4,579

9,506

10,090

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

252

273

569

671

202

209

854

412

301

118

$ 422

181

$ 186

540

368

890

1,298

Operating Segments [Member]

^[3]

48,402

47,556

158

147

238

196

7,689

8,076

17,166

17,769

494

542

1,460

1,179

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

121,596

119,666

Revenue from Contract with Customer, Including Assessed Tax

(3)

(7)

Intersegment Eliminations [Member]

1,076

(1)

(4)

(2)

(751)

(779)

(1,537)

(1,655)

(750)

(776)

(1,534)

(1,650)

(744)

(790)

(1,526)

(1,675)

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

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

(10,299)

(9,800)

(98)

(109)

(206)

(222)

(99)

(109)

(205)

(222)

(1)

(101)

(112)

(204)

(223)

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

(108)

(88)

(227)

(157)

(1)

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

(5,839)

(5,421)

159

151

240

198

4,210

4,579

9,506

10,090

409

466

814

914

4,096

4,298

9,059

9,515

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

116

102

227

202

202

209

854

412

301

118

181

540

368

383

670

890

1,298

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

48,402

47,556

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

252

273

568

672

1,351

1,398

2,759

2,910

257

231

508

459

1,040

1,111

2,174

2,335

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

178

175

232

207

429

417

186

164

344

329

459

495

961

1,026

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

31,889

31,213

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

655

653

1,554

1,518

164

149

510

526

1,187

1,249

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

115

307

207

(1)

(3)

102

270

210

225

194

447

411

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

11,002

10,642

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

649

662

1,625

1,639

117

114

252

248

569

578

1,325

1,378

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

253

220

206

179

284

210

542

434

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

10,006

9,716

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

1,091

1,076

2,319

2,327

188

180

369

363

926

923

1,981

2,048

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

131

128

112

234

173

106

223

149

340

371

698

629

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

22,454

21,984

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

531

523

1,106

1,080

186

188

438

929

939

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

123

119

154

160

298

287

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

8,556

8,299

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

287

289

667

673

243

247

550

582

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

101

160

166

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

4,683

4,588

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

274

265

547

575

246

240

498

526

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

107

227

170

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

3,886

3,699

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

484

487

940

484

492

942

936

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

152

125

(73)

(61)

(151)

(114)

(10)

(27)

(57)

(63)

(34)

(123)

(56)

(13)

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

8,142

8,355

108

205

221

100

110

208

224

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

106

219

149

(4)

(5)

(7)

(10)

(15)

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

11,168

$ 10,819

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

482

487

935

937

Generation Mid Atlantic [Member]

107

205

220

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

1,189

1,282

2,445

2,722

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

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

133

128

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

122

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

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

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

1,183

1,278

2,446

2,712

Generation Midwest [Member]

(1)

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

1,034

1,130

2,142

2,475

Generation Midwest [Member] | Operating Segments [Member]

103

183

297

Generation Midwest [Member] | Intersegment Eliminations [Member]

1,042

1,135

2,156

2,479

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

(8)

(5)

(14)

(4)

Revenue from Contract with Customer, Including Assessed Tax

333

489

1,213

1,436

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

Revenue from Contract with Customer, Including Assessed Tax

(1)

(8)

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

Revenue from Contract with Customer, Including Assessed Tax

333

489

1,214

1,444

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

1,067

1,052

2,205

2,202

Electricity, US Regulated | Operating Segments [Member]

Revenue from Contract with Customer, Including Assessed Tax

3,512

3,542

7,343

7,496

Electricity, US Regulated | Intersegment Eliminations [Member]

Revenue from Contract with Customer, Including Assessed Tax

(8)

(9)

(17)

(27)

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

Revenue from Contract with Customer, Including Assessed Tax

(3)

(4)

(7)

(8)

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

1,351

1,398

2,759

2,910

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

Revenue from Contract with Customer, Including Assessed Tax

566

560

1,185

1,193

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

Revenue from Contract with Customer, Including Assessed Tax

540

548

1,198

1,206

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

Revenue from Contract with Customer, Including Assessed Tax

1,063

1,045

2,218

2,214

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

Revenue from Contract with Customer, Including Assessed Tax

531

523

1,106

1,080

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

Revenue from Contract with Customer, Including Assessed Tax

261

572

567

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

Revenue from Contract with Customer, Including Assessed Tax

274

265

547

575

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

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

Revenue from Contract with Customer, Including Assessed Tax

3,468

3,669

7,487

7,785

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

Revenue from Contract with Customer, Including Assessed Tax

(250)

(270)

(565)

(663)

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

Revenue from Contract with Customer, Including Assessed Tax

3,718

3,939

8,052

8,448

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

106

Natural Gas, US Regulated | Operating Segments [Member]

Revenue from Contract with Customer, Including Assessed Tax

218

230

883

855

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

Natural Gas, US Regulated | Intersegment Eliminations [Member]

Revenue from Contract with Customer, Including Assessed Tax

(4)

(5)

(8)

(9)

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

369

325

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

Revenue from Contract with Customer, Including Assessed Tax

109

114

427

433

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

Revenue from Contract with Customer, Including Assessed Tax

106

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

106

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

(488)

(491)

(944)

(946)

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

Revenue from Contract with Customer, Including Assessed Tax

(95)

(105)

(199)

(214)

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

484

487

940

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