View Filing Data

$ 5,113

$ 4,550

4,570

4,118

^[1]

9,693

8,747

Competitive businesses purchased power and fuel

3,289

2,795

Cost of Purchased Power

1,438

1,104

2,384

2,438

1,091

896

446

436

Gain (Loss) on Disposition of Other Assets

8,648

7,669

Bargain purchase gain

226

1,101

1,308

(365)

(363)

(6)

(10)

(28)

257

(399)

(116)

702

1,192

Equity in losses of unconsolidated affiliates

211

(7)

(10)

Net income (loss) attributable to noncontrolling interests

636

971

(19)

Net income attributable to common shareholders

585

990

Other comprehensive income (loss), net of income taxes

Prior service benefit reclassified to periodic benefit cost

(17)

(13)

Actuarial loss reclassified to periodic benefit cost

Pension and non-pension postretirement benefit plan valuation adjustment

(59)

Unrealized gain on cash flow hedges

Other Comprehensive Income Unrealized Income Loss On Equity Investments Arising During Period Net Of Tax

Unrealized gain on foreign currency translation

Unrealized gain on marketable securities

(12)

Comprehensive income (loss) attributable to noncontrolling interests

708

959

(21)

Comprehensive Income (Loss), Net of Tax, Attributable to Parent

$ 656

$ 980

Average shares of common stock outstanding:

Weighted average common shares outstanding — basic

966

928

Weighted average common shares outstanding — diluted

968

930

Earnings per average common share:

Basic

$ 0.61

$ 1.07

Diluted

0.60

1.06

Dividends declared per common share

$ 0.35

$ 0.33

$ 5,114

$ 4,548

398

330

5,512

4,878

Cost of Purchased Power

3,289

2,796

1,178

1,313

161

179

448

302

138

143

Gain (Loss) on Disposition of Other Assets

5,218

4,735

Bargain purchase gain

226

347

373

(91)

(90)

(10)

(44)

259

(145)

159

202

532

Equity in losses of unconsolidated affiliates

123

(7)

(10)

Net income (loss) attributable to noncontrolling interests

186

399

(19)

Net income attributable to membership interest

136

418

Other comprehensive income (loss), net of income taxes

Unrealized gain on cash flow hedges

Other Comprehensive Income Unrealized Income Loss On Equity Investments Arising During Period Net Of Tax

Unrealized gain on foreign currency translation

(1)

Comprehensive income (loss) attributable to noncontrolling interests

193

410

(21)

Comprehensive Income (Loss), Net of Tax, Attributable to Parent

142

431

1,493

1,279

1,512

1,298

411

329

194

253

307

228

208

Gain (Loss) on Disposition of Other Assets

1,223

984

292

314

(86)

(82)

(3)

(81)

211

233

Other comprehensive income (loss), net of income taxes

165

141

165

141

633

589

232

206

(1)

866

796

199

156

233

174

724

604

142

192

(30)

(28)

(3)

(31)

(29)

111

163

(2)

Other comprehensive income (loss), net of income taxes

113

127

113

127

654

640

330

271

(13)

977

951

192

133

123

134

184

148

134

128

800

723

177

228

(25)

(23)

(4)

(21)

(23)

156

205

Other comprehensive income (loss), net of income taxes

128

125

128

125

1,151

1,067

1,251

1,175

374

288

105

144

271

223

183

167

113

111

1,125

995

126

180

(63)

(62)

(52)

(49)

131

(9)

Other comprehensive income (loss), net of income taxes

140

Comprehensive Income (Loss), Net of Tax, Attributable to Parent

140

536

514

557

530

130

101

501

451

(31)

(29)

(23)

(21)

Other comprehensive income (loss), net of income taxes

303

285

384

362

335

284

(13)

(11)

(10)

Other comprehensive income (loss), net of income taxes

Comprehensive Income (Loss), Net of Tax, Attributable to Parent

311

268

(2)

310

275

155

128

287

250

(16)

(15)

(15)

(13)

(16)

Other comprehensive income (loss), net of income taxes

$ 7

$ 28

[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.

Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Cash flows from operating activities
Net income	$ 636	$ 971
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	1,501	1,274
Impairment of long-lived assets and losses on regulatory assets	0	10
Gain on sales of assets and businesses	(56)	(4)
Bargain purchase gain	0	(226)
Deferred income taxes and amortization of investment tax credits	(14)	185
Net fair value changes related to derivatives	259	47
Net realized and unrealized gains (losses) on nuclear decommissioning trust fund investments	68	(175)
Other non-cash operating activities	240	118
Changes in assets and liabilities:
Accounts receivable	133	291
Inventories	167	109
Accounts payable and accrued expenses	(451)	(728)
Option premiums paid, net	(27)	(6)
Collateral posted, net	(214)	(110)
Income taxes	86	50
Pension and non-pension postretirement benefit contributions	(331)	(307)
Other assets and liabilities	(495)	(425)
Net cash flows provided by (used in) operating activities	1,502	1,074
Cash flows from investing activities
Capital expenditures	(1,880)	(2,009)
Proceeds from nuclear decommissioning trust fund sales	1,189	1,767
Investment in nuclear decommissioning trust funds	(1,248)	(1,833)
Acquisition of businesses, net	0	(212)
Proceeds from sales of assets and businesses	79	22
Other investing activities	3	(18)
Net cash flows provided by (used in) investing activities	(1,857)	(2,283)
Cash flows from financing activities
Changes in short-term borrowings	726	721
Proceeds from short-term borrowings with maturities greater than 90 days	1	560
Repayments on short-term borrowings with maturities greater than 90 days	(1)	(500)
Issuance of long-term debt	1,130	763
Retirement of long-term debt	(1,241)	(65)
Dividends paid on common stock	(333)	(303)
Proceeds from employee stock plans	12	12
Other financing activities	(30)	(4)
Net cash flows provided by (used in) financing activities	264	1,184
Increase (Decrease) in cash and cash equivalents	(91)	(25)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	1,190	914
Cash, Cash Equivalents and Restricted Cash at End of Period	1,099	889
Exelon Generation Co L L C [Member]
Cash flows from operating activities
Net income	186	399
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	858	678
Impairment of long-lived assets and losses on regulatory assets	0	10
Gain on sales of assets and businesses	(53)	(4)
Bargain purchase gain	0	(226)
Deferred income taxes and amortization of investment tax credits	(68)	108
Net fair value changes related to derivatives	264	51
Net realized and unrealized gains (losses) on nuclear decommissioning trust fund investments	68	(175)
Other non-cash operating activities	45	(10)
Changes in assets and liabilities:
Accounts receivable	194	173
Receivables from and payables to affiliates, net	(15)	23
Inventories	122	81
Accounts payable and accrued expenses	(317)	(236)
Option premiums paid, net	(27)	(6)
Collateral posted, net	(214)	(102)
Income taxes	79	(81)
Pension and non-pension postretirement benefit contributions	(125)	(110)
Other assets and liabilities	(142)	(153)
Net cash flows provided by (used in) operating activities	855	420
Cash flows from investing activities
Capital expenditures	(628)	(625)
Proceeds from nuclear decommissioning trust fund sales	1,189	1,767
Investment in nuclear decommissioning trust funds	(1,248)	(1,833)
Acquisition of businesses, net	0	(212)
Proceeds from sales of assets and businesses	79	22
Other investing activities	(7)	(29)
Net cash flows provided by (used in) investing activities	(615)	(910)
Cash flows from financing activities
Changes in short-term borrowings	165	(42)
Proceeds from short-term borrowings with maturities greater than 90 days	1	60
Repayments on short-term borrowings with maturities greater than 90 days	(1)	0
Issuance of long-term debt	4	762
Retirement of long-term debt	(29)	(30)
Change in Exelon intercompany money pool	0	(1)
Distributions to member	(188)	(164)
Other financing activities	(9)	(3)
Net cash flows provided by (used in) financing activities	(57)	582
Increase (Decrease) in cash and cash equivalents	183	92
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	554	448
Cash, Cash Equivalents and Restricted Cash at End of Period	737	540
Commonwealth Edison Co [Member]
Cash flows from operating activities
Net income	165	141
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	228	208
