View Filing Data

Competitive businesses revenues

$ 4,979

$ 5,113

Rate-regulated utility revenues

4,503

4,570

(5)

^[1]

9,477

9,693

Competitive businesses purchased power and fuel

3,204

3,289

Rate-regulated utility purchased power and fuel

1,349

1,438

2,189

2,384

1,075

1,091

445

446

Gain on sales of assets and businesses

8,262

8,648

1,218

1,101

(397)

(365)

(6)

467

(28)

(399)

1,282

702

Equity in losses of unconsolidated affiliates

310

(6)

(7)

Net income attributable to noncontrolling interest

966

636

Net income (loss) attributable to common shareholders

907

585

Other comprehensive (loss) income, net of income taxes

Prior service benefit reclassified to periodic benefit cost

(16)

(17)

Actuarial loss reclassified to periodic benefit cost

Pension and non-pension postretirement benefit plan valuation adjustment

(38)

Unrealized gain on cash flow hedges

Unrealized (loss) gain on investments in unconsolidated affiliates

(2)

Unrealized gain (loss) on foreign currency translation

(18)

Comprehensive income attributable to noncontrolling interests

948

708

Comprehensive income attributable to common shareholders

$ 890

$ 656

Average shares of common stock outstanding:

Basic average shares of common stock outstanding

971

966

Assumed exercise and/or distributions of stock-based awards

Diluted average shares of common stock outstanding

^[2]

972

968

Earnings per average common share:

Basic earnings per average common share

$ 0.93

$ 0.61

Diluted earnings per average common share

$ 0.93

$ 0.60

Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount

Competitive businesses revenues

$ 4,979

$ 5,114

317

398

5,296

5,512

Competitive businesses purchased power and fuel

3,204

3,289

1,068

1,178

150

161

405

448

135

138

Gain on sales of assets and businesses

4,963

5,218

333

347

(102)

(91)

(9)

(10)

430

(44)

319

(145)

652

202

Equity in losses of unconsolidated affiliates

224

(6)

(7)

Net income attributable to noncontrolling interest

422

186

Net income attributable to membership interest

363

136

Other comprehensive (loss) income, net of income taxes

Unrealized gain on cash flow hedges

Unrealized (loss) gain on investments in unconsolidated affiliates

(2)

Unrealized gain (loss) on foreign currency translation

(1)

Comprehensive income attributable to noncontrolling interests

423

193

Comprehensive income attributable to common shareholders

365

142

1,432

1,493

(28)

1,408

1,512

388

411

194

259

253

251

228

Gain on sales of assets and businesses

1,135

1,223

276

292

(84)

(86)

(3)

(79)

(81)

197

211

Other comprehensive (loss) income, net of income taxes

157

165

157

165

622

633

280

232

(3)

(1)

900

866

152

199

135

187

233

678

724

222

142

(30)

(3)

(29)

(31)

193

111

(2)

Other comprehensive (loss) income, net of income taxes

168

113

168

113

652

654

308

330

(13)

976

977

190

192

123

153

184

136

134

756

800

220

177

(29)

(25)

(24)

(21)

196

156

Other comprehensive (loss) income, net of income taxes

160

128

160

128

1,139

1,151

1,228

1,251

355

374

101

105

239

271

180

183

111

113

1,053

1,125

175

126

(65)

(63)

(53)

(52)

122

Other comprehensive (loss) income, net of income taxes

117

Comprehensive income attributable to common shareholders

117

559

536

575

557

117

130

491

501

(34)

(31)

(27)

(23)

Other comprehensive (loss) income, net of income taxes

307

303

380

384

107

308

335

(15)

(13)

(12)

(11)

Other comprehensive (loss) income, net of income taxes

271

311

(2)

273

310

131

155

252

287

(14)

(16)

(11)

(15)

Other comprehensive (loss) income, net of income taxes

$ 10

$ 7

[1]

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.

[2]

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 months ended March 31, 2019 and approximately 5 million for the three months ended March 31, 2018.

Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Cash flows from operating activities
Net income	$ 966	$ 636
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization	1,460	1,501
Impairment of long-lived assets	7	0
Gain on sales of assets and businesses	0	(56)
Deferred income taxes and amortization of investment tax credits	187	(14)
Net fair value changes related to derivatives	31	259
Net realized and unrealized (gains) losses on NDT funds	(308)	68
Other non-cash operating activities	127	240
Changes in assets and liabilities:
Accounts receivable	79	133
Inventories	128	167
Accounts payable and accrued expenses	(764)	(451)
Option premiums received (paid), net	6	(27)
Collateral posted, net	(101)	(214)
Income taxes	141	86
Pension and non-pension postretirement benefit contributions	(328)	(331)
Other assets and liabilities	(587)	(495)
Net cash flows provided by operating activities	1,044	1,502
Cash flows from investing activities
Capital expenditures	(1,873)	(1,880)
Proceeds from NDT fund sales	3,713	1,189
Investment in NDT funds	(3,666)	(1,248)
Proceeds from sales of assets and businesses	8	79
Other investing activities	32	3
Net cash flows used in investing activities	(1,786)	(1,857)
Cash flows from financing activities
Changes in short-term borrowings	540	726
Proceeds from short-term borrowings with maturities greater than 90 days	0	1
Repayments on short-term borrowings with maturities greater than 90 days	0	(1)
Issuance of long-term debt	402	1,130
Retirement of long-term debt	(352)	(1,241)
Dividends paid on common stock	(352)	(333)
Proceeds from employee stock plans	51	12
Other financing activities	(14)	(30)
Net cash flows provided by (used in) financing activities	275	264
Increase (Decrease) in cash, cash equivalents and restricted cash	(467)	(91)
Cash, cash equivalents and restricted cash at beginning of period	1,781	1,190
Cash, cash equivalents and restricted cash at end of period	1,314	1,099
Exelon Generation Co L L C [Member]
Cash flows from operating activities
Net income	422	186
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization	789	858
Impairment of long-lived assets	7	0
Gain on sales of assets and businesses	0	(53)
Deferred income taxes and amortization of investment tax credits	108	(68)
Net fair value changes related to derivatives	33	264
Net realized and unrealized (gains) losses on NDT funds	(308)	68
Other non-cash operating activities	(90)	45
Changes in assets and liabilities:
Accounts receivable	197	194
Receivables from and payables to affiliates, net	(5)	(15)
Inventories	103	122
Accounts payable and accrued expenses	(411)	(317)
Option premiums received (paid), net	6	(27)
Collateral posted, net	(87)	(214)
Income taxes	146	79
Pension and non-pension postretirement benefit contributions	(141)	(125)
Other assets and liabilities	(187)	(142)
Net cash flows provided by operating activities	582	855
Cash flows from investing activities
Capital expenditures	(511)	(628)
Proceeds from NDT fund sales	3,713	1,189
Investment in NDT funds	(3,666)	(1,248)
Proceeds from sales of assets and businesses	8	79
Other investing activities	23	(7)
Net cash flows used in investing activities	(433)	(615)
Cash flows from financing activities
Changes in short-term borrowings	0	165
Proceeds from short-term borrowings with maturities greater than 90 days	0	1
Repayments on short-term borrowings with maturities greater than 90 days	0	(1)
Issuance of long-term debt	2	4
Retirement of long-term debt	(47)	(29)
Changes in Exelon intercompany money pool	(100)	0
Distributions to member	(225)	(188)
Other financing activities	(6)	(9)
Net cash flows provided by (used in) financing activities	(376)	(57)
Increase (Decrease) in cash, cash equivalents and restricted cash	(227)	183
Cash, cash equivalents and restricted cash at beginning of period	903	554
Cash, cash equivalents and restricted cash at end of period	676	737
Commonwealth Edison Co [Member]
Cash flows from operating activities
Net income	157	165
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization	251	228
Deferred income taxes and amortization of investment tax credits	34	50
Other non-cash operating activities	56	46
Changes in assets and liabilities:
Accounts receivable	14	39
Receivables from and payables to affiliates, net	(34)	(19)
Inventories	(3)	5
Accounts payable and accrued expenses	(188)	(158)
Collateral posted, net	(13)	(3)
Income taxes	5	(5)
Pension and non-pension postretirement benefit contributions	(67)	(38)
Other assets and liabilities	(121)	(176)
Net cash flows provided by operating activities	91	134
Cash flows from investing activities
Capital expenditures	(503)	(531)
Other investing activities	11	8
Net cash flows used in investing activities	(492)	(523)
Cash flows from financing activities
Changes in short-term borrowings	322	317
Issuance of long-term debt	400	800
Retirement of long-term debt	(300)	(700)
Dividends paid on common stock	(127)	(114)
Contributions from parent	63	113
Other financing activities	(9)	(9)
Net cash flows provided by (used in) financing activities	349	407
Increase (Decrease) in cash, cash equivalents and restricted cash	(52)	18
Cash, cash equivalents and restricted cash at beginning of period	330	144
Cash, cash equivalents and restricted cash at end of period	278	162
PECO Energy Co [Member]
Cash flows from operating activities
Net income	168	113
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization	81	75
Deferred income taxes and amortization of investment tax credits	5	(4)
Other non-cash operating activities	16	21
Changes in assets and liabilities:
Accounts receivable	(86)	(51)
Receivables from and payables to affiliates, net	7	7
Inventories	23	12
Accounts payable and accrued expenses	(13)	6
Income taxes	20	5
Pension and non-pension postretirement benefit contributions	(25)	(24)
Other assets and liabilities	(119)	(141)
Net cash flows provided by operating activities	77	19
Cash flows from investing activities
Capital expenditures	(222)	(217)
Other investing activities	2	2
Net cash flows used in investing activities	(220)	(215)
Cash flows from financing activities
Changes in short-term borrowings	0	220
Issuance of long-term debt	0	325
Retirement of long-term debt	0	(500)
Dividends paid on common stock	(90)	(287)
Changes in Exelon intercompany money pool	0	194
Contributions from parent	145	0
Other financing activities	0	(5)
Net cash flows provided by (used in) financing activities	55	(53)
Increase (Decrease) in cash, cash equivalents and restricted cash	(88)	(249)
Cash, cash equivalents and restricted cash at beginning of period	135	275
Cash, cash equivalents and restricted cash at end of period	47	26
Baltimore Gas and Electric Company [Member]
Cash flows from operating activities
Net income	160	128
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization	136	134
Deferred income taxes and amortization of investment tax credits	28	22
Other non-cash operating activities	27	20
Changes in assets and liabilities:
Accounts receivable	(39)	(32)
Receivables from and payables to affiliates, net	(10)	0
Inventories	17	20
Accounts payable and accrued expenses	(27)	(9)
Collateral posted, net	(1)	0
Income taxes	8	14
Pension and non-pension postretirement benefit contributions	(40)	(45)
Other assets and liabilities	(14)	61
Net cash flows provided by operating activities	245	313
Cash flows from investing activities
Capital expenditures	(258)	(224)
Other investing activities	1	1
Net cash flows used in investing activities	(257)	(223)
Cash flows from financing activities
Changes in short-term borrowings	71	(32)
Dividends paid on common stock	(56)	(52)
Net cash flows provided by (used in) financing activities	15	(84)
Increase (Decrease) in cash, cash equivalents and restricted cash	3	6
Cash, cash equivalents and restricted cash at beginning of period	13	18
Cash, cash equivalents and restricted cash at end of period	16	24
Pepco Holdings LLC [Member]
Cash flows from operating activities
Net income	117	65
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization	180	183
Deferred income taxes and amortization of investment tax credits	0	17
Other non-cash operating activities	35	53
Changes in assets and liabilities:
Accounts receivable	(11)	(9)
Receivables from and payables to affiliates, net	(8)	10
Inventories	(12)	4
Accounts payable and accrued expenses	(9)	44
Income taxes	4	(9)
Pension and non-pension postretirement benefit contributions	(6)	(55)
Other assets and liabilities	(61)	(24)
Net cash flows provided by operating activities	229	279
Cash flows from investing activities
Capital expenditures	(358)	(258)
Other investing activities	1	0
Net cash flows used in investing activities	(357)	(258)
Cash flows from financing activities
Changes in short-term borrowings	147	57
Retirement of long-term debt	(5)	(12)
Changes in Exelon intercompany money pool	0	13
Distributions to member	(128)	(71)
Contributions from member	19	0
Net cash flows provided by (used in) financing activities	33	(13)
Increase (Decrease) in cash, cash equivalents and restricted cash	(95)	8
Cash, cash equivalents and restricted cash at beginning of period	186	95
Cash, cash equivalents and restricted cash at end of period	91	103
Potomac Electric Power Company [Member]
Cash flows from operating activities
Net income	55	31
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization	94	96
Deferred income taxes and amortization of investment tax credits	(2)	4
Other non-cash operating activities	3	10
Changes in assets and liabilities:
Accounts receivable	(19)	0
Receivables from and payables to affiliates, net	3	(18)
Inventories	(14)	(2)
Accounts payable and accrued expenses	(2)	36
Income taxes	4	(3)
Pension and non-pension postretirement benefit contributions	(4)	(7)
Other assets and liabilities	(37)	(21)
Net cash flows provided by operating activities	81	126
Cash flows from investing activities
Capital expenditures	(144)	(127)
Other investing activities	1	0
Net cash flows used in investing activities	(143)	(127)
Cash flows from financing activities
Changes in short-term borrowings	65	34
Dividends paid on common stock	(24)	(25)
Contributions from parent	14	0
Net cash flows provided by (used in) financing activities	55	9
Increase (Decrease) in cash, cash equivalents and restricted cash	(7)	8
Cash, cash equivalents and restricted cash at beginning of period	53	40
Cash, cash equivalents and restricted cash at end of period	46	48
Delmarva Power and Light Company [Member]
Cash flows from operating activities
Net income	53	31
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization	46	45
Deferred income taxes and amortization of investment tax credits	1	10
Other non-cash operating activities	11	19
Changes in assets and liabilities:
Accounts receivable	(5)	(1)
Receivables from and payables to affiliates, net	(15)	(16)
Inventories	1	7
Accounts payable and accrued expenses	11	18
Income taxes	5	(5)
Other assets and liabilities	(10)	7
Net cash flows provided by operating activities	98	115
Cash flows from investing activities
Capital expenditures	(78)	(65)
Net cash flows used in investing activities	(78)	(65)
Cash flows from financing activities
Changes in short-term borrowings	5	(5)
Retirement of long-term debt	0	(4)
Dividends paid on common stock	(41)	(36)
Net cash flows provided by (used in) financing activities	(36)	(45)
Increase (Decrease) in cash, cash equivalents and restricted cash	(16)	5
Cash, cash equivalents and restricted cash at beginning of period	24	2
Cash, cash equivalents and restricted cash at end of period	8	7
Atlantic City Electric Company [Member]
Cash flows from operating activities
Net income	10	7
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization	31	33
Deferred income taxes and amortization of investment tax credits	0	2
Other non-cash operating activities	5	9
Changes in assets and liabilities:
Accounts receivable	13	(5)
Receivables from and payables to affiliates, net	(4)	(4)
Inventories	1	0
Accounts payable and accrued expenses	12	30
Income taxes	(1)	0
Pension and non-pension postretirement benefit contributions	0	(6)
Other assets and liabilities	(7)	(7)
Net cash flows provided by operating activities	60	59
Cash flows from investing activities
Capital expenditures	(128)	(63)
Other investing activities	0	(1)
Net cash flows used in investing activities	(128)	(64)
Cash flows from financing activities
Changes in short-term borrowings	77	28
Retirement of long-term debt	(4)	(8)
Dividends paid on common stock	(12)	(9)
Contributions from parent	5	0
Net cash flows provided by (used in) financing activities	66	11
Increase (Decrease) in cash, cash equivalents and restricted cash	(2)	6
Cash, cash equivalents and restricted cash at beginning of period	30	31
Cash, cash equivalents and restricted cash at end of period	$ 28	$ 37

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

Mar. 31, 2019

Dec. 31, 2018

$ 880

$ 1,349

223

247

4,564

4,607

Mark-to-market derivative assets, current

1,062

1,256

652

804

Unamortized energy contract assets, current

179

334

1,380

1,351

1,191

1,222

Assets held for sale

890

904

1,406

1,238

12,476

13,360

77,460

76,707

Nuclear decommissioning trust funds

8,222

8,237

12,302

11,661

620

625

Mark-to-market derivative assets, noncurrent

6,677

454

452

Unamortized energy contract assets, noncurrent

365

372

3,017

1,575

31,657

29,599

^[1]

121,593

119,666

1,254

714

2,508

1,349

3,327

3,800

1,725

2,112

Mark-to-market derivative liabilities, current

522

644

345

475

Unamortized energy contract liabilities, current

151

149

Renewable energy credit obligation

348

344

799

777

1,245

1,035

12,229

11,404

Long-term debt to financing trusts

32,960

34,075

390

Deferred income taxes and unamortized investment tax credits

11,642

11,330

9,967

9,679

Pension obligations

3,734

3,988

Spent nuclear fuel obligation

1,984

1,928

1,178

1,171

Mark-to-market derivative liabilities, noncurrent

9,781

9,559

434

479

Unamortized energy contract liabilities, noncurrent

432

463

3,158

2,130

42,310

40,727

^[1]

87,889

86,596

Treasury stock, at cost (2 shares at March 31, 2019 and December 31, 2018)

19,171

19,116

(123)

Accumulated other comprehensive loss, net

15,321

14,766

(3,012)

(2,995)

31,357

30,764

Noncontrolling Interests

2,347

2,306

Total equity

33,704

33,070

Variable Interest Entity, Consolidated, Assets, Pledged

121,593

119,666

9,546

9,667

Variable Interest Entity, Consolidated, Liabilities, No Recourse

3,572

3,548

537

750

139

153

2,800

2,941

Mark-to-market derivative assets, current

367

562

652

804

Unamortized energy contract assets, current

163

173

146

251

965

963

Assets held for sale

890

904

1,013

883

7,721

8,433

24,034

23,981

Nuclear decommissioning trust funds

12,302

11,661

404

414

Mark-to-market derivative assets, noncurrent

454

452

Unamortized energy contract assets, noncurrent

1,525

1,421

364

371

Deferred income taxes

1,813

755

16,927

15,142

^[2]

48,682

47,556

2,365

906

1,566

1,847

675

898

Borrowings from Exelon intercompany money pool

136

139

100

Mark-to-market derivative liabilities, current

318

449

Unamortized energy contract liabilities, current

Renewable energy credit obligation

348

343

799

777

425

279

6,660

5,769

Long-term debt to affiliates

5,487

6,989

895

898

Deferred income taxes and unamortized investment tax credits

3,502

3,383

9,737

9,450

Spent nuclear fuel obligation

894

900

1,178

1,171

Payables to affiliates, noncurrent

2,870

2,606

Mark-to-market derivative liabilities, noncurrent

219

252

Unamortized energy contract liabilities, noncurrent

1,528

610

19,944

18,392

^[2]

32,986

32,048

Accumulated other comprehensive loss, net

3,862

3,724

(36)

(38)

Membership interest

9,525

9,518

Total members' equity

13,351

13,204

Noncontrolling Interests

2,345

2,304

Total equity

15,696

15,508

Variable Interest Entity, Consolidated, Assets, Pledged

48,682

47,556

9,515

9,634

Variable Interest Entity, Consolidated, Liabilities, No Recourse

3,508

3,480

135

539

336

320

Inventories, net

152

148

285

293

1,507

1,570

22,274

22,058

1,338

1,307

Receivable from affiliates, noncurrent

2,625

2,412

2,217

1,073

1,035

347

395

7,801

7,585

31,582

31,213

322

300

491

607

229

373

119

112

111

Mark-to-market derivative liabilities, current

241

293

1,594

1,925

Long-term debt to financing trusts

8,194

7,801

205

Deferred income taxes and unamortized investment tax credits

3,870

3,813

119

118

196

201

Mark-to-market derivative liabilities, noncurrent

6,269

6,050

213

223

582

630

11,249

11,035

21,242

20,966

Retained deficit unappropriated

1,588

Other paid-in capital

7,385

7,322

(1,639)

Retained earnings appropriated

3,006

2,976

10,340

10,247

31,582

31,213

130

394

321

148

151

Prepaid utility taxes

100

816

782

8,766

8,610

491

460

Receivable from affiliates, noncurrent

457

389

372

349

1,374

1,250

10,956

10,642

379

370

119

113

123

175

787

809

Long-term debt to financing trusts

3,084

184

Deferred income taxes and unamortized investment tax credits

1,974

1,933

288

488

421

2,858

2,745

6,913

6,822

2,723

2,578

1,320

1,242

4,043

3,820

10,956

10,642

385

353

Prepaid utility taxes

161

177

753

786

8,408

8,243

395

398

301

279

105

806

687

9,967

9,716

106

291

295

142

155

120

834

774

2,876

Deferred income taxes and unamortized investment tax credits

1,275

1,222

198

201

1,172

1,192

130

2,799

2,712

6,509

6,362

1,714

1,744

1,640

3,458

3,354

9,967

9,716

124

445

453

189

177

184

163

506

489

1,453

1,533

13,619

13,446

2,236

2,312

132

130

4,005

467

486

Deferred income taxes

370

7,222

7,005

^[3]

22,294

21,984

326

179

125

441

496

253

256

117

116

Unamortized energy contract liabilities, current

123

119

127

123

1,675

1,592

6,119

6,134

Deferred income taxes and unamortized investment tax credits

2,182

2,146

101

103

Unamortized energy contract liabilities, noncurrent

1,829

1,864

416

442

630

369

5,210

4,976

^[3]

13,004

12,702

Membership interest

9,239

9,220

Total members' equity

9,290

9,282

Total equity

9,290

9,282

Variable Interest Entity, Consolidated, Assets, Pledged

22,294

21,984

Variable Interest Entity, Consolidated, Liabilities, No Recourse

219

225

102

Inventories, net

109

270

769

760

6,534

6,460

620

643

106

105

311

316

1,117

1,079

8,420

8,299

105

188

214

139

126

Merger related obligation

Current portion of DC PLUG obligation

658

628

2,705

2,704

Deferred income taxes and unamortized investment tax credits

1,081

1,064

805

822

360

312

2,272

2,227

5,635

5,559

1,650

1,636

1,135

1,104

2,785

2,740

8,420

8,299

141

134

316

336

3,848

3,821

225

231

182

186

496

431

4,660

4,588

111

366

375

1,404

1,403

Deferred income taxes and unamortized investment tax credits

643

628

596

606

114

1,369

1,301

3,139

3,079

914

607

595

1,521

1,509

4,660

4,588

Inventories, net

238

240

3,041

2,966

377

386

504

493

^[4]

3,783

3,699

216

139

139

154

492

422

1,165

1,170

Deferred income taxes and unamortized investment tax credits

539

535

395

402

997

981

^[4]

2,654

2,573

984

979

145

147

1,129

1,126

Variable Interest Entity, Consolidated, Assets, Pledged

3,783

3,699

Variable Interest Entity, Consolidated, Liabilities, No Recourse

$ 54

$ 59

[1]	Exelon’s consolidated assets include $9,546 million and $9,667 million at March 31, 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 $3,572 million and $3,548 million at March 31, 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 $9,515 million and $9,634 million at March 31, 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 $3,508 million and $3,480 million at March 31, 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 $31 million and $33 million at March 31, 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 $64 million and $69 million at March 31, 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 $22 million and $23 million at March 31, 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 $54 million and $59 million at March 31, 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) - shares	Mar. 31, 2019	Dec. 31, 2018
Statement of Financial Position [Abstract]
Common Stock, Shares Authorized	2,000,000,000	2,000,000,000
Common Stock, Shares, Outstanding	970,954,879	968,187,955
Treasury Stock, Shares held	1,832,457	1,832,457

Consolidated Statement 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]

Exelon Generation Co L L C [Member]

Membership Interest [Member]

Exelon Generation Co L L C [Member]

Retained/Undistributed Earnings (Losses), Unappropriated [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]

Common Stock [Member]

Commonwealth Edison Co [Member]

Other Paid-in-Capital [Member]

Commonwealth Edison Co [Member]

Retained/Undistributed Earnings (Losses), Unappropriated [Member]

Commonwealth Edison Co [Member]

Retained Earnings, Appropriated [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]

Common Stock [Member]

Baltimore Gas and Electric Company [Member]

Retained Earnings [Member]

Pepco Holdings LLC [Member]

Membership Interest [Member]

Pepco Holdings LLC [Member]

Retained/Undistributed Earnings (Losses), Unappropriated [Member]

Potomac Electric Power Company [Member]

Common Stock [Member]

Potomac Electric Power Company [Member]

Retained Earnings [Member]

Delmarva Power and Light Company [Member]

Common Stock [Member]

Delmarva Power and Light Company [Member]

Retained Earnings [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

965,168,000

Beginning balance at Dec. 31, 2017

$ 32,187

$ 18,964

$ (123)

$ 14,081

$ (3,026)

^[1]

$ 2,291

Beginning Balance at Dec. 31, 2017

$ 15,959

$ 9,357

$ 4,349

$ (37)

^[1]

$ 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]

Stock issued during period, shares, long-term incentive plan activity

$ 636

585

186

136

165

113

128

1,685,000

Stock issued during period, value, long-term incentive plan activity

$ (3)

(3)

Stock issued during period, shares, employee stock purchase plan

361,000

Stock issued during period, value, employee stock purchase plan

$ 12

Changes in equity of noncontrolling interests

(9)

Common stock dividends

(334)

(114)

(287)

(52)

(25)

(36)

(9)

Contributions from parent

113

Distributions to member

(188)

(71)

Other comprehensive income (loss), net of income taxes

^[1]

Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard

$ 4

(10)

(3)

(1)

Ending balance (in shares) at Mar. 31, 2018

967,214,000

Ending balance at Mar. 31, 2018

$ 32,565

18,973

(123)

14,346

(2,965)

^[1]

2,334

Ending Balance at Mar. 31, 2018

15,958

9,357

4,303

(34)

^[1]

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

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]

Appropriation of retained earnings for future dividends

(165)

165

Appropriation of retained earnings for future dividends

(2,976)

Beginning balance (in shares) at Dec. 31, 2018

970,020,000

Beginning balance at Dec. 31, 2018

$ 33,070

19,116

(123)

14,766

(2,995)

^[1]

2,306

Beginning Balance at Dec. 31, 2018

15,508

9,518

3,724

(38)

^[1]

2,304

9,282

9,220

Beginning Balance at Dec. 31, 2018

30,764

10,247

1,588

7,322

(1,639)

2,976

3,820

2,578

1,242

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]

Stock issued during period, shares, long-term incentive plan activity

$ 966

907

422

363

157

168

160

117

2,446,000

Stock issued during period, value, long-term incentive plan activity

$ (3)

(3)

Stock issued during period, shares, employee stock purchase plan

320,000

Stock issued during period, value, employee stock purchase plan

$ 51

Changes in equity of noncontrolling interests

(17)

Sale of noncontrolling interests

Common stock dividends

(352)

(127)

(90)

(56)

(24)

(41)

(12)

Contributions from parent

(145)

Distributions to member

(225)

(128)

Other comprehensive income (loss), net of income taxes

$ (18)

(17)

^[1]

(1)

^[1]

(1)

Ending balance (in shares) at Mar. 31, 2019

972,786,000

Ending balance at Mar. 31, 2019

$ 33,704

$ 19,171

$ (123)

$ 15,321

$ (3,012)

^[1]

$ 2,347

Ending Balance at Mar. 31, 2019

$ 15,696

$ 9,525

$ 3,862

$ (36)

^[1]

$ 2,345

$ 9,290

$ 9,239

$ 51

Ending Balance at Mar. 31, 2019

$ 31,357

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]

Appropriation of retained earnings for future dividends

$ (3,006)

$ (157)

$ 157

[1]	All amounts are net of tax and noncontrolling interests. Amounts in parenthesis represent a decrease in AOCI.

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

Significant Accounting Policies

3 Months Ended

Mar. 31, 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 March 31, 2019 and 2018 and for the three 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 March 31, 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 March 31, 2019. Unless otherwise indicated, the Registrants are currently assessing the impacts such guidance may have (which could be material) in their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures, as well as the potential to early adopt where applicable. The Registrants have assessed other FASB issuances of new standards which are not listed below given the current expectation that such standards will not significantly impact the Registrants' financial reporting.

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 have goodwill as of March 31, 2019. This updated guidance is not currently expected to impact the Registrants’ financial reporting. 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)

3 Months Ended

Mar. 31, 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 March 31, 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 March 31, 2019 and December 31, 2018, Exelon and Generation collectively had significant interests in seven 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 March 31, 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 March 31, 2019 and December 31, 2018, Exelon's, PHI's and ACE's consolidated VIE consist of:


•	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 March 31, 2019 and December 31, 2018, ComEd, PECO, BGE, Pepco and DPL did not have any material consolidated VIEs.

As of March 31, 2019 and December 31, 2018, Exelon and Generation provided the following support to their respective consolidated VIEs:


•	Generation provides operating and capital funding to the renewable energy project companies and there is limited recourse to Generation related to certain renewable energy project companies.


•	Generation provides approximately $32 million 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. However, pursuant to amendments dated March 31, 2015, the energy obligations under the Ginna Nuclear Power Plant (Ginna) PPAs were suspended during the term of the RSSA, through the end of March 31, 2017. With the expiration of the RSSA, the PPA was reinstated beginning April 1, 2017,


•	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 March 31, 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 months ended March 31, 2019, ACE transferred $4 million to ATF. During the three months ended March 31, 2018, ACE transferred $8 million to ATF.

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 March 31, 2019 and December 31, 2018 are as follows:



	March 31, 2019								December 31, 2018
	Exelon^(a)		Generation		PHI^(a)		ACE		Exelon^(a)		Generation		PHI^(a)		ACE
Current assets	$	645	$	639	$	6	$	3	$	938	$	931	$	7	$	4
Noncurrent assets	9,235		9,210		25		19		9,071		9,045		26		19
Total assets	$	9,880	$	9,849	$	31	$	22	$	10,009	$	9,976	$	33	$	23
Current liabilities	$	748	$	725	$	23	$	19	$	274	$	252	$	22	$	19
Noncurrent liabilities	2,831		2,790		41		35		3,280		3,233		47		40
Total liabilities	$	3,579	$	3,515	$	64	$	54	$	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 March 31, 2019 and December 31, 2018, these assets and liabilities primarily consisted of the following:



	March 31, 2019								December 31, 2018
	Exelon^(a)		Generation		PHI^(a)		ACE		Exelon^(a)		Generation		PHI^(a)		ACE
Cash and cash equivalents	$	125	$	125	$	—	$	—	$	414	$	414	$	—	$	—
Restricted cash and cash equivalents	58		55		3		3		66		62		4		4
Accounts receivable, net
Customer	152		152		—		—		146		146		—		—
Other	23		23		—		—		23		23		—		—
Inventory, net
Materials and supplies	213		213		—		—		212		212		—		—
Other current assets	51		48		3		—		52		49		3		—
Total current assets	622		616		6		3		913		906		7		4
Property, plant and equipment, net	6,147		6,147		—		—		6,145		6,145		—		—
NDT funds	2,520		2,520		—		—		2,351		2,351		—		—
Other noncurrent assets	257		232		25		19		258		232		26		19
Total noncurrent assets	8,924		8,899		25		19		8,754		8,728		26		19
Total assets	$	9,546	$	9,515	$	31	$	22	$	9,667	$	9,634	$	33	$	23
Long-term debt due within one year	$	567	$	545	$	22	$	19	$	87	$	66	$	21	$	18
Accounts payable	120		120		—		—		96		96		—		—
Accrued expenses	42		41		1		—		72		72		1		1
Unamortized energy contract liabilities	13		13		—		—		15		15		—		—
Other current liabilities	6		6		—		—		3		3		—		—
Total current liabilities	748		725		23		19		273		252		22		19
Long-term debt	565		524		41		35		1,072		1,025		47		40
Asset retirement obligations	2,190		2,190		—		—		2,160		2,160		—		—
Unamortized energy contract liabilities	—		—		—		—		1		1		—		—
Other noncurrent liabilities	69		69		—		—		42		42		—		—
Total noncurrent liabilities	2,824		2,783		41		35		3,275		3,228		47		40
Total liabilities	$	3,572	$	3,508	$	64	$	54	$	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 March 31, 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 March 31, 2019 and December 31, 2018, the Utility Registrants did not have any material unconsolidated VIEs.

As of March 31, 2019 and December 31, 2018, Exelon and Generation had significant unconsolidated variable interests in seven VIEs 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, respectively, as of March 31, 2019. These immaterial VIEs are equity and debt securities in energy development companies. As of March 31, 2019, 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, 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:



March 31, 2019	Commercial Agreement VIEs		Equity Investment VIEs		Total
Total assets^(a)	$	601	$	463	$	1,064
Total liabilities^(a)	42		223		265
Exelon's ownership interest in VIE^(a)	—		214		214
Other ownership interests in VIE^(a)	559		26		585
Registrants’ maximum exposure to loss:
Carrying amount of equity method investments	—		214		214
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)	3 Months Ended
	Mar. 31, 2019
Discontinued Operations and Disposal Groups [Abstract]
Disposal Groups, Including Discontinued Operations, Disclosure [Text Block]	Mergers, Acquisitions and Dispositions (Exelon and Generation) 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. On September 17, 2018, Oyster Creek permanently ceased generation operations. Under the terms of the transaction, Generation will transfer 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. In addition to the assumption of liability for the full decommissioning and ongoing management of spent fuel, other consideration to be received in the transaction is contingent on several factors, including a requirement that Generation deliver a minimum NDT fund balance at closing, subject to adjustment for specific terms that include income taxes that would be imposed on any net unrealized built-in gains and certain decommissioning activities to be performed during the pre-close period after the unit shuts down in the fall of 2018 and prior to the anticipated close of the transaction. 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 $888 million and $765 million of Assets and Liabilities held for sale, respectively, at March 31, 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 in the third quarter of 2018, Exelon and Generation recognized an $84 million pre-tax charge to Operating and maintenance expense. Completion of the transaction contemplated by the sale agreement is 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 was received in April 2019. Generation currently anticipates satisfaction of the remaining closing conditions to occur in the second half of 2019. 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 three months ended March 31, 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)

3 Months Ended

Mar. 31, 2019

Revenue from Contract with Customer [Abstract]

Revenue from Contract with Customer [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 March 31, 2019:



	Contract Assets						Contract Liabilities
	Exelon			Generation			Exelon			Generation
Balance as of January 1, 2018	$	283		$	283		$	35		$	35
Increases as a result of changes in the estimate of the stage of completion	50			50			—			—
Increases as a result of additional cash received or due	—			—			179			465
Amounts reclassified into receivables or recognized into revenues	(146		)	(146		)	(187		)	(458		)
Balance at December 31, 2018	187			187			27			42
Increases as a result of changes in the estimate of the stage of completion	26			26			—			—
Increases as a result of additional cash received or due	—			—			21			63
Amounts reclassified into receivables or recognized into revenues	(26		)	(26		)	(23		)	(66		)
Balance at March 31, 2019	$	187		$	187		$	25		$	39

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 March 31, 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 March 31, 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	$	393	$	273	$	112	$	50	$	142	$	970
Generation	493		331		126		50		142		1,142

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)

3 Months Ended

Mar. 31, 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	1-34	1-15	1-87	1-13	1-13	1-13	1-8
Options to extend the term	3-30	3-30	3-10	N/A	N/A	3-30	5	3-30	N/A
Options to terminate within	1-3	2	N/A	N/A	3	N/A	N/A	N/A	N/A

The components of lease costs for the three months ended March 31, 2019 were as follows:



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Operating lease costs	$	68	$	46	$	1	$	—	$	8	$	10	$	3	$	3	$	1
Variable lease costs	73		68		—		—		—		2		—		1		—
Short-term lease costs	9		8		—		—		—		—		—		—		—
Total lease costs ^(a)	$	150	$	122	$	1	$	—	$	8	$	12	$	3	$	4	$	1

__________


(a)	Excludes $3 million, $2 million, $1 million and $1 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 March 31, 2019:



	Exelon^(a)		Generation^(a)		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Operating lease ROU assets
Other deferred debits and other assets	$	1,465	$	1,027	$	5	$	2	$	97	$	314	$	67	$	75	$	26

Operating lease liabilities
Other current liabilities	249		173		3		1		31		36		8		11		6
Other deferred credits and other liabilities	1,395		1,023		4		1		66		284		60		72		20
Total operating lease liabilities	$	1,644	$	1,196	$	7	$	2	$	97	$	320	$	68	$	83	$	26

__________


(a)	Exelon's and Generation's operating ROU assets and lease liabilities include $631 million and $778 million, respectively, related to contracted generation.

The weighted average remaining lease terms, in years, and discount rates for operating leases as of March 31, 2019 were as follows:



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Remaining lease term	10.0		10.7		2.9		4.4		5.6		9.4		9.9		9.8		5.3
Discount rate	4.6	%	4.8	%	3.3	%	3.4	%	3.6	%	4.1	%	3.9	%	3.9	%	3.5	%

Future minimum lease payments for operating leases as of March 31, 2019 were as follows:



Year	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
2019	$	214	$	154	$	2	$	1	$	19	$	33	$	8	$	7	$	5
2020	289		202		2		1		34		43		9		12		5
2021	244		162		2		—		32		42		9		11		5
2022	174		112		1		—		16		40		8		11		4
2023	139		99		—		—		—		39		8		10		3
Remaining years	1,052		840		—		—		18		194		42		52		7
Total	2,112		1,569		7		2		119		391		84		103		29
Interest	468		373		—		—		22		71		16		20		3
Total operating lease liabilities	$	1,644	$	1,196	$	7	$	2	$	97	$	320	$	68	$	83	$	26

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



	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 three months ended March 31, 2019 were as follows:



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Operating cash flows from operating leases	$	78	$	52	$	1	$	—	$	14	$	8	$	2	$	2	$	1

Lessor, Operating Leases [Text Block]

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 March 31, 2019 were as follows:



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Operating lease income	$	4	$	3	$	—	$	—	$	—	$	1	$	—	$	1	$	—
Variable lease income	$	52	$	52	$	—	$	—	$	—	$	—	$	—	$	—	$	—

Future minimum lease payments to be recovered under operating leases as of March 31, 2019 were as follows:



Year	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
2019	$	47	$	43	$	—	$	—	$	—	$	4	$	—	$	3	$	—
2020	51		46		—		—		—		4		—		3		—
2021	50		45		—		—		—		4		—		3		—
2022	50		45		—		—		—		4		—		3		—
2023	49		45		—		—		—		4		—		3		—
Remaining years	315		271		1		3		1		39		1		38		—
Total	$	562	$	495	$	1	$	3	$	1	$	59	$	1	$	53	$	—

Leases (All Registrants)

Regulatory Matters (All Registrants)

3 Months Ended

Mar. 31, 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 Increase			Approved Revenue Requirement Increase (Decrease)			Approved ROE		Approval Date	Rate Effective Date
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	^(a)	$	70	^(a)	9.6	%	March 13, 2019	April 1, 2019

__________


(a)	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 April 30, 2019)	$	27		10.3	%	Third quarter of 2019
ComEd - Illinois (Electric)^(a)	April 8, 2019	$	(6	)	8.91	%	December 2019

__________

(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.

Transmission Formula Rates

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. The formula rate filing includes a requested increase of $22 million to PECO’s annual transmission revenues and a requested rate of return on common equity of 11%, inclusive of a 50 basis point adder for being a member of a regional transmission organization. PECO requested that the new transmission rate be effective as of July 2017. 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. On May 4, 2018, the Chief Administrative Law Judge terminated settlement judge procedures and designated a new presiding judge. On February 8, 2019, PECO and the active parties reached an agreement in principle to settle this case. The presiding Administrative Law Judge has since suspended the procedural schedule in order for PECO and the active parties to continue working towards finalizing a settlement. On April 15, 2019, PECO and the active parties filed a status update with the presiding Administrative Law Judge requesting an additional 45 days to file a settlement. PECO cannot predict the outcome of this proceeding, or the transmission formula FERC may approve.

On May 11, 2018, pursuant to the transmission formula rate request discussed above, PECO made its first annual formula rate update, which included a revenue decrease of $6 million. The revenue decrease of $6 million included an approximately $20 million reduction as a result of the tax savings associated with the TCJA. The updated transmission rate was effective June 1, 2018, subject to refund.

Other State Regulatory Matters

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 allows 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 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, must begin 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). ComEd’s, BGE’s, Pepco’s, DPL’s and ACE’s transmission formula rates currently do not provide for the pass back or recovery of income tax-related regulatory liabilities or assets, including those established upon enactment of the TCJA.

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 $76 million, $51 million, $15 million, $10 million, $3 million, $5 million and $2 million, respectively, as of March 31, 2019.

Regulatory Assets and Liabilities

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

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
March 31, 2019	$	64	$	7	$	—	$	49	$	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 three months ended March 31, 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 the same day, Generation filed certain Supplemental Information with the NJBPU providing proprietary information that was requested in the application but which could not be shared with PSEG. On April 18, 2019, the NJBPU approved the award of ZECs to Salem 1 and Salem 2. 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.

Other legal challenges remain possible, the outcomes of which remain uncertain. 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 Maryland Department of the Environment (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 March 31, 2019, $38 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)	3 Months Ended
Impairment of Long-Lived Assets (Exelon and Generation)	Mar. 31, 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 Pacific Gas and Electric Company (PG&E) through a PPA. As of March 31, 2019, Generation had approximately $750 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 $1,970 million of additional net long-lived assets as of March 31, 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)

3 Months Ended

Mar. 31, 2019

Property, Plant and Equipment [Abstract]

Implications Of Potential Early Retirement Disclosure [Text Block]

Early Plant Retirements (Exelon and Generation)

Exelon and Generation continuously evaluate factors that affect the current and expected economic value of Generation’s plants, including, but not limited to: market power prices, results of capacity auctions, potential legislative and regulatory solutions to ensure plants are fairly compensated for benefits they provide through their carbon-free emissions, reliability, or fuel security, and the impact of potential rules from the EPA requiring reduction of carbon and other emissions and the efforts of states to implement those final rules. The precise timing of an early retirement date for any plant, and the resulting financial statement impacts, may be affected by many factors, including the status of potential regulatory or legislative solutions, results of any transmission system reliability study assessments, the nature of any co-owner requirements and stipulations, and NDT fund requirements for nuclear plants, among other factors. However, the earliest retirement date for any plant would usually be the first year in which the unit does not have capacity or other obligations, and where applicable, just prior to its next scheduled nuclear refueling outage.

Nuclear Generation

In 2015 and 2016, Generation identified the Clinton and Quad Cities nuclear plants in Illinois, Ginna and Nine Mile Point nuclear plants in New York and 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, Exelon announced that Generation will permanently cease generation operations at TMI on or about September 30, 2019. TMI is currently committed to operate through May 2019 and is licensed to operate through 2034. Generation has filed the required market and regulatory notifications to shut down the plant. PJM has subsequently notified Generation that it has not identified any reliability issues and has approved the deactivation of TMI as proposed. On April 5, 2019, Generation filed the post shutdown decommissioning activities report (PSDAR) with the NRC detailing the plans for TMI after its final shutdown.

On February 2, 2018, Exelon announced that Generation will 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 months ended March 31, 2019 and 2018 are summarized in the table below.



	Three Months Ended March 31,
Income statement expense (pre-tax)	2019			2018
Depreciation and amortization^(a)
Accelerated depreciation^(b)	$	74		$	137
Accelerated nuclear fuel amortization	5			15
Operating and maintenance^(c)	(83		)	26
Total	$	(4	)	$	178

_________


(a)	Reflects incremental accelerated depreciation and amortization for TMI for the three months ended March 31, 2019. Reflects incremental accelerated depreciation for TMI and Oyster Creek for the three months ended March 31, 2018. The Oyster Creek amounts are from February 2, 2018 through March 31, 2018.


(b)	Reflects incremental accelerated depreciation of plant assets, including any ARC.


(c)	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.

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 current capacity commitment for Mystic Units 7 and 8. Mystic Unit 9 is currently 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 are due 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 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 the long-term, market-based fuel security rules by October 15, 2019.

The following table provides the balance sheet amounts as of March 31, 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.



	March 31, 2019
Asset Balances
Materials and supplies inventory	$	30
Fuel inventory	22
Completed plant, net	900
Construction work in progress	2
Liability Balances
Asset retirement obligation	(1		)

Fair Value of Financial Assets and Liabilities (All Registrants)

3 Months Ended

Mar. 31, 2019

Fair Value Disclosures [Abstract]

Fair Value of Financial Assets and Liabilities (All Registrants)

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 March 31, 2019 and December 31, 2018:

Exelon



	March 31, 2019
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	1,254	$	—	$	1,254	$	—	$	1,254
Long-term debt (including amounts due within one year)^(a)	35,468		—		35,066		2,188		37,254
Long-term debt to financing trusts^(b)	390		—		—		411		411
SNF obligation	1,178		—		989		—		989



	December 31, 2018
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	714	$	—	$	714	$	—	$	714
Long-term debt (including amounts due within one year)^(a)	35,424		—		33,711		2,158		35,869
Long-term debt to financing trusts^(b)	390		—		—		400		400
SNF obligation	1,171		—		949		—		949

Generation



	March 31, 2019
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year)^(a)	$	8,747	$	—	$	7,641	$	1,443	$	9,084
SNF obligation	1,178		—		989		—		989



	December 31, 2018
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year)^(a)	$	8,793	$	—	$	7,467	$	1,443	$	8,910
SNF obligation	1,171		—		949		—		949

ComEd



	March 31, 2019
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	322	$	—	$	322	$	—	$	322
Long-term debt (including amounts due within one year)^(a)	8,194		—		8,855		—		8,855
Long-term debt to financing trusts^(b)	205		—		—		215		215



	December 31, 2018
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year)^(a)	$	8,101	$	—	$	8,390	$	—	$	8,390
Long-term debt to financing trusts^(b)	205		—		—		209		209

PECO



	March 31, 2019
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year)^(a)	$	3,084	$	—	$	3,295	$	50	$	3,345
Long-term debt to financing trusts^(b)	184		—		—		196		196



	December 31, 2018
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year)^(a)	$	3,084	$	—	$	3,157	$	50	$	3,207
Long-term debt to financing trusts^(b)	184		—		—		191		191

BGE



	March 31, 2019
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	106	$	—	$	106	$	—	$	106
Long-term debt (including amounts due within one year)^(a)	2,876		—		3,051		—		3,051



	December 31, 2018
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	35	$	—	$	35	$	—	$	35
Long-term debt (including amounts due within one year)^(a)	2,876		—		2,950		—		2,950

PHI



	March 31, 2019
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	326	$	—	$	326	$	—	$	326
Long-term debt (including amounts due within one year)^(a)	6,244		—		5,608		695		6,303



	December 31, 2018
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	179	$	—	$	179	$	—	$	179
Long-term debt (including amounts due within one year)^(a)	6,259		—		5,436		665		6,101

Pepco



	March 31, 2019
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	105	$	—	$	105	$	—	$	105
Long-term debt (including amounts due within one year)^(a)	2,720		—		3,000		208		3,208



	December 31, 2018
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	40	$	—	$	40	$	—	$	40
Long-term debt (including amounts due within one year)^(a)	2,719		—		2,901		196		3,097

DPL



	March 31, 2019
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	5	$	—	$	5	$	—	$	5
Long-term debt (including amounts due within one year)^(a)	1,495		—		1,345		204		1,549



	December 31, 2018
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year)^(a)	$	1,494	$	—	$	1,303	$	193	$	1,496

ACE



	March 31, 2019
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	216	$	—	$	216	$	—	$	216
Long-term debt (including amounts due within one year)^(a)	1,184		—		1,004		283		1,287



	December 31, 2018
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	139	$	—	$	139	$	—	$	139
Long-term debt (including amounts due within one year)^(a)	1,188		—		987		275		1,262

_________

(a)

Includes unamortized debt issuance costs which are not fair valued of $216 million, $49 million, $67 million, $22 million, $18 million, $14 million, $33 million, $12 million and $6 million for Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, as of March 31, 2019. Includes unamortized debt issuance costs which are not fair valued of $216 million, $51 million, $63 million, $23 million, $18 million, $14 million, $34 million, $12 million and $7 million for Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, as of December 31, 2018.


(b)	Includes unamortized debt issuance costs which are not fair valued of $1 million and $1 million for Exelon and ComEd, respectively, as of March 31, 2019. Includes unamortized debt issuance costs which are not fair valued of less than $1 million and $1 million for Exelon and ComEd, respectively, as of December 31, 2018.

Recurring Fair Value Measurements

Exelon records the fair value of assets and liabilities in accordance with the hierarchy established by the authoritative guidance for fair value measurements. 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.

Generation and Exelon

In accordance with the applicable guidance on fair value measurement, certain investments that are measured at fair value using the NAV per share as a practical expedient are no longer classified within the fair value hierarchy and are included under "Not subject to leveling" in the table below.

The following tables present assets and liabilities measured and recorded at fair value in Exelon's and Generation’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of March 31, 2019 and December 31, 2018:



	Generation														Exelon
As of March 31, 2019	Level 1			Level 2			Level 3			Not subject to leveling		Total			Level 1			Level 2			Level 3			Not subject to leveling		Total
Assets
Cash equivalents^(a)	$	370		$	—		$	—		$	—	$	370		$	817		$	—		$	—		$	—	$	817
NDT fund investments
Cash equivalents^(b)	369			74			—			—		443			369			74			—			—		443
Equities	3,060			1,753			1			1,545		6,359			3,060			1,753			1			1,545		6,359
Fixed income
Corporate debt	—			1,545			236			1		1,782			—			1,545			236			1		1,782
U.S. Treasury and agencies	2,033			112			—			—		2,145			2,033			112			—			—		2,145
Foreign governments	—			43			—			—		43			—			43			—			—		43
State and municipal debt	—			110			—			—		110			—			110			—			—		110
Other^(c)	—			26			—			935		961			—			26			—			935		961
Fixed income subtotal	2,033			1,836			236			936		5,041			2,033			1,836			236			936		5,041
Middle market lending	—			—			303			406		709			—			—			303			406		709
Private equity	—			—			—			352		352			—			—			—			352		352
Real estate	—			—			—			535		535			—			—			—			535		535
NDT fund investments subtotal^(d)	5,462			3,663			540			3,774		13,439			5,462			3,663			540			3,774		13,439
Rabbi trust investments
Cash equivalents	4			—			—			—		4			47			—			—			—		47
Mutual funds	25			—			—			—		25			74			—			—			—		74
Fixed income	—			—			—			—		—			—			14			—			—		14
Life insurance contracts	—			23			—			—		23			—			71			39			—		110
Rabbi trust investments subtotal^(e)	29			23			—			—		52			121			85			39			—		245
Commodity derivative assets
Economic hedges	273			2,164			1,442			—		3,879			273			2,164			1,442			—		3,879
Proprietary trading	—			74			104			—		178			—			74			104			—		178
Effect of netting and allocation of collateral^(f)(g)	(294		)	(1,836		)	(820		)	—		(2,950		)	(294		)	(1,836		)	(820		)	—		(2,950		)
Commodity derivative assets subtotal	(21		)	402			726			—		1,107			(21		)	402			726			—		1,107
Interest rate and foreign currency derivative assets
Economic hedges	—			4			—			—		4			—			4			—			—		4
Effect of netting and allocation of collateral	—			(5		)	—			—		(5		)	—			(5		)	—			—		(5		)
Interest rate and foreign currency derivative assets subtotal	—			(1		)	—			—		(1		)	—			(1		)	—			—		(1		)
Other investments	—			—			42			—		42			—			—			42			—		42
Total assets	5,840			4,087			1,308			3,774		15,009			6,379			4,149			1,347			3,774		15,649



	Generation														Exelon
As of March 31, 2019	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	(350		)	(2,339		)	(1,164		)	—		(3,853		)	(350		)	(2,339		)	(1,404		)	—		(4,093		)
Proprietary trading	—			(79		)	(40		)	—		(119		)	—			(79		)	(40		)	—		(119		)
Effect of netting and allocation of collateral^(f)(g)	346			2,119			977			—		3,442			346			2,119			977			—		3,442
	(4		)	(299		)	(227		)	—		(530		)	(4		)	(299		)	(467		)	—		(770		)
Interest rate and foreign currency derivative liabilities
Derivatives designated as hedging instruments	—			—			—			—		—			—			(2		)	—			—		(2		)
Economic hedges	—			(12		)	—			—		(12		)	—			(12		)	—			—		(12		)
Effect of netting and allocation of collateral	—			5			—			—		5			—			5			—			—		5
Interest rate and foreign currency derivative liabilities subtotal	—			(7		)	—			—		(7		)	—			(9		)	—			—		(9		)
Deferred compensation obligation	—			(36		)	—			—		(36		)	—			(140		)	—			—		(140		)
Total liabilities	(4		)	(342		)	(227		)	—		(573		)	(4		)	(448		)	(467		)	—		(919		)
Total net assets	$	5,836		$	3,745		$	1,081		$	3,774	$	14,436		$	6,375		$	3,701		$	880		$	3,774	$	14,730



	Generation														Exelon
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)	$	581		$	—		$	—		$	—	$	581		$	1,243		$	—		$	—		$	—	$	1,243
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	5			—			—			—		5			48			—			—			—		48
Mutual funds	24			—			—			—		24			72			—			—			—		72
Fixed income	—			—			—			—		—			—			15			—			—		15
Life insurance contracts	—			22			—			—		22			—			70			38			—		108
Rabbi trust investments subtotal^(e)	29			22			—			—		51			120			85			38			—		243
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^(f)(g)	(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
Interest rate and foreign currency derivative assets
Economic hedges	—			13			—			—		13			—			13			—			—		13
Effect of netting and allocation of collateral	—			(3		)	—			—		(3		)	—			(3		)	—			—		(3		)
Interest rate and foreign currency derivative assets subtotal	—			10			—			—		10			—			10			—			—		10
Other investments	—			—			42			—		42			—			—			42			—		42
Total assets	5,820			4,102			1,400			3,433		14,755			6,573			4,165			1,438			3,433		15,609



	Generation														Exelon
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		)	(1,027		)	—		(4,632		)	(642		)	(2,963		)	(1,276		)	—		(4,881		)
Proprietary trading	—			(73		)	(21		)	—		(94		)	—			(73		)	(21		)	—		(94		)
Effect of netting and allocation of collateral^(f)(g)	639			2,581			808			—		4,028			639			2,581			808			—		4,028
Commodity derivative liabilities subtotal	(3		)	(455		)	(240		)	—		(698		)	(3		)	(455		)	(489		)	—		(947		)
Interest rate and foreign currency derivative liabilities
Derivatives designated as hedging instruments	—			—			—			—		—			—			(4		)	—			—		(4		)
Economic hedges	—			(6		)	—			—		(6		)	—			(6		)	—			—		(6		)
Effect of netting and allocation of collateral	—			3			—			—		3			—			3			—			—		3
Interest rate and foreign currency derivative liabilities subtotal	—			(3		)	—			—		(3		)	—			(7		)	—			—		(7		)
Deferred compensation obligation	—			(35		)	—			—		(35		)	—			(137		)	—			—		(137		)
Total liabilities	(3		)	(493		)	(240		)	—		(736		)	(3		)	(599		)	(489		)	—		(1,091		)
Total net assets	$	5,817		$	3,609		$	1,160		$	3,433	$	14,019		$	6,570		$	3,566		$	949		$	3,433	$	14,518

_________

(a)

Generation excludes cash of $270 million and $283 million at March 31, 2019 and December 31, 2018 and restricted cash of $36 million and $39 million at March 31, 2019 and December 31, 2018. Exelon excludes cash of $426 million and $458 million at March 31, 2019 and December 31, 2018 and restricted cash of $71 million and $80 million at March 31, 2019 and December 31, 2018 and includes long-term restricted cash of $211 million and $185 million at March 31, 2019 and December 31, 2018, which is reported in Other deferred debits in the Consolidated Balance Sheets.


(b)	Includes $43 million and $50 million of cash received from outstanding repurchase agreements at March 31, 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 derivative instruments of $7 million and $44 million, which have a total notional amount of $1,223 million and $1,432 million at March 31, 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 $94 million and $130 million at March 31, 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)	The amount of unrealized gains/(losses) at Generation totaled less than $1 million for the three months ended March 31, 2019 and March 31, 2018, respectively. The amount of unrealized gains/(losses) at Exelon totaled $1 million for the three months ended March 31, 2019 and March 31, 2018, respectively.

(f)

Collateral posted/(received) from counterparties totaled $52 million, $283 million and $157 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of March 31, 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.


(g)	Of the collateral posted/(received), $(33) million and $(94) million represents variation margin on the exchanges as of March 31, 2019 and December 31, 2018, respectively.

Exelon and Generation hold investments without readily determinable fair values with carrying amounts of $71 million as of March 31, 2019. Changes were immaterial in fair value, cumulative adjustments and impairments for the three months ended March 31, 2019.

ComEd, PECO and BGE

The following tables present assets and liabilities measured and recorded at fair value in ComEd's, PECO's and BGE's Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of March 31, 2019 and December 31, 2018:



	ComEd											PECO										BGE
As of March 31, 2019	Level 1		Level 2			Level 3			Total			Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3		Total
Assets
Cash equivalents^(a)	$	194	$	—		$	—		$	194		$	16	$	—		$	—	$	16		$	3	$	—		$	—	$	3
Rabbi trust investments
Mutual funds	—		—			—			—			7		—			—		7			6		—			—		6
Life insurance contracts	—		—			—			—			—		10			—		10			—		—			—		—
Rabbi trust investments subtotal^(b)	—		—			—			—			7		10			—		17			6		—			—		6
Total assets	194		—			—			194			23		10			—		33			9		—			—		9
Liabilities
Deferred compensation obligation	—		(7		)	—			(7		)	—		(10		)	—		(10		)	—		(5		)	—		(5		)
Mark-to-market derivative liabilities^(c)	—		—			(240		)	(240		)	—		—			—		—			—		—			—		—
Total liabilities	—		(7		)	(240		)	(247		)	—		(10		)	—		(10		)	—		(5		)	—		(5		)
Total net assets (liabilities)	$	194	$	(7	)	$	(240	)	$	(53	)	$	23	$	—		$	—	$	23		$	9	$	(5	)	$	—	$	4



	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^(b)	—		—			—			—			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^(c)	—		—			(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 $69 million and $93 million at March 31, 2019 and December 31, 2018 and restricted cash of $15 million and $28 million at March 31, 2019 and December 31, 2018 and includes long-term restricted cash of $193 million and $166 million at March 31, 2019 and December 31, 2018, which is reported in Other deferred debits in the Consolidated Balance Sheets. PECO excludes cash of $31 million and $24 million at March 31, 2019 and December 31, 2018. BGE excludes cash of $12 million and $7 million at March 31, 2019 and December 31, 2018 and restricted cash of $1 million and $2 million at March 31, 2019 and December 31, 2018.


(b)	The amount of unrealized gains/(losses) at ComEd, PECO and BGE totaled less than $1 million for the three months ended March 31, 2019 and March 31, 2018.


(c)	The Level 3 balance consists of the current and noncurrent liability of $27 million and $213 million, respectively, at March 31, 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

The following tables present assets and liabilities measured and recorded at fair value in PHI's, Pepco's, DPL's and ACE's Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of March 31, 2019 and December 31, 2018:




	As of March 31, 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)	$	63	$	—		$	—	$	63		$	147	$	—		$	—	$	147
Rabbi trust investments
Cash equivalents	42		—			—		42			42		—			—		42
Mutual funds	14		—			—		14			13		—			—		13
Fixed income	—		14			—		14			—		15			—		15
Life insurance contracts	—		22			39		61			—		22			38		60
Rabbi trust investments subtotal^(b)	56		36			39		131			55		37			38		130
Total assets	119		36			39		194			202		37			38		277
Liabilities
Deferred compensation obligation	—		(20		)	—		(20		)	—		(21		)	—		(21		)
Total liabilities	—		(20		)	—		(20		)	—		(21		)	—		(21		)
Total net assets	$	119	$	16		$	39	$	174		$	202	$	16		$	38	$	256



	Pepco										DPL										ACE
As of March 31, 2019	Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3		Total			Level 1		Level 2		Level 3		Total
Assets
Cash equivalents^(a)	$	35	$	—		$	—	$	35		$	2	$	—		$	—	$	2		$	21	$	—	$	—	$	21
Rabbi trust investments
Cash equivalents	42		—			—		42			—		—			—		—			—		—		—		—
Fixed income	—		4			—		4			—		—			—		—			—		—		—		—
Life insurance contracts	—		22			38		60			—		—			—		—			—		—		—		—
Rabbi trust investments subtotal^(b)	42		26			38		106			—		—			—		—			—		—		—		—
Total assets	77		26			38		141			2		—			—		2			21		—		—		21
Liabilities
Deferred compensation obligation	—		(3		)	—		(3		)	—		(1		)	—		(1		)	—		—		—		—
Total liabilities	—		(3		)	—		(3		)	—		(1		)	—		(1		)	—		—		—		—
Total net assets (liabilities)	$	77	$	23		$	38	$	138		$	2	$	(1	)	$	—	$	1		$	21	$	—	$	—	$	21



	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^(b)	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 $29 million and $39 million at March 31, 2019 and December 31, 2018, respectively, and includes long-term restricted cash of $19 million at both March 31, 2019 and December 31, 2018, which is reported in Other deferred debits in the Consolidated Balance Sheets. Pepco excludes cash of $11 million and $15 million at March 31, 2019 and December 31, 2018, respectively. DPL excludes cash of $6 million and $8 million at March 31, 2019 and December 31, 2018, respectively. ACE excludes cash of $7 million at both March 31, 2019 and December 31, 2018, and includes long-term restricted cash of $19 million at both March 31, 2019 and December 31, 2018, which is reported in Other deferred debits in the Consolidated Balance Sheets.


(b)	The amount of unrealized gains/(losses) at PHI totaled less than $1 million for both the three months ended March 31, 2019 and 2018. The amount of unrealized gains/(losses) at Pepco totaled less than $1 million for both the three months ended March 31, 2019 and 2018.

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 months ended March 31, 2019 and 2018:



	Generation												ComEd				PHI					Exelon
Three Months Ended March 31, 2019	NDT Fund Investments			Mark-to-Market Derivatives				Other Investments		Total Generation			Mark-to-Market Derivatives				Life Insurance Contracts^(c)		Eliminated in Consolidation			Total
Balance as of December 31, 2018	$	543		$	575			$	42	$	1,160		$	(249	)		$	38	$	—		$	949
Total realized / unrealized gains (losses)
Included in net income	2			(231		)	^(a)	—		(229		)	—				1		—			(228		)
Included in noncurrent payables to affiliates	11			—				—		11			—				—		(11		)	—
Included in regulatory assets/liabilities	—			—				—		—			9			^(b)	—		11			20
Change in collateral	—			81				—		81			—				—		—			81
Purchases, sales, issuances and settlements
Purchases	1			57				—		58			—				—		—			58
Sales	—			—				—		—			—				—		—			—
Settlements	(17		)	—				—		(17		)	—				—		—			(17		)
Transfers into Level 3	—			—			^(d)	—		—			—				—		—			—
Transfers out of Level 3	—			17			^(d)	—		17			—				—		—			17
Balance at March 31, 2019	$	540		$	499			$	42	$	1,081		$	(240	)		$	39	$	—		$	880
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of March 31, 2019	$	2		$	(151	)		$	—	$	(149	)	$	—			$	1	$	—		$	(148	)



	Generation													ComEd				PHI					Exelon
Three Months Ended March 31, 2018	NDT Fund Investments			Mark-to-Market Derivatives				Other Investments			Total Generation			Mark-to-Market Derivatives				Life Insurance Contracts^(c)		Eliminated in Consolidation			Total
Balance as of December 31, 2017	$	648		$	552			$	37		$	1,237		$	(256	)		$	22	$	—		$	1,003
Total realized / unrealized gains (losses)
Included in net income	—			184			^(a)	1			185			—				1		—			186
Included in noncurrent payables to affiliates	7			—				—			7			—				—		(7		)	—
Included in regulatory assets	—			—				—			—			(11		)	^(b)	—		7			(4		)
Change in collateral	—			105				—			105			—				—		—			105
Purchases, sales, issuances and settlements
Purchases	2			88				—			90			—				—		—			90
Sales	—			(3		)		—			(3		)	—				—		—			(3		)
Issuances	—			—				—			—			—				—		—			—
Settlements	(48		)	—				—			(48		)	—				—		—			(48		)
Transfers into Level 3	—			(8		)	^(d)	—			(8		)	—				—		—			(8		)
Transfers out of Level 3	—			—			^(d)	(2		)	(2		)	—				—		—			(2		)
Balance as of March 31, 2018	$	609		$	918			$	36		$	1,563		$	(267	)		$	23	$	—		$	1,319
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of March 31, 2018	$	—		$	256			$	1		$	257		$	—			$	1	$	—		$	258

__________


(a)	Includes a reduction for the reclassification of $80 million and $72 million of realized gains due to the settlement of derivative contracts for the three months ended March 31, 2019 and 2018, respectively.

(b)

Includes $14 million of decreases in fair value and an increase for realized losses due to settlements of $5 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended March 31, 2019. Includes $17 million of increases in fair value and an increase for realized losses due to settlements of $6 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended March 31, 2018.


(c)	The amounts represented are life insurance contracts at Pepco.


(d)	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 months ended March 31, 2019 and 2018:



	Generation								PHI		Exelon
	Operating Revenues			Purchased Power and Fuel			Other, net		Operating and Maintenance		Operating Revenues			Purchased Power and Fuel			Operating and Maintenance		Other, net
Total gains (losses) included in net income for the three months ended March 31, 2019	$	(128	)	$	(103	)	$	2	$	1	$	(128	)	$	(103	)	$	1	$	2
Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended March 31, 2019	(91		)	(60		)	2		1		(91		)	(60		)	1		2



	Generation							PHI		Exelon
	Operating Revenues		Purchased Power and Fuel			Other, net		Operating and Maintenance		Operating Revenues		Purchased Power and Fuel			Operating and Maintenance		Other, net
Total gains (losses) included in net income for the three months ended March 31, 2018	$	335	$	(151	)	$	1	$	1	$	335	$	(151	)	$	1	$	1
Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended March 31, 2018	309		(53		)	1		1		309		(53		)	1		1

Valuation Techniques Used to Determine Fair Value

The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the tables above.

Cash Equivalents (All Registrants). The Registrants’ cash equivalents include investments with original maturities of three months or less when purchased. The cash equivalents shown in the fair value tables are comprised of investments in mutual and money market funds. The fair values of the shares of these funds are based on observable market prices and, therefore, have been categorized in Level 1 in the fair value hierarchy.

NDT Fund Investments (Exelon and Generation). The trust fund investments have been established to satisfy Generation’s and CENG's nuclear decommissioning obligations as required by the NRC. The NDT funds hold debt and equity securities directly and indirectly through commingled funds and mutual funds, which are included in Equities and Fixed Income. Generation’s and CENG's NDT fund investments policies outline investment guidelines for the trusts and limit the trust funds’ exposures to investments in highly illiquid markets and other alternative investments. Investments with maturities of three months or less when purchased, including certain short-term fixed income securities are considered cash equivalents and included in the recurring fair value measurements hierarchy as Level 1 or Level 2.

With respect to individually held equity securities, the trustees obtain prices from pricing services, whose prices are generally obtained from direct feeds from market exchanges, which Generation is able to independently corroborate. The fair values of equity securities held directly by the trust funds which are based on quoted prices in active markets are categorized in Level 1. Certain equity securities have been categorized as Level 2 because they are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities. Equity securities held individually are primarily traded on the New York Stock Exchange and NASDAQ-Global Select Market, which contain only actively traded securities due to the volume trading requirements imposed by these exchanges.

For fixed income securities, multiple prices from pricing services are obtained whenever possible, which enables cross-provider validations in addition to checks for unusual daily movements. A primary price source is identified based on asset type, class or issue for each security. With respect to individually held fixed income securities, the trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the portfolio managers challenge an assigned price and the trustees determine that another price source is considered to be preferable. Generation has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, Generation selectively corroborates the fair values of securities by comparison to other market-based price sources. U.S. Treasury securities are categorized as Level 1 because they trade in a highly liquid and transparent market. The fair values of fixed income securities, excluding U.S. Treasury securities, are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities, adjusted for observable differences and are categorized in Level 2. The fair values of private placement fixed income securities, which are included in Corporate debt, are determined using a third-party valuation that contains significant unobservable inputs and are categorized in Level 3.

Equity and fixed income commingled funds and mutual funds are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives such as holding short-term fixed income securities or tracking the performance of certain equity indices by purchasing equity securities to replicate the capitalization and characteristics of the indices. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For commingled funds and mutual funds, which are not publicly quoted, the funds are valued using NAV as a practical expedient for fair value, which is primarily derived from the quoted prices in active markets on the underlying securities, and are not classified within the fair value hierarchy. These investments typically can be redeemed monthly with 30 or less days of notice and without further restrictions.

Derivative instruments consisting primarily of futures and interest rate swaps to manage risk are recorded at fair value. Over the counter derivatives are valued daily based on quoted prices in active markets and trade in open markets and have been categorized as Level 1. Derivative instruments other than over the counter derivatives are valued based on external price data of comparable securities and have been categorized as Level 2.

Middle market lending are investments in loans or managed funds which lend to private companies. Generation elected the fair value option for its investments in certain limited partnerships that invest in middle market lending managed funds. The fair value of these loans is determined using a combination of valuation models including cost models, market models and income models. Investments in loans are categorized as Level 3 because the fair value of these securities is based largely on inputs that are unobservable and utilize complex valuation models. Managed funds are valued using NAV or its equivalent as a practical expedient, and therefore, are not classified within the fair value hierarchy. Investments in middle market lending 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. The fair value of private equity and real estate investments is determined using NAV or its equivalent as a practical expedient, and therefore, are not classified within the fair value hierarchy. These investments typically cannot be redeemed and are generally liquidated over a period of 8 to 10 years from the initial investment date. 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.

As of March 31, 2019, Exelon and Generation have outstanding commitments to invest in fixed income, middle market lending, private equity and real estate investments of approximately $127 million, $179 million, $301 million, and $268 million, respectively. These commitments will be funded by Generation’s existing NDT funds.

Concentrations of Credit Risk. Generation evaluated its NDT portfolios for the existence of significant concentrations of credit risk as of March 31, 2019. Types of concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, and individual fund. As of March 31, 2019, there were no significant concentrations (generally defined as greater than 10 percent) of risk in Generation's NDT assets.

See Note 13 — Nuclear Decommissioning for additional information on the NDT fund investments.

Rabbi Trust Investments (Exelon, Generation, PECO, BGE, PHI, and Pepco). The Rabbi trusts were established to hold assets related to deferred compensation plans existing for certain active and retired members of Exelon’s executive management and directors. The Rabbi trusts assets are included in investments in the Registrants’ Consolidated Balance Sheets and consist primarily of money market funds, mutual funds, fixed income securities and life insurance policies. The mutual funds are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives, which are consistent with Exelon’s overall investment strategy. Money market funds and mutual funds are publicly quoted and have been categorized as Level 1 given the clear observability of the prices. The fair values of fixed income securities are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities, adjusted for observable differences and are categorized in Level 2. The life insurance policies are valued using the cash surrender value of the policies, net of loans against those policies, which is provided by a third-party. Certain life insurance policies, which consist primarily of mutual funds that are priced based on observable market data, have been categorized as Level 2 because the life insurance policies can be liquidated at the reporting date for the value of the underlying assets. Life insurance policies that are valued using unobservable inputs have been categorized as Level 3.

Mark-to-Market Derivatives (Exelon, Generation, ComEd, PHI and DPL). Derivative contracts are traded in both exchange-based and non-exchange-based markets. Exchange-based derivatives that are valued using unadjusted quoted prices in active markets are categorized in Level 1 in the fair value hierarchy. Certain derivatives’ pricing is verified using indicative price quotations available through brokers or over-the-counter, on-line exchanges and are categorized in Level 2. These price quotations reflect the average of the bid-ask, mid-point prices and are obtained from sources that the Registrants believe provide the most liquid market for the commodity. The price quotations are reviewed and corroborated to ensure the prices are observable and representative of an orderly transaction between market participants. This includes consideration of actual transaction volumes, market delivery points, bid-ask spreads and contract duration. The remainder of derivative contracts are valued using the Black model, an industry standard option valuation model. The Black model takes into account inputs such as contract terms, including maturity, and market parameters, including assumptions of the future prices of energy, interest rates, volatility, credit worthiness and credit spread. For derivatives that trade in liquid markets, such as generic forwards, swaps and options, model inputs are generally observable. Such instruments are categorized in Level 2. The Registrants’ derivatives are predominantly at liquid trading points. For derivatives that trade in less liquid markets with limited pricing information model inputs generally would include both observable and unobservable inputs. These valuations may include an estimated basis adjustment from an illiquid trading point to a liquid trading point for which active price quotations are available. Such instruments are categorized in Level 3.