Deferred income taxes and amortization of investment tax credits	50	137
Other non-cash operating activities	46	31
Changes in assets and liabilities:
Accounts receivable	39	92
Receivables from and payables to affiliates, net	(19)	(16)
Inventories	5	4
Accounts payable and accrued expenses	(158)	(236)
Collateral posted, net	(3)	(7)
Income taxes	(5)	(34)
Pension and non-pension postretirement benefit contributions	(38)	(35)
Other assets and liabilities	(176)	(49)
Net cash flows provided by (used in) operating activities	134	236
Cash flows from investing activities
Capital expenditures	(531)	(626)
Other investing activities	8	7
Net cash flows provided by (used in) investing activities	(523)	(619)
Cash flows from financing activities
Changes in short-term borrowings	317	365
Issuance of long-term debt	800	0
Retirement of long-term debt	(700)	0
Dividends paid on common stock	(114)	(105)
Contributions from parent	113	100
Other financing activities	(9)	(1)
Net cash flows provided by (used in) financing activities	407	359
Increase (Decrease) in cash and cash equivalents	18	(24)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	144	58
Cash, Cash Equivalents and Restricted Cash at End of Period	162	34
PECO Energy Co [Member]
Cash flows from operating activities
Net income	113	127
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	75	71
Deferred income taxes and amortization of investment tax credits	(4)	24
Other non-cash operating activities	21	23
Changes in assets and liabilities:
Accounts receivable	(51)	(25)
Receivables from and payables to affiliates, net	7	(10)
Inventories	12	19
Accounts payable and accrued expenses	6	(40)
Income taxes	5	25
Pension and non-pension postretirement benefit contributions	(24)	(23)
Other assets and liabilities	(141)	(85)
Net cash flows provided by (used in) operating activities	19	106
Cash flows from investing activities
Capital expenditures	(217)	(201)
Changes in Exelon intercompany money pool	0	131
Other investing activities	2	1
Net cash flows provided by (used in) investing activities	(215)	(69)
Cash flows from financing activities
Changes in short-term borrowings	220	0
Issuance of long-term debt	325	0
Retirement of long-term debt	(500)	0
Dividends paid on common stock	(287)	(72)
Change in Exelon intercompany money pool	194	0
Other financing activities	(5)	0
Net cash flows provided by (used in) financing activities	(53)	(72)
Increase (Decrease) in cash and cash equivalents	(249)	(35)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	275	67
Cash, Cash Equivalents and Restricted Cash at End of Period	26	32
Baltimore Gas and Electric Company [Member]
Cash flows from operating activities
Net income	128	125
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	134	128
Deferred income taxes and amortization of investment tax credits	22	72
Other non-cash operating activities	20	24
Changes in assets and liabilities:
Accounts receivable	(32)	(7)
Receivables from and payables to affiliates, net	0	(7)
Inventories	20	17
Accounts payable and accrued expenses	(9)	(81)
Income taxes	14	33
Pension and non-pension postretirement benefit contributions	(45)	(44)
Other assets and liabilities	61	(52)
Net cash flows provided by (used in) operating activities	313	208
Cash flows from investing activities
Capital expenditures	(224)	(206)
Other investing activities	1	4
Net cash flows provided by (used in) investing activities	(223)	(202)
Cash flows from financing activities
Changes in short-term borrowings	(32)	50
Dividends paid on common stock	(52)	(49)
Net cash flows provided by (used in) financing activities	(84)	1
Increase (Decrease) in cash and cash equivalents	6	7
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	18	50
Cash, Cash Equivalents and Restricted Cash at End of Period	24	57
Pepco Holdings LLC [Member]
Cash flows from operating activities
Net income	65	140
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	183	167
Deferred income taxes and amortization of investment tax credits	17	13
Other non-cash operating activities	53	(8)
Changes in assets and liabilities:
Accounts receivable	(9)	68
Receivables from and payables to affiliates, net	10	(8)
Inventories	4	(11)
Accounts payable and accrued expenses	44	(81)
Income taxes	(9)	55
Pension and non-pension postretirement benefit contributions	(55)	(66)
Other assets and liabilities	(24)	(75)
Net cash flows provided by (used in) operating activities	279	194