Exelon may utilize fixed-to-floating interest rate swaps as a means to achieve its targeted level of variable-rate debt as a percent of total debt. In addition, the Registrants may utilize interest rate derivatives to lock in interest rate levels in anticipation of future financings. Exelon determines the current fair value by calculating the net present value of expected payments and receipts under the swap agreement, based on and discounted by the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk and other market parameters. As these inputs are based on observable data and valuations of similar instruments, the interest rate swaps are categorized in Level 2 in the fair value hierarchy. See Note 10 — Derivative Financial Instruments for additional information on mark-to-market derivatives.

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

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

Additional Information Regarding Level 3 Fair Value Measurements (Exelon, Generation, ComEd, PHI, Pepco, DPL and ACE)

NDT Fund Investments (Exelon and Generation). For middle market lending and certain corporate debt securities investments, the fair value is determined using a combination of valuation models including cost models, market models and income models. The valuation estimates are based on discounting the forecasted cash flows, market-based comparable data, credit and liquidity factors, as well as other factors that may impact value. Significant judgment is required in the application of discounts or premiums applied for factors such as size, marketability, credit risk and relative performance.

Because Generation relies on third-party fund managers to develop the quantitative unobservable inputs without adjustment for the valuations of its Level 3 investments, quantitative information about significant unobservable inputs used in valuing these investments is not reasonably available to Generation. This includes information regarding the sensitivity of the fair values to changes in the unobservable inputs. Therefore, Generation has not disclosed such inputs.

Rabbi Trust Investments - Life insurance contracts (Exelon, PHI, and Pepco). For life insurance policies categorized as Level 3, the fair value is determined based on the cash surrender value of the policy, which contains unobservable inputs and assumptions. Because Exelon relies on its third-party insurance provider to develop the inputs without adjustment for the valuations of its Level 3 investments, quantitative information about significant unobservable inputs used in valuing these investments is not reasonably available to Exelon. Therefore, Exelon has not disclosed such inputs.

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

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

For commodity derivatives, the primary input to the valuation models is the forward commodity price curve for each instrument. Forward commodity price curves are derived by risk management for liquid locations and by the traders and portfolio managers for illiquid locations. All locations are reviewed and verified by risk management considering published exchange transaction prices, executed bilateral transactions, broker quotes, and other observable or public data sources. The relevant forward commodity curve used to value each of the derivatives depends on a number of factors, including commodity type, delivery location, and delivery period. Price volatility varies by commodity and location. When appropriate, Generation discounts future cash flows using risk free interest rates with adjustments to reflect the credit quality of each counterparty for assets and Generation’s own credit quality for liabilities. The level of observability of a forward commodity price varies generally due to the delivery location and delivery period. Certain delivery locations including PJM West Hub (for power) and Henry Hub (for natural gas) are more liquid and prices are observable for up to three years in the future. The observability period of volatility is generally shorter than the underlying power curve used in option valuations. The forward curve for a less liquid location is estimated by using the forward curve from the liquid location and applying a spread to represent the cost to transport the commodity to the delivery location. This spread does not typically represent a majority of the instrument’s market price. As a result, the change in fair value is closely tied to liquid market movements and not a change in the applied spread. The change in fair value associated with a change in the spread is generally immaterial. An average spread calculated across all Level 3 power and gas delivery locations is approximately $2.52 and $0.46 for power and natural gas, respectively. Many of the commodity derivatives are short-term in nature and thus a majority of the fair value may be based on observable inputs even though the contract as a whole must be classified as Level 3.

On December 17, 2010, ComEd entered into several 20-year floating to fixed energy swap contracts with unaffiliated suppliers for the procurement of long-term renewable energy and associated RECs. See Note 10 —Derivative Financial Instruments for additional information. The fair value of these swaps has been designated as a Level 3 valuation due to the long tenure of the positions and internal modeling assumptions. The modeling assumptions include using natural gas heat rates to project long term forward power curves adjusted by a renewable factor that incorporates time of day and seasonality factors to reflect accurate renewable energy pricing. In addition, marketability reserves are applied to the positions based on the tenor and supplier risk.

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



Type of trade	Fair Value at March 31, 2019			Valuation Technique	Unobservable Input	Range
Mark-to-market derivatives — Economic Hedges (Exelon and Generation)^(a)(b)	$	278		Discounted Cash Flow	Forward power price	$9	-	$164
					Forward gas price	$1.76	-	$11.63
				Option Model	Volatility percentage	10%	-	334%

Mark-to-market derivatives — Proprietary trading (Exelon and Generation)^(a)(b)	$	64		Discounted Cash Flow	Forward power price	$9	-	$162

Mark-to-market derivatives (Exelon and ComEd)	$	(240	)	Discounted Cash Flow	Forward heat rate^(c)	10x	-	11x
					Marketability reserve	4%	-	8%
					Renewable factor	85%	-	120%



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

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

Mark-to-market derivatives (Exelon and ComEd)	$	(249	)	Discounted Cash Flow	Forward heat rate^(c)	10x	-	11x
					Marketability reserve	4%	-	8%
					Renewable factor	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 $157 million and $76 million as of March 31, 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)

3 Months Ended

Mar. 31, 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.

Commodity Price Risk (All Registrants)

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. 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.

Derivative 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 normal purchase normal sale (NPNS), cash flow hedges and fair value hedges. For Generation, all derivative economic hedges related to commodities are recorded at fair value through earnings for the consolidated company, referred to as economic hedges in the following tables. 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.

Fair value authoritative guidance and disclosures 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 Sheet. 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. Generation’s use of cash collateral is generally unrestricted, unless Generation is downgraded below investment grade (i.e., to BB+ or Ba1). In the table below, 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 column. As of March 31, 2019, $6 million of cash collateral held, and as of December 31, 2018, $2 million of cash collateral posted and an additional $12 million of cash collateral posted with ComEd, was not offset against derivative positions because such collateral was not associated with any energy-related derivatives, were associated with accrual positions, or had no positions to offset as of the balance sheet date. Excluded from the tables below are economic hedges that qualify for the NPNS scope exception and other non-derivative contracts that are accounted for under the accrual method of accounting.

ComEd’s use of cash collateral is generally unrestricted unless ComEd is downgraded below investment grade (i.e., to BB+ or Ba1).

Cash collateral held by PECO and BGE must be deposited in an unaffiliated major U.S. commercial bank or foreign bank with a U.S. branch office that meet certain qualifications.

The following table provides a summary of the derivative fair value balances recorded by the Registrants as of March 31, 2019:



	Generation												ComEd			Exelon
Derivatives	Economic Hedges			Proprietary Trading			Collateral and Netting^(a)(d)			Subtotal^(b)			Economic Hedges^(c)			Total Derivatives
Mark-to-market derivative assets (current assets)	$	2,691		$	118		$	(2,156	)	$	653		$	—		$	653
Mark-to-market derivative assets (noncurrent assets)	1,188			60			(794		)	454			—			454
Total mark-to-market derivative assets	3,879			178			(2,950		)	1,107			—			1,107
Mark-to-market derivative liabilities (current liabilities)	(2,711		)	(89		)	2,485			(315		)	(27		)	(342		)
Mark-to-market derivative liabilities (noncurrent liabilities)	(1,142		)	(30		)	957			(215		)	(213		)	(428		)
Total mark-to-market derivative liabilities	(3,853		)	(119		)	3,442			(530		)	(240		)	(770		)
Total mark-to-market derivative net assets (liabilities)	$	26		$	59		$	492		$	577		$	(240	)	$	337

_________

(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 are not reflected in the table above.


(b)	Current and noncurrent assets are shown net of collateral of $152 million and $63 million, respectively, and current and noncurrent liabilities are shown net of collateral of $177 million and $100 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $492 million at March 31, 2019.


(c)	Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.


(d)	Of the collateral posted/(received), $(33) million represents variation margin on the exchanges.

The following table provides a summary of the derivative fair value balances recorded by the Registrants as of December 31, 2018:



	Generation												ComEd			Exelon
Description	Economic Hedges			Proprietary Trading			Collateral and Netting^(a)(d)			Subtotal^(b)			Economic Hedges^(c)			Total Derivatives
Mark-to-market derivative assets (current assets)	$	3,505		$	105		$	(2,809	)	$	801		$	—		$	801
Mark-to-market derivative assets (noncurrent assets)	1,266			41			(862		)	445			—			445
Total mark-to-market derivative assets	4,771			146			(3,671		)	1,246			—			1,246
Mark-to-market derivative liabilities (current liabilities)	(3,429		)	(74		)	3,056			(447		)	(26		)	(473		)
Mark-to-market derivative liabilities (noncurrent liabilities)	(1,203		)	(20		)	972			(251		)	(223		)	(474		)
Total mark-to-market derivative liabilities	(4,632		)	(94		)	4,028			(698		)	(249		)	(947		)
Total mark-to-market derivative net assets (liabilities)	$	139		$	52		$	357		$	548		$	(249	)	$	299

_________

(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, and letters of credit and other forms of non-cash collateral. These are not reflected in the table above.


(b)	Current and noncurrent assets are shown net of collateral of $121 million and $51 million, respectively, and current and noncurrent liabilities are shown net of collateral of $125 million and $60 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $357 million at December 31, 2018.


(c)	Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.


(d)	Of the collateral posted/(received), $(94) million represents variation margin on the exchanges.

Economic Hedges (Commodity Price Risk)

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. For the three months ended March 31, 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" in the Consolidated Statements of Cash Flows.



	Three Months Ended March 31,
	2019			2018
Income Statement Location	Gain (Loss)
Operating revenues	$	(50	)	$	(100	)
Purchased power and fuel	30			(167		)
Total Exelon and Generation	$	(20	)	$	(267	)

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 March 31, 2019, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York and ERCOT reportable segments is 90%-93%, 64%-67% and 38%-41% for 2019, 2020 and 2021, respectively.

On December 17, 2010, ComEd executed several 20-year floating-to-fixed energy swap contracts with unaffiliated suppliers for the procurement of long-term renewable energy and associated RECs. Delivery under the contracts began in June 2012. These contracts are designed to lock in a portion of the long-term commodity price risk resulting from the renewable energy resource procurement requirements in the Illinois Settlement Legislation. ComEd has not elected hedge accounting for these derivative financial instruments. ComEd records the fair value of the swap contracts in its balance sheet. Because ComEd receives full cost recovery for energy procurement and related costs from retail customers, the change in fair value each period is recorded by ComEd as a regulatory asset or liability. See Note 4 — Regulatory Matters of the Exelon 2018 Form 10-K for additional information.

PECO’s natural gas procurement policy is designed to achieve a reasonable balance of long-term and short-term gas purchases under different pricing approaches to achieve system supply reliability at the least cost. PECO’s reliability strategy is two-fold. First, PECO must assure that there is sufficient transportation capacity to satisfy delivery requirements. Second, PECO must ensure that a firm source of supply exists to utilize the capacity resources. All of PECO’s natural gas supply and asset management agreements that are derivatives either qualify for the NPNS scope exception and have been designated as such or have no mark-to-market balances because the derivatives are index priced. Additionally, in accordance with the 2018 PAPUC PGC settlement and to reduce the exposure of PECO and its customers to natural gas price volatility, PECO has continued its program to purchase natural gas for both winter and summer supplies using a layered approach of locking-in prices ahead of each season with long-term gas purchase agreements (those with primary terms of at least twelve months). Under the terms of the 2018 and previous PGC settlements, PECO is required to lock in (i.e., economically hedge) the price of a minimum volume of its long-term gas commodity purchases. PECO’s gas-hedging program is designed to cover about 20% of planned natural gas purchases in support of projected firm sales. The hedging program for natural gas procurement has no direct impact on PECO’s results of operations and financial position as natural gas costs are fully recovered from customers under the PGC.

BGE has contracts to procure SOS electric supply that are executed through a competitive procurement process approved by the MDPSC. The SOS rates charged recover BGE's wholesale power supply costs and include an administrative fee. BGE’s commodity price risk related to electric supply procurement is limited. BGE locks in fixed prices for all of its SOS requirements through full requirements contracts. Certain of BGE’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other BGE full requirements contracts are not derivatives.

BGE provides natural gas to its customers under a MBR mechanism approved by the MDPSC. Under this mechanism, BGE’s actual cost of gas is compared to a market index (a measure of the market price of gas in a given period). The difference between BGE’s actual cost and the market index is shared equally between shareholders and customers. BGE must also secure fixed price contracts for at least 10%, but not more than 20%, of forecasted system supply requirements for flowing (i.e., non-storage) gas for the November through March period. These fixed-price contracts are not subject to sharing under the MBR mechanism. BGE also ensures it has sufficient pipeline transportation capacity to meet customer requirements. BGE’s natural gas supply and asset management agreements qualify for the NPNS scope exception and result in physical delivery.

Pepco has contracts to procure SOS electric supply that are executed through a competitive procurement process approved by the MDPSC and DCPSC. The SOS rates charged recover Pepco's wholesale power supply costs and include an administrative fee. The administrative fee includes an incremental cost component and a shareholder return component for residential and commercial rate classes. Pepco’s commodity price risk related to electric supply procurement is limited. Pepco locks in fixed prices for its SOS requirements through full requirements contracts. Certain of Pepco’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other Pepco full requirements contracts are not derivatives.

DPL has contracts to procure SOS electric supply that are executed through a competitive procurement process approved by the MDPSC and the DPSC. The SOS rates charged recover DPL's wholesale power supply costs. In Delaware, DPL is also entitled to recover a Reasonable Allowance for Retail Margin (RARM). The RARM includes a fixed annual margin of approximately $2.75 million, plus an incremental cost component and a cash working capital allowance. In Maryland, DPL charges an administrative fee intended to allow it to recover its administrative costs. DPL locks in fixed prices for its SOS requirements through full requirements contracts. DPL’s commodity price risk related to electric supply procurement is limited. Certain of DPL’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other DPL full requirements contracts are not derivatives.

DPL provides natural gas to its customers under an Annual GCR mechanism approved by the DPSC. Under this mechanism, DPL’s Annual GCR Filing establishes a future GCR for firm bundled sales customers by using a forecast of demand and commodity costs. The actual costs are trued up against forecasts on a monthly basis and any shortfall or excess is carried forward as a recovery balance in the next GCR filing. The demand portion of the GCR is based upon DPL’s firm transportation and storage contracts. DPL has firm deliverability of swing and seasonal storage, a liquefied natural gas facility and firm transportation capacity to meet customer demand and provide a reserve margin. The commodity portion of the GCR includes a commission approved hedging program which is intended to reduce gas commodity price volatility while limiting the firm natural gas customers’ exposure to adverse changes in the market price of natural gas. The hedge program requires that DPL hedge, on a non-discretionary basis, an amount equal to 50% of estimated purchase requirements for each month, including estimated monthly purchases for storage injections. The 50% hedge monthly target is achieved by hedging 1/12th of the 50% target each month beginning 12-months prior to the month in which the physical gas is to be purchased. Currently, DPL uses only exchange traded futures for its gas hedging program, which are considered derivatives, however, it retains the capability to employ other physical and financial hedges if needed. DPL has not elected hedge accounting for these derivative financial instruments. Because of the DPSC-approved fuel adjustment clause for DPL's derivatives, the change in fair value of the derivatives each period, in addition to all premiums paid and other transaction costs incurred as part of the gas hedging program, are fully recoverable and are recorded by DPL as regulatory assets or liabilities. DPL’s physical gas purchases are currently all daily, monthly or intra-month transactions. From time to time, DPL will enter into seasonal purchase or sale arrangements, however, there are none currently in the portfolio. Certain of DPL's full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other DPL full requirements contracts are not derivatives.

ACE has contracts to procure BGS electric supply that are executed through a competitive procurement process approved by the NJBPU. The BGS rates charged recover ACE's wholesale power supply costs. ACE does not make any profit or incur any loss on the supply component of the BGS it supplies to customers. ACE’s commodity price risk related to electric supply procurement is limited. ACE locks in fixed prices for all of its BGS requirements through full requirements contracts. Certain of ACE’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other ACE full requirements contracts are not derivatives.

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. Proprietary trading activities are subject to limits established by Exelon’s RMC. The proprietary trading portfolio is subject to a risk management policy that includes stringent risk management limits to manage exposure to market risk. Additionally, the Exelon risk management group and Exelon's RMC monitor the financial risks of the 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 revenue from energy marketing activities. 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. For the three months ended March 31, 2019 and 2018 Exelon and Generation recognized the following net pre-tax commodity mark-to-market gains (losses) which are also included in the "Net fair value changes related to derivatives" in the Consolidated Statements of Cash Flows. The Utility Registrants do not execute derivatives for proprietary trading purposes.



	Three Months Ended March 31,
	2019		2018
Income Statement Location	Gain (Loss)
Operating revenues	$	2	$	2

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 $1,419 million and $1,420 million at March 31, 2019 and December 31, 2018, respectively, for Exelon and $619 million and $620 million at March 31, 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 $209 million and $268 million at March 31, 2019 and December 31, 2018, respectively.

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

Credit Risk, Collateral and Contingent-Related Features (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. 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 March 31, 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 $36 million, $31 million, $27 million, $37 million, $5 million and $4 million as of March 31, 2019, respectively.



Rating as of March 31, 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	$	819	$	11	$	808	1	$	135
Non-investment grade	86		39		47
No external ratings
Internally rated — investment grade	162		—		162
Internally rated — non-investment grade	87		7		80
Total	$	1,154	$	57	$	1,097	1	$	135



Net Credit Exposure by Type of Counterparty	As of March 31, 2019
Financial institutions	$	13
Investor-owned utilities, marketers, power producers	762
Energy cooperatives and municipalities	287
Other	35
Total	$	1,097

_________


(a)	As of March 31, 2019, credit collateral held from counterparties where Generation had credit exposure included $37 million of cash and $19 million of letters of credit. The credit collateral does not include non-liquid collateral.

ComEd’s power procurement contracts provide suppliers with a certain amount of unsecured credit. The credit position is based on daily, updated forward market prices compared to the benchmark prices. The benchmark prices are the forward prices of energy projected through the contract term and are set at the point of supplier bid submittals. If the forward market price of energy exceeds the benchmark price on a given day, the suppliers are required to post collateral for the secured credit portion after adjusting for any unpaid deliveries and unsecured credit allowed under the contract. The unsecured credit used by the suppliers represents ComEd’s net credit exposure. As of March 31, 2019, ComEd’s net credit exposure to suppliers was $2 million.

ComEd is permitted to recover its costs of procuring energy through the Illinois Settlement Legislation. ComEd’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 4 — Regulatory Matters of the Exelon 2018 Form 10-K for additional information.

PECO’s unsecured credit used by the suppliers represents PECO’s net credit exposure. As of March 31, 2019, PECO had no material net credit exposure to its electric suppliers.

PECO’s natural gas procurement plan is reviewed and approved annually on a prospective basis by the PAPUC. PECO’s counterparty credit risk under its natural gas supply and asset management agreements is mitigated by its ability to recover its natural gas costs through the PGC, which allows PECO to adjust rates quarterly to reflect realized natural gas prices. As of March 31, 2019, PECO had no material credit exposure under its natural gas supply and asset management agreements with investment grade suppliers.

BGE is permitted to recover its costs of procuring energy through the MDPSC-approved procurement tariffs. BGE’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 4 — Regulatory Matters of the Exelon 2018 Form 10-K for additional information.

BGE’s full requirement wholesale electric power agreements that govern the terms of its electric supply procurement contracts, which define a supplier’s performance assurance requirements, allow a supplier, or its guarantor, to meet its credit requirements with a certain amount of unsecured credit. As of March 31, 2019, BGE's net credit exposure to suppliers was immaterial.

BGE’s regulated gas business is exposed to market-price risk. At March 31, 2019, BGE's credit exposure related to off-system sales, which is mitigated by parental guarantees, letters of credit or right to offset clauses within other contracts with those third-party suppliers, was immaterial.

Pepco’s, DPL's and ACE's power procurement contracts provide suppliers with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s lowest credit rating from the major credit rating agencies and the supplier’s tangible net worth. The credit position is based on the initial market price, which is the forward price of energy on the day a transaction is executed, compared to the current forward price curve for energy. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. The unsecured credit used by the suppliers represents Pepco’s, DPL's and ACE's net credit exposure. As of March 31, 2019, Pepco’s, DPL's and ACE's net credit exposures to suppliers were immaterial.

Pepco is permitted to recover its costs of procuring energy through the MDPSC-approved and DCPSC-approved procurement tariffs. DPL is permitted to recover its costs of procuring energy through the MDPSC-approved and DPSC-approved procurement tariffs. ACE is permitted to recover its costs of procuring energy through the NJBPU-approved procurement tariffs. Pepco’s, DPL's and ACE's counterparty credit risks are mitigated by their ability to recover realized energy costs through customer rates. See Note 2 — Regulatory Matters of the Exelon 2018 Form 10-K for additional information.

DPL’s natural gas procurement plan is reviewed and approved annually on a prospective basis by the DPSC. DPL’s counterparty credit risk under its natural gas supply and asset management agreements is mitigated by its ability to recover its natural gas costs through the GCR, which allows DPL to adjust rates annually to reflect realized natural gas prices. To the extent that the fair value of the transactions in a net loss position exceeds the unsecured credit threshold, then collateral is required to be posted in an amount equal to the amount by which the unsecured credit threshold is exceeded. Exchange-traded contracts are required to be fully collateralized without regard to the credit rating of the holder. As of March 31, 2019, DPL's credit exposure under its natural gas supply and asset management agreements with investment grade suppliers was immaterial.

Collateral (All Registrants)

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	March 31, 2019			December 31, 2018
Gross fair value of derivative contracts containing this feature^(a)	$	(1,667	)	$	(1,723	)
Offsetting fair value of in-the-money contracts under master netting arrangements^(b)	1,177			1,105
Net fair value of derivative contracts containing this feature^(c)	$	(490	)	$	(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.

Generation had cash collateral posted of $542 million and letters of credit posted of $289 million and cash collateral held of $56 million and letters of credit held of $26 million as of March 31, 2019 for external counterparties with derivative positions. Generation had cash collateral posted of $418 million and letters of credit posted of $367 million and cash collateral held of $47 million and letters of credit held of $44 million at December 31, 2018 for external counterparties with derivative positions. In the event of a credit downgrade below investment grade (i.e., to BB+ by S&P or Ba1 by Moody’s), Generation would have been required to post additional collateral of $1.9 billion and $2.1 billion as of March 31, 2019 and December 31, 2018, respectively. These amounts represent the potential additional collateral required after giving consideration to offsetting derivative and non-derivative positions under master netting agreements.

Exelon's interest rate swaps contain provisions that, in the event of a merger, if Exelon’s debt ratings were to materially weaken, it would be in violation of these provisions, resulting in the ability of the counterparty to terminate the agreement prior to maturity. Collateralization would not be required under any circumstance. Termination of the agreement could result in a settlement payment by Exelon or the counterparty on any interest rate swap in a net liability position. The settlement amount would be equal to the fair value of the swap on the termination date. As of March 31, 2019, Exelon's swaps were in a liability position that is not material.

See Note 24 — Segment Information of the Exelon 2018 Form 10-K for additional information regarding the letters of credit supporting the cash collateral.

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. Under the terms of ComEd’s standard block energy contracts, collateral postings are one-sided from suppliers, including Generation, should exposures between market prices and benchmark prices exceed established unsecured credit limits outlined in the contracts. As of March 31, 2019, ComEd held $11 million in collateral from suppliers in association with energy procurement contracts. Under the terms of ComEd's REC and ZEC contracts, collateral postings are required to cover a percentage of the REC and ZEC contract value. As of March 31, 2019, ComEd held $31 million in collateral from suppliers for REC and ZEC contract obligations. Under the terms of ComEd’s long-term renewable energy contracts, collateral postings are required from suppliers for both RECs and energy. The REC portion is a fixed value and the energy portion is one-sided from suppliers should the forward market prices exceed contract prices. As of March 31, 2019, ComEd held $19 million in collateral from suppliers for the long-term renewable energy contracts. If ComEd lost its investment grade credit rating as of March 31, 2019, it would have been required to post approximately $8 million of collateral to its counterparties. See Note 4 — Regulatory Matters of the Exelon 2018 Form 10-K for additional information.

PECO’s natural gas procurement contracts contain provisions that could require PECO to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon PECO’s credit rating from the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. As of March 31, 2019, PECO was not required to post collateral for any of these agreements. If PECO lost its investment grade credit rating as of March 31, 2019, PECO could have been required to post $34 million of collateral to its counterparties.

PECO’s supplier master agreements that govern the terms of its DSP Program contracts do not contain provisions that would require PECO to post collateral.

BGE’s natural gas procurement contracts contain provisions that could require BGE to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon BGE’s credit rating from the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. As of March 31, 2019, BGE was not required to post collateral for any of these agreements. If BGE lost its investment grade credit rating as of March 31, 2019, BGE could have been required to post $46 million of collateral to its counterparties.

DPL's natural gas procurement contracts contain provisions that could require DPL to post collateral. To the extent that the fair value of the natural gas derivative transaction in a net loss position exceeds the unsecured credit threshold, then collateral is required to be posted in an amount equal to the amount by which the unsecured credit threshold is exceeded. The DPL obligations are standalone, without the guaranty of PHI. If DPL lost its investment grade credit rating as of March 31, 2019, DPL could have been required to post an additional amount of $14 million of collateral to its counterparties.

BGE's, Pepco's, DPL's and ACE's full requirements wholesale power agreements that govern the terms of its electric supply procurement contracts do not contain provisions that would require BGE, Pepco, DPL or ACE to post collateral.

Debt and Credit Agreements (All Registrants)

3 Months Ended

Mar. 31, 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 March 31, 2019 and December 31, 2018. Generation and PECO had no commercial paper borrowings as of both March 31, 2019 and December 31, 2018.



	Outstanding Commercial Paper at				Average Interest Rate on Commercial Paper Borrowings as of
Commercial Paper Issuer	March 31, 2019		December 31, 2018		March 31, 2019		December 31, 2018
Exelon	$	629	$	89	2.63	%	2.15	%
ComEd	322		—		2.64	%	2.14	%
BGE	106		35		2.59	%	2.18	%
PHI	201		54		2.62	%	2.15	%
PEPCO	105		40		2.62	%	2.24	%
DPL	5		—		2.61	%	2.07	%
ACE	91		14		2.62	%	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 three months ended March 31, 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

Funding to install energy conservation measures for the Fort Meade 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.

Debt Covenants

As of March 31, 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 March 31, 2019, $502 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 Pacific Gas and Electric Company (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 as of March 31, 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 March 31, 2019, $834 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)

3 Months Ended

Mar. 31, 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 March 31, 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	3.9	3.1	8.2	1.0	6.3	4.7	2.1	6.5	6.7
Qualified NDT fund income	7.2	14.2	—	—	—	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(0.5)	(0.9)	(0.2)	—	(0.1)	(0.2)	(0.1)	(0.2)	(0.3)
Plant basis differences	(1.4)	—	(0.5)	(6.7)	(0.9)	(1.7)	(2.0)	(0.7)	(2.3)
Production tax credits and other credits	(0.8)	(1.5)	—	—	—	—	—	—	—
Noncontrolling interests	(0.6)	(1.1)	—	—	—	—	—	—	—
Excess deferred tax amortization	(4.7)	—	(8.5)	(2.5)	(7.9)	(19.4)	(17.9)	(15.6)	(23.9)
Other	0.1	(0.5)	0.3	0.2	—	(0.3)	0.4	0.7	(1.2)
Effective income tax rate	24.2%	34.3%	20.3%	13.0%	18.4%	4.1%	3.5%	11.7%	—%



	Three Months Ended March 31, 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	4.1	2.4	8.2	(3.9)	6.3	4.6	1.7	6.3	6.6
Qualified NDT fund income	(0.4)	(1.3)	—	—	—	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(1.3)	(4.3)	(0.2)	(0.1)	(0.1)	(0.2)	(0.1)	(0.2)	(0.3)
Plant basis differences	(2.7)	—	0.1	(14.2)	(0.7)	(2.6)	(3.4)	(1.3)	(2.6)
Production tax credits and other credits	(2.8)	(9.5)	(0.1)	—	—	—	—	—	—
Noncontrolling interests	(0.7)	(2.5)	—	—	—	—	—	—	—
Excess deferred tax amortization	(6.0)	—	(7.5)	(4.8)	(8.6)	(10.6)	(12.8)	(7.9)	(8.7)
Other	(2.8)	(1.3)	0.3	0.2	—	—	(0.3)	0.5	(3.5)
Effective income tax rate	8.4%	4.5%	21.8%	(1.8)%	17.9%	12.2%	6.1%	18.4%	12.5%

Accounting for Uncertainty in Income Taxes

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



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
March 31, 2019	$	448	$	411	$	—	$	—	$	—	$	45	$	—	$	—	$	14



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
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 March 31, 2019, Exelon, Generation, PHI and ACE have approximately $425 million, $411 million, $14 million and $14 million 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.

Nuclear Decommissioning (Exelon and Generation)

3 Months Ended

Mar. 31, 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 March 31, 2019:



Nuclear decommissioning ARO at December 31, 2018 ^(a)(b)	$	10,005
Net increase due to changes in, and timing of, estimated future cash flows	223
Accretion expense	120
Costs incurred related to decommissioning plants	(19		)
Nuclear decommissioning ARO at March 31, 2019 ^(a)(b)	$	10,329

_________


(a)	Includes $41 million and $22 million as the current portion of the ARO at March 31, 2019 and December 31, 2018, respectively, which is included in Other current liabilities in Exelon’s and Generation’s Consolidated Balance Sheets.


(b)	Includes $760 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 March 31, 2019 and December 31, 2018, respectively. See Note 3 — Mergers, Acquisitions and Dispositions for additional information.

During the three months ended March 31, 2019, Exelon's and Generation’s total nuclear ARO increased by approximately $324 million, primarily reflecting the impacts of ARO updates completed during first quarter 2019 and the accretion of the ARO liability due to the passage of time. 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 $13,345 million and $12,695 million at March 31, 2019 and December 31, 2018, respectively. The NDT funds include $881 million and $890 million at March 31, 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 announced pending sale of Oyster Creek. The NDT funds also include $163 million and $144 million for the current portion of the NDT funds at March 31, 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)

3 Months Ended

Mar. 31, 2019

Retirement Benefits [Abstract]

Retirement Benefits (Exelon, Generation, ComEd, PECO and BGE)

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 months ended March 31, 2019 and 2018.



	Pension Benefits Three Months Ended March 31,						Other Postretirement Benefits Three Months Ended March 31,
	2019			2018			2019			2018
Components of net periodic benefit cost:
Service cost	$	89		$	101		$	24		$	28
Interest cost	221			201			47			43
Expected return on assets	(307		)	(312		)	(38		)	(43		)
Amortization of:
Prior service cost (benefit)	—			—			(45		)	(46		)
Actuarial loss	104			157			11			16
Net periodic benefit cost	$	107		$	147		$	(1	)	$	(2	)

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 months ended March 31, 2019 and 2018, while the non-service cost components are included in Other, net and Regulatory assets for the three months ended March 31, 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 months ended March 31, 2019 and 2018.



	Three Months Ended March 31,
Pension and Other Postretirement Benefit Costs	2019		2018
Exelon	$	106	$	145
Generation	31		51
ComEd	24		45
PECO	2		5
BGE	16		15
PHI	23		15
Pepco	6		4
DPL	4		—
ACE	4		3

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 months ended March 31, 2019 and 2018, respectively.



	Three Months Ended March 31,
Savings Plan Matching Contributions	2019		2018
Exelon	$	31	$	32
Generation	13		15
ComEd	7		7
PECO	2		2
BGE	2		2
PHI	4		3
Pepco	1		1
DPL	1		1
ACE	1		—

Changes in Accumulated Other Comprehensive Income (Exelon and Generation)

3 Months Ended

Mar. 31, 2019

Changes in Accumulated Other Comprehensive Income [Abstract]

Comprehensive Income (Loss) 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 three months ended March 31, 2019 and 2018:



Three Months Ended March 31, 2019	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	$	(2	)	$	—	$	(2,960	)	$	(33	)	$	—		$	(2,995	)
OCI before reclassifications	—			—		(38		)	2			(1		)	(37		)
Amounts reclassified from AOCI^(b)	—			—		20			—			—			20
Net current-period OCI	—			—		(18		)	2			(1		)	(17		)
Ending balance	$	(2	)	$	—	$	(2,978	)	$	(31	)	$	(1	)	$	(3,012	)
Generation^(a)
Beginning balance	$	(4	)	$	—	$	—		$	(33	)	$	(1	)	$	(38	)
OCI before reclassifications	—			—		—			2			(1		)	1
Amounts reclassified from AOCI	1			—		—			—			—			1
Net current-period OCI	1			—		—			2			(1		)	2
Ending balance	$	(3	)	$	—	$	—		$	(31	)	$	(2	)	$	(36	)



Three Months Ended March 31, 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	8			—			18				1			—			27
Amounts reclassified from AOCI^(b)	—			—			44				—			—			44
Net current-period OCI	8			—			62				1			—			71
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard^(c)	—			(10		)	—				—			—			(10		)
Ending balance	$	(6	)	$	—		$	(2,936	)		$	(22	)	$	(1	)	$	(2,965	)
Generation^(a)
Beginning balance	$	(16	)	$	3		$	—			$	(23	)	$	(1	)	$	(37	)
OCI before reclassifications	7			—			—				(1		)	—			6
Amounts reclassified from AOCI	—			—			—				—			—			—
Net current-period OCI	7			—			—				(1		)	—			6
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard^(c)	—			(3		)	—				—			—			(3		)
Ending balance	$	(9	)	$	—		$	—			$	(24	)	$	(1	)	$	(34	)

_________


(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.

Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE did not have any reclassifications out of AOCI to Net income during the three months ended March 31, 2019 and 2018. The following tables present amounts reclassified out of AOCI to Net income for Exelon during the three months ended March 31, 2019 and 2018.

Three Months Ended March 31, 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

Total Reclassifications	$	(20	)	Net of tax

Three Months Ended March 31, 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

Total Reclassifications	$	(44	)	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 months ended March 31, 2019 and 2018:



	Three Months Ended March 31,
	2019			2018
Exelon
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	$	6		$	6
Actuarial loss reclassified to periodic benefit cost	(13		)	(22		)
Pension and non-pension postretirement benefit plans valuation adjustment	14			(7		)
Change in unrealized loss on cash flow hedges	—			(3		)
Change in unrealized loss on investments in unconsolidated affiliates	—			(1		)
Total	$	7		$	(27	)

Generation
Change in unrealized gain (loss) on cash flow hedges	$	1		$	(3	)
Change in unrealized loss on investments in unconsolidated affiliates	—			(1		)
Total	$	1		$	(4	)

Commitments and Contingencies (All Registrants)

3 Months Ended

Mar. 31, 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 March 31, 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		$	123	$	90	$	71	$	12	$	7

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, will be recognized as incurred and recorded in Exelon's and Generation's financial statements. As of March 31, 2019, 27 MWs of new generation were developed and Exelon and Generation have incurred costs of $97 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 March 31, 2019, representing commitments potentially triggered by future events were as follows:



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Letters of credit	$	1,480	$	1,455	$	6	$	—	$	2	$	8	$	8	$	—	$	—
Surety bonds^(a)	1,597		1,376		51		9		17		40		32		5		3
Financing trust guarantees	378		—		200		178		—		—		—		—		—
Guaranteed lease residual values^(b)	26		—		—		—		—		26		8		11		7
Total commercial commitments	$	3,481	$	2,831	$	257	$	187	$	19	$	74	$	48	$	16	$	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 maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $68 million, $22 million of which is a guarantee by Pepco, $28 million by DPL and $17 million by ACE. The minimum lease term associated with these assets ranges from 1 to 4 years. 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 March 31, 2019, the current liability limit per incident is $14.1 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 $13.6 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 $3.1 billion, however any amounts payable under this secondary layer would be capped at $454 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 $14.1 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 $335 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 March 31, 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:



March 31, 2019	Total environmental investigation and remediation reserve		Portion of total related to MGP investigation and remediation
Exelon	$	486	$	347
Generation	108		—
ComEd	320		318
PECO	27		25
BGE	5		4
PHI	26		—
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 are negotiating Consent Agreements to design and implement the ROD remedy, and negotiations are expected to be completed in the first quarter of 2020. 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 March 31, 2019 and December 31, 2018, Generation had recorded estimated liabilities of approximately $77 million and $79 million, respectively, in total for asbestos-related bodily injury claims. As of March 31, 2019, approximately $25 million of this amount related to 239 open claims presented to Generation, while the remaining $52 million is for estimated future asbestos-related bodily injury claims anticipated to arise through 2050, 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)

3 Months Ended

Mar. 31, 2019

Supplemental Financial Information [Abstract]

Supplemental Financial Information (All Registrants)

Supplemental Statement of Operations Information

The following tables provide additional information about the Registrants’ Consolidated Statements of Operations and Comprehensive Income for the three months ended March 31, 2019 and 2018.



	Three Months Ended March 31, 2019
	Exelon			Generation			ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Other, Net
Decommissioning-related activities:
Net realized income on NDT funds^(a)
Regulatory agreement units^(b)	$	54		$	54		$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-regulatory agreement units	54			54			—		—		—		—		—		—		—
Net unrealized gains on NDT funds
Regulatory agreement units^(b)	379			379			—		—		—		—		—		—		—
Non-regulatory agreement units	280			280			—		—		—		—		—		—		—
Regulatory offset to NDT fund-related activities^(c)	(348		)	(348		)	—		—		—		—		—		—		—
Total decommissioning-related activities	419			419			—		—		—		—		—		—		—
Investment income	12			7			—		1		—		—		—		—		—
Interest income related to uncertain income tax positions	1			—			—		—		—		—		—		—		—
AFUDC — Equity	22			—			5		3		5		9		6		1		2
Non-service net periodic benefit cost	5			—			—		—		—		—		—		—		—
Other	8			4			3		—		—		3		1		2		1
Other, net	$	467		$	430		$	8	$	4	$	5	$	12	$	7	$	3	$	3



	Three Months Ended March 31, 2018
	Exelon			Generation			ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Other, Net
Decommissioning-related activities:
Net realized income on NDT funds^(a)
Regulatory agreement units^(b)	$	46		$	46		$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-regulatory agreement units	56			56			—		—		—		—		—		—		—
Net unrealized losses on NDT funds
Regulatory agreement units^(b)	(75		)	(75		)	—		—		—		—		—		—		—
Non-regulatory agreement units	(96		)	(96		)	—		—		—		—		—		—		—
Regulatory offset to NDT fund-related activities^(c)	24			24			—		—		—		—		—		—		—
Total decommissioning-related activities	(45		)	(45		)	—		—		—		—		—		—		—
Investment income	4			2			—		—		—		—		—		—		—
Interest income related to uncertain income tax positions	2			1			—		—		—		—		—		—		—
AFUDC — Equity	18			—			6		2		4		6		5		1		—
Non-service net periodic benefit cost	(10		)	—			—		—		—		—		—		—		—
Other	3			(2		)	2		—		—		5		3		1		1
Other, net	$	(28	)	$	(44	)	$	8	$	2	$	4	$	11	$	8	$	2	$	1

_________


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


(b)	Net realized and unrealized gains (losses) related to Generation’s NDT funds associated with Regulatory Agreement Units are included in Regulatory liabilities in Exelon’s Consolidated Balance Sheets and Noncurrent payables to affiliates in Generation’s Consolidated Balance Sheets.


(c)	Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units, including the elimination of net 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.

The following utility taxes are included in revenues and expenses for the three months ended March 31, 2019 and 2018. Generation’s utility tax expense represents gross receipts tax related to its retail operations, and the Utility Registrants' utility tax expense 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.



	Three Months Ended March 31, 2019
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Utility taxes	$	223	$	26	$	62	$	34	$	27	$	74	$	69	$	5	$	—



	Three Months Ended March 31, 2018
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Utility taxes	$	235	$	32	$	61	$	33	$	26	$	83	$	77	$	6	$	—

Supplemental Cash Flow Information

The following tables provide additional information regarding the Registrants’ Consolidated Statements of Cash Flows for the three months ended March 31, 2019 and 2018.



	Three Months Ended March 31, 2019
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Depreciation, amortization and accretion
Property, plant and equipment^(a)	$	917	$	392	$	219	$	74	$	85	$	127	$	58	$	35	$	25
Amortization of regulatory assets^(a)	143		—		32		7		51		53		36		11		6
Amortization of intangible assets, net^(a)	15		13		—		—		—		—		—		—		—
Nuclear fuel^(c)	261		261		—		—		—		—		—		—		—
ARO accretion^(d)	124		123		—		—		—		—		—		—		—
Total depreciation, amortization and accretion	$	1,460	$	789	$	251	$	81	$	136	$	180	$	94	$	46	$	31



	Three Months Ended March 31, 2018
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Depreciation, amortization and accretion
Property, plant and equipment^(a)	$	926	$	436	$	201	$	68	$	82	$	117	$	53	$	32	$	23
Amortization of regulatory assets^(a)	152		—		27		7		52		66		43		13		10
Amortization of intangible assets, net^(a)	13		12		—		—		—		—		—		—		—
Amortization of energy contract assets and liabilities^(b)	3		3		—		—		—		—		—		—		—
Nuclear fuel^(c)	287		287		—		—		—		—		—		—		—
ARO accretion^(d)	120		120		—		—		—		—		—		—		—
Total depreciation, amortization and accretion	$	1,501	$	858	$	228	$	75	$	134	$	183	$	96	$	45	$	33

_________


(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.



	Three Months Ended March 31, 2019
	Exelon			Generation			ComEd			PECO			BGE			PHI			Pepco			DPL			ACE
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	106		$	31		$	24		$	2		$	15		$	23		$	6		$	4		$	4
Loss from equity method investments	6			6			—			—			—			—			—			—			—
Provision for uncollectible accounts	43			—			9			16			8			10			4			4			2
Stock-based compensation costs	28			—			—			—			—			—			—			—			—
Other decommissioning-related activity^(a)	(202		)	(202		)	—			—			—			—			—			—			—
Energy-related options^(b)	37			37			—			—			—			—			—			—			—
Amortization of regulatory asset related to debt costs	3			—			—			—			—			1			—			—			—
Amortization of rate stabilization deferral	(6		)	—			—			—			—			(6		)	(7		)	1			—
Amortization of debt fair value adjustment	(4		)	(3		)	—			—			—			(1		)	—			—			—
Discrete impacts from EIMA and FEJA^(c)	28			—			28			—			—			—			—			—			—
Amortization of debt costs	9			3			1			—			—			1			1			—			—
Long-term incentive plan	25			—			—			—			—			—			—			—			—
Amortization of operating ROU asset	53			34			1			—			8			9			2			2			1
Other	1			4			(7		)	(2		)	(4		)	(2		)	(3		)	—			(2		)
Total other non-cash operating activities	$	127		$	(90	)	$	56		$	16		$	27		$	35		$	3		$	11		$	5
Non-cash investing and financing activities:
Change in capital expenditures not paid	$	(229	)	$	(93	)	$	(80	)	$	8		$	2		$	(55	)	$	(15	)	$	(17	)	$	(24	)
Change in PPE related to ARO update	301			301			—			—			—			—			—			—			—
Dividends on stock compensation	1			—			—			—			—			—			—			—			—



	Three Months Ended March 31, 2018
	Exelon			Generation			ComEd			PECO			BGE			PHI		Pepco			DPL		ACE
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	145		$	51		$	45		$	5		$	14		$	15	$	4		$	—	$	3
Loss from equity method investments	7			7			—			—			—			—		—			—		—
Provision for uncollectible accounts	64			11			8			17			8			20		6			8		5
Stock-based compensation costs	29			—			—			—			—			—		—			—		—
Other decommissioning-related activity^(a)	(31		)	(31		)	—			—			—			—		—			—		—
Energy-related options^(b)	(7		)	(7		)	—			—			—			—		—			—		—
Amortization of regulatory asset related to debt costs	2			—			1			—			—			1		—			—		—
Amortization of rate stabilization deferral	7			—			—			—			—			7		1			6		—
Amortization of debt fair value adjustment	(3		)	(3		)	—			—			—			—		—			—		—
Discrete impacts from EIMA and FEJA^(c)	(4		)	—			(4		)	—			—			—		—			—		—
Amortization of debt costs	9			3			1			—			—			1		—			—		—
Provision for excess and obsolete inventory	13			12			1			—			—			—		—			—		—
Other	9			2			(6		)	(1		)	(2		)	9		(1		)	5		1
Total other non-cash operating activities	$	240		$	45		$	46		$	21		$	20		$	53	$	10		$	19	$	9
Non-cash investing and financing activities:
Change in capital expenditures not paid	$	(177	)	$	(131	)	$	(48	)	$	(25	)	$	(11	)	$	61	$	19		$	14	$	27
Change in PPE related to ARO update	32			32			—			—			—			—		—			—		—
Dividends on stock compensation	1			—			—			—			—			—		—			—		—

_________

(a)

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


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


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

The following tables provide a reconciliation of cash, cash equivalents and restricted cash reported within the Registrants’ Consolidated Balance Sheets that sum to the total of the same amounts in their Consolidated Statements of Cash Flows.



March 31, 2019	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Cash and cash equivalents	$	880	$	537	$	68	$	41	$	12	$	33	$	11	$	7	$	6
Restricted cash	223		139		17		6		4		39		35		1		3
Restricted cash included in other long-term assets	211		—		193		—		—		19		—		—		19
Total cash, cash equivalents and restricted cash	$	1,314	$	676	$	278	$	47	$	16	$	91	$	46	$	8	$	28



December 31, 2018	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
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



March 31, 2018	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Cash and cash equivalents	$	787	$	610	$	70	$	21	$	22	$	43	$	15	$	7	$	10
Restricted cash	209		127		9		5		2		40		33		—		7
Restricted cash included in other long-term assets	103		—		83		—		—		20		—		—		20
Total cash, cash equivalents and restricted cash	$	1,099	$	737	$	162	$	26	$	24	$	103	$	48	$	7	$	37



December 31, 2017	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
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 assets and liabilities of the Registrants as of March 31, 2019 and December 31, 2018.



March 31, 2019	Exelon			Generation			ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Property, plant and equipment:
Accumulated depreciation and amortization	$	23,695	^(a)	$	12,663	^(a)	$	4,833	$	3,598	$	3,670	$	930	$	3,392	$	1,354	$	1,154
Accounts receivable:
Allowance for uncollectible accounts	$	340		$	87		$	97	$	72	$	27	$	57	$	23	$	15	$	19



December 31, 2018	Exelon			Generation			ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Property, plant and equipment:
Accumulated depreciation and amortization	$	22,902	^(b)	$	12,206	^(b)	$	4,684	$	3,561	$	3,633	$	841	$	3,354	$	1,329	$	1,137
Accounts receivable:
Allowance for uncollectible accounts	$	319		$	104		$	81	$	61	$	20	$	53	$	21	$	13	$	19

_________


(a)	Includes accumulated amortization of nuclear fuel in the reactor core of $3,040 million.


(b)	Includes accumulated amortization of nuclear fuel in the reactor core of $2,969 million.

The Utility Registrants are required, under separate legislation and regulations in Illinois, Pennsylvania, Maryland, District of Columbia and New Jersey, to purchase certain receivables from alternative retail electric and, as applicable, natural gas suppliers that participate in the utilities' consolidated billing. ComEd, BGE, Pepco and DPL purchase receivables at a discount to recover primarily uncollectible accounts expense from the suppliers. PECO and ACE purchase receivables at face value and recover uncollectible accounts expense, including those from alternative retail electric and natural gas supplies, through base distribution rates and a rate rider, respectively. Exelon and the Utility Registrants do not record unbilled commodity receivables under their POR programs. Purchased billed receivables are recorded on a net basis in Exelon’s and the Utility Registrant's Consolidated Statements of Operations and Comprehensive Income and are classified in Other accounts receivable, net in their Consolidated Balance Sheets. The following tables provide information about the purchased receivables of those companies as of March 31, 2019 and December 31, 2018.



March 31, 2019	Exelon			ComEd			PECO			BGE			PHI			Pepco			DPL			ACE
Purchased receivables	$	332		$	105		$	77		$	65		$	85		$	58		$	8		$	19
Allowance for uncollectible accounts^(a)	(38		)	(19		)	(6		)	(4		)	(9		)	(5		)	(1		)	(3		)
Purchased receivables, net	$	294		$	86		$	71		$	61		$	76		$	53		$	7		$	16



December 31, 2018	Exelon			ComEd			PECO			BGE			PHI			Pepco			DPL			ACE
Purchased receivables	$	313		$	94		$	74		$	61		$	84		$	57		$	8		$	19
Allowance for uncollectible accounts^(a)	(34		)	(17		)	(5		)	(3		)	(9		)	(5		)	(1		)	(3		)
Purchased receivables, net	$	279		$	77		$	69		$	58		$	75		$	52		$	7		$	16

__________


(a)	For ComEd, BGE, Pepco and DPL, reflects the incremental allowance for uncollectible accounts recorded, which is in addition to the purchase discount. For ComEd, the incremental uncollectible accounts expense is recovered through a rate rider. BGE, Pepco and DPL recover actual write-offs which are reflected in the POR discount rate.

Segment Information (All Registrants)

3 Months Ended

Mar. 31, 2019

Segment Reporting [Abstract]

Segment Information (All Registrants)

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

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

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


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


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


•	New York represents operations within ISO-NY.


•	ERCOT represents operations within Electric Reliability Council of Texas.


•	Other Power Regions:


•	New England represents the operations within ISO-NE.


•	South represents operations in the FRCC, MISO’s Southern Region, and the remaining portions of the SERC not included within MISO or PJM.


•	West represents operations in the WECC, which includes California ISO.


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

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

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

An analysis and reconciliation of the Registrants’ reportable segment information to the respective information in the consolidated financial statements for the three months ended March 31, 2019 and 2018 is as follows:

Three Months Ended March 31, 2019 and 2018



	Generation^(a)		ComEd		PECO		BGE		PHI		Other^(b)		Intersegment Eliminations			Exelon
Operating revenues^(c):
2019
Competitive businesses electric revenues	$	4,337	$	—	$	—	$	—	$	—	$	—	$	(315	)	$	4,022
Competitive businesses natural gas revenues	879		—		—		—		—		—		(1		)	878
Competitive businesses other revenues	80		—		—		—		—		—		(1		)	79
Rate-regulated electric revenues	—		1,408		620		658		1,153		—		(8		)	3,831
Rate-regulated natural gas revenues	—		—		280		318		71		—		(4		)	665
Shared service and other revenues	—		—		—		—		4		455		(457		)	2
Total operating revenues	$	5,296	$	1,408	$	900	$	976	$	1,228	$	455	$	(786	)	$	9,477



	Generation^(a)		ComEd		PECO			BGE		PHI		Other^(b)			Intersegment Eliminations			Exelon
2018
Competitive businesses electric revenues	$	4,509	$	—	$	—		$	—	$	—	$	—		$	(391	)	$	4,118
Competitive businesses natural gas revenues	955		—		—			—		—		—			(8		)	947
Competitive businesses other revenues	48		—		—			—		—		—			—			48
Rate-regulated electric revenues	—		1,512		634			658		1,169		—			(18		)	3,955
Rate-regulated natural gas revenues	—		—		232			319		78		—			(4		)	625
Shared service and other revenues	—		—		—			—		4		451			(455		)	—
Total operating revenues	$	5,512	$	1,512	$	866		$	977	$	1,251	$	451		$	(876	)	$	9,693
Intersegment revenues^(d):
2019	$	317	$	4	$	1		$	6	$	4	$	453		$	(785	)	$	—
2018	400		14		2			6		4		450			(876		)	—
Depreciation and amortization:
2019	$	405	$	251	$	81		$	136	$	180	$	22		$	—		$	1,075
2018	448		228		75			134		183		23			—			1,091
Operating expenses:
2019	$	4,963	$	1,135	$	678		$	756	$	1,054	$	459		$	(783	)	$	8,262
2018	5,218		1,223		724			800		1,125		444			(886		)	8,648
Interest expense, net:
2019	$	111	$	87	$	33		$	29	$	65	$	78		$	—		$	403
2018	101		89		33			25		63		60			—			371
Income (loss) before income taxes:
2019	$	652	$	197	$	193		$	196	$	122	$	(78	)	$	—		$	1,282
2018	202		211		111			156		74		(52		)	—			702
Income Taxes:
2019	$	224	$	40	$	25		$	36	$	5	$	(20	)	$	—		$	310
2018	9		46		(2		)	28		9		(31		)	—			59
Net income (loss):
2019	$	422	$	157	$	168		$	160	$	117	$	(58	)	$	—		$	966
2018	186		165		113			128		65		(21		)	—			636
Capital Expenditures
2019	$	511	$	503	$	222		$	258	$	358	$	21		$	—		$	1,873
2018	628		531		217			224		258		22			—			1,880
Total assets:
March 31, 2019	$	48,682	$	31,582	$	10,956		$	9,967	$	22,294	$	8,325		$	(10,213	)	$	121,593
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 $45 million, sales to BGE of $76 million, sales to Pepco of $70 million, sales to DPL of $23 million and sales to ACE of $8 million in the Mid-Atlantic region, and sales to ComEd of $94 million in the Midwest region, which eliminate upon consolidation. Intersegment revenues for Generation in 2018 include revenue from sales to PECO of $37 million, sales to BGE of $65 million, sales to Pepco of $52 million, sales to DPL of $46 million and sales to ACE of $6 million in the Mid-Atlantic region, and sales to ComEd of $194 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	$	575	$	310	$	273	$	—		$	(5	)	$	1,153
Rate-regulated natural gas revenues	—		70		—		—			1			71
Shared service and other revenues	—		—		—		106			(102		)	4
Total operating revenues	$	575	$	380	$	273	$	106		$	(106	)	$	1,228
2018
Rate-regulated electric revenues	$	557	$	306	$	310	$	—		$	(4	)	$	1,169
Rate-regulated natural gas revenues	—		78		—		—			—			78
Shared service and other revenues	—		—		—		113			(109		)	4
Total operating revenues	$	557	$	384	$	310	$	113		$	(113	)	$	1,251
Intersegment revenues:
2019	$	2	$	2	$	1	$	105		$	(106	)	$	4
2018	2		2		1		112			(113		)	4
Depreciation and amortization:
2019	$	94	$	46	$	31	$	10		$	(1	)	$	180
2018	96		45		33		9			—			183
Operating expenses:
2019	$	491	$	308	$	252	$	108		$	(105	)	$	1,054
2018	501		335		287		114			(112		)	1,125
Interest expense, net:
2019	$	34	$	15	$	14	$	3		$	(1	)	$	65
2018	31		13		16		2			1			63
Income (loss) before income taxes:
2019	$	57	$	60	$	10	$	113		$	(118	)	$	122
2018	33		38		8		64			(69		)	74
Income Taxes:
2019	$	2	$	7	$	—	$	(4	)	$	—		$	5
2018	2		7		1		(1		)	—			9
Net income (loss):
2019	$	55	$	53	$	10	$	(5	)	$	4		$	117
2018	31		31		7		(8		)	4			65
Capital Expenditures
2019	$	144	$	78	$	128	$	8		$	—		$	358
2018	127		65		63		3			—			258
Total assets:
March 31, 2019	$	8,420	$	4,660	$	3,783	$	10,909		$	(5,478	)	$	22,294
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.

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 March 31, 2019
	Revenues from external parties^(a)							Intersegment revenues			Total Revenues
	Contracts with customers		Other^(b)			Total		Intersegment revenues			Total Revenues
Mid-Atlantic	$	1,286	$	(24	)	$	1,262	$	(6	)	$	1,256
Midwest	1,055		59			1,114		(6		)	1,108
New York	409		(16		)	393		—			393
ERCOT	130		79			209		3			212
Other Power Regions	1,165		194			1,359		(6		)	1,353
Total Competitive Businesses Electric Revenues	4,045		292			4,337		(15		)	4,322
Competitive Businesses Natural Gas Revenues	584		295			879		15			894
Competitive Businesses Other Revenues^(c)	120		(40		)	80		—			80
Total Generation Consolidated Operating Revenues	$	4,749	$	547		$	5,296	$	—		$	5,296



	Three Months Ended March 31, 2018
	Revenues from external customers^(a)							Intersegment revenues			Total Revenues
	Contracts with customers		Other^(b)			Total		Intersegment revenues			Total Revenues
Mid-Atlantic	$	1,355	$	80		$	1,435	$	5		$	1,440
Midwest	1,273		71			1,344		2			1,346
New York	439		(29		)	410		(1		)	409
ERCOT	149		59			208		1			209
Other Power Regions	935		177			1,112		(32		)	1,080
Total Competitive Businesses Electric Revenues	4,151		358			4,509		(25		)	4,484
Competitive Businesses Natural Gas Revenues	522		433			955		25			980
Competitive Businesses Other Revenues^(c)	134		(86		)	48		—			48
Total Generation Consolidated Operating Revenues	$	4,807	$	705		$	5,512	$	—		$	5,512

__________


(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 $52 million and $98 million in 2019 and 2018, respectively, and elimination of intersegment revenues.

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



	Three Months Ended March 31, 2019							Three Months Ended March 31, 2018
	RNF from external customers^(a)		Intersegment RNF			Total RNF		RNF from external customers^(a)			Intersegment RNF			Total RNF
Mid-Atlantic	$	679	$	4		$	683	$	836		$	14		$	850
Midwest	769		2			771		847			13			860
New York	262		3			265		282			1			283
ERCOT	98		(24		)	74		106			(70		)	36
Other Power Regions	174		(18		)	156		279			(43		)	236
Total Revenues net of purchased power and fuel for Reportable Segments	1,982		(33		)	1,949		2,350			(85		)	2,265
Other^(b)	109		33			142		(131		)	85			(46		)
Total Generation Revenues net of purchased power and fuel expense	$	2,091	$	—		$	2,091	$	2,219		$	—		$	2,219

__________


(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 $28 million and $266 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 and $15 million decrease to RNF in 2019 and 2018, respectively, and the elimination of intersegment RNF.

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



	Three Months Ended March 31, 2019
Revenues from contracts with customers	ComEd			PECO			BGE		PHI		Pepco		DPL		ACE
Rate-regulated electric revenues
Residential	$	710		$	409		$	385	$	579	$	256	$	185	$	138
Small commercial & industrial	360			96			70		120		38		48		34
Large commercial & industrial	132			48			110		267		204		24		39
Public authorities & electric railroads	13			7			7		14		8		3		3
Other^(a)	217			62			80		157		53		47		57
Total rate-regulated electric revenues^(b)	$	1,432		$	622		$	652	$	1,137	$	559	$	307	$	271
Rate-regulated natural gas revenues
Residential	$	—		$	198		$	219	$	44	$	—	$	44	$	—
Small commercial & industrial	—			72			35		19		—		19		—
Large commercial & industrial	—			1			50		1		—		1		—
Transportation	—			7			—		4		—		4		—
Other^(c)	—			2			4		3		—		3		—
Total rate-regulated natural gas revenues^(d)	$	—		$	280		$	308	$	71	$	—	$	71	$	—
Total rate-regulated revenues from contracts with customers	$	1,432		$	902		$	960	$	1,208	$	559	$	378	$	271

Other revenues
Revenues from alternative revenue programs	$	(28	)	$	(3	)	$	10	$	15	$	14	$	—	$	1
Other rate-regulated electric revenues^(e)	4			1			3		4		2		1		1
Other rate-regulated natural gas revenues^(e)	—			—			3		1		—		1		—
Total other revenues	$	(24	)	$	(2	)	$	16	$	20	$	16	$	2	$	2
Total rate-regulated revenues for reportable segments	$	1,408		$	900		$	976	$	1,228	$	575	$	380	$	273



	Three Months Ended March 31, 2018
Revenues from contracts with customers	ComEd		PECO			BGE			PHI		Pepco		DPL		ACE
Rate-regulated electric revenues
Residential	$	717	$	403		$	393		$	610	$	259	$	191	$	160
Small commercial & industrial	385		101			68			115		32		46		37
Large commercial & industrial	152		58			106			259		190		23		46
Public authorities & electric railroads	14		8			7			14		7		4		3
Other^(a)	230		62			78			156		49		41		66
Total rate-regulated electric revenues^(b)	$	1,498	$	632		$	652		$	1,154	$	537	$	305	$	312
Rate-regulated natural gas revenues
Residential	$	—	$	161		$	224		$	47	$	—	$	47	$	—
Small commercial & industrial	—		62			34			18		—		18		—
Large commercial & industrial	—		1			47			4		—		4		—
Transportation	—		6			—			5		—		5		—
Other^(c)	—		2			27			4		—		4		—
Total rate-regulated natural gas revenues^(d)	$	—	$	232		$	332		$	78	$	—	$	78	$	—
Total rate-regulated revenues from contracts with customers	$	1,498	$	864		$	984		$	1,232	$	537	$	383	$	312

Other revenues
Revenues from alternative revenue programs	$	5	$	(1	)	$	(13	)	$	18	$	19	$	1	$	(2	)
Other rate-regulated electric revenues^(e)	9		3			4			1		1		—		—
Other rate-regulated natural gas revenues^(e)	—		—			2			—		—		—		—
Total other revenues	$	14	$	2		$	(7	)	$	19	$	20	$	1	$	(2	)
Total rate-regulated revenues for reportable segments	$	1,512	$	866		$	977		$	1,251	$	557	$	384	$	310

__________


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


(b)	Includes operating revenues from affiliates of $4 million, $1 million, $2 million, $3 million, $2 million, $2 million and $1 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2019 and $14 million, $2 million, $2 million, $4 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.

Significant Accounting Policies (Policies)

3 Months Ended

Mar. 31, 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]

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

Valuation Techniques Used to Determine Fair Value

The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the tables above.

See Note 13 — Nuclear Decommissioning for additional information on the NDT fund investments.

Additional Information Regarding Level 3 Fair Value Measurements (Exelon, Generation, ComEd, PHI, Pepco, DPL and ACE)

Lessee, Leases [Policy Text Block]

Leases (All Registrants)

See Note 5 —Leases for additional information.

Variable Interest Entities (Tables)

3 Months Ended

Mar. 31, 2019

Variable Interest Entity [Abstract]

Schedule of Variable Interest Entities



	March 31, 2019								December 31, 2018
	Exelon^(a)		Generation		PHI^(a)		ACE		Exelon^(a)		Generation		PHI^(a)		ACE
Current assets	$	645	$	639	$	6	$	3	$	938	$	931	$	7	$	4
Noncurrent assets	9,235		9,210		25		19		9,071		9,045		26		19
Total assets	$	9,880	$	9,849	$	31	$	22	$	10,009	$	9,976	$	33	$	23
Current liabilities	$	748	$	725	$	23	$	19	$	274	$	252	$	22	$	19
Noncurrent liabilities	2,831		2,790		41		35		3,280		3,233		47		40
Total liabilities	$	3,579	$	3,515	$	64	$	54	$	3,554	$	3,485	$	69	$	59

_________


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



March 31, 2019	Commercial Agreement VIEs		Equity Investment VIEs		Total
Total assets^(a)	$	601	$	463	$	1,064
Total liabilities^(a)	42		223		265
Exelon's ownership interest in VIE^(a)	—		214		214
Other ownership interests in VIE^(a)	559		26		585
Registrants’ maximum exposure to loss:
Carrying amount of equity method investments	—		214		214
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.



	March 31, 2019								December 31, 2018
	Exelon^(a)		Generation		PHI^(a)		ACE		Exelon^(a)		Generation		PHI^(a)		ACE
Cash and cash equivalents	$	125	$	125	$	—	$	—	$	414	$	414	$	—	$	—
Restricted cash and cash equivalents	58		55		3		3		66		62		4		4
Accounts receivable, net
Customer	152		152		—		—		146		146		—		—
Other	23		23		—		—		23		23		—		—
Inventory, net
Materials and supplies	213		213		—		—		212		212		—		—
Other current assets	51		48		3		—		52		49		3		—
Total current assets	622		616		6		3		913		906		7		4
Property, plant and equipment, net	6,147		6,147		—		—		6,145		6,145		—		—
NDT funds	2,520		2,520		—		—		2,351		2,351		—		—
Other noncurrent assets	257		232		25		19		258		232		26		19
Total noncurrent assets	8,924		8,899		25		19		8,754		8,728		26		19
Total assets	$	9,546	$	9,515	$	31	$	22	$	9,667	$	9,634	$	33	$	23
Long-term debt due within one year	$	567	$	545	$	22	$	19	$	87	$	66	$	21	$	18
Accounts payable	120		120		—		—		96		96		—		—
Accrued expenses	42		41		1		—		72		72		1		1
Unamortized energy contract liabilities	13		13		—		—		15		15		—		—
Other current liabilities	6		6		—		—		3		3		—		—
Total current liabilities	748		725		23		19		273		252		22		19
Long-term debt	565		524		41		35		1,072		1,025		47		40
Asset retirement obligations	2,190		2,190		—		—		2,160		2,160		—		—
Unamortized energy contract liabilities	—		—		—		—		1		1		—		—
Other noncurrent liabilities	69		69		—		—		42		42		—		—
Total noncurrent liabilities	2,824		2,783		41		35		3,275		3,228		47		40
Total liabilities	$	3,572	$	3,508	$	64	$	54	$	3,548	$	3,480	$	69	$	59

_________


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

- 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)

3 Months Ended

Mar. 31, 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 March 31, 2019:



	Contract Assets						Contract Liabilities
	Exelon			Generation			Exelon			Generation
Balance as of January 1, 2018	$	283		$	283		$	35		$	35
Increases as a result of changes in the estimate of the stage of completion	50			50			—			—
Increases as a result of additional cash received or due	—			—			179			465
Amounts reclassified into receivables or recognized into revenues	(146		)	(146		)	(187		)	(458		)
Balance at December 31, 2018	187			187			27			42
Increases as a result of changes in the estimate of the stage of completion	26			26			—			—
Increases as a result of additional cash received or due	—			—			21			63
Amounts reclassified into receivables or recognized into revenues	(26		)	(26		)	(23		)	(66		)
Balance at March 31, 2019	$	187		$	187		$	25		$	39

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



	2019		2020		2021		2022		2023 and thereafter		Total
Exelon	$	393	$	273	$	112	$	50	$	142	$	970
Generation	493		331		126		50		142		1,142

Leases (Tables)

3 Months Ended

Mar. 31, 2019

Leases [Abstract]

Components of Lease Cost [Table Text Block]

ROU assets obtained in exchange for lease obligations for the three months ended March 31, 2019 were as follows:



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Operating leases	$	20	$	9	$	—	$	—	$	—	$	11	$	4	$	4	$	3

The weighted average remaining lease terms, in years, and discount rates for operating leases as of March 31, 2019 were as follows:



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Remaining lease term	10.0		10.7		2.9		4.4		5.6		9.4		9.9		9.8		5.3
Discount rate	4.6	%	4.8	%	3.3	%	3.4	%	3.6	%	4.1	%	3.9	%	3.9	%	3.5	%

The components of lease costs for the three months ended March 31, 2019 were as follows:



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Operating lease costs	$	68	$	46	$	1	$	—	$	8	$	10	$	3	$	3	$	1
Variable lease costs	73		68		—		—		—		2		—		1		—
Short-term lease costs	9		8		—		—		—		—		—		—		—
Total lease costs ^(a)	$	150	$	122	$	1	$	—	$	8	$	12	$	3	$	4	$	1

__________


(a)	Excludes $3 million, $2 million, $1 million and $1 million of sublease income recorded at Exelon, Generation, PHI and DPL.

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	$	1,465	$	1,027	$	5	$	2	$	97	$	314	$	67	$	75	$	26

Operating lease liabilities
Other current liabilities	249		173		3		1		31		36		8		11		6
Other deferred credits and other liabilities	1,395		1,023		4		1		66		284		60		72		20
Total operating lease liabilities	$	1,644	$	1,196	$	7	$	2	$	97	$	320	$	68	$	83	$	26

__________


(a)	Exelon's and Generation's operating ROU assets and lease liabilities include $631 million and $778 million, respectively, related to contracted generation.

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

Future minimum lease payments for operating leases as of March 31, 2019 were as follows:



Year	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
2019	$	214	$	154	$	2	$	1	$	19	$	33	$	8	$	7	$	5
2020	289		202		2		1		34		43		9		12		5
2021	244		162		2		—		32		42		9		11		5
2022	174		112		1		—		16		40		8		11		4
2023	139		99		—		—		—		39		8		10		3
Remaining years	1,052		840		—		—		18		194		42		52		7
Total	2,112		1,569		7		2		119		391		84		103		29
Interest	468		373		—		—		22		71		16		20		3
Total operating lease liabilities	$	1,644	$	1,196	$	7	$	2	$	97	$	320	$	68	$	83	$	26

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:



	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 three months ended March 31, 2019 were as follows:



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Operating cash flows from operating leases	$	78	$	52	$	1	$	—	$	14	$	8	$	2	$	2	$	1

Components of Operating Lease Income [Table Text Block]

The components of lease income for the three months ended March 31, 2019 were as follows:



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Operating lease income	$	4	$	3	$	—	$	—	$	—	$	1	$	—	$	1	$	—
Variable lease income	$	52	$	52	$	—	$	—	$	—	$	—	$	—	$	—	$	—

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

Future minimum lease payments to be recovered under operating leases as of March 31, 2019 were as follows:



Year	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
2019	$	47	$	43	$	—	$	—	$	—	$	4	$	—	$	3	$	—
2020	51		46		—		—		—		4		—		3		—
2021	50		45		—		—		—		4		—		3		—
2022	50		45		—		—		—		4		—		3		—
2023	49		45		—		—		—		4		—		3		—
Remaining years	315		271		1		3		1		39		1		38		—
Total	$	562	$	495	$	1	$	3	$	1	$	59	$	1	$	53	$	—

Regulatory Matters (Tables)

3 Months Ended

Mar. 31, 2019

Regulated Operations [Abstract]

Public Utilities General Disclosures [Table Text Block]



	Exelon		ComEd^(a)		PECO		BGE^(b)		PHI		Pepco^(c)		DPL^(c)		ACE
March 31, 2019	$	64	$	7	$	—	$	49	$	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)

3 Months Ended

Mar. 31, 2019

Property, Plant and Equipment [Abstract]

Schedule of Other Operating Cost and Expense, by Component [Table Text Block]



	Three Months Ended March 31,
Income statement expense (pre-tax)	2019			2018
Depreciation and amortization^(a)
Accelerated depreciation^(b)	$	74		$	137
Accelerated nuclear fuel amortization	5			15
Operating and maintenance^(c)	(83		)	26
Total	$	(4	)	$	178

_________


(a)	Reflects incremental accelerated depreciation and amortization for TMI for the three months ended March 31, 2019. Reflects incremental accelerated depreciation for TMI and Oyster Creek for the three months ended March 31, 2018. The Oyster Creek amounts are from February 2, 2018 through March 31, 2018.


(b)	Reflects incremental accelerated depreciation of plant assets, including any ARC.


(c)	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.