Cash flows from investing activities
Capital expenditures	(258)	(320)
Other investing activities	0	(3)
Net cash flows provided by (used in) investing activities	(258)	(323)
Cash flows from financing activities
Changes in short-term borrowings	57	145
Repayments on short-term borrowings with maturities greater than 90 days	0	(500)
Issuance of long-term debt	0	1
Retirement of long-term debt	(12)	(24)
Change in Exelon intercompany money pool	13	13
Distributions to member	(71)	(69)
Contributions from member	0	500
Net cash flows provided by (used in) financing activities	(13)	66
Increase (Decrease) in cash and cash equivalents	8	(63)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	95	236
Cash, Cash Equivalents and Restricted Cash at End of Period	103	173
Potomac Electric Power Company [Member]
Cash flows from operating activities
Net income	31	58
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	96	82
Deferred income taxes and amortization of investment tax credits	4	5
Other non-cash operating activities	10	(15)
Changes in assets and liabilities:
Accounts receivable	0	45
Receivables from and payables to affiliates, net	(18)	(6)
Inventories	(2)	(10)
Accounts payable and accrued expenses	36	(49)
Income taxes	(3)	20
Pension and non-pension postretirement benefit contributions	(7)	(64)
Other assets and liabilities	(21)	(37)
Net cash flows provided by (used in) operating activities	126	29
Cash flows from investing activities
Capital expenditures	(127)	(139)
Other investing activities	0	(5)
Net cash flows provided by (used in) investing activities	(127)	(144)
Cash flows from financing activities
Changes in short-term borrowings	34	144
Issuance of long-term debt	0	1
Dividends paid on common stock	(25)	(30)
Other financing activities	0	(1)
Net cash flows provided by (used in) financing activities	9	114
Increase (Decrease) in cash and cash equivalents	8	(1)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	40	42
Cash, Cash Equivalents and Restricted Cash at End of Period	48	41
Delmarva Power and Light Company [Member]
Cash flows from operating activities
Net income	31	57
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	45	39
Deferred income taxes and amortization of investment tax credits	10	13
Other non-cash operating activities	19	(7)
Changes in assets and liabilities:
Accounts receivable	(1)	6
Receivables from and payables to affiliates, net	(16)	1
Inventories	7	1
Accounts payable and accrued expenses	18	14
Income taxes	(5)	21
Other assets and liabilities	7	(23)
Net cash flows provided by (used in) operating activities	115	122
Cash flows from investing activities
Capital expenditures	(65)	(82)
Other investing activities	0	2
Net cash flows provided by (used in) investing activities	(65)	(80)
Cash flows from financing activities
Changes in short-term borrowings	(5)	0
Retirement of long-term debt	(4)	(14)
Dividends paid on common stock	(36)	(30)
Net cash flows provided by (used in) financing activities	(45)	(44)
Increase (Decrease) in cash and cash equivalents	5	(2)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	2	46
Cash, Cash Equivalents and Restricted Cash at End of Period	7	44
Atlantic City Electric Company [Member]
Cash flows from operating activities
Net income	7	28
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	33	35
Deferred income taxes and amortization of investment tax credits	2	(7)
Other non-cash operating activities	9	2
Changes in assets and liabilities:
Accounts receivable	(5)	14
Receivables from and payables to affiliates, net	(4)	(5)
Inventories	0	(1)
Accounts payable and accrued expenses	30	(5)
Income taxes	0	3
Pension and non-pension postretirement benefit contributions	(6)	0
Other assets and liabilities	(7)	(6)
Net cash flows provided by (used in) operating activities	59	58
Cash flows from investing activities
Capital expenditures	(63)	(88)
Other investing activities	(1)	1
Net cash flows provided by (used in) investing activities	(64)	(87)
Cash flows from financing activities
Changes in short-term borrowings	28	0
Retirement of long-term debt	(8)	(10)
Dividends paid on common stock	(9)	(10)
Net cash flows provided by (used in) financing activities	11	(20)
Increase (Decrease) in cash and cash equivalents	6	(49)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	31	133
Cash, Cash Equivalents and Restricted Cash at End of Period	$ 37	$ 84