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



	March 31, 2019
Asset Balances
Materials and supplies inventory	$	30
Fuel inventory	22
Completed plant, net	900
Construction work in progress	2
Liability Balances
Asset retirement obligation	(1		)

Fair Value of Financial Assets and Liabilities (Tables)

3 Months Ended

Mar. 31, 2019

Fair Value Disclosures [Abstract]

Fair value of financial liabilities recorded at the carrying amount

Exelon



	March 31, 2019
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	1,254	$	—	$	1,254	$	—	$	1,254
Long-term debt (including amounts due within one year)^(a)	35,468		—		35,066		2,188		37,254
Long-term debt to financing trusts^(b)	390		—		—		411		411
SNF obligation	1,178		—		989		—		989



	December 31, 2018
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	714	$	—	$	714	$	—	$	714
Long-term debt (including amounts due within one year)^(a)	35,424		—		33,711		2,158		35,869
Long-term debt to financing trusts^(b)	390		—		—		400		400
SNF obligation	1,171		—		949		—		949

Generation



	March 31, 2019
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year)^(a)	$	8,747	$	—	$	7,641	$	1,443	$	9,084
SNF obligation	1,178		—		989		—		989



	December 31, 2018
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year)^(a)	$	8,793	$	—	$	7,467	$	1,443	$	8,910
SNF obligation	1,171		—		949		—		949

ComEd



	March 31, 2019
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	322	$	—	$	322	$	—	$	322
Long-term debt (including amounts due within one year)^(a)	8,194		—		8,855		—		8,855
Long-term debt to financing trusts^(b)	205		—		—		215		215



	December 31, 2018
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year)^(a)	$	8,101	$	—	$	8,390	$	—	$	8,390
Long-term debt to financing trusts^(b)	205		—		—		209		209

PECO



	March 31, 2019
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year)^(a)	$	3,084	$	—	$	3,295	$	50	$	3,345
Long-term debt to financing trusts^(b)	184		—		—		196		196



	December 31, 2018
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year)^(a)	$	3,084	$	—	$	3,157	$	50	$	3,207
Long-term debt to financing trusts^(b)	184		—		—		191		191

BGE



	March 31, 2019
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	106	$	—	$	106	$	—	$	106
Long-term debt (including amounts due within one year)^(a)	2,876		—		3,051		—		3,051



	December 31, 2018
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	35	$	—	$	35	$	—	$	35
Long-term debt (including amounts due within one year)^(a)	2,876		—		2,950		—		2,950

PHI



	March 31, 2019
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	326	$	—	$	326	$	—	$	326
Long-term debt (including amounts due within one year)^(a)	6,244		—		5,608		695		6,303



	December 31, 2018
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	179	$	—	$	179	$	—	$	179
Long-term debt (including amounts due within one year)^(a)	6,259		—		5,436		665		6,101

Pepco



	March 31, 2019
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	105	$	—	$	105	$	—	$	105
Long-term debt (including amounts due within one year)^(a)	2,720		—		3,000		208		3,208



	December 31, 2018
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	40	$	—	$	40	$	—	$	40
Long-term debt (including amounts due within one year)^(a)	2,719		—		2,901		196		3,097

DPL



	March 31, 2019
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	5	$	—	$	5	$	—	$	5
Long-term debt (including amounts due within one year)^(a)	1,495		—		1,345		204		1,549



	December 31, 2018
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year)^(a)	$	1,494	$	—	$	1,303	$	193	$	1,496

ACE



	March 31, 2019
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	216	$	—	$	216	$	—	$	216
Long-term debt (including amounts due within one year)^(a)	1,184		—		1,004		283		1,287



	December 31, 2018
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	139	$	—	$	139	$	—	$	139
Long-term debt (including amounts due within one year)^(a)	1,188		—		987		275		1,262

_________

(a)


(b)	Includes unamortized debt issuance costs which are not fair valued of $1 million and $1 million for Exelon and ComEd, respectively, as of March 31, 2019. Includes unamortized debt issuance costs which are not fair valued of less than $1 million and $1 million for Exelon and ComEd, respectively, as of December 31, 2018.

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



	Generation														Exelon
As of March 31, 2019	Level 1			Level 2			Level 3			Not subject to leveling		Total			Level 1			Level 2			Level 3			Not subject to leveling		Total
Assets
Cash equivalents^(a)	$	370		$	—		$	—		$	—	$	370		$	817		$	—		$	—		$	—	$	817
NDT fund investments
Cash equivalents^(b)	369			74			—			—		443			369			74			—			—		443
Equities	3,060			1,753			1			1,545		6,359			3,060			1,753			1			1,545		6,359
Fixed income
Corporate debt	—			1,545			236			1		1,782			—			1,545			236			1		1,782
U.S. Treasury and agencies	2,033			112			—			—		2,145			2,033			112			—			—		2,145
Foreign governments	—			43			—			—		43			—			43			—			—		43
State and municipal debt	—			110			—			—		110			—			110			—			—		110
Other^(c)	—			26			—			935		961			—			26			—			935		961
Fixed income subtotal	2,033			1,836			236			936		5,041			2,033			1,836			236			936		5,041
Middle market lending	—			—			303			406		709			—			—			303			406		709
Private equity	—			—			—			352		352			—			—			—			352		352
Real estate	—			—			—			535		535			—			—			—			535		535
NDT fund investments subtotal^(d)	5,462			3,663			540			3,774		13,439			5,462			3,663			540			3,774		13,439
Rabbi trust investments
Cash equivalents	4			—			—			—		4			47			—			—			—		47
Mutual funds	25			—			—			—		25			74			—			—			—		74
Fixed income	—			—			—			—		—			—			14			—			—		14
Life insurance contracts	—			23			—			—		23			—			71			39			—		110
Rabbi trust investments subtotal^(e)	29			23			—			—		52			121			85			39			—		245
Commodity derivative assets
Economic hedges	273			2,164			1,442			—		3,879			273			2,164			1,442			—		3,879
Proprietary trading	—			74			104			—		178			—			74			104			—		178
Effect of netting and allocation of collateral^(f)(g)	(294		)	(1,836		)	(820		)	—		(2,950		)	(294		)	(1,836		)	(820		)	—		(2,950		)
Commodity derivative assets subtotal	(21		)	402			726			—		1,107			(21		)	402			726			—		1,107
Interest rate and foreign currency derivative assets
Economic hedges	—			4			—			—		4			—			4			—			—		4
Effect of netting and allocation of collateral	—			(5		)	—			—		(5		)	—			(5		)	—			—		(5		)
Interest rate and foreign currency derivative assets subtotal	—			(1		)	—			—		(1		)	—			(1		)	—			—		(1		)
Other investments	—			—			42			—		42			—			—			42			—		42
Total assets	5,840			4,087			1,308			3,774		15,009			6,379			4,149			1,347			3,774		15,649



	Generation														Exelon
As of March 31, 2019	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	(350		)	(2,339		)	(1,164		)	—		(3,853		)	(350		)	(2,339		)	(1,404		)	—		(4,093		)
Proprietary trading	—			(79		)	(40		)	—		(119		)	—			(79		)	(40		)	—		(119		)
Effect of netting and allocation of collateral^(f)(g)	346			2,119			977			—		3,442			346			2,119			977			—		3,442
	(4		)	(299		)	(227		)	—		(530		)	(4		)	(299		)	(467		)	—		(770		)
Interest rate and foreign currency derivative liabilities
Derivatives designated as hedging instruments	—			—			—			—		—			—			(2		)	—			—		(2		)
Economic hedges	—			(12		)	—			—		(12		)	—			(12		)	—			—		(12		)
Effect of netting and allocation of collateral	—			5			—			—		5			—			5			—			—		5
Interest rate and foreign currency derivative liabilities subtotal	—			(7		)	—			—		(7		)	—			(9		)	—			—		(9		)
Deferred compensation obligation	—			(36		)	—			—		(36		)	—			(140		)	—			—		(140		)
Total liabilities	(4		)	(342		)	(227		)	—		(573		)	(4		)	(448		)	(467		)	—		(919		)
Total net assets	$	5,836		$	3,745		$	1,081		$	3,774	$	14,436		$	6,375		$	3,701		$	880		$	3,774	$	14,730



	Generation														Exelon
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)	$	581		$	—		$	—		$	—	$	581		$	1,243		$	—		$	—		$	—	$	1,243
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	5			—			—			—		5			48			—			—			—		48
Mutual funds	24			—			—			—		24			72			—			—			—		72
Fixed income	—			—			—			—		—			—			15			—			—		15
Life insurance contracts	—			22			—			—		22			—			70			38			—		108
Rabbi trust investments subtotal^(e)	29			22			—			—		51			120			85			38			—		243
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^(f)(g)	(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
Interest rate and foreign currency derivative assets
Economic hedges	—			13			—			—		13			—			13			—			—		13
Effect of netting and allocation of collateral	—			(3		)	—			—		(3		)	—			(3		)	—			—		(3		)
Interest rate and foreign currency derivative assets subtotal	—			10			—			—		10			—			10			—			—		10
Other investments	—			—			42			—		42			—			—			42			—		42
Total assets	5,820			4,102			1,400			3,433		14,755			6,573			4,165			1,438			3,433		15,609



	Generation														Exelon
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		)	(1,027		)	—		(4,632		)	(642		)	(2,963		)	(1,276		)	—		(4,881		)
Proprietary trading	—			(73		)	(21		)	—		(94		)	—			(73		)	(21		)	—		(94		)
Effect of netting and allocation of collateral^(f)(g)	639			2,581			808			—		4,028			639			2,581			808			—		4,028
Commodity derivative liabilities subtotal	(3		)	(455		)	(240		)	—		(698		)	(3		)	(455		)	(489		)	—		(947		)
Interest rate and foreign currency derivative liabilities
Derivatives designated as hedging instruments	—			—			—			—		—			—			(4		)	—			—		(4		)
Economic hedges	—			(6		)	—			—		(6		)	—			(6		)	—			—		(6		)
Effect of netting and allocation of collateral	—			3			—			—		3			—			3			—			—		3
Interest rate and foreign currency derivative liabilities subtotal	—			(3		)	—			—		(3		)	—			(7		)	—			—		(7		)
Deferred compensation obligation	—			(35		)	—			—		(35		)	—			(137		)	—			—		(137		)
Total liabilities	(3		)	(493		)	(240		)	—		(736		)	(3		)	(599		)	(489		)	—		(1,091		)
Total net assets	$	5,817		$	3,609		$	1,160		$	3,433	$	14,019		$	6,570		$	3,566		$	949		$	3,433	$	14,518

_________

(a)


(b)	Includes $43 million and $50 million of cash received from outstanding repurchase agreements at March 31, 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)	The amount of unrealized gains/(losses) at Generation totaled less than $1 million for the three months ended March 31, 2019 and March 31, 2018, respectively. The amount of unrealized gains/(losses) at Exelon totaled $1 million for the three months ended March 31, 2019 and March 31, 2018, respectively.

(f)


(g)	Of the collateral posted/(received), $(33) million and $(94) million represents variation margin on the exchanges as of March 31, 2019 and December 31, 2018, respectively.

ComEd, PECO and BGE



	ComEd											PECO										BGE
As of March 31, 2019	Level 1		Level 2			Level 3			Total			Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3		Total
Assets
Cash equivalents^(a)	$	194	$	—		$	—		$	194		$	16	$	—		$	—	$	16		$	3	$	—		$	—	$	3
Rabbi trust investments
Mutual funds	—		—			—			—			7		—			—		7			6		—			—		6
Life insurance contracts	—		—			—			—			—		10			—		10			—		—			—		—
Rabbi trust investments subtotal^(b)	—		—			—			—			7		10			—		17			6		—			—		6
Total assets	194		—			—			194			23		10			—		33			9		—			—		9
Liabilities
Deferred compensation obligation	—		(7		)	—			(7		)	—		(10		)	—		(10		)	—		(5		)	—		(5		)
Mark-to-market derivative liabilities^(c)	—		—			(240		)	(240		)	—		—			—		—			—		—			—		—
Total liabilities	—		(7		)	(240		)	(247		)	—		(10		)	—		(10		)	—		(5		)	—		(5		)
Total net assets (liabilities)	$	194	$	(7	)	$	(240	)	$	(53	)	$	23	$	—		$	—	$	23		$	9	$	(5	)	$	—	$	4



	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^(b)	—		—			—			—			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^(c)	—		—			(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 amount of unrealized gains/(losses) at ComEd, PECO and BGE totaled less than $1 million for the three months ended March 31, 2019 and March 31, 2018.


(c)	The Level 3 balance consists of the current and noncurrent liability of $27 million and $213 million, respectively, at March 31, 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 March 31, 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)	$	63	$	—		$	—	$	63		$	147	$	—		$	—	$	147
Rabbi trust investments
Cash equivalents	42		—			—		42			42		—			—		42
Mutual funds	14		—			—		14			13		—			—		13
Fixed income	—		14			—		14			—		15			—		15
Life insurance contracts	—		22			39		61			—		22			38		60
Rabbi trust investments subtotal^(b)	56		36			39		131			55		37			38		130
Total assets	119		36			39		194			202		37			38		277
Liabilities
Deferred compensation obligation	—		(20		)	—		(20		)	—		(21		)	—		(21		)
Total liabilities	—		(20		)	—		(20		)	—		(21		)	—		(21		)
Total net assets	$	119	$	16		$	39	$	174		$	202	$	16		$	38	$	256



	Pepco										DPL										ACE
As of March 31, 2019	Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3		Total			Level 1		Level 2		Level 3		Total
Assets
Cash equivalents^(a)	$	35	$	—		$	—	$	35		$	2	$	—		$	—	$	2		$	21	$	—	$	—	$	21
Rabbi trust investments
Cash equivalents	42		—			—		42			—		—			—		—			—		—		—		—
Fixed income	—		4			—		4			—		—			—		—			—		—		—		—
Life insurance contracts	—		22			38		60			—		—			—		—			—		—		—		—
Rabbi trust investments subtotal^(b)	42		26			38		106			—		—			—		—			—		—		—		—
Total assets	77		26			38		141			2		—			—		2			21		—		—		21
Liabilities
Deferred compensation obligation	—		(3		)	—		(3		)	—		(1		)	—		(1		)	—		—		—		—
Total liabilities	—		(3		)	—		(3		)	—		(1		)	—		(1		)	—		—		—		—
Total net assets (liabilities)	$	77	$	23		$	38	$	138		$	2	$	(1	)	$	—	$	1		$	21	$	—	$	—	$	21



	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^(b)	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)


(b)	The amount of unrealized gains/(losses) at PHI totaled less than $1 million for both the three months ended March 31, 2019 and 2018. The amount of unrealized gains/(losses) at Pepco totaled less than $1 million for both the three months ended March 31, 2019 and 2018

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 months ended March 31, 2019 and 2018:



	Generation												ComEd				PHI					Exelon
Three Months Ended March 31, 2019	NDT Fund Investments			Mark-to-Market Derivatives				Other Investments		Total Generation			Mark-to-Market Derivatives				Life Insurance Contracts^(c)		Eliminated in Consolidation			Total
Balance as of December 31, 2018	$	543		$	575			$	42	$	1,160		$	(249	)		$	38	$	—		$	949
Total realized / unrealized gains (losses)
Included in net income	2			(231		)	^(a)	—		(229		)	—				1		—			(228		)
Included in noncurrent payables to affiliates	11			—				—		11			—				—		(11		)	—
Included in regulatory assets/liabilities	—			—				—		—			9			^(b)	—		11			20
Change in collateral	—			81				—		81			—				—		—			81
Purchases, sales, issuances and settlements
Purchases	1			57				—		58			—				—		—			58
Sales	—			—				—		—			—				—		—			—
Settlements	(17		)	—				—		(17		)	—				—		—			(17		)
Transfers into Level 3	—			—			^(d)	—		—			—				—		—			—
Transfers out of Level 3	—			17			^(d)	—		17			—				—		—			17
Balance at March 31, 2019	$	540		$	499			$	42	$	1,081		$	(240	)		$	39	$	—		$	880
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of March 31, 2019	$	2		$	(151	)		$	—	$	(149	)	$	—			$	1	$	—		$	(148	)



	Generation													ComEd				PHI					Exelon
Three Months Ended March 31, 2018	NDT Fund Investments			Mark-to-Market Derivatives				Other Investments			Total Generation			Mark-to-Market Derivatives				Life Insurance Contracts^(c)		Eliminated in Consolidation			Total
Balance as of December 31, 2017	$	648		$	552			$	37		$	1,237		$	(256	)		$	22	$	—		$	1,003
Total realized / unrealized gains (losses)
Included in net income	—			184			^(a)	1			185			—				1		—			186
Included in noncurrent payables to affiliates	7			—				—			7			—				—		(7		)	—
Included in regulatory assets	—			—				—			—			(11		)	^(b)	—		7			(4		)
Change in collateral	—			105				—			105			—				—		—			105
Purchases, sales, issuances and settlements
Purchases	2			88				—			90			—				—		—			90
Sales	—			(3		)		—			(3		)	—				—		—			(3		)
Issuances	—			—				—			—			—				—		—			—
Settlements	(48		)	—				—			(48		)	—				—		—			(48		)
Transfers into Level 3	—			(8		)	^(d)	—			(8		)	—				—		—			(8		)
Transfers out of Level 3	—			—			^(d)	(2		)	(2		)	—				—		—			(2		)
Balance as of March 31, 2018	$	609		$	918			$	36		$	1,563		$	(267	)		$	23	$	—		$	1,319
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of March 31, 2018	$	—		$	256			$	1		$	257		$	—			$	1	$	—		$	258

__________


(a)	Includes a reduction for the reclassification of $80 million and $72 million of realized gains due to the settlement of derivative contracts for the three months ended March 31, 2019 and 2018, respectively.

(b)


(c)	The amounts represented are life insurance contracts at Pepco.


(d)	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



	Generation								PHI		Exelon
	Operating Revenues			Purchased Power and Fuel			Other, net		Operating and Maintenance		Operating Revenues			Purchased Power and Fuel			Operating and Maintenance		Other, net
Total gains (losses) included in net income for the three months ended March 31, 2019	$	(128	)	$	(103	)	$	2	$	1	$	(128	)	$	(103	)	$	1	$	2
Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended March 31, 2019	(91		)	(60		)	2		1		(91		)	(60		)	1		2



	Generation							PHI		Exelon
	Operating Revenues		Purchased Power and Fuel			Other, net		Operating and Maintenance		Operating Revenues		Purchased Power and Fuel			Operating and Maintenance		Other, net
Total gains (losses) included in net income for the three months ended March 31, 2018	$	335	$	(151	)	$	1	$	1	$	335	$	(151	)	$	1	$	1
Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended March 31, 2018	309		(53		)	1		1		309		(53		)	1		1

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 March 31, 2019			Valuation Technique	Unobservable Input	Range
Mark-to-market derivatives — Economic Hedges (Exelon and Generation)^(a)(b)	$	278		Discounted Cash Flow	Forward power price	$9	-	$164
					Forward gas price	$1.76	-	$11.63
				Option Model	Volatility percentage	10%	-	334%

Mark-to-market derivatives — Proprietary trading (Exelon and Generation)^(a)(b)	$	64		Discounted Cash Flow	Forward power price	$9	-	$162

Mark-to-market derivatives (Exelon and ComEd)	$	(240	)	Discounted Cash Flow	Forward heat rate^(c)	10x	-	11x
					Marketability reserve	4%	-	8%
					Renewable factor	85%	-	120%



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

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

Mark-to-market derivatives (Exelon and ComEd)	$	(249	)	Discounted Cash Flow	Forward heat rate^(c)	10x	-	11x
					Marketability reserve	4%	-	8%
					Renewable factor	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 $157 million and $76 million as of March 31, 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)

3 Months Ended

Mar. 31, 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 the Registrants as of March 31, 2019:



	Generation												ComEd			Exelon
Derivatives	Economic Hedges			Proprietary Trading			Collateral and Netting^(a)(d)			Subtotal^(b)			Economic Hedges^(c)			Total Derivatives
Mark-to-market derivative assets (current assets)	$	2,691		$	118		$	(2,156	)	$	653		$	—		$	653
Mark-to-market derivative assets (noncurrent assets)	1,188			60			(794		)	454			—			454
Total mark-to-market derivative assets	3,879			178			(2,950		)	1,107			—			1,107
Mark-to-market derivative liabilities (current liabilities)	(2,711		)	(89		)	2,485			(315		)	(27		)	(342		)
Mark-to-market derivative liabilities (noncurrent liabilities)	(1,142		)	(30		)	957			(215		)	(213		)	(428		)
Total mark-to-market derivative liabilities	(3,853		)	(119		)	3,442			(530		)	(240		)	(770		)
Total mark-to-market derivative net assets (liabilities)	$	26		$	59		$	492		$	577		$	(240	)	$	337

_________

(a)


(b)	Current and noncurrent assets are shown net of collateral of $152 million and $63 million, respectively, and current and noncurrent liabilities are shown net of collateral of $177 million and $100 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $492 million at March 31, 2019.


(c)	Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.


(d)	Of the collateral posted/(received), $(33) million represents variation margin on the exchanges.

The following table provides a summary of the derivative fair value balances recorded by the Registrants as of December 31, 2018:



	Generation												ComEd			Exelon
Description	Economic Hedges			Proprietary Trading			Collateral and Netting^(a)(d)			Subtotal^(b)			Economic Hedges^(c)			Total Derivatives
Mark-to-market derivative assets (current assets)	$	3,505		$	105		$	(2,809	)	$	801		$	—		$	801
Mark-to-market derivative assets (noncurrent assets)	1,266			41			(862		)	445			—			445
Total mark-to-market derivative assets	4,771			146			(3,671		)	1,246			—			1,246
Mark-to-market derivative liabilities (current liabilities)	(3,429		)	(74		)	3,056			(447		)	(26		)	(473		)
Mark-to-market derivative liabilities (noncurrent liabilities)	(1,203		)	(20		)	972			(251		)	(223		)	(474		)
Total mark-to-market derivative liabilities	(4,632		)	(94		)	4,028			(698		)	(249		)	(947		)
Total mark-to-market derivative net assets (liabilities)	$	139		$	52		$	357		$	548		$	(249	)	$	299

_________

(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, and letters of credit and other forms of non-cash collateral. These are not reflected in the table above.


(b)	Current and noncurrent assets are shown net of collateral of $121 million and $51 million, respectively, and current and noncurrent liabilities are shown net of collateral of $125 million and $60 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $357 million at December 31, 2018.


(c)	Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.


(d)	Of the collateral posted/(received), $(94) million represents variation margin on the exchanges.

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

For the three months ended March 31, 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" in the Consolidated Statements of Cash Flows.



	Three Months Ended March 31,
	2019			2018
Income Statement Location	Gain (Loss)
Operating revenues	$	(50	)	$	(100	)
Purchased power and fuel	30			(167		)
Total Exelon and Generation	$	(20	)	$	(267	)

Schedule of Derivative Instruments Included in Trading Activities [Table Text Block]

For the three months ended March 31, 2019 and 2018 Exelon and Generation recognized the following net pre-tax commodity mark-to-market gains (losses) which are also included in the "Net fair value changes related to derivatives" in the Consolidated Statements of Cash Flows. The Utility Registrants do not execute derivatives for proprietary trading purposes.



	Three Months Ended March 31,
	2019		2018
Income Statement Location	Gain (Loss)
Operating revenues	$	2	$	2

Information on Generation's credit exposure for all derivative instruments, normal purchase normal sales, and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements



Credit-Risk Related Contingent Features	March 31, 2019			December 31, 2018
Gross fair value of derivative contracts containing this feature^(a)	$	(1,667	)	$	(1,723	)
Offsetting fair value of in-the-money contracts under master netting arrangements^(b)	1,177			1,105
Net fair value of derivative contracts containing this feature^(c)	$	(490	)	$	(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.



Rating as of March 31, 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	$	819	$	11	$	808	1	$	135
Non-investment grade	86		39		47
No external ratings
Internally rated — investment grade	162		—		162
Internally rated — non-investment grade	87		7		80
Total	$	1,154	$	57	$	1,097	1	$	135



Net Credit Exposure by Type of Counterparty	As of March 31, 2019
Financial institutions	$	13
Investor-owned utilities, marketers, power producers	762
Energy cooperatives and municipalities	287
Other	35
Total	$	1,097

_________


(a)	As of March 31, 2019, credit collateral held from counterparties where Generation had credit exposure included $37 million of cash and $19 million of letters of credit. The credit collateral does not include non-liquid collateral.

Debt and Credit Agreements (Tables)

3 Months Ended

Mar. 31, 2019

Debt Disclosure [Abstract]

Commercial Paper Borrowings



	Outstanding Commercial Paper at				Average Interest Rate on Commercial Paper Borrowings as of
Commercial Paper Issuer	March 31, 2019		December 31, 2018		March 31, 2019		December 31, 2018
Exelon	$	629	$	89	2.63	%	2.15	%
ComEd	322		—		2.64	%	2.14	%
BGE	106		35		2.59	%	2.18	%
PHI	201		54		2.62	%	2.15	%
PEPCO	105		40		2.62	%	2.24	%
DPL	5		—		2.61	%	2.07	%
ACE	91		14		2.62	%	2.21	%

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

During the three months ended March 31, 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

Funding to install energy conservation measures for the Fort Meade 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.

- 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://www.xbrl.org/2003/role/presentationRef
-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://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=84159872&loc=d3e21475-112644

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-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 4: http://www.xbrl.org/2003/role/presentationRef
-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://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 55
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=64930739&loc=d3e28878-108400

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=84159872&loc=d3e21538-112644

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=84159872&loc=d3e21506-112644

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=64930785&loc=d3e28541-108399

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=64930785&loc=d3e28551-108399

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 7
-URI http://asc.fasb.org/extlink&oid=84159872&loc=d3e21521-112644

+ Details

Income Taxes (Tables)

3 Months Ended

Mar. 31, 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 March 31, 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	3.9	3.1	8.2	1.0	6.3	4.7	2.1	6.5	6.7
Qualified NDT fund income	7.2	14.2	—	—	—	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(0.5)	(0.9)	(0.2)	—	(0.1)	(0.2)	(0.1)	(0.2)	(0.3)
Plant basis differences	(1.4)	—	(0.5)	(6.7)	(0.9)	(1.7)	(2.0)	(0.7)	(2.3)
Production tax credits and other credits	(0.8)	(1.5)	—	—	—	—	—	—	—
Noncontrolling interests	(0.6)	(1.1)	—	—	—	—	—	—	—
Excess deferred tax amortization	(4.7)	—	(8.5)	(2.5)	(7.9)	(19.4)	(17.9)	(15.6)	(23.9)
Other	0.1	(0.5)	0.3	0.2	—	(0.3)	0.4	0.7	(1.2)
Effective income tax rate	24.2%	34.3%	20.3%	13.0%	18.4%	4.1%	3.5%	11.7%	—%



	Three Months Ended March 31, 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	4.1	2.4	8.2	(3.9)	6.3	4.6	1.7	6.3	6.6
Qualified NDT fund income	(0.4)	(1.3)	—	—	—	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(1.3)	(4.3)	(0.2)	(0.1)	(0.1)	(0.2)	(0.1)	(0.2)	(0.3)
Plant basis differences	(2.7)	—	0.1	(14.2)	(0.7)	(2.6)	(3.4)	(1.3)	(2.6)
Production tax credits and other credits	(2.8)	(9.5)	(0.1)	—	—	—	—	—	—
Noncontrolling interests	(0.7)	(2.5)	—	—	—	—	—	—	—
Excess deferred tax amortization	(6.0)	—	(7.5)	(4.8)	(8.6)	(10.6)	(12.8)	(7.9)	(8.7)
Other	(2.8)	(1.3)	0.3	0.2	—	—	(0.3)	0.5	(3.5)
Effective income tax rate	8.4%	4.5%	21.8%	(1.8)%	17.9%	12.2%	6.1%	18.4%	12.5%

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

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



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
March 31, 2019	$	448	$	411	$	—	$	—	$	—	$	45	$	—	$	—	$	14



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

Nuclear Decommissioning (Tables)

3 Months Ended

Mar. 31, 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 March 31, 2019:



Nuclear decommissioning ARO at December 31, 2018 ^(a)(b)	$	10,005
Net increase due to changes in, and timing of, estimated future cash flows	223
Accretion expense	120
Costs incurred related to decommissioning plants	(19		)
Nuclear decommissioning ARO at March 31, 2019 ^(a)(b)	$	10,329

_________


(a)	Includes $41 million and $22 million as the current portion of the ARO at March 31, 2019 and December 31, 2018, respectively, which is included in Other current liabilities in Exelon’s and Generation’s Consolidated Balance Sheets.


(b)	Includes $760 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 March 31, 2019 and December 31, 2018, respectively. See Note 3 — Mergers, Acquisitions and Dispositions for additional information.

^[1]

[1]	Includes $41 million and $22 million as the current portion of the ARO at March 31, 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)

3 Months Ended

Mar. 31, 2019

Retirement Benefits [Abstract]

Schedule of Net Benefit Costs [Table Text Block]

The following table presents the components of Exelon's net periodic benefit costs, prior to capitalization, for the three months ended March 31, 2019 and 2018.



	Pension Benefits Three Months Ended March 31,						Other Postretirement Benefits Three Months Ended March 31,
	2019			2018			2019			2018
Components of net periodic benefit cost:
Service cost	$	89		$	101		$	24		$	28
Interest cost	221			201			47			43
Expected return on assets	(307		)	(312		)	(38		)	(43		)
Amortization of:
Prior service cost (benefit)	—			—			(45		)	(46		)
Actuarial loss	104			157			11			16
Net periodic benefit cost	$	107		$	147		$	(1	)	$	(2	)

Schedule Of Pension And Other Postretirement Benefit Costs



	Three Months Ended March 31,
Pension and Other Postretirement Benefit Costs	2019		2018
Exelon	$	106	$	145
Generation	31		51
ComEd	24		45
PECO	2		5
BGE	16		15
PHI	23		15
Pepco	6		4
DPL	4		—
ACE	4		3

Schedule Of Defined Contributions

Defined Contribution Savings Plans



	Three Months Ended March 31,
Savings Plan Matching Contributions	2019		2018
Exelon	$	31	$	32
Generation	13		15
ComEd	7		7
PECO	2		2
BGE	2		2
PHI	4		3
Pepco	1		1
DPL	1		1
ACE	1		—

Changes in Accumulated Other Comprehensive Income (Tables)

3 Months Ended

Mar. 31, 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 three months ended March 31, 2019 and 2018:



Three Months Ended March 31, 2019	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	$	(2	)	$	—	$	(2,960	)	$	(33	)	$	—		$	(2,995	)
OCI before reclassifications	—			—		(38		)	2			(1		)	(37		)
Amounts reclassified from AOCI^(b)	—			—		20			—			—			20
Net current-period OCI	—			—		(18		)	2			(1		)	(17		)
Ending balance	$	(2	)	$	—	$	(2,978	)	$	(31	)	$	(1	)	$	(3,012	)
Generation^(a)
Beginning balance	$	(4	)	$	—	$	—		$	(33	)	$	(1	)	$	(38	)
OCI before reclassifications	—			—		—			2			(1		)	1
Amounts reclassified from AOCI	1			—		—			—			—			1
Net current-period OCI	1			—		—			2			(1		)	2
Ending balance	$	(3	)	$	—	$	—		$	(31	)	$	(2	)	$	(36	)



Three Months Ended March 31, 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	8			—			18				1			—			27
Amounts reclassified from AOCI^(b)	—			—			44				—			—			44
Net current-period OCI	8			—			62				1			—			71
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard^(c)	—			(10		)	—				—			—			(10		)
Ending balance	$	(6	)	$	—		$	(2,936	)		$	(22	)	$	(1	)	$	(2,965	)
Generation^(a)
Beginning balance	$	(16	)	$	3		$	—			$	(23	)	$	(1	)	$	(37	)
OCI before reclassifications	7			—			—				(1		)	—			6
Amounts reclassified from AOCI	—			—			—				—			—			—
Net current-period OCI	7			—			—				(1		)	—			6
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard^(c)	—			(3		)	—				—			—			(3		)
Ending balance	$	(9	)	$	—		$	—			$	(24	)	$	(1	)	$	(34	)

_________


(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 March 31, 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

Total Reclassifications	$	(20	)	Net of tax

Three Months Ended March 31, 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

Total Reclassifications	$	(44	)	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 months ended March 31, 2019 and 2018:



	Three Months Ended March 31,
	2019			2018
Exelon
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	$	6		$	6
Actuarial loss reclassified to periodic benefit cost	(13		)	(22		)
Pension and non-pension postretirement benefit plans valuation adjustment	14			(7		)
Change in unrealized loss on cash flow hedges	—			(3		)
Change in unrealized loss on investments in unconsolidated affiliates	—			(1		)
Total	$	7		$	(27	)

Generation
Change in unrealized gain (loss) on cash flow hedges	$	1		$	(3	)
Change in unrealized loss on investments in unconsolidated affiliates	—			(1		)
Total	$	1		$	(4	)

Commitments and Contingencies (Tables)

3 Months Ended

Mar. 31, 2019

Commitments And Contingencies Tables Disclosure [Line Items]

Other Commitments

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 March 31, 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		$	123	$	90	$	71	$	12	$	7

The Registrants’ commercial commitments as of March 31, 2019, representing commitments potentially triggered by future events were as follows:



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Letters of credit	$	1,480	$	1,455	$	6	$	—	$	2	$	8	$	8	$	—	$	—
Surety bonds^(a)	1,597		1,376		51		9		17		40		32		5		3
Financing trust guarantees	378		—		200		178		—		—		—		—		—
Guaranteed lease residual values^(b)	26		—		—		—		—		26		8		11		7
Total commercial commitments	$	3,481	$	2,831	$	257	$	187	$	19	$	74	$	48	$	16	$	10

_________


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

(b)

Accrued environmental liabilities



March 31, 2019	Total environmental investigation and remediation reserve		Portion of total related to MGP investigation and remediation
Exelon	$	486	$	347
Generation	108		—
ComEd	320		318
PECO	27		25
BGE	5		4
PHI	26		—
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)

3 Months Ended

Mar. 31, 2019

Supplemental Financial Information [Abstract]

Schedule of Other Nonoperating Income, by Component

The following tables provide additional information about the Registrants’ Consolidated Statements of Operations and Comprehensive Income for the three months ended March 31, 2019 and 2018.



	Three Months Ended March 31, 2019
	Exelon			Generation			ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Other, Net
Decommissioning-related activities:
Net realized income on NDT funds^(a)
Regulatory agreement units^(b)	$	54		$	54		$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-regulatory agreement units	54			54			—		—		—		—		—		—		—
Net unrealized gains on NDT funds
Regulatory agreement units^(b)	379			379			—		—		—		—		—		—		—
Non-regulatory agreement units	280			280			—		—		—		—		—		—		—
Regulatory offset to NDT fund-related activities^(c)	(348		)	(348		)	—		—		—		—		—		—		—
Total decommissioning-related activities	419			419			—		—		—		—		—		—		—
Investment income	12			7			—		1		—		—		—		—		—
Interest income related to uncertain income tax positions	1			—			—		—		—		—		—		—		—
AFUDC — Equity	22			—			5		3		5		9		6		1		2
Non-service net periodic benefit cost	5			—			—		—		—		—		—		—		—
Other	8			4			3		—		—		3		1		2		1
Other, net	$	467		$	430		$	8	$	4	$	5	$	12	$	7	$	3	$	3



	Three Months Ended March 31, 2018
	Exelon			Generation			ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Other, Net
Decommissioning-related activities:
Net realized income on NDT funds^(a)
Regulatory agreement units^(b)	$	46		$	46		$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-regulatory agreement units	56			56			—		—		—		—		—		—		—
Net unrealized losses on NDT funds
Regulatory agreement units^(b)	(75		)	(75		)	—		—		—		—		—		—		—
Non-regulatory agreement units	(96		)	(96		)	—		—		—		—		—		—		—
Regulatory offset to NDT fund-related activities^(c)	24			24			—		—		—		—		—		—		—
Total decommissioning-related activities	(45		)	(45		)	—		—		—		—		—		—		—
Investment income	4			2			—		—		—		—		—		—		—
Interest income related to uncertain income tax positions	2			1			—		—		—		—		—		—		—
AFUDC — Equity	18			—			6		2		4		6		5		1		—
Non-service net periodic benefit cost	(10		)	—			—		—		—		—		—		—		—
Other	3			(2		)	2		—		—		5		3		1		1
Other, net	$	(28	)	$	(44	)	$	8	$	2	$	4	$	11	$	8	$	2	$	1

_________


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


(b)	Net realized and unrealized gains (losses) related to Generation’s NDT funds associated with Regulatory Agreement Units are included in Regulatory liabilities in Exelon’s Consolidated Balance Sheets and Noncurrent payables to affiliates in Generation’s Consolidated Balance Sheets.


(c)	Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units, including the elimination of net 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.

Schedule Of Taxes Excluding Income And Excise Taxes [Table Text Block]



	Three Months Ended March 31, 2019
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Utility taxes	$	223	$	26	$	62	$	34	$	27	$	74	$	69	$	5	$	—



	Three Months Ended March 31, 2018
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Utility taxes	$	235	$	32	$	61	$	33	$	26	$	83	$	77	$	6	$	—

Cash Flow Supplemental Disclosures

The following tables provide additional information regarding the Registrants’ Consolidated Statements of Cash Flows for the three months ended March 31, 2019 and 2018.



	Three Months Ended March 31, 2019
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Depreciation, amortization and accretion
Property, plant and equipment^(a)	$	917	$	392	$	219	$	74	$	85	$	127	$	58	$	35	$	25
Amortization of regulatory assets^(a)	143		—		32		7		51		53		36		11		6
Amortization of intangible assets, net^(a)	15		13		—		—		—		—		—		—		—
Nuclear fuel^(c)	261		261		—		—		—		—		—		—		—
ARO accretion^(d)	124		123		—		—		—		—		—		—		—
Total depreciation, amortization and accretion	$	1,460	$	789	$	251	$	81	$	136	$	180	$	94	$	46	$	31



	Three Months Ended March 31, 2018
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Depreciation, amortization and accretion
Property, plant and equipment^(a)	$	926	$	436	$	201	$	68	$	82	$	117	$	53	$	32	$	23
Amortization of regulatory assets^(a)	152		—		27		7		52		66		43		13		10
Amortization of intangible assets, net^(a)	13		12		—		—		—		—		—		—		—
Amortization of energy contract assets and liabilities^(b)	3		3		—		—		—		—		—		—		—
Nuclear fuel^(c)	287		287		—		—		—		—		—		—		—
ARO accretion^(d)	120		120		—		—		—		—		—		—		—
Total depreciation, amortization and accretion	$	1,501	$	858	$	228	$	75	$	134	$	183	$	96	$	45	$	33

_________


(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.



	Three Months Ended March 31, 2019
	Exelon			Generation			ComEd			PECO			BGE			PHI			Pepco			DPL			ACE
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	106		$	31		$	24		$	2		$	15		$	23		$	6		$	4		$	4
Loss from equity method investments	6			6			—			—			—			—			—			—			—
Provision for uncollectible accounts	43			—			9			16			8			10			4			4			2
Stock-based compensation costs	28			—			—			—			—			—			—			—			—
Other decommissioning-related activity^(a)	(202		)	(202		)	—			—			—			—			—			—			—
Energy-related options^(b)	37			37			—			—			—			—			—			—			—
Amortization of regulatory asset related to debt costs	3			—			—			—			—			1			—			—			—
Amortization of rate stabilization deferral	(6		)	—			—			—			—			(6		)	(7		)	1			—
Amortization of debt fair value adjustment	(4		)	(3		)	—			—			—			(1		)	—			—			—
Discrete impacts from EIMA and FEJA^(c)	28			—			28			—			—			—			—			—			—
Amortization of debt costs	9			3			1			—			—			1			1			—			—
Long-term incentive plan	25			—			—			—			—			—			—			—			—
Amortization of operating ROU asset	53			34			1			—			8			9			2			2			1
Other	1			4			(7		)	(2		)	(4		)	(2		)	(3		)	—			(2		)
Total other non-cash operating activities	$	127		$	(90	)	$	56		$	16		$	27		$	35		$	3		$	11		$	5
Non-cash investing and financing activities:
Change in capital expenditures not paid	$	(229	)	$	(93	)	$	(80	)	$	8		$	2		$	(55	)	$	(15	)	$	(17	)	$	(24	)
Change in PPE related to ARO update	301			301			—			—			—			—			—			—			—
Dividends on stock compensation	1			—			—			—			—			—			—			—			—



	Three Months Ended March 31, 2018
	Exelon			Generation			ComEd			PECO			BGE			PHI		Pepco			DPL		ACE
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	145		$	51		$	45		$	5		$	14		$	15	$	4		$	—	$	3
Loss from equity method investments	7			7			—			—			—			—		—			—		—
Provision for uncollectible accounts	64			11			8			17			8			20		6			8		5
Stock-based compensation costs	29			—			—			—			—			—		—			—		—
Other decommissioning-related activity^(a)	(31		)	(31		)	—			—			—			—		—			—		—
Energy-related options^(b)	(7		)	(7		)	—			—			—			—		—			—		—
Amortization of regulatory asset related to debt costs	2			—			1			—			—			1		—			—		—
Amortization of rate stabilization deferral	7			—			—			—			—			7		1			6		—
Amortization of debt fair value adjustment	(3		)	(3		)	—			—			—			—		—			—		—
Discrete impacts from EIMA and FEJA^(c)	(4		)	—			(4		)	—			—			—		—			—		—
Amortization of debt costs	9			3			1			—			—			1		—			—		—
Provision for excess and obsolete inventory	13			12			1			—			—			—		—			—		—
Other	9			2			(6		)	(1		)	(2		)	9		(1		)	5		1
Total other non-cash operating activities	$	240		$	45		$	46		$	21		$	20		$	53	$	10		$	19	$	9
Non-cash investing and financing activities:
Change in capital expenditures not paid	$	(177	)	$	(131	)	$	(48	)	$	(25	)	$	(11	)	$	61	$	19		$	14	$	27
Change in PPE related to ARO update	32			32			—			—			—			—		—			—		—
Dividends on stock compensation	1			—			—			—			—			—		—			—		—

_________

(a)


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


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



March 31, 2019	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Cash and cash equivalents	$	880	$	537	$	68	$	41	$	12	$	33	$	11	$	7	$	6
Restricted cash	223		139		17		6		4		39		35		1		3
Restricted cash included in other long-term assets	211		—		193		—		—		19		—		—		19
Total cash, cash equivalents and restricted cash	$	1,314	$	676	$	278	$	47	$	16	$	91	$	46	$	8	$	28



December 31, 2018	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
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



March 31, 2018	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Cash and cash equivalents	$	787	$	610	$	70	$	21	$	22	$	43	$	15	$	7	$	10
Restricted cash	209		127		9		5		2		40		33		—		7
Restricted cash included in other long-term assets	103		—		83		—		—		20		—		—		20
Total cash, cash equivalents and restricted cash	$	1,099	$	737	$	162	$	26	$	24	$	103	$	48	$	7	$	37



December 31, 2017	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
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 assets and liabilities of the Registrants as of March 31, 2019 and December 31, 2018.



March 31, 2019	Exelon			Generation			ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Property, plant and equipment:
Accumulated depreciation and amortization	$	23,695	^(a)	$	12,663	^(a)	$	4,833	$	3,598	$	3,670	$	930	$	3,392	$	1,354	$	1,154
Accounts receivable:
Allowance for uncollectible accounts	$	340		$	87		$	97	$	72	$	27	$	57	$	23	$	15	$	19



December 31, 2018	Exelon			Generation			ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Property, plant and equipment:
Accumulated depreciation and amortization	$	22,902	^(b)	$	12,206	^(b)	$	4,684	$	3,561	$	3,633	$	841	$	3,354	$	1,329	$	1,137
Accounts receivable:
Allowance for uncollectible accounts	$	319		$	104		$	81	$	61	$	20	$	53	$	21	$	13	$	19

_________


(a)	Includes accumulated amortization of nuclear fuel in the reactor core of $3,040 million.


(b)	Includes accumulated amortization of nuclear fuel in the reactor core of $2,969 million.



March 31, 2019	Exelon			ComEd			PECO			BGE			PHI			Pepco			DPL			ACE
Purchased receivables	$	332		$	105		$	77		$	65		$	85		$	58		$	8		$	19
Allowance for uncollectible accounts^(a)	(38		)	(19		)	(6		)	(4		)	(9		)	(5		)	(1		)	(3		)
Purchased receivables, net	$	294		$	86		$	71		$	61		$	76		$	53		$	7		$	16



December 31, 2018	Exelon			ComEd			PECO			BGE			PHI			Pepco			DPL			ACE
Purchased receivables	$	313		$	94		$	74		$	61		$	84		$	57		$	8		$	19
Allowance for uncollectible accounts^(a)	(34		)	(17		)	(5		)	(3		)	(9		)	(5		)	(1		)	(3		)
Purchased receivables, net	$	279		$	77		$	69		$	58		$	75		$	52		$	7		$	16

__________


(a)	For ComEd, BGE, Pepco and DPL, reflects the incremental allowance for uncollectible accounts recorded, which is in addition to the purchase discount. For ComEd, the incremental uncollectible accounts expense is recovered through a rate rider. BGE, Pepco and DPL recover actual write-offs which are reflected in the POR discount rate.

Segment Information (Tables)

3 Months Ended

Mar. 31, 2019

Segment Reporting [Abstract]

Analysis and reconciliation of reportable segment information

Three Months Ended March 31, 2019 and 2018



	Generation^(a)		ComEd		PECO		BGE		PHI		Other^(b)		Intersegment Eliminations			Exelon
Operating revenues^(c):
2019
Competitive businesses electric revenues	$	4,337	$	—	$	—	$	—	$	—	$	—	$	(315	)	$	4,022
Competitive businesses natural gas revenues	879		—		—		—		—		—		(1		)	878
Competitive businesses other revenues	80		—		—		—		—		—		(1		)	79
Rate-regulated electric revenues	—		1,408		620		658		1,153		—		(8		)	3,831
Rate-regulated natural gas revenues	—		—		280		318		71		—		(4		)	665
Shared service and other revenues	—		—		—		—		4		455		(457		)	2
Total operating revenues	$	5,296	$	1,408	$	900	$	976	$	1,228	$	455	$	(786	)	$	9,477



	Generation^(a)		ComEd		PECO			BGE		PHI		Other^(b)			Intersegment Eliminations			Exelon
2018
Competitive businesses electric revenues	$	4,509	$	—	$	—		$	—	$	—	$	—		$	(391	)	$	4,118
Competitive businesses natural gas revenues	955		—		—			—		—		—			(8		)	947
Competitive businesses other revenues	48		—		—			—		—		—			—			48
Rate-regulated electric revenues	—		1,512		634			658		1,169		—			(18		)	3,955
Rate-regulated natural gas revenues	—		—		232			319		78		—			(4		)	625
Shared service and other revenues	—		—		—			—		4		451			(455		)	—
Total operating revenues	$	5,512	$	1,512	$	866		$	977	$	1,251	$	451		$	(876	)	$	9,693
Intersegment revenues^(d):
2019	$	317	$	4	$	1		$	6	$	4	$	453		$	(785	)	$	—
2018	400		14		2			6		4		450			(876		)	—
Depreciation and amortization:
2019	$	405	$	251	$	81		$	136	$	180	$	22		$	—		$	1,075
2018	448		228		75			134		183		23			—			1,091
Operating expenses:
2019	$	4,963	$	1,135	$	678		$	756	$	1,054	$	459		$	(783	)	$	8,262
2018	5,218		1,223		724			800		1,125		444			(886		)	8,648
Interest expense, net:
2019	$	111	$	87	$	33		$	29	$	65	$	78		$	—		$	403
2018	101		89		33			25		63		60			—			371
Income (loss) before income taxes:
2019	$	652	$	197	$	193		$	196	$	122	$	(78	)	$	—		$	1,282
2018	202		211		111			156		74		(52		)	—			702
Income Taxes:
2019	$	224	$	40	$	25		$	36	$	5	$	(20	)	$	—		$	310
2018	9		46		(2		)	28		9		(31		)	—			59
Net income (loss):
2019	$	422	$	157	$	168		$	160	$	117	$	(58	)	$	—		$	966
2018	186		165		113			128		65		(21		)	—			636
Capital Expenditures
2019	$	511	$	503	$	222		$	258	$	358	$	21		$	—		$	1,873
2018	628		531		217			224		258		22			—			1,880
Total assets:
March 31, 2019	$	48,682	$	31,582	$	10,956		$	9,967	$	22,294	$	8,325		$	(10,213	)	$	121,593
December 31, 2018	47,556		31,213		10,642			9,716		21,984		8,355			(9,800		)	119,666

__________

(a)


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


(c)	Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 17 — Supplemental Financial Information for additional information on total utility taxes.

(d)

PHI:



	Pepco		DPL		ACE		Other^(b)			Intersegment Eliminations			PHI
Operating revenues^(a):
2019
Rate-regulated electric revenues	$	575	$	310	$	273	$	—		$	(5	)	$	1,153
Rate-regulated natural gas revenues	—		70		—		—			1			71
Shared service and other revenues	—		—		—		106			(102		)	4
Total operating revenues	$	575	$	380	$	273	$	106		$	(106	)	$	1,228
2018
Rate-regulated electric revenues	$	557	$	306	$	310	$	—		$	(4	)	$	1,169
Rate-regulated natural gas revenues	—		78		—		—			—			78
Shared service and other revenues	—		—		—		113			(109		)	4
Total operating revenues	$	557	$	384	$	310	$	113		$	(113	)	$	1,251
Intersegment revenues:
2019	$	2	$	2	$	1	$	105		$	(106	)	$	4
2018	2		2		1		112			(113		)	4
Depreciation and amortization:
2019	$	94	$	46	$	31	$	10		$	(1	)	$	180
2018	96		45		33		9			—			183
Operating expenses:
2019	$	491	$	308	$	252	$	108		$	(105	)	$	1,054
2018	501		335		287		114			(112		)	1,125
Interest expense, net:
2019	$	34	$	15	$	14	$	3		$	(1	)	$	65
2018	31		13		16		2			1			63
Income (loss) before income taxes:
2019	$	57	$	60	$	10	$	113		$	(118	)	$	122
2018	33		38		8		64			(69		)	74
Income Taxes:
2019	$	2	$	7	$	—	$	(4	)	$	—		$	5
2018	2		7		1		(1		)	—			9
Net income (loss):
2019	$	55	$	53	$	10	$	(5	)	$	4		$	117
2018	31		31		7		(8		)	4			65
Capital Expenditures
2019	$	144	$	78	$	128	$	8		$	—		$	358
2018	127		65		63		3			—			258
Total assets:
March 31, 2019	$	8,420	$	4,660	$	3,783	$	10,909		$	(5,478	)	$	22,294
December 31, 2018	8,299		4,588		3,699		10,819			(5,421		)	21,984

__________


(a)	Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 17 — Supplemental Financial Information for additional information on total utility taxes.


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

Competitive Business Revenues (Generation):



	Three Months Ended March 31, 2019
	Revenues from external parties^(a)							Intersegment revenues			Total Revenues
	Contracts with customers		Other^(b)			Total		Intersegment revenues			Total Revenues
Mid-Atlantic	$	1,286	$	(24	)	$	1,262	$	(6	)	$	1,256
Midwest	1,055		59			1,114		(6		)	1,108
New York	409		(16		)	393		—			393
ERCOT	130		79			209		3			212
Other Power Regions	1,165		194			1,359		(6		)	1,353
Total Competitive Businesses Electric Revenues	4,045		292			4,337		(15		)	4,322
Competitive Businesses Natural Gas Revenues	584		295			879		15			894
Competitive Businesses Other Revenues^(c)	120		(40		)	80		—			80
Total Generation Consolidated Operating Revenues	$	4,749	$	547		$	5,296	$	—		$	5,296

Analysis and reconciliation of reportable segment revenues for Generation

etitive Business Revenues (Generation):



	Three Months Ended March 31, 2019
	Revenues from external parties^(a)							Intersegment revenues			Total Revenues
	Contracts with customers		Other^(b)			Total		Intersegment revenues			Total Revenues
Mid-Atlantic	$	1,286	$	(24	)	$	1,262	$	(6	)	$	1,256
Midwest	1,055		59			1,114		(6		)	1,108
New York	409		(16		)	393		—			393
ERCOT	130		79			209		3			212
Other Power Regions	1,165		194			1,359		(6		)	1,353
Total Competitive Businesses Electric Revenues	4,045		292			4,337		(15		)	4,322
Competitive Businesses Natural Gas Revenues	584		295			879		15			894
Competitive Businesses Other Revenues^(c)	120		(40		)	80		—			80
Total Generation Consolidated Operating Revenues	$	4,749	$	547		$	5,296	$	—		$	5,296



	Three Months Ended March 31, 2018
	Revenues from external customers^(a)							Intersegment revenues			Total Revenues
	Contracts with customers		Other^(b)			Total		Intersegment revenues			Total Revenues
Mid-Atlantic	$	1,355	$	80		$	1,435	$	5		$	1,440
Midwest	1,273		71			1,344		2			1,346
New York	439		(29		)	410		(1		)	409
ERCOT	149		59			208		1			209
Other Power Regions	935		177			1,112		(32		)	1,080
Total Competitive Businesses Electric Revenues	4,151		358			4,509		(25		)	4,484
Competitive Businesses Natural Gas Revenues	522		433			955		25			980
Competitive Businesses Other Revenues^(c)	134		(86		)	48		—			48
Total Generation Consolidated Operating Revenues	$	4,807	$	705		$	5,512	$	—		$	5,512

__________


(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 $52 million and $98 million in 2019 and 2018, respectively, and elimination of intersegment revenues.

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



	Three Months Ended March 31, 2019							Three Months Ended March 31, 2018
	RNF from external customers^(a)		Intersegment RNF			Total RNF		RNF from external customers^(a)			Intersegment RNF			Total RNF
Mid-Atlantic	$	679	$	4		$	683	$	836		$	14		$	850
Midwest	769		2			771		847			13			860
New York	262		3			265		282			1			283
ERCOT	98		(24		)	74		106			(70		)	36
Other Power Regions	174		(18		)	156		279			(43		)	236
Total Revenues net of purchased power and fuel for Reportable Segments	1,982		(33		)	1,949		2,350			(85		)	2,265
Other^(b)	109		33			142		(131		)	85			(46		)
Total Generation Revenues net of purchased power and fuel expense	$	2,091	$	—		$	2,091	$	2,219		$	—		$	2,219

__________


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

(b)

Electric and Gas Revenue by Customer Class (Utility Registrants)

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

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



	Three Months Ended March 31, 2019
Revenues from contracts with customers	ComEd			PECO			BGE		PHI		Pepco		DPL		ACE
Rate-regulated electric revenues
Residential	$	710		$	409		$	385	$	579	$	256	$	185	$	138
Small commercial & industrial	360			96			70		120		38		48		34
Large commercial & industrial	132			48			110		267		204		24		39
Public authorities & electric railroads	13			7			7		14		8		3		3
Other^(a)	217			62			80		157		53		47		57
Total rate-regulated electric revenues^(b)	$	1,432		$	622		$	652	$	1,137	$	559	$	307	$	271
Rate-regulated natural gas revenues
Residential	$	—		$	198		$	219	$	44	$	—	$	44	$	—
Small commercial & industrial	—			72			35		19		—		19		—
Large commercial & industrial	—			1			50		1		—		1		—
Transportation	—			7			—		4		—		4		—
Other^(c)	—			2			4		3		—		3		—
Total rate-regulated natural gas revenues^(d)	$	—		$	280		$	308	$	71	$	—	$	71	$	—
Total rate-regulated revenues from contracts with customers	$	1,432		$	902		$	960	$	1,208	$	559	$	378	$	271

Other revenues
Revenues from alternative revenue programs	$	(28	)	$	(3	)	$	10	$	15	$	14	$	—	$	1
Other rate-regulated electric revenues^(e)	4			1			3		4		2		1		1
Other rate-regulated natural gas revenues^(e)	—			—			3		1		—		1		—
Total other revenues	$	(24	)	$	(2	)	$	16	$	20	$	16	$	2	$	2
Total rate-regulated revenues for reportable segments	$	1,408		$	900		$	976	$	1,228	$	575	$	380	$	273



	Three Months Ended March 31, 2018
Revenues from contracts with customers	ComEd		PECO			BGE			PHI		Pepco		DPL		ACE
Rate-regulated electric revenues
Residential	$	717	$	403		$	393		$	610	$	259	$	191	$	160
Small commercial & industrial	385		101			68			115		32		46		37
Large commercial & industrial	152		58			106			259		190		23		46
Public authorities & electric railroads	14		8			7			14		7		4		3
Other^(a)	230		62			78			156		49		41		66
Total rate-regulated electric revenues^(b)	$	1,498	$	632		$	652		$	1,154	$	537	$	305	$	312
Rate-regulated natural gas revenues
Residential	$	—	$	161		$	224		$	47	$	—	$	47	$	—
Small commercial & industrial	—		62			34			18		—		18		—
Large commercial & industrial	—		1			47			4		—		4		—
Transportation	—		6			—			5		—		5		—
Other^(c)	—		2			27			4		—		4		—
Total rate-regulated natural gas revenues^(d)	$	—	$	232		$	332		$	78	$	—	$	78	$	—
Total rate-regulated revenues from contracts with customers	$	1,498	$	864		$	984		$	1,232	$	537	$	383	$	312

Other revenues
Revenues from alternative revenue programs	$	5	$	(1	)	$	(13	)	$	18	$	19	$	1	$	(2	)
Other rate-regulated electric revenues^(e)	9		3			4			1		1		—		—
Other rate-regulated natural gas revenues^(e)	—		—			2			—		—		—		—
Total other revenues	$	14	$	2		$	(7	)	$	19	$	20	$	1	$	(2	)
Total rate-regulated revenues for reportable segments	$	1,512	$	866		$	977		$	1,251	$	557	$	384	$	310

__________


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


(b)	Includes operating revenues from affiliates of $4 million, $1 million, $2 million, $3 million, $2 million, $2 million and $1 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2019 and $14 million, $2 million, $2 million, $4 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.

Variable Interest Entities - Narrative (Details) $ in Millions	3 Months Ended
	Mar. 31, 2019 USD ($) VIE	Mar. 31, 2018 USD ($)	Dec. 31, 2018 VIE	Apr. 01, 2014 USD ($)
Variable Interest Entity [Line Items]
Number Of Variable Interest Entities Consolidated \| VIE	5		5
Number of Variable Interest Entities not consolidated by equity holders \| VIE	7		7
Guarantor Obligations, Maximum Exposure, Undiscounted	$ 68
Variable Interest Entity, Nonconsolidated, Carrying Amount, Assets and Liabilities, Net	16
Variable Interest Entity, Reporting Entity Involvement, Maximum Loss Exposure, Amount	16
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]
Guarantor Obligations, Current Carrying Value	32
Variable Interest Entity, Nonconsolidated, Carrying Amount, Assets and Liabilities, Net	12
Variable Interest Entity, Reporting Entity Involvement, Maximum Loss Exposure, Amount	12
Exelon Generation Co L L C [Member] \| CENG [Member]
Variable Interest Entity [Line Items]
Guarantor Obligations, Current Carrying Value	$ 688
Equity Method Investment, Ownership Percentage	50.01%
Due from Affiliates				$ 400
Atlantic City Electric Company [Member]
Variable Interest Entity [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	$ 17
Atlantic City Electric Company [Member] \| ATF [Member]
Variable Interest Entity [Line Items]
Cash Remitted To VIE	$ 4	$ 8

Variable Interest Entities - Carrying Amounts and Classification of Consolidated VIE Assets and Liabilities (Details) - USD ($)
$ in Millions

Mar. 31, 2019

Dec. 31, 2018

Current assets

$ 645

$ 938

Noncurrent assets

9,235

9,071

^[1]

9,880

10,009

Current liabilities

748

274

2,831

3,280

^[1]

3,579

3,554

Current assets

639

931

Noncurrent assets

9,210

9,045

9,849

9,976

Current liabilities

725

252

2,790

3,233

3,515

3,485

^[1]

^[1]

$ 54

$ 59

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

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

Mar. 31, 2019

Dec. 31, 2018

Mar. 31, 2018

Dec. 31, 2017

$ 880

$ 1,349

$ 787

$ 898

223

247

209

207

4,564

4,607

1,062

1,256

1,380

1,351

1,406

1,238

12,476

13,360

77,460

76,707

12,302

11,661

3,017

1,575

^[1]

121,593

119,666

2,508

1,349

3,327

3,800

1,725

2,112

151

149

1,245

1,035

12,229

11,404

32,960

34,075

9,967

9,679

432

463

3,158

2,130

Variable Interest Entity, Primary Beneficiary [Member]

^[1]

87,889

86,596

125

414

152

146

213

212

^[2]

622

913

6,147

6,145

2,520

2,351

257

258

^[2]

8,924

8,754

^[2]

9,546

9,667

567

120

^[2]

748

273

565

1,072

2,190

2,160

^[2]

2,824

3,275

^[2]

3,572

3,548

537

750

610

416

139

153

127

138

2,800

2,941

367

562

965

963

1,013

883

7,721

8,433

24,034

23,981

12,302

11,661

1,813

755

^[3]

48,682

47,556

2,365

906

1,566

1,847

675

898

425

279

6,660

5,769

5,487

6,989

9,737

9,450

1,528

610

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

^[3]

32,986

32,048

125

414

152

146

213

212

616

906

6,147

6,145

2,520

2,351

232

8,899

8,728

9,515

9,634

545

120

725

252

524

1,025

2,190

2,160

2,783

3,228

3,508

3,480

124

445

453

189

177

184

163

1,453

1,533

13,619

13,446

370

^[4]

22,294

21,984

125

441

496

253

256

123

119

127

123

1,675

1,592

6,119

6,134

416

442

630

369

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

^[4]

13,004

12,702

^[2]

^[2]

^[2]

^[2]

^[2]

^[2]

$ 7

$ 6

238

240

3,041

2,966

^[5]

3,783

3,699

139

154

492

422

1,165

1,170

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

^[5]

2,654

2,573

$ 54

$ 59

[1]	Exelon’s consolidated assets include $9,546 million and $9,667 million at March 31, 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 $3,572 million and $3,548 million at March 31, 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]	Includes certain purchase accounting adjustments not pushed down to the ACE standalone entity.
[3]	Generation’s consolidated assets include $9,515 million and $9,634 million at March 31, 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 $3,508 million and $3,480 million at March 31, 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.
[4]	PHI’s consolidated total assets include $31 million and $33 million at March 31, 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 $64 million and $69 million at March 31, 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.
[5]	ACE’s consolidated total assets include $22 million and $23 million at March 31, 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 $54 million and $59 million at March 31, 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

Mar. 31, 2019

Dec. 31, 2018

^[1]

$ 1,064

$ 1,069

Exelon's ownership interest in VIE

^[1]

265

259

^[1]

214

223

Other ownership interests in VIE

^[1]

585

587

Carrying amount of equity method investments

Contract intangible asset

214

223

Commercial Agreement Variable Interest Entities [Member]

601

597

Exelon's ownership interest in VIE

Other ownership interests in VIE

559

560

Commercial Agreement Variable Interest Entities [Member] | Carrying amount of equity method investments

Commercial Agreement Variable Interest Entities [Member] | Contract intangible asset

Equity Investment VIE [Member]

463

472

Exelon's ownership interest in VIE

223

222

214

223

Other ownership interests in VIE

Equity Investment VIE [Member] | Carrying amount of equity method investments

Equity Investment VIE [Member] | Contract intangible asset

214

223

$ 0

Schedule of Components of Lease Cost [Line Items]

$ 12

[1]	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.

Mergers, Acquisitions and Dispositions - Narrative (Details) - USD ($) $ in Millions		3 Months Ended
	Feb. 28, 2018	Sep. 30, 2018	Mar. 31, 2019	Dec. 31, 2018
Business Dispositions [Line Items]
Assets held for sale			$ 890	$ 904
Liabilities held for sale			799	777
Proceeds from Divestiture of Businesses	$ 87
Exelon Generation Co L L C [Member]
Business Dispositions [Line Items]
Assets held for sale			890	904
Liabilities held for sale			799	777
Proceeds from Divestiture of Businesses	$ 87
Oyster Creek [Member]
Business Dispositions [Line Items]
Assets held for sale			888	897
Liabilities held for sale			765	777
Oyster Creek [Member] \| Exelon Generation Co L L C [Member]
Business Dispositions [Line Items]
Assets held for sale			888	897
Liabilities held for sale			$ 765	$ 777
Asset Retirement Obligation Revision Of Estimate In Operating And Maintenance Expense		$ 84

Revenue from Contracts with Customers Change in Contract with Customer, Asset and Liability (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Change in Contract with Customer, Asset and Liability [Line Items]
Contract with Customer, Asset, Net, Current	$ 187	$ 187	$ 283
Contract with Customer, Liability, Current	25	27	35
Increases (decreases) as a result of changes in the estimate of the stage of completion, contract assets	26	50
Increases (decreases) as a result of changes in the estimate of the stage of completion, contract liabilities	0	0
Increases (decreases) as a result of additional cash received or due, contract assets	0	0
Increases (decreases) as a result of additional cash received or due, contract liabilities	21	179
Amounts reclassified to receivables, contract assets	(26)	(146)
Amounts recognized into revenues, contract liabilities	(23)	(187)
Exelon Generation Co L L C [Member]
Change in Contract with Customer, Asset and Liability [Line Items]
Contract with Customer, Asset, Net, Current	187	187	283
Contract with Customer, Liability, Current	39	42	$ 35
Increases (decreases) as a result of changes in the estimate of the stage of completion, contract assets	26	50
Increases (decreases) as a result of changes in the estimate of the stage of completion, contract liabilities	0	0
Increases (decreases) as a result of additional cash received or due, contract assets	0	0
Increases (decreases) as a result of additional cash received or due, contract liabilities	63	465
Amounts reclassified to receivables, contract assets	(26)	(146)
Amounts recognized into revenues, contract liabilities	$ (66)	$ (458)

Leases Components of Lease Cost (Details)
$ in Millions

3 Months Ended

Mar. 31, 2019

USD ($)

$ 68

150

^[1]

Operating Lease, Weighted Average Remaining Lease Term

$ 3

10 years

Operating Lease Weighted Average Discount Rate, Percent

4.60%

Right-of-Use Asset Obtained in Exchange for Operating Lease Liability

$ 20

Schedule of Components of Lease Cost [Line Items]

122

^[1]

Operating Lease, Weighted Average Remaining Lease Term

$ 2

10 years 8 months 12 days

Operating Lease Weighted Average Discount Rate, Percent

4.80%

Right-of-Use Asset Obtained in Exchange for Operating Lease Liability

$ 9

Schedule of Components of Lease Cost [Line Items]

Operating Lease, Weighted Average Remaining Lease Term

$ 1

2 years 10 months 24 days

Operating Lease Weighted Average Discount Rate, Percent

3.30%

Right-of-Use Asset Obtained in Exchange for Operating Lease Liability

$ 0

Schedule of Components of Lease Cost [Line Items]

Operating Lease, Weighted Average Remaining Lease Term

$ 0

4 years 4 months 24 days

Operating Lease Weighted Average Discount Rate, Percent

3.40%

Right-of-Use Asset Obtained in Exchange for Operating Lease Liability

$ 0

Schedule of Components of Lease Cost [Line Items]

Operating Lease, Weighted Average Remaining Lease Term

$ 8

5 years 7 months 6 days

Operating Lease Weighted Average Discount Rate, Percent

3.60%

Right-of-Use Asset Obtained in Exchange for Operating Lease Liability

$ 0

Schedule of Components of Lease Cost [Line Items]

^[1]

Operating Lease, Weighted Average Remaining Lease Term

$ 1

9 years 4 months 24 days

Operating Lease Weighted Average Discount Rate, Percent

4.10%

Right-of-Use Asset Obtained in Exchange for Operating Lease Liability

$ 11

Schedule of Components of Lease Cost [Line Items]

Operating Lease, Weighted Average Remaining Lease Term

$ 3

9 years 10 months 24 days

Operating Lease Weighted Average Discount Rate, Percent

3.90%

Right-of-Use Asset Obtained in Exchange for Operating Lease Liability

$ 4

Schedule of Components of Lease Cost [Line Items]

^[1]

Operating Lease, Weighted Average Remaining Lease Term

$ 1

9 years 9 months 18 days

Operating Lease Weighted Average Discount Rate, Percent

3.90%

Right-of-Use Asset Obtained in Exchange for Operating Lease Liability

$ 4

Schedule of Components of Lease Cost [Line Items]

Operating Lease, Weighted Average Remaining Lease Term

$ 1

5 years 3 months 18 days

Operating Lease Weighted Average Discount Rate, Percent

3.50%

Right-of-Use Asset Obtained in Exchange for Operating Lease Liability

$ 3

[1]	Excludes $3 million, $2 million, $1 million and $1 million of sublease income recorded at Exelon, Generation, PHI and DPL.

Leases Lessee Future Minimum Operating Lease Maturity Payments (Details)
$ in Millions

Mar. 31, 2019

USD ($)

Schedule of Lessee, Operating Lease, Liability, Maturity [Line Items]

$ 214

289

244

174

139

1,052

2,112

468

1,644

^[1]

Schedule of Lessee, Operating Lease, Liability, Maturity [Line Items]

154

202

162

112

840

1,569

373

1,196

^[1]

Schedule of Lessee, Operating Lease, Liability, Maturity [Line Items]

Schedule of Lessee, Operating Lease, Liability, Maturity [Line Items]

Schedule of Lessee, Operating Lease, Liability, Maturity [Line Items]

119

Schedule of Lessee, Operating Lease, Liability, Maturity [Line Items]

194

391

320

Schedule of Lessee, Operating Lease, Liability, Maturity [Line Items]

Schedule of Lessee, Operating Lease, Liability, Maturity [Line Items]

103

Schedule of Lessee, Operating Lease, Liability, Maturity [Line Items]

Operating Leases Future Minimum Payments Due [Line Items]

$ 26

[1]	Exelon's and Generation's operating ROU assets and lease liabilities include $631 million and $778 million, respectively, related to contracted generation.

Leases Lessee 2018 Schedule of Minimum Future Operating Lease Payments (Details)
$ in Millions

Dec. 31, 2018

USD ($)

2019

$ 140

^[1],[2]

2020

149

^[1],[2]

2021

143

^[1],[2]

2022

126

^[1],[2]

2023

^[1],[2]

Remaining Years

723

^[1],[2]

1,378

^[1],[2]

Operating Leases Future Minimum Payments Due [Line Items]

^[1],[2]

^[1],[2]

^[1],[2]

^[1],[2]

^[1],[2]

545

^[1],[2]

763

^[1],[2]

Operating Leases Future Minimum Payments Due [Line Items]

^[2],[3]

^[2],[3]

^[2],[3]

^[2],[3]

^[2],[3]

^[2],[3]

^[2],[3]

Operating Leases Future Minimum Payments Due [Line Items]

^[2],[3]

^[2],[3]

^[2],[3]

^[2],[3]

^[2],[3]

^[2],[3]

^[2],[3]

Operating Leases Future Minimum Payments Due [Line Items]

^{[2],[3],[4],[5]}

^{[2],[3],[4],[5]}

^{[2],[3],[4],[5]}

^{[2],[3],[4],[5]}

^{[2],[3],[4],[5]}

^{[2],[3],[4],[5]}

143

^{[2],[3],[4],[5]}

Operating Leases Future Minimum Payments Due [Line Items]

^[2]

^[2]

^[2]

^[2]

^[2]

159

^[2]

377

^[2]

Operating Leases Future Minimum Payments Due [Line Items]

^[2]

^[2]

^[2]

^[2]

^[2]

^[2]

^[2]

Operating Leases Future Minimum Payments Due [Line Items]

^[2],[3]

^[2],[3]

^[2],[3]

^[2],[3]

^[2],[3]

^[2],[3]

^[2],[3]

Operating Leases Future Minimum Payments Due [Line Items]

^[2]

^[2]

^[2]

^[2]

^[2]

^[2]

Real Estate Leases and Railroad Licenses [Member] | Commonwealth Edison Co [Member]

^[2]

Operating Leases Future Minimum Payments Due [Line Items]

Real Estate Leases and Railroad Licenses [Member] | PECO Energy Co [Member]

Operating Leases Future Minimum Payments Due [Line Items]

Real Estate Leases and Railroad Licenses [Member] | Baltimore Gas and Electric Company [Member]

Operating Leases Future Minimum Payments Due [Line Items]

Real Estate Leases and Railroad Licenses [Member] | Delmarva Power and Light Company [Member]

Operating Leases Future Minimum Payments Due [Line Items]

Electrical Conduit System [Member] | Baltimore Gas and Electric Company [Member]

Operating Leases Future Minimum Payments Due [Line Items]

$ 14

[1]	Excludes Generation’s contingent operating lease payments associated with contracted generation.
[2]	Includes amounts related to shared use land arrangements.
[3]	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.
[4]	Includes all future lease payments on a 99-year real estate lease that expires in 2106.
[5]	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.

Leases Supplemental Cash Flow Information Related to Leases (Details) $ in Millions	3 Months Ended
	Mar. 31, 2019 USD ($)
Supplemental Cash Flow Information [Line Items]
Operating cash flows from operating leases	$ 78
Exelon Generation Co L L C [Member]
Supplemental Cash Flow Information [Line Items]
Operating cash flows from operating leases	52
Commonwealth Edison Co [Member]
Supplemental Cash Flow Information [Line Items]
Operating cash flows from operating leases	1
PECO Energy Co [Member]
Supplemental Cash Flow Information [Line Items]
Operating cash flows from operating leases	0
Baltimore Gas and Electric Company [Member]
Supplemental Cash Flow Information [Line Items]
Operating cash flows from operating leases	14
Pepco Holdings LLC [Member]
Supplemental Cash Flow Information [Line Items]
Operating cash flows from operating leases	8
Potomac Electric Power Company [Member]
Supplemental Cash Flow Information [Line Items]
Operating cash flows from operating leases	2
Delmarva Power and Light Company [Member]
Supplemental Cash Flow Information [Line Items]
Operating cash flows from operating leases	2
Atlantic City Electric Company [Member]
Supplemental Cash Flow Information [Line Items]
Operating cash flows from operating leases	$ 1

Leases Components of Operating Lease Income (Details) $ in Millions	3 Months Ended
	Mar. 31, 2019 USD ($)
Schedule of Operating Lease, Lease Income [Line Items]
Operating Lease Income	$ 4
Variable Lease Income	52
Exelon Generation Co L L C [Member]
Schedule of Operating Lease, Lease Income [Line Items]
Operating Lease Income	3
Variable Lease Income	52
Commonwealth Edison Co [Member]
Schedule of Operating Lease, Lease Income [Line Items]
Operating Lease Income	0
Variable Lease Income	0
PECO Energy Co [Member]
Schedule of Operating Lease, Lease Income [Line Items]
Operating Lease Income	0
Variable Lease Income	0
Baltimore Gas and Electric Company [Member]
Schedule of Operating Lease, Lease Income [Line Items]
Operating Lease Income	0
Variable Lease Income	0
Pepco Holdings LLC [Member]
Schedule of Operating Lease, Lease Income [Line Items]
Operating Lease Income	1
Variable Lease Income	0
Potomac Electric Power Company [Member]
Schedule of Operating Lease, Lease Income [Line Items]
Operating Lease Income	0
Variable Lease Income	0
Delmarva Power and Light Company [Member]
Schedule of Operating Lease, Lease Income [Line Items]
Operating Lease Income	1
Variable Lease Income	0
Atlantic City Electric Company [Member]
Schedule of Operating Lease, Lease Income [Line Items]
Operating Lease Income	0
Variable Lease Income	$ 0

Leases Lessor Future Minimum Operating Lease Maturity Payments (Details) $ in Millions	Mar. 31, 2019 USD ($)
Schedule of Lessor, Operating Lease, Payments to be Received, Maturity [Line Items]
2019	$ 47
2020	51
2021	50
2022	50
2023	49
Remaining years	315
Total Lessor, Operating Lease, Payments to be Received	562
Exelon Generation Co L L C [Member]
Schedule of Lessor, Operating Lease, Payments to be Received, Maturity [Line Items]
2019	43
2020	46
2021	45
2022	45
2023	45
Remaining years	271
Total Lessor, Operating Lease, Payments to be Received	495
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 Lessor, Operating Lease, Payments to be Received	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 Lessor, Operating Lease, Payments to be Received	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 Lessor, Operating Lease, Payments to be Received	1
Pepco Holdings LLC [Member]
Schedule of Lessor, Operating Lease, Payments to be Received, Maturity [Line Items]
2019	4
2020	4
2021	4
2022	4
2023	4
Remaining years	39
Total Lessor, Operating Lease, Payments to be Received	59
Potomac Electric Power 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 Lessor, Operating Lease, Payments to be Received	1
Delmarva Power and Light Company [Member]
Schedule of Lessor, Operating Lease, Payments to be Received, Maturity [Line Items]
2019	3
2020	3
2021	3
2022	3
2023	3
Remaining years	38
Total Lessor, Operating Lease, Payments to be Received	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 Lessor, Operating Lease, Payments to be Received	$ 0

Regulatory Matters - Narrative (Details) - USD ($) $ in Millions				3 Months Ended		7 Months Ended
	Apr. 15, 2019	Feb. 28, 2019	May 01, 2017	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2018
Regulatory Matters Additional Narrative Information [Line Items]
Payments to Acquire Property, Plant, and Equipment				$ 1,873	$ 1,880
Maximum [Member] \| One-Time Revenue Adjustment [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Amount of Impairment to Carrying Amount of Regulatory Assets							$ 76
Exelon Generation Co L L C [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Payments to Acquire Property, Plant, and Equipment				511	628
License Costs				38
Commonwealth Edison Co [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Payments to Acquire Property, Plant, and Equipment				503	531
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							51
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%
Prior Year Revenue Adjustment				6
Payments to Acquire Property, Plant, and Equipment				222	217
PECO Energy Co [Member] \| Electric Transmission [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Tax Savings From Tax Cuts and Jobs Act				20
Baltimore Gas and Electric Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Payments to Acquire Property, Plant, and Equipment				258	224
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							15
Pepco Holdings LLC [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Payments to Acquire Property, Plant, and Equipment				358	258
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
Potomac Electric Power Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Payments to Acquire Property, Plant, and Equipment				144	127
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
Delmarva Power and Light Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Payments to Acquire Property, Plant, and Equipment				78	65
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
Atlantic City Electric Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Payments to Acquire Property, Plant, and Equipment		$ 338		$ 128	$ 63
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
Atlantic City Electric Company [Member] \| Subsequent Event [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Payments to Acquire Property, Plant, and Equipment	$ 96
Zero Emission Standard [Member] \| Exelon Generation Co L L C [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Other Revenue, Net						$ 150
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 Share				42.59%

Regulatory Matters Schedule of Completed Rate Cases (Details) (Details) - USD ($)
$ in Millions

Mar. 13, 2019

Jan. 04, 2019

Nov. 19, 2018

Jun. 08, 2018

Baltimore Gas and Electric Company [Member] | Gas Distribution [Member]

Regulatory Matters Completed Rate Cases [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 61

Public Utilities, Requested Rate Increase (Decrease), Amended, Amount

$ 43

Public Utilities, Requested Return on Equity, Percentage

9.80%

Atlantic City Electric Company [Member] | Electric Distribution [Member]

Regulatory Matters Completed Rate Cases [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

^[1]

$ 122

Public Utilities, Requested Rate Increase (Decrease), Amended, Amount

^[1]

$ 70

Public Utilities, Requested Return on Equity, Percentage

9.60%

[1]	Requested and approved increases are before New Jersey sales and use tax

Regulatory Matters Schedule of Pending Rate Cases (Details) (Details) - Electric Distribution [Member] - USD ($)
$ in Millions

12 Months Ended

Apr. 08, 2019

Jan. 15, 2019

Dec. 31, 2018

Regulatory Matters Pending Rate Cases [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 27

Public Utilities, Requested Return on Equity, Percentage

10.30%

Regulatory Matters Pending Rate Cases [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 57

Public Utilities, Approved Rate Increase (Decrease), Amount

$ (63)

Public Utilities, Requested Equity Capital Structure, Percentage

6.53%

Subsequent Event [Member] | Commonwealth Edison Co [Member]

Regulatory Matters Pending Rate Cases [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amended, Amount

^[1]

$ (6)

Public Utilities, Requested Return on Equity, Percentage

^[1]

8.90%

[1]

Regulatory Matters - Capitalized Ratemaking Amount Not Recognized (Details) - USD ($)
$ in Millions

Mar. 31, 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

$ 64

$ 65

Public Utility, Property, Plant and Equipment [Line Items]

Public Utilities, Amount of Allowance for Earnings on Equity Capitalized for Rate Making Purposes

^[1]

Public Utility, Property, Plant and Equipment [Line Items]

Public Utilities, Amount of Allowance for Earnings on Equity Capitalized for Rate Making Purposes

Public Utility, Property, Plant and Equipment [Line Items]

Public Utilities, Amount of Allowance for Earnings on Equity Capitalized for Rate Making Purposes

^[2]

Public Utility, Property, Plant and Equipment [Line Items]

Public Utilities, Amount of Allowance for Earnings on Equity Capitalized for Rate Making Purposes

Public Utility, Property, Plant and Equipment [Line Items]

Public Utilities, Amount of Allowance for Earnings on Equity Capitalized for Rate Making Purposes

^[3]

Public Utility, Property, Plant and Equipment [Line Items]

Public Utilities, Amount of Allowance for Earnings on Equity Capitalized for Rate Making Purposes

^[3]

Public Utility, Property, Plant and Equipment [Line Items]

Public Utilities, Amount of Allowance for Earnings on Equity Capitalized for Rate Making Purposes

$ 0

[1]	Reflects ComEd's unrecognized equity returns earned for ratemaking purposes on its electric distribution formula rate regulatory assets.
[2]	BGE's authorized amounts capitalized for ratemaking purposes primarily relate to earnings on shareholders' investment on its AMI programs.
[3]	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.

Regulatory Matters - Annual Electric Transmission Fillings (Details) - USD ($)
$ in Millions

Mar. 13, 2019

Jan. 04, 2019

Nov. 19, 2018

Jun. 08, 2018

Baltimore Gas and Electric Company [Member] | Gas Distribution [Member]

Public Utilities, General Disclosures [Line Items]

Initial revenue requirement (decrease) increase

$ 61

Public Utilities, Requested Rate Increase (Decrease), Amended, Amount

$ 43

Public Utilities, Requested Return on Equity, Percentage

9.80%

Atlantic City Electric Company [Member] | Electric Distribution [Member]

Public Utilities, General Disclosures [Line Items]

Initial revenue requirement (decrease) increase

^[1]

$ 122

Public Utilities, Requested Rate Increase (Decrease), Amended, Amount

^[1]

$ 70

Public Utilities, Requested Return on Equity, Percentage

9.60%

[1]	Requested and approved increases are before New Jersey sales and use tax

Impairment of Long-Lived Assets - Narrative (Details) $ in Millions	Mar. 31, 2019 USD ($)
Antelope Valley [Member]
Property, Plant and Equipment [Line Items]
Long-lived assets	$ 750
Exelon Generation Co L L C [Member] \| Antelope Valley [Member]
Property, Plant and Equipment [Line Items]
Long-lived assets	750
ExGen Renewables IV, LLC [Member]
Property, Plant and Equipment [Line Items]
Long-lived assets	1,970
ExGen Renewables IV, LLC [Member] \| Exelon Generation Co L L C [Member]
Property, Plant and Equipment [Line Items]
Long-lived assets	$ 1,970

Early Plant Retirements - Narrative (Details)	Mar. 31, 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

Mar. 31, 2019

Mar. 31, 2018

Three Mile Island [Member]

^[1],[2]

$ 74

^[1]

^[3]

(83)

(4)

TMI,OysterCreek [Member]

^[1],[2]

$ 137

^[1]

^[3]

Exelon Generation Co L L C [Member] | Three Mile Island [Member]

178

^[1],[2]

^[1]

^[3]

(83)

Exelon Generation Co L L C [Member] | TMI,OysterCreek [Member]

$ (4)

^[1],[2]

137

^[1]

^[3]

Fair Value, Inputs, Level 3 [Member]

$ 178

[1]	Reflects incremental accelerated depreciation and amortization for TMI for the three months ended March 31, 2019. Reflects incremental accelerated depreciation for TMI and Oyster Creek for the three months ended March 31, 2018. The Oyster Creek amounts are from February 2, 2018 through March 31, 2018.
[2]	Reflects incremental accelerated depreciation of plant assets, including any ARC.
[3]	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.

Early Plant Retirements - Implications of Potential Early Plant Retirement on Balance Sheet (Details) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Implications of Potential Early Plant Retirement [Line Items]
Completed plant, net	$ 77,460	$ 76,707
Mystic Generating Station [Member] \| Facility Closing [Member]
Implications of Potential Early Plant Retirement [Line Items]
Materials and supplies inventory	30
Fuel inventory	22
Completed plant, net	900
Construction work in progress	2
Asset retirement obligation	(1)
Exelon Generation Co L L C [Member]
Implications of Potential Early Plant Retirement [Line Items]
Completed plant, net	24,034	$ 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	22
Completed plant, net	900
Construction work in progress	2
Asset retirement obligation	$ (1)

Fair Value of Financial Assets and Liabilities - Narrative (Details) - USD ($)	Mar. 31, 2019	Dec. 31, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Issuance Costs, Net	$ 216,000,000	$ 216,000,000
EquitySecuritiesWithoutReadilyDeterminableFairValueAmount	71,000,000
Forward Power Basis	2.52
Forward Gas Basis	0.46
Exelon Generation Co L L C [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Issuance Costs, Net	49,000,000	$ 51,000,000
EquitySecuritiesWithoutReadilyDeterminableFairValueAmount	71,000,000
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	127,000,000
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	127,000,000
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	179,000,000
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	179,000,000
Private Equity Funds [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Unfunded Commitments	301,000,000
Private Equity Funds [Member] \| Exelon Generation Co L L C [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Unfunded Commitments	301,000,000
Real Estate Funds [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Unfunded Commitments	268,000,000
Real Estate Funds [Member] \| Exelon Generation Co L L C [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Unfunded Commitments	$ 268,000,000

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

Mar. 31, 2019

Mar. 31, 2018

Dec. 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

$ 880

$ 1,319

$ 949

$ 1,003

(228)

186

(4)

105

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Issuances

(3)

(17)

(48)

(8)

Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)

(2)

(148)

258

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

(11)

(7)

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Issuances

Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)

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

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

1,081

1,563

1,160

1,237

(229)

185

105

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Issuances

(3)

(17)

(48)

(8)

Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)

(2)

(149)

257

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

540

609

543

648

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Issuances

(17)

(48)

Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)

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

499

918

575

552

^[1]

(231)

184

105

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Issuances

(3)

^[2]

(8)

Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)

^[2]

(151)

256

Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Other 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

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Issuances

Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)

(2)

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)

(5)

(6)

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

(240)

(267)

(249)

(256)

^[3]

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Issuances

Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)

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)

(14)

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

^[4]

$ 38

$ 22

^[4]

^[4]

^[4]

^[4]

^[4]

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Issuances

^[4]

^[4]

^[4]

^[4]

Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)

^[4]

^[4]

$ 1

[1]	Includes a reduction for the reclassification of $80 million and $72 million of realized gains due to the settlement of derivative contracts for the three months ended March 31, 2019 and 2018, respectively.
[2]	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.
[3]	Includes $14 million of decreases in fair value and an increase for realized losses due to settlements of $5 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended March 31, 2019. Includes $17 million of increases in fair value and an increase for realized losses due to settlements of $6 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended March 31, 2018.
[4]	The amounts represented are life insurance contracts at Pepco.

Fair Value of Financial Assets and Liabilities - Fair Value Inputs Assets Quantitative Information (Details) - USD ($)

3 Months Ended

12 Months Ended

Mar. 31, 2019

Dec. 31, 2018

Fair Value, Inputs, Level 3 [Member]

$ 37,000,000

Fair Value, Inputs, Level 3 [Member] | Economic Hedges [Member]

157,000,000

$ 76,000,000

Derivative Asset, Fair Value, Amount Not Offset Against Collateral

^[1],[2]

278,000,000

443,000,000

Fair Value, Inputs, Level 3 [Member] | Derivative [Member]

Derivative Asset, Fair Value, Amount Not Offset Against Collateral

(240,000,000)

(249,000,000)

Fair Value, Inputs, Level 3 [Member] | Derivative [Member] | Discounted Cash Flow [Member] | Minimum [Member]

^[1],[2]

^[1],[2]

$ 1.76

$ 0.78

Fair Value Inputs, Discount for Lack of Marketability

^[3]

1000.00%

4.00%

Fair Value, Inputs, Level 3 [Member] | Derivative [Member] | Discounted Cash Flow [Member] | Maximum [Member]

85.00%

86.00%

^[1],[2]

$ 164

$ 174

^[1],[2]

$ 11.63

$ 12.38

Fair Value Inputs, Discount for Lack of Marketability

^[3]

1100.00%

8.00%

Fair Value, Inputs, Level 3 [Member] | Derivative [Member] | Option Model Valuation Technique [Member] | Minimum [Member]

120.00%

Fair Value, Inputs, Level 3 [Member] | Derivative [Member] | Option Model Valuation Technique [Member] | Maximum [Member]

^[1],[2]

9.84%

10.00%

Fair Value, Inputs, Level 3 [Member] | Proprietary Trading [Member]

^[1],[2]

334.36%

277.00%

Derivative Liability, Fair Value, Amount Not Offset Against Collateral

^[1],[2]

$ 64,000,000

$ 56,000,000

Fair Value, Inputs, Level 3 [Member] | Proprietary Trading [Member] | Discounted Cash Flow [Member] | Minimum [Member]

Fair Value, Inputs, Level 3 [Member] | Proprietary Trading [Member] | Discounted Cash Flow [Member] | Maximum [Member]

^[1],[2]

^[1],[2]

162

174

Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member]

542,000,000

418,000,000

Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Economic Hedges [Member]

157,000,000

76,000,000

Derivative Asset, Fair Value, Amount Not Offset Against Collateral

^[1],[2]

278,000,000

443,000,000

Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative [Member] | Discounted Cash Flow [Member] | Minimum [Member]

^[1],[2]

Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative [Member] | Discounted Cash Flow [Member] | Maximum [Member]

^[1],[2]

1.76

0.78

^[1],[2]

164

174

Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative [Member] | Option Model Valuation Technique [Member] | Minimum [Member]

^[1],[2]

$ 11.63

$ 12.38

Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative [Member] | Option Model Valuation Technique [Member] | Maximum [Member]

^[1],[2]

9.84%

10.00%

Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Proprietary Trading [Member]

^[1],[2]

334.36%

277.00%

Derivative Liability, Fair Value, Amount Not Offset Against Collateral

^[1],[2]

$ 64,000,000

$ 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]

Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Proprietary Trading [Member] | Discounted Cash Flow [Member] | Maximum [Member]

^[1],[2]

Commonwealth Edison Co [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative [Member]

^[1],[2]

162

174

Derivative Asset, Fair Value, Amount Not Offset Against Collateral

$ (240,000,000)

$ (249,000,000)

Commonwealth Edison Co [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative [Member] | Discounted Cash Flow [Member] | Minimum [Member]

Fair Value Inputs, Discount for Lack of Marketability

^[3]

1000.00%

4.00%

Commonwealth Edison Co [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative [Member] | Discounted Cash Flow [Member] | Maximum [Member]

85.00%

86.00%

Fair Value Inputs, Discount for Lack of Marketability

^[3]

1100.00%

8.00%

120.00%

[1]	The fair values do not include cash collateral posted on level three positions of $157 million and $76 million as of March 31, 2019 and December 31, 2018, respectively.
[2]	The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions.
[3]	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 - Summary of Derivative Fair Value Balances (Details) - USD ($)
$ in Millions

Mar. 31, 2019

Dec. 31, 2018

$ 652

$ 804

454

452

(345)

(475)

(434)

(479)

Commodity Contract [Member]

653

801

454

445

1,107

1,246

(342)

(473)

(428)

(474)

Total mark-to-market derivative net assets (liabilities)

(770)

(947)

337

299

652

804

454

452

(318)

(449)

(219)

(252)

Derivative Liability, Fair Value, Amount Offset Against Collateral

(1,177)

^[1]

1,105

Exelon Generation Co L L C [Member] | Commodity Contract [Member]

653

^[2]

801

^[3]

454

^[2]

445

^[3]

1,107

^[2]

1,246

^[3]

(315)

^[2]

(447)

^[3]

(215)

^[2]

(251)

^[3]

Total mark-to-market derivative net assets (liabilities)

(530)

^[2]

(698)

^[3]

577

^[2]

548

^[3]

(27)

(26)

Collateral And Netting [Member] | Exelon Generation Co L L C [Member] | Commodity Contract [Member]

(213)

(223)

^[4]

(2,156)

^[5]

(2,809)

^[6]

^[4]

(794)

^[5]

(862)

^[6]

^[4]

(2,950)

^[5]

(3,671)

^[6]

^[4]

2,485

^[5]

3,056

^[6]

^[4]

957

^[5]

972

^[6]

Total mark-to-market derivative net assets (liabilities)

^[4]

3,442

^[5]

4,028

^[6]

^[4]

492

^[5]

357

^[6]

Not Designated as Hedging Instrument, Economic Hedge [Member] | Exelon Generation Co L L C [Member] | Commodity Contract [Member]

2,691

3,505

1,188

1,266

3,879

4,771

(2,711)

(3,429)

(1,142)

(1,203)

Total mark-to-market derivative net assets (liabilities)

(3,853)

(4,632)

139

Not Designated as Hedging Instrument, Economic Hedge [Member] | Commonwealth Edison Co [Member] | Commodity Contract [Member]

^[7]

^[7]

^[7]

^[7]

(27)

(26)

^[7]

(213)

(223)

Total mark-to-market derivative net assets (liabilities)

^[7]

(240)

(249)

^[7]

(240)

(249)

Not Designated as Hedging Instrument [Member] | Exelon Generation Co L L C [Member] | Commodity Contract [Member]

118

105

178

146

(89)

(74)

(30)

(20)

Total mark-to-market derivative net assets (liabilities)

(119)

(94)

Designated as Hedging Instrument [Member] | Exelon Generation Co L L C [Member]

Derivative Liability, Collateral, Right to Reclaim Cash, Offset

(492)

(357)

Current liabilities collateral offset

177

125

Noncurrent liabilities collateral offset

100

Designated as Hedging Instrument [Member] | Exelon Generation Co L L C [Member] | Other Current Assets [Member]

Derivative Liability, Fair Value, Amount Offset Against Collateral

152

121

(33)

(94)

Designated as Hedging Instrument [Member] | Exelon Generation Co L L C [Member] | Other Noncurrent Assets [Member]

$ 63

$ 51

[1]	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.
[2]	Current and noncurrent assets are shown net of collateral of $152 million and $63 million, respectively, and current and noncurrent liabilities are shown net of collateral of $177 million and $100 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $492 million at March 31, 2019.
[3]	Current and noncurrent assets are shown net of collateral of $121 million and $51 million, respectively, and current and noncurrent liabilities are shown net of collateral of $125 million and $60 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $357 million at December 31, 2018.
[4]	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 are not reflected in the table above.
[5]	Of the collateral posted/(received), $(33) million represents variation margin on the exchanges.
[6]	Of the collateral posted/(received), $(94) million represents variation margin on the exchanges.
[7]	Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.

Derivative Financial Instruments - Summary of Economic Hedges (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	$ (31)	$ (259)
Exelon Generation Co L L C [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	(33)	(264)
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	(20)	(267)
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	(50)	(100)
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	$ 30	$ (167)

Derivative Financial Instruments - Summary of Proprietary Trading Activities (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	$ (31)	$ (259)
Exelon Generation Co L L C [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	(33)	(264)
Not Designated as Hedging Instrument [Member] \| Operating Revenue [Member] \| Exelon Generation Co L L C [Member] \| Commodity Contract [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	$ 2	$ 2

Derivative Financial Instruments - Summary of Credit Risk Exposure (Details) - USD ($)
$ in Millions

Mar. 31, 2019

Dec. 31, 2018

$ 37

Letters Of Credit Posted

Investor-owned utilities, marketers and power producers

Financial institutions

762

Energy Cooperatives And Municipalities

287

Exelon Generation Co L L C [Member] | Total Exposure Before Credit Collateral [Member]

542

$ 418

Letters Of Credit Posted

289

$ 367

819

No external ratings - internally rated - investment grade

162

No external ratings - internally rated - non-investment grade

Exelon Generation Co L L C [Member] | Credit Collateral [Member]

1,154

No external ratings - internally rated - investment grade

No external ratings - internally rated - non-investment grade

Exelon Generation Co L L C [Member] | Net Exposure [Member]

^[1]

808

No external ratings - internally rated - investment grade

162

No external ratings - internally rated - non-investment grade

Exelon Generation Co L L C [Member] | Number Of Counterparties Greater Than Ten Percent Of Net Exposure [Member]

1,097

No external ratings - internally rated - investment grade

No external ratings - internally rated - non-investment grade

Exelon Generation Co L L C [Member] | Net Exposure Of Counterparties Greater Than Ten Percent Of Net Exposure [Member]

135

No external ratings - internally rated - investment grade

No external ratings - internally rated - non-investment grade

$ 135

[1]	As of March 31, 2019, credit collateral held from counterparties where Generation had credit exposure included $37 million of cash and $19 million of letters of credit. The credit collateral does not include non-liquid collateral.

Derivative Financial Instruments - Summary of Credit Risk Related Contingent Features (Details) - Exelon Generation Co L L C [Member] - USD ($)
$ in Millions

Mar. 31, 2019

Dec. 31, 2018

Aggregate fair value of derivatives with credit-risk-related contingent features

$ (1,667)

^[1]

$ 1,723

Contractual right of offset related to derivative assets

1,177

^[2]

(1,105)

Net liability position after contractual right of offset

^[3]

$ (490)

$ (618)

[1]	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.
[2]	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.
[3]	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.

Derivative Financial Instruments - Narrative (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Dec. 31, 2018
Derivative [Line Items]
Cash Collateral Posted	$ 37,000
Letters of credit posted	19,000
Exelon Generation Co L L C [Member]
Derivative [Line Items]
Cash collateral received not offset against net derivative positions	(6,000)	$ 2,000
Cash Collateral Posted	542,000	418,000
Letters of credit held	26,000	44,000
Letters of credit posted	289,000	367,000
Cash collateral held	56,000	47,000
Incremental collateral for loss of investment grade credit rating	1,900,000	2,100,000
Commonwealth Edison Co [Member]
Derivative [Line Items]
Incremental collateral for loss of investment grade credit rating	8,000
Credit Exposure Under Off System Sales	$ 2,000
PECO Energy Co [Member]
Derivative [Line Items]
Estimated percentage of natural gas purchases hedged	20.00%
Incremental collateral for loss of investment grade credit rating	$ 34,000
Baltimore Gas and Electric Company [Member]
Derivative [Line Items]
Incremental collateral for loss of investment grade credit rating	46,000
Delmarva Power and Light Company [Member]
Derivative [Line Items]
Incremental collateral for loss of investment grade credit rating	$ 14,000
Minimum [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Expected Generation Hedged In Next Twelve Months	90.00%
Expected Generation Hedged In Year Two	64.00%
Expected generation hedged in year three	38.00%
Minimum [Member] \| Baltimore Gas and Electric Company [Member]
Derivative [Line Items]
Estimated percentage of natural gas purchases hedged	10.00%
Maximum [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Expected Generation Hedged In Next Twelve Months	93.00%
Expected Generation Hedged In Year Two	67.00%
Expected generation hedged in year three	41.00%
Maximum [Member] \| Baltimore Gas and Electric Company [Member]
Derivative [Line Items]
Estimated percentage of natural gas purchases hedged	20.00%
Other Contract [Member] \| Commonwealth Edison Company [Member]
Derivative [Line Items]
Credit Derivative, Collateral Held Directly or by Third Parties	19000000
Energy Related Derivative [Member] \| Commonwealth Edison Company [Member]
Derivative [Line Items]
Credit Derivative, Collateral Held Directly or by Third Parties	11000000
Energy Related Derivative [Member] \| Delmarva Power and Light Company [Member]
Derivative [Line Items]
Brokered Natural Gas Margin Revenue	$ 2,750
Renewable Energy Program [Member] \| Commonwealth Edison Company [Member]
Derivative [Line Items]
Credit Derivative, Collateral Held Directly or by Third Parties	31000000
Commonwealth Edison Co Affiliate [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Cash collateral received not offset against net derivative positions		12,000
Net receivable from electric utility	$ 36,000
PECO Energy Co Affiliate [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Net receivable from affiliated electric and gas utility	31,000
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	27,000
Potomac Electric Power Company [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Net receivable from electric utility	37,000
Delmarva Power and Light Company [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Net receivable from electric utility	5,000
Atlantic City Electric Company [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Net receivable from electric utility	4,000
Not Designated as Hedging Instrument, Economic Hedge [Member] \| Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	1,419,000	1,420,000
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	619,000	620,000
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	$ 209,000	$ 268,000

Debt and Credit Agreements - Narrative (Details) $ in Millions	3 Months Ended
	Mar. 31, 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]
Non-Recourse Debt	502
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	502
ExGenRenewablesIVNov2024 [Member] \| Non Recourse Debt [Member]
Debt Instrument [Line Items]
Non-Recourse Debt	834
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	$ 834

Debt and Credit Agreements - Commercial Paper Borrowings (Details) - Commercial Paper [Member] - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Short-term Debt [Line Items]
Outstanding Commercial Paper	$ 629	$ 89
Average Interest Rate on Commercial Paper Borrowings	2.63%	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	$ 322	$ 0
Average Interest Rate on Commercial Paper Borrowings	2.64%	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	$ 106	$ 35
Average Interest Rate on Commercial Paper Borrowings	2.59%	2.18%
Pepco Holdings LLC [Member]
Short-term Debt [Line Items]
Outstanding Commercial Paper	$ 201	$ 54
Average Interest Rate on Commercial Paper Borrowings	2.62%	2.15%
Potomac Electric Power Company [Member]
Short-term Debt [Line Items]
Outstanding Commercial Paper	$ 105	$ 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	$ 5	$ 0
Average Interest Rate on Commercial Paper Borrowings	2.61%	2.07%
Atlantic City Electric Company [Member]
Short-term Debt [Line Items]
Outstanding Commercial Paper	$ 91	$ 14
Average Interest Rate on Commercial Paper Borrowings	2.62%	2.21%

Debt and Credit Agreements - Issuance of Long-Term Debt (Details) $ in Millions	Mar. 31, 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
Commonwealth Edison Co [Member] \| FMB400Mar2049 [Member] \| First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Interest Rate	4.00%
Debt Instrument, Face Amount	$ 400

Income Taxes - Narrative (Details) $ in Millions	3 Months Ended
Income Taxes - Narrative (Details) $ in Millions	Mar. 31, 2019 USD ($)
Income Tax Additional Narrative Information [Line Items]
Unrecognized Tax Benefits, Period Increase (Decrease)	$ 33
Decrease in Unrecognized Tax Benefits is Reasonably Possible	425
Unrecognized tax benefits that if recognized would affect the effective tax rate	411
Exelon Generation Co L L C [Member]
Income Tax Additional Narrative Information [Line Items]
Decrease in Unrecognized Tax Benefits is Reasonably Possible	411
Commonwealth Edison Co [Member]
Income Tax Additional Narrative Information [Line Items]
Unrecognized Tax Benefits, Period Increase (Decrease)	2
Pepco Holdings LLC [Member]
Income Tax Additional Narrative Information [Line Items]
Decrease in Unrecognized Tax Benefits is Reasonably Possible	14
Atlantic City Electric Company [Member]
Income Tax Additional Narrative Information [Line Items]
Decrease in Unrecognized Tax Benefits is Reasonably Possible	$ 14

Income Taxes - Reconciliation to Effective Tax Rate (Details)	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Effective Income Tax Rate Reconciliation, Percent [Abstract]
U.S. Federal statutory rate	21.00%	21.00%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	3.90%	4.10%
Qualified nuclear decommissioning trust fund income	7.20%	(0.40%)
Amortization of investment tax credit, including deferred taxes on basis difference	(0.50%)	(1.30%)
Plant basis differences	(1.40%)	(2.70%)
Production tax credits and other credits	(0.80%)	(2.80%)
Noncontrolling interests	(0.60%)	(0.70%)
Excess deferred tax amortization	(4.70%)	(6.00%)
Other	0.10%	(2.80%)
Effective income tax rate	24.20%	8.40%
Exelon Generation Co L L C [Member]
Effective Income Tax Rate Reconciliation, Percent [Abstract]
U.S. Federal statutory rate	21.00%	21.00%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	3.10%	2.40%
Qualified nuclear decommissioning trust fund income	14.20%	(1.30%)
Amortization of investment tax credit, including deferred taxes on basis difference	(0.90%)	(4.30%)
Plant basis differences	(0.00%)	(0.00%)
Production tax credits and other credits	(1.50%)	(9.50%)
Noncontrolling interests	(1.10%)	(2.50%)
Excess deferred tax amortization	0.00%	0.00%
Other	(0.50%)	(1.30%)
Effective income tax rate	34.30%	4.50%
Commonwealth Edison Co [Member]
Effective Income Tax Rate Reconciliation, Percent [Abstract]
U.S. Federal statutory rate	21.00%	21.00%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	8.20%	8.20%
Qualified nuclear decommissioning trust fund income	0.00%	0.00%
Amortization of investment tax credit, including deferred taxes on basis difference	(0.20%)	(0.20%)
Plant basis differences	(0.50%)	0.10%
Production tax credits and other credits	(0.00%)	(0.10%)
Noncontrolling interests	(0.00%)	(0.00%)
Excess deferred tax amortization	(8.50%)	(7.50%)
Other	0.30%	0.30%
Effective income tax rate	20.30%	21.80%
PECO Energy Co [Member]
Effective Income Tax Rate Reconciliation, Percent [Abstract]
U.S. Federal statutory rate	21.00%	21.00%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	1.00%	(3.90%)
Qualified nuclear decommissioning trust fund income	0.00%	0.00%
Amortization of investment tax credit, including deferred taxes on basis difference	(0.00%)	(0.10%)
Plant basis differences	(6.70%)	(14.20%)
Production tax credits and other credits	(0.00%)	(0.00%)
Noncontrolling interests	(0.00%)	(0.00%)
Excess deferred tax amortization	(2.50%)	(4.80%)
Other	0.20%	0.20%
Effective income tax rate	13.00%	(1.80%)
Baltimore Gas and Electric Company [Member]
Effective Income Tax Rate Reconciliation, Percent [Abstract]
U.S. Federal statutory rate	21.00%	21.00%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	6.30%	6.30%
Qualified nuclear decommissioning trust fund income	0.00%	0.00%
Amortization of investment tax credit, including deferred taxes on basis difference	(0.10%)	(0.10%)
Plant basis differences	(0.90%)	(0.70%)
Production tax credits and other credits	(0.00%)	(0.00%)
Noncontrolling interests	(0.00%)	(0.00%)
Excess deferred tax amortization	(7.90%)	(8.60%)
Other	0.00%	0.00%
Effective income tax rate	18.40%	17.90%
Pepco Holdings LLC [Member]
Effective Income Tax Rate Reconciliation, Percent [Abstract]
U.S. Federal statutory rate	21.00%	21.00%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	4.70%	4.60%
Qualified nuclear decommissioning trust fund income	0.00%	0.00%
Amortization of investment tax credit, including deferred taxes on basis difference	(0.20%)	(0.20%)
Plant basis differences	(1.70%)	(2.60%)
Production tax credits and other credits	(0.00%)	(0.00%)
Noncontrolling interests	(0.00%)	(0.00%)
Excess deferred tax amortization	(19.40%)	(10.60%)
Other	(0.30%)	0.00%
Effective income tax rate	4.10%	12.20%
Potomac Electric Power Company [Member]
Effective Income Tax Rate Reconciliation, Percent [Abstract]
U.S. Federal statutory rate	21.00%	21.00%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	2.10%	1.70%
Qualified nuclear decommissioning trust fund income	0.00%	0.00%
Amortization of investment tax credit, including deferred taxes on basis difference	(0.10%)	(0.10%)
Plant basis differences	(2.00%)	(3.40%)
Production tax credits and other credits	(0.00%)	(0.00%)
Noncontrolling interests	(0.00%)	(0.00%)
Excess deferred tax amortization	(17.90%)	(12.80%)
Other	0.40%	(0.30%)
Effective income tax rate	3.50%	6.10%
Delmarva Power and Light Company [Member]
Effective Income Tax Rate Reconciliation, Percent [Abstract]
U.S. Federal statutory rate	21.00%	21.00%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	6.50%	6.30%
Qualified nuclear decommissioning trust fund income	0.00%	0.00%
Amortization of investment tax credit, including deferred taxes on basis difference	(0.20%)	(0.20%)
Plant basis differences	(0.70%)	(1.30%)
Production tax credits and other credits	(0.00%)	(0.00%)
Noncontrolling interests	(0.00%)	(0.00%)
Excess deferred tax amortization	(15.60%)	(7.90%)
Other	0.70%	0.50%
Effective income tax rate	11.70%	18.40%
Atlantic City Electric Company [Member]
Effective Income Tax Rate Reconciliation, Percent [Abstract]
U.S. Federal statutory rate	21.00%	21.00%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	6.70%	6.60%
Qualified nuclear decommissioning trust fund income	0.00%	0.00%
Amortization of investment tax credit, including deferred taxes on basis difference	(0.30%)	(0.30%)
Plant basis differences	(2.30%)	(2.60%)
Production tax credits and other credits	(0.00%)	(0.00%)
Noncontrolling interests	(0.00%)	(0.00%)
Excess deferred tax amortization	(23.90%)	(8.70%)
Other	(1.20%)	(3.50%)
Effective income tax rate	0.00%	12.50%

Income Taxes - Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	Mar. 31, 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		9 Months Ended
	Mar. 31, 2019	Sep. 30, 2018	Sep. 30, 2018	Dec. 31, 2018
Nuclear Decommissioning Additional Narrative Information [Line Items]
Asset Retirement Obligation, Period Increase (Decrease)	$ 324
Asset Retirement Obligation, Revision of Estimate	330		$ 84
Decommissioning Fund Investments	12,302			$ 11,661
Assets held for sale	890			904
Exelon Generation Co L L C [Member]
Nuclear Decommissioning Additional Narrative Information [Line Items]
Asset Retirement Obligation, Period Increase (Decrease)	324
Asset Retirement Obligation, Revision of Estimate	330
Decommissioning Fund Investments	12,302			11,661
Assets held for sale	890			904
Nuclear Decommissioning [Member]
Nuclear Decommissioning Additional Narrative Information [Line Items]
Asset Retirement Obligation, Revision of Estimate	223
Nuclear Decommissioning [Member] \| Exelon Generation Co L L C [Member]
Nuclear Decommissioning Additional Narrative Information [Line Items]
Asset Retirement Obligation, Revision of Estimate	223
Oyster Creek [Member]
Nuclear Decommissioning Additional Narrative Information [Line Items]
Assets held for sale	888			897
Oyster Creek [Member] \| Exelon Generation Co L L C [Member]
Nuclear Decommissioning Additional Narrative Information [Line Items]
Asset Retirement Obligation Revision Of Estimate In Operating And Maintenance Expense		$ (84)
Assets held for sale	888			897
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	13,345			12,695
Assets, Total [Member] \| Exelon Generation Co L L C [Member]
Nuclear Decommissioning Additional Narrative Information [Line Items]
Decommissioning Fund Investments	13,345			12,695
Nuclear Decommissioning Trust Fund Investments [Member] \| Oyster Creek [Member]
Nuclear Decommissioning Additional Narrative Information [Line Items]
Assets held for sale	881			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	881			890
Other Current Assets [Member]
Nuclear Decommissioning Additional Narrative Information [Line Items]
Decommissioning Fund Investments	163			144
Other Current Assets [Member] \| Exelon Generation Co L L C [Member]
Nuclear Decommissioning Additional Narrative Information [Line Items]
Decommissioning Fund Investments	$ 163			$ 144

Nuclear Decommissioning - Rollforward of Nuclear Decommissioning ARO (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

Mar. 31, 2019

Mar. 31, 2018

Sep. 30, 2018

Dec. 31, 2018

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

Net increase due to changes in, and timing of, estimated future cash flows

$ 330

$ 84

^[1]

124

$ 120

Nuclear Decommissioning [Member]

799

$ 777

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

Nuclear decommissioning ARO, beginning balance

^[2],[3]

10,005

Net increase due to changes in, and timing of, estimated future cash flows

223

Costs incurred related to decommissioning plants

120

(19)

Nuclear decommissioning ARO, ending balance

^[2],[3]

10,329

Current portion of ARO

Oyster Creek [Member]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

765

777

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

Net increase due to changes in, and timing of, estimated future cash flows

330

^[1]

123

$ 120

Exelon Generation Co L L C [Member] | Nuclear Decommissioning [Member]

799

777

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

Nuclear decommissioning ARO, beginning balance

^[2],[3]

10,005

Net increase due to changes in, and timing of, estimated future cash flows

223

Costs incurred related to decommissioning plants

120

(19)

Nuclear decommissioning ARO, ending balance

^[2],[3]

10,329

Current portion of ARO

Exelon Generation Co L L C [Member] | Oyster Creek [Member]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

Nuclear Decommissioning Asset Retirement Obligation [Member] | Oyster Creek [Member]

765

777

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

Nuclear Decommissioning Asset Retirement Obligation [Member] | Exelon Generation Co L L C [Member] | Oyster Creek [Member]

760

772

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

$ 760

$ 772

[1]	Included in Operating and maintenance expense in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
[2]	Includes $41 million and $22 million as the current portion of the ARO at March 31, 2019 and December 31, 2018, respectively, which is included in Other current liabilities in Exelon’s and Generation’s Consolidated Balance Sheets.
[3]	Includes $760 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 March 31, 2019 and December 31, 2018, respectively. See Note 3 — Mergers, Acquisitions and Dispositions for additional information.

Retirement Benefits - Narrative (Details) $ in Millions	3 Months Ended
Retirement Benefits - Narrative (Details) $ in Millions	Mar. 31, 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)
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
	Mar. 31, 2019	Mar. 31, 2018
Amortization of:
Net periodic benefit cost	$ (5)	$ 10
Pension Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	89	101
Interest cost	221	201
Expected return on assets	(307)	(312)
Amortization of:
Prior service cost (benefit)	0	0
Actuarial loss	104	157
Net periodic benefit cost	107	147
Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	24	28
Interest cost	47	43
Expected return on assets	(38)	(43)
Amortization of:
Prior service cost (benefit)	(45)	(46)
Actuarial loss	11	16
Net periodic benefit cost	$ (1)	$ (2)

Retirement Benefits - Allocated Portion of Pension and Postretirement Benefit Plan Costs (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Benefits Cost (Reversal of Cost)	$ 106	$ 145
Pension and other post retirement benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Benefits Cost (Reversal of Cost)	106	145
Exelon Generation Co L L C [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Benefits Cost (Reversal of Cost)	31	51
Exelon Generation Co L L C [Member] \| Pension and other post retirement benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Benefits Cost (Reversal of Cost)	31	51
Commonwealth Edison Co [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Benefits Cost (Reversal of Cost)	24	45
Commonwealth Edison Co [Member] \| Pension and other post retirement benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Benefits Cost (Reversal of Cost)	24	45
PECO Energy Co [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Benefits Cost (Reversal of Cost)	2	5
PECO Energy Co [Member] \| Pension and other post retirement benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Benefits Cost (Reversal of Cost)	2	5
Baltimore Gas and Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Benefits Cost (Reversal of Cost)	15	14
Baltimore Gas and Electric Company [Member] \| Pension and other post retirement benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Benefits Cost (Reversal of Cost)	16	15
Pepco Holdings LLC [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Benefits Cost (Reversal of Cost)	23	15
Pepco Holdings LLC [Member] \| Pension and other post retirement benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Benefits Cost (Reversal of Cost)	23	15
Potomac Electric Power Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Benefits Cost (Reversal of Cost)	6	4
Potomac Electric Power Company [Member] \| Pension and other post retirement benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Benefits Cost (Reversal of Cost)	6	4
Delmarva Power and Light Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Benefits Cost (Reversal of Cost)	4	0
Delmarva Power and Light Company [Member] \| Pension and other post retirement benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Benefits Cost (Reversal of Cost)	4	0
Atlantic City Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Benefits Cost (Reversal of Cost)	4	3
Atlantic City Electric Company [Member] \| Pension and other post retirement benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Benefits Cost (Reversal of Cost)	$ 4	$ 3

Retirement Benefits - Defined Contribution Savings Plans (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Defined Benefit Plan Disclosure [Line Items]
Savings Plan Matching Contributions	$ 31	$ 32
Exelon Generation Co L L C [Member]
Defined Benefit Plan Disclosure [Line Items]
Savings Plan Matching Contributions	13	15
Commonwealth Edison Co [Member]
Defined Benefit Plan Disclosure [Line Items]
Savings Plan Matching Contributions	7	7
PECO Energy Co [Member]
Defined Benefit Plan Disclosure [Line Items]
Savings Plan Matching Contributions	2	2
Baltimore Gas and Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Savings Plan Matching Contributions	2	2
Pepco Holdings LLC [Member]
Defined Benefit Plan Disclosure [Line Items]
Savings Plan Matching Contributions	4	3
Potomac Electric Power Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Savings Plan Matching Contributions	1	1
Delmarva Power and Light Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Savings Plan Matching Contributions	1	1
Atlantic City Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Savings Plan Matching Contributions	$ 1	$ 0

Changes in Accumulated Other Comprehensive Income - Schedule of Changes in AOCI (Details) - USD ($)
$ in Millions

3 Months Ended

Mar. 31, 2019

Mar. 31, 2018

$ 33,070

$ 32,187

30,764

^[1]

(18)

33,704

32,565

Tax Cuts and Jobs Act, Reclassification from AOCI to Retained Earnings

31,357

539

Gains (Losses) on Cash Flow Hedges

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[2]

(2)

(14)

^[2]

^[2],[3]

^[2]

Gains (Losses) on Cash Flow Hedges | Accounting Standards Update 2016-01 [Member]

^[2]

(2)

(6)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard(c)

Unrealized Gains (Losses) on Marketable Securities

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[2]

^[2]

^[2],[3]

^[2]

Unrealized Gains (Losses) on Marketable Securities | Accounting Standards Update 2016-01 [Member]

^[2]

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]

^[2]

(2,960)

(2,998)

^[2]

(38)

^[1],[2],[3]

^[2]

(18)

Pension and Non-Pension Postretirement Benefit Plan Items | Accounting Standards Update 2016-01 [Member]

^[2]

(2,978)

(2,936)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard(c)

Foreign Currency Items

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[2]

(33)

(23)

^[2]

^[2],[3]

^[2]

Foreign Currency Items | Accounting Standards Update 2016-01 [Member]

^[2]

(31)

(22)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard(c)

AOCI of Investments in Unconsolidated Affiliates

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[2]

(1)

^[2]

(1)

^[2],[3]

^[2]

(1)

AOCI of Investments in Unconsolidated Affiliates | Accounting Standards Update 2016-01 [Member]

^[2]

(1)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard(c)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[2]

(2,995)

(3,026)

^[2]

(37)

^[2],[3]

^[2]

(17)

Total | Accounting Standards Update 2016-01 [Member]

^[2]

(3,012)

(2,965)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard(c)

(10)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

15,508

15,959

Exelon Generation Co L L C [Member] | Gains (Losses) on Cash Flow Hedges

15,696

15,958

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[2]

(4)

(16)

^[2]

^[2],[3]

^[2]

Exelon Generation Co L L C [Member] | Gains (Losses) on Cash Flow Hedges | Accounting Standards Update 2016-01 [Member]

^[2]

(3)

(9)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard(c)

Exelon Generation Co L L C [Member] | Unrealized Gains (Losses) on Marketable Securities

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[2]

^[2]

^[2],[3]

^[2]

Exelon Generation Co L L C [Member] | Unrealized Gains (Losses) on Marketable Securities | Accounting Standards Update 2016-01 [Member]

^[2]

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]

^[2]

^[2]

^[2],[3]

^[2]

Exelon Generation Co L L C [Member] | Pension and Non-Pension Postretirement Benefit Plan Items | Accounting Standards Update 2016-01 [Member]

^[2]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard(c)

Exelon Generation Co L L C [Member] | Foreign Currency Items

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[2]

(33)

(23)

^[2]

(1)

^[2],[3]

^[2]

(1)

Exelon Generation Co L L C [Member] | Foreign Currency Items | Accounting Standards Update 2016-01 [Member]

^[2]

(31)

(24)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard(c)

Exelon Generation Co L L C [Member] | AOCI of Investments in Unconsolidated Affiliates

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[2]

(1)

^[2]

(1)

^[2],[3]

^[2]

(1)

Exelon Generation Co L L C [Member] | AOCI of Investments in Unconsolidated Affiliates | Accounting Standards Update 2016-01 [Member]

^[2]

(2)

(1)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard(c)

Exelon Generation Co L L C [Member] | Total

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[2]

(38)

(37)

^[2]

^[2],[3]

^[2]

Exelon Generation Co L L C [Member] | Total | Accounting Standards Update 2016-01 [Member]

^[2]

$ (36)

(34)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard(c)

$ (3)

[1]	Amounts in parenthesis represent a decrease in net income.
[2]	All amounts are net of tax and noncontrolling interests. Amounts in parenthesis represent a decrease in AOCI.
[3]	See next tables for details about these reclassifications.

Changes in Accumulated Other Comprehensive Income - Reclassification out of Accumulated Other Comprehensive Income (Details) - USD ($)
$ in Millions

3 Months Ended

Mar. 31, 2019

Mar. 31, 2018

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

Income Tax Expense (Benefit)

$ 310

$ 59

Amortization of pension and other postretirement benefit plan items

Gains (Losses) on Cash Flow Hedges

^[1]

(20)

(44)

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

^[2],[3]

Prior service costs

Amortization of pension and other postretirement benefit plan items

^[1],[4]

Actuarial losses

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

Amortization of pension and other postretirement benefit plan items

^[1],[4]

(49)

(83)

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

^[1]

(27)

(60)

Tax benefit

^[1]

^[1],[2],[3]

$ (20)

$ (44)

[1]	Amounts in parenthesis represent a decrease in net income.
[2]	All amounts are net of tax and noncontrolling interests. Amounts in parenthesis represent a decrease in AOCI.
[3]	See next tables for details about these reclassifications.
[4]	This AOCI component is included in the computation of net periodic pension and OPEB cost. See Note 14 — Retirement Benefits for additional information.

Changes in Accumulated Other Comprehensive Income - Components of Other Comprehensive Income (Loss) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), Tax	$ 7	$ (27)
Prior service costs
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), Tax	6	6
Actuarial losses
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), Tax	(13)	(22)
Pension and Non-Pension Postretirement Benefit Plan Items
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), Tax	14	(7)
Gains (Losses) on Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), Tax	0	(3)
Unrealized Gains (Losses) on Marketable Securities
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), Unrealized Holding Gain (Loss) on Securities Arising During Period, Tax	0	(1)
Exelon Generation Co L L C [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), Tax	1	(4)
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	1	(3)
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	$ 0	$ (1)

Commitments and Contingencies - Narrative (Details) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2019 USD ($) MGPSite Open_claim gal MW	Dec. 31, 2022 MW	Dec. 31, 2018 USD ($) MW	Dec. 31, 2017 MW
Commitments And Contingencies Additional Narrative Information [Line Items]
Other Commitment	$ 3,481
Accrual for Environmental Loss Contingencies, Gross	486		$ 496
Exelon Generation Co L L C [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Other Commitment	2,831
Accrued Insurance, Current	14,100
Loss Contingency, Undiscounted Amount of Insurance-related Assessment Liability	450
Maximum liability per nuclear incident	13,600
Prepaid Reinsurance Premiums	335
Estimated Insurance Recoveries	3,200
Accrual for Environmental Loss Contingencies, Gross	108		108
Accrual for Environmental Loss Contingencies, Component Amount	90
Liability for Asbestos and Environmental Claims, Gross	$ 77		79
Open Asbestos Related Personal Injury Claims \| Open_claim	239
Pepco Holdings LLC [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Other Commitment	$ 74
Accrual for Environmental Loss Contingencies, Gross	26		27
Commonwealth Edison Co [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Other Commitment	$ 257
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	$ 320		329
Potomac Electric Power Company [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Other Commitment	48
Accrual for Environmental Loss Contingencies, Gross	24		25
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	$ 27		27
Baltimore Gas and Electric Company [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Other Commitment	$ 19
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
Delmarva Power and Light Company [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Other Commitment	$ 16
Mgp Site Contingency Approved Cleanup Count \| gal	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	25
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	52
Nuclear Insurance Premiums [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Nuclear financial protection pool value	3,100
Nuclear Insurance Premiums [Member] \| Maximum [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Nuclear financial protection pool value	454
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
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	$ 97
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	$ 97
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 - Operations (Detail) - USD ($)
$ in Millions

3 Months Ended

Mar. 31, 2019

Mar. 31, 2018

Net realized income on NDT funds - Regulatory agreement units

^[1],[2]

$ 54

$ 46

Net realized income on NDT funds - Non-regulatory agreement units

^[2]

Net unrealized gains (losses) on NDT funds - Regulatory agreement units

^[1]

379

(75)

Net unrealized gains (losses) on NDT funds - Non-regulatory agreement units

280

(96)

Regulatory offset to NDT fund-related activities

^[3]

(348)

Total decommissioning-related activities

419

(45)

Interest income related to uncertain income tax positions

Non-service net periodic benefit cost

(10)

467

(28)

Net realized income on NDT funds - Regulatory agreement units

^[1],[2]

Net realized income on NDT funds - Non-regulatory agreement units

^[2]

Net unrealized gains (losses) on NDT funds - Regulatory agreement units

^[1]

379

(75)

Net unrealized gains (losses) on NDT funds - Non-regulatory agreement units

280

(96)

Regulatory offset to NDT fund-related activities

^[3]

(348)

Total decommissioning-related activities

419

(45)

Interest income related to uncertain income tax positions

(2)

430

(44)

Interest income related to uncertain income tax positions

Interest income related to uncertain income tax positions

Interest income related to uncertain income tax positions

Interest income related to uncertain income tax positions

Interest income related to uncertain income tax positions

Interest income related to uncertain income tax positions

Interest income related to uncertain income tax positions

Depreciation, Amortization and Accretion [Abstract]

$ 3

$ 1

[1]	Net realized and unrealized gains (losses) related to Generation’s NDT funds associated with Regulatory Agreement Units are included in Regulatory liabilities in Exelon’s Consolidated Balance Sheets and Noncurrent payables to affiliates in Generation’s Consolidated Balance Sheets.
[2]	Realized income includes interest, dividends and realized gains and losses on sales of NDT fund investments.
[3]	Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units, including the elimination of net 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 Financial Information - Utility Taxes (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Supplemental Statement of Operations Information [Line Items]
Utility taxes	$ 223	$ 235
Exelon Generation Co L L C [Member]
Supplemental Statement of Operations Information [Line Items]
Utility taxes	26	32
Commonwealth Edison Co [Member]
Supplemental Statement of Operations Information [Line Items]
Utility taxes	62	61
PECO Energy Co [Member]
Supplemental Statement of Operations Information [Line Items]
Utility taxes	34	33
Baltimore Gas and Electric Company [Member]
Supplemental Statement of Operations Information [Line Items]
Utility taxes	27	26
Pepco Holdings LLC [Member]
Supplemental Statement of Operations Information [Line Items]
Utility taxes	74	83
Potomac Electric Power Company [Member]
Supplemental Statement of Operations Information [Line Items]
Utility taxes	69	77
Delmarva Power and Light Company [Member]
Supplemental Statement of Operations Information [Line Items]
Utility taxes	5	6
Atlantic City Electric Company [Member]
Supplemental Statement of Operations Information [Line Items]
Utility taxes	$ 0	$ 0

Supplemental Financial Information - Cash Flow (Details) - USD ($)
$ in Millions

3 Months Ended

Mar. 31, 2019

Mar. 31, 2018

^[1]

$ 917

$ 926

^[1]

143

152

Amortization of energy contract assets and liabilities

^[1]

^[2]

Amortization of nuclear fuel

^[3]

261

287

^[4]

124

120

1,460

1,501

Pension and non-pension postretirement benefit costs

106

145

Stock-based compensation costs

Other decommissioning-related activity

^[5]

(202)

(31)

Energy-related options

^[6]

(7)

Amortization of regulatory asset related to debt costs

(6)

Discrete impacts from EIMA and FEJA

(4)

(3)

^[7]

(4)

Long-term incentive plan

Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]

127

240

(229)

(177)

Dividends on stock compensation

301

Depreciation, Amortization and Accretion [Abstract]

^[1]

392

436

^[1]

Amortization of energy contract assets and liabilities

^[1]

^[2]

Amortization of nuclear fuel

^[3]

261

287

^[4]

123

120

789

858

Pension and non-pension postretirement benefit costs

Other decommissioning-related activity

^[5]

(202)

(31)

Energy-related options

^[6]

(7)

Amortization of regulatory asset related to debt costs

(3)

Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]

(90)

(93)

(131)

301

Depreciation, Amortization and Accretion [Abstract]

^[1]

219

201

^[1]

^[1]

^[4]

251

228

Pension and non-pension postretirement benefit costs

Amortization of regulatory asset related to debt costs

Discrete impacts from EIMA and FEJA

^[7]

(4)

(7)

(6)

Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]

(80)

(48)

Depreciation, Amortization and Accretion [Abstract]

^[1]

^[1]

^[1]

^[4]

Pension and non-pension postretirement benefit costs

Amortization of regulatory asset related to debt costs

(2)

(1)

Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]

(25)

Depreciation, Amortization and Accretion [Abstract]

^[1]

^[1]

^[1]

^[4]

136

134

Pension and non-pension postretirement benefit costs

Amortization of regulatory asset related to debt costs

(4)

(2)

Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]

(11)

Depreciation, Amortization and Accretion [Abstract]

^[1]

127

117

^[1]

^[1]

^[4]

180

183

Pension and non-pension postretirement benefit costs

Amortization of regulatory asset related to debt costs

(6)

(1)

(2)

Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]

(55)

Depreciation, Amortization and Accretion [Abstract]

^[1]

^[1]

^[1]

^[4]

Pension and non-pension postretirement benefit costs

Amortization of regulatory asset related to debt costs

(7)

(3)

(1)

Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]

(15)

Depreciation, Amortization and Accretion [Abstract]

^[1]

^[1]

^[1]

^[4]

Pension and non-pension postretirement benefit costs

Amortization of regulatory asset related to debt costs

Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]

(17)

Depreciation, Amortization and Accretion [Abstract]

^[1]

^[1]

^[1]

^[4]

Pension and non-pension postretirement benefit costs

Amortization of regulatory asset related to debt costs

(2)

Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]

(24)

$ 0

[1]	Included in Depreciation and amortization in the Registrants' Consolidated Statements of Operations and Comprehensive Income.
[2]	Included in Operating revenues or Purchased power and fuel expense in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
[3]	Included in Purchased power and fuel expense in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
[4]	Included in Operating and maintenance expense in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
[5]	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.
[6]	Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded in Operating revenues and expenses.
[7]	Reflects the change in ComEd's distribution and energy efficiency formula rates. See Note 6 — Regulatory Matters for additional information.

Supplemental Financial Information - Balance Sheet (Details) - USD ($)
$ in Millions

Mar. 31, 2019

Dec. 31, 2018

Mar. 31, 2018

Dec. 31, 2017

$ 23,695

^[1]

$ 22,902

^[2]

Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]

340

319

880

1,349

$ 787

$ 898

223

247

209

207

211

185

103

1,314

1,781

1,099

1,190

332

313

^[3]

(38)

(34)

294

279

Nuclear Fuel [Member]

3,040

2,969

12,663

^[1]

12,206

^[2]

Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]

104

537

750

610

416

139

153

127

138

Exelon Generation Co L L C [Member] | Nuclear Fuel [Member]

676

903

737

554

3,040

2,969

4,833

4,684

Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]

135

193

166

278

330

162

144

105

^[3]

(19)

(17)

3,598

3,561

Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]

130

271

135

275

^[3]

(6)

(5)

3,670

3,633

Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]

^[3]

(4)

(3)

930

841

Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]

124

186

103

^[3]

(9)

3,392

3,354

Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]

^[3]

(5)

1,354

1,329

Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]

^[3]

(1)

1,154

1,137

Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]

$ 37

$ 31

^[3]

(3)

$ 16

[1]	Includes accumulated amortization of nuclear fuel in the reactor core of $3,040 million.
[2]	Includes accumulated amortization of nuclear fuel in the reactor core of $2,969 million.
[3]	For ComEd, BGE, Pepco and DPL, reflects the incremental allowance for uncollectible accounts recorded, which is in addition to the purchase discount. For ComEd, the incremental uncollectible accounts expense is recovered through a rate rider. BGE, Pepco and DPL recover actual write-offs which are reflected in the POR discount rate.

Segment Information - Narrative (Details)	3 Months Ended
Segment Information - Narrative (Details)	Mar. 31, 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

Mar. 31, 2019

Mar. 31, 2018

Dec. 31, 2018

$ 9,477

$ 9,693

^[1]

1,075

1,091

8,262

8,648

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

403

371

1,282

702

310

966

636

1,873

1,880

^[2]

121,593

$ 119,666

1,139

1,151

1,228

1,251

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

122

117

358

258

^[3]

22,294

21,984

5,296

5,512

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

317

398

652

202

224

422

186

511

628

Operating Segments [Member]

^[4]

48,682

47,556

^[5]

4,022

4,118

^[5]

878

947

^[5]

^[5]

3,831

3,955

^[5]

665

625

^[5]

^[5]

9,477

9,693

Intersegment Eliminations [Member]

966

636

^[5]

(315)

(391)

^[5]

(1)

(8)

^[5]

(1)

^[5]

(8)

(18)

^[5]

(4)

^[5]

(457)

(455)

^[5]

(786)

(876)

^[1]

(785)

(876)

(783)

(886)

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

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

(10,213)

(9,800)

^[6]

(5)

(4)

^[6]

^[6]

(102)

(109)

^[6]

(106)

(113)

(106)

(113)

(1)

(105)

(112)

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

(1)

(118)

(69)

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

(5,478)

(5,421)

^[5],[7]

4,337

4,509

^[5],[7]

879

955

^[5],[7]

^[5],[7]

^[5],[7]

^[5],[7]

^[5],[7]

5,296

5,512

405

448

4,963

5,218

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

111

101

652

202

224

^[7]

422

186

511

628

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

^[7]

48,682

47,556

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

^[1],[7]

317

400

^[5]

^[5]

^[5]

^[5]

1,408

1,512

^[5]

^[5]

^[5]

1,408

1,512

251

228

1,135

1,223

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

197

211

157

165

503

531

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

31,582

31,213

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

^[1]

^[5]

^[5]

^[5]

^[5]

620

634

^[5]

280

232

^[5]

^[5]

900

866

678

724

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

193

111

(2)

168

113

222

217

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

10,956

10,642

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

^[1]

^[5]

^[5]

^[5]

^[5]

658

^[5]

318

319

^[5]

^[5]

976

977

136

134

756

800

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

196

156

160

128

258

224

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

9,967

9,716

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

^[1]

^[5]

^[5]

^[5]

^[5],[6]

1,153

1,169

^[5],[6]

^[5],[6]

^[5],[6]

1,228

1,251

180

183

1,054

1,125

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

122

117

358

258

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

22,294

21,984

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

^[1]

^[6]

575

557

^[6]

^[6]

^[6]

575

557

491

501

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

144

127

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

8,420

8,299

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

^[6]

310

306

^[6]

^[6]

^[6]

380

384

308

335

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

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

4,660

4,588

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

^[6]

273

310

^[6]

^[6]

^[6]

273

310

252

287

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

128

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

3,783

3,699

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

^[5],[8]

^[5],[8]

^[5],[8]

^[8]

^[7]

^[5]

^[5],[8]

^[5],[8]

455

451

^[5],[8]

455

451

^[8]

^[8]

459

444

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

^[8]

^[8]

(78)

(52)

^[8]

(20)

(31)

^[8]

(58)

(21)

^[8]

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

^[8]

8,325

8,355

^[6],[9]

^[6],[9]

^[6],[9]

106

113

^[6],[9]

106

113

108

114

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

113

(4)

(1)

^[9]

(5)

(8)

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

10,909

$ 10,819

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

^[1],[8]

453

450

Generation Mid Atlantic [Member]

^[9]

105

112

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

1,256

1,440

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]

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

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]

^[10]

1,262

1,435

Generation Midwest [Member]

(6)

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

1,108

1,346

Generation Midwest [Member] | Operating Segments [Member]

194

Generation Midwest [Member] | Intersegment Eliminations [Member]

^[10]

1,114

1,344

$ (6)

$ 2

[1]	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.
[2]	Exelon’s consolidated assets include $9,546 million and $9,667 million at March 31, 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 $3,572 million and $3,548 million at March 31, 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.
[3]	PHI’s consolidated total assets include $31 million and $33 million at March 31, 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 $64 million and $69 million at March 31, 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]	Generation’s consolidated assets include $9,515 million and $9,634 million at March 31, 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 $3,508 million and $3,480 million at March 31, 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.
[5]	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.
[6]	ncludes 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.
[7]	Intersegment revenues for Generation in 2019 include revenue from sales to PECO of $45 million, sales to BGE of $76 million, sales to Pepco of $70 million, sales to DPL of $23 million and sales to ACE of $8 million in the Mid-Atlantic region, and sales to ComEd of $94 million in the Midwest region, which eliminate upon consolidation. Intersegment revenues for Generation in 2018 include revenue from sales to PECO of $37 million, sales to BGE of $65 million, sales to Pepco of $52 million, sales to DPL of $46 million and sales to ACE of $6 million in the Mid-Atlantic region, and sales to ComEd of $194 million in the Midwest region, which eliminate upon consolidation.
[8]	Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities.
[9]	ther primarily includes PHI’s corporate operations, shared service entities and other financing and investment activities.The following tables disaggregate the Registrants' revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. For Generation, the disaggregation of revenues reflects Generation’s two primary products of power sales and natural gas sales, with further disaggregation of power sales provided by geographic region. For the Utility Registrants, the disaggregation of revenues reflects the two primary utility services of rate-regulated electric sales and rate-regulated natural gas sales (where applicable), with further disaggregation of these tariff sales provided by major customer groups. Exelon’s disaggregated revenues are consistent with Generation and the Utility Registrants, but exclude any intercompany revenues.Competitive Business Revenues (Generation):
[10]	des all wholesale and retail electric sales to third parties and affiliated sales to the Utility Registrants.(b)

Segment Information - Generation Total Revenues (Details) - USD ($)
$ in Millions

3 Months Ended

Mar. 31, 2019

Mar. 31, 2018

$ 9,477

$ 9,693

Generation Mid Atlantic [Member]

^[1]

Generation Midwest [Member]

1,256

1,440

Generation New York [Member]

1,108

1,346

Generation ERCOT [Member]

393

409

Generation Other Regions [Member]

212

209

Generation Reportable Segments Total [Member]

1,353

1,080

Generation Natural Gas [Member]

4,322

4,484

Generation All Other Segments [Member]

894

980

^[2]

Generation Total Consolidated Group [Member]

(52)

(98)

Operating Segments [Member]

5,296

5,512

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

^[3]

9,477

9,693

Operating Segments [Member] | Generation Midwest [Member]

^[4]

1,262

1,435

Operating Segments [Member] | Generation New York [Member]

^[4]

1,114

1,344

Operating Segments [Member] | Generation ERCOT [Member]

^[4]

393

410

Operating Segments [Member] | Generation Other Regions [Member]

^[4]

209

208

Operating Segments [Member] | Generation Reportable Segments Total [Member]

^[4]

1,359

1,112

Operating Segments [Member] | Generation Natural Gas [Member]

^[4]

4,337

4,509

Operating Segments [Member] | Generation All Other Segments [Member]

^[4]

879

955

Operating Segments [Member] | Generation Total Consolidated Group [Member]

(28)

(266)

Corporate, Non-Segment [Member] | Generation All Other Segments [Member]

^[4]

5,296

5,512

Intersegment Eliminations [Member]

^[4],[5]

^[3]

(786)

(876)

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

^[1]

(785)

(876)

Intersegment Eliminations [Member] | Generation Midwest [Member]

(6)

Intersegment Eliminations [Member] | Generation New York [Member]

(6)

Intersegment Eliminations [Member] | Generation ERCOT [Member]

(1)

Intersegment Eliminations [Member] | Generation Other Regions [Member]

Intersegment Eliminations [Member] | Generation Reportable Segments Total [Member]

(6)

(32)

Intersegment Eliminations [Member] | Generation Natural Gas [Member]

(15)

(25)

Intersegment Eliminations [Member] | Generation All Other Segments [Member]

Intersegment Eliminations [Member] | Generation Total Consolidated Group [Member]

^[2]

Revenue from Contract with Customer [Member] | Operating Segments [Member] | Generation Mid Atlantic [Member]

Revenue from Contract with Customer [Member] | Operating Segments [Member] | Generation Midwest [Member]

^[4]

1,286

1,355

Revenue from Contract with Customer [Member] | Operating Segments [Member] | Generation New York [Member]

^[4]

1,055

1,273

Revenue from Contract with Customer [Member] | Operating Segments [Member] | Generation ERCOT [Member]

^[4]

409

439

Revenue from Contract with Customer [Member] | Operating Segments [Member] | Generation Other Regions [Member]

^[4]

130

149

Revenue from Contract with Customer [Member] | Operating Segments [Member] | Generation Reportable Segments Total [Member]

^[4]

1,165

935

Revenue from Contract with Customer [Member] | Operating Segments [Member] | Generation Natural Gas [Member]

^[4]

4,045

4,151

Revenue from Contract with Customer [Member] | Operating Segments [Member] | Generation Total Consolidated Group [Member]

^[4]

584

522

Revenue from Contract with Customer [Member] | Corporate, Non-Segment [Member] | Generation All Other Segments [Member]

^[4]

4,749

4,807

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

^[4],[5]

120

134

Other [Member] | Operating Segments [Member] | Generation Midwest [Member]

^[4],[6]

(24)

Other [Member] | Operating Segments [Member] | Generation New York [Member]

^[4],[6]

Other [Member] | Operating Segments [Member] | Generation ERCOT [Member]

^[4],[6]

(16)

(29)

Other [Member] | Operating Segments [Member] | Generation Other Regions [Member]

^[4],[6]

Other [Member] | Operating Segments [Member] | Generation Reportable Segments Total [Member]

^[4],[6]

194

177

Other [Member] | Operating Segments [Member] | Generation Natural Gas [Member]

^[4],[6]

292

358

Other [Member] | Operating Segments [Member] | Generation Total Consolidated Group [Member]

^[4],[6]

295

433

Other [Member] | Corporate, Non-Segment [Member] | Generation All Other Segments [Member]

^[4],[6]

547

705

Generation Mid Atlantic [Member]

^[4],[5],[6]

$ (40)

$ (86)

[1]	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.
[2]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOjhiOGQyMzgxMWZiYjQ2YjNiZDRmMDg0ZmFhZDBiZGFjfFRleHRTZWxlY3Rpb246Nzg0RjkwRDlGOTIxNTBDQkFGM0EzREE2MkIyMjdEOTEM}
[3]	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.
[4]	des all wholesale and retail electric sales to third parties and affiliated sales to the Utility Registrants.(b)
[5]	represents activities not allocated to a region. See text above for a description of included activities. Includes unrealized mark-to-market losses of $52 million and $98 million in 2019 and 2018, respectively, and elimination of intersegment revenues.Reve
[6]	des revenues from derivatives and leases. (c)

Segment Information - Generation Total Revenues Net of Purchased Power and Fuel Expense (Details) - USD ($)
$ in Millions

3 Months Ended

Mar. 31, 2019

Mar. 31, 2018

Generation Midwest [Member]

$ 683

$ 850

Generation New York [Member]

771

860

Generation ERCOT [Member]

265

283

Generation Other Regions [Member]

Generation Reportable Segments Total [Member]

156

236

Generation All Other Segments [Member]

1,949

2,265

^[1]

142

(46)

Generation Total Consolidated Group [Member]

(52)

(98)

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

2,091

2,219

Revenue Net Of Purchase Power And Fuel From External Customers

^[2]

679

836

Operating Segments [Member] | Generation Midwest [Member]

Revenue Net Of Purchase Power And Fuel From External Customers

^[2]

769

847

Operating Segments [Member] | Generation New York [Member]

Revenue Net Of Purchase Power And Fuel From External Customers

^[2]

262

282

Operating Segments [Member] | Generation ERCOT [Member]

Revenue Net Of Purchase Power And Fuel From External Customers

^[2]

106

Operating Segments [Member] | Generation Other Regions [Member]

Revenue Net Of Purchase Power And Fuel From External Customers

^[2]

174

279

Operating Segments [Member] | Generation Reportable Segments Total [Member]

Revenue Net Of Purchase Power And Fuel From External Customers

^[2]

1,982

2,350

Operating Segments [Member] | Generation All Other Segments [Member]

Revenue Net Of Purchase Power And Fuel From External Customers

^[1],[2]

109

(131)

Nuclear Fuel Amortization

(28)

(266)

Operating Segments [Member] | Generation Total Consolidated Group [Member]

Revenue Net Of Purchase Power And Fuel From External Customers

^[2]

2,091

2,219

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

Intersegment Revenue Net Of Purchase Power And Fuel

Intersegment Eliminations [Member] | Generation Midwest [Member]

Intersegment Revenue Net Of Purchase Power And Fuel

Intersegment Eliminations [Member] | Generation New York [Member]

Intersegment Revenue Net Of Purchase Power And Fuel

Intersegment Eliminations [Member] | Generation ERCOT [Member]

Intersegment Revenue Net Of Purchase Power And Fuel

(24)

(70)

Intersegment Eliminations [Member] | Generation Other Regions [Member]

Intersegment Revenue Net Of Purchase Power And Fuel

(18)

(43)

Intersegment Eliminations [Member] | Generation Reportable Segments Total [Member]

Intersegment Revenue Net Of Purchase Power And Fuel

(33)

(85)

Intersegment Eliminations [Member] | Generation All Other Segments [Member]

Intersegment Revenue Net Of Purchase Power And Fuel

^[1]

Intersegment Eliminations [Member] | Generation Total Consolidated Group [Member]