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

Mar. 31, 2018

Dec. 31, 2017

$ 787

$ 898

209

207

4,190

4,445

Mark-to-market derivative assets, current

1,103

1,132

978

976

180

340

1,291

1,311

1,245

1,267

1,495

1,260

11,533

11,896

74,711

74,202

8,063

8,021

13,149

13,272

640

Mark-to-market derivative assets, noncurrent

6,677

527

337

385

395

1,333

1,330

30,774

30,672

^[1]

117,018

116,770

1,654

929

1,203

2,088

3,207

3,532

1,569

1,837

522

523

415

232

Energy Marketing Accounts Payable

202

231

333

352

Accounts Payable and Accrued Liabilities, Current

956

982

10,153

10,798

Long-term debt to financing trust

32,905

32,176

389

Deferred Income Taxes and Other Tax Liabilities, Noncurrent

11,344

11,235

10,126

10,029

Pension obligations

3,433

3,736

Spent nuclear fuel obligation

2,114

2,093

1,151

1,147

Mark-to-market derivative liabilities, noncurrent

9,724

9,865

468

409

579

609

2,067

2,097

41,006

41,220

Commitments and contingencies

^[1]

84,453

84,583

Treasury stock, at cost (2 shares at March 31, 2018 and December 31, 2017)

18,973

18,964

(123)

Accumulated other comprehensive loss, net

14,346

14,081

(2,965)

(3,026)

30,231

29,896

Noncontrolling Interests

2,334

2,291

Total equity

32,565

32,187

Variable Interest Entity, Consolidated, Liabilities, No Recourse

117,018

116,770

3,556

3,618

Variable Interest Entity, Consolidated, Assets, Not Pledged

9,727

9,597

610

416

127

138

2,478

2,697

Mark-to-market derivative assets, current

294

321

978

976

153

140

151

264

916

937

1,122

933

6,884

6,882

24,714

24,906

13,149

13,272

431

433

Mark-to-market derivative assets, noncurrent

527

334

1,571

1,502

385

395

Deferred income taxes

657

670

16,777

16,669

^[2]

48,375

48,457

166

373

346

1,447

1,773

951

1,022

Borrowings from Exelon intercompany money pool

114

123

391

211

Energy Marketing Accounts Payable

333

352

288

265

4,156

4,191

Long-term debt to affiliate

7,685

7,734

907

910

Deferred Income Taxes and Other Tax Liabilities, Noncurrent

3,749

3,811

9,941

9,844

Spent nuclear fuel obligation

911

916

1,151

1,147

Payables to affiliates, noncurrent

2,970

3,065

Mark-to-market derivative liabilities, noncurrent

221

174

686

658

19,669

19,663

Commitments and contingencies

^[2]

32,417

32,498

Accumulated other comprehensive loss, net

4,303

4,349

(34)

(37)

Membership Interest

9,357

Total members' equity

13,626

13,669

Noncontrolling Interests

2,332

2,290

Total equity

15,958

15,959

Variable Interest Entity, Consolidated, Liabilities, No Recourse

48,375

48,457

3,461

3,516

Variable Interest Entity, Consolidated, Assets, Not Pledged

9,688

9,556

485

559

290

266

Inventories, net

146

152

226

225

1,336

1,364

21,010

20,723

1,125

1,054

Receivable from affiliate, noncurrent

2,625

2,464

2,528

1,177

1,188

259

238

7,656

7,639

30,002

29,726

317

440

840

491

568

198

327

212

249

111

112

103

1,945

2,294

Long-term debt to financing trust

7,254

6,761

205

Deferred Income Taxes and Other Tax Liabilities, Noncurrent

3,539

3,469

111

215

219

Mark-to-market derivative liabilities, noncurrent

6,212

6,328

243

235

572

562

10,892

10,924

20,296

20,184

Retained Earnings, Unappropriated

1,588

Other paid-in capital

6,935

6,822

(1,639)

Retained Earnings, Appropriated

2,822

2,771

9,706

9,542

30,002

29,726

271

349

327

117

105

Prepaid Taxes

736

822

8,176

8,053

408

381

Receivable from affiliate, noncurrent

505

537

359

340

1,306

1,295

10,218

10,170

220

500

379

370

114

Borrowings from Exelon intercompany money pool

194

117

141

1,155

1,267

Long-term debt to financing trust

2,723

2,403

184

Deferred Income Taxes and Other Tax Liabilities, Noncurrent

1,824

1,789

288

529

549

2,753

2,739

6,815

6,593

2,489

Accumulated other comprehensive loss, net

914

1,087

3,403

3,577

10,218

10,170

394

375

149

174

Prepaid Taxes

755

811

7,725

7,602

391

397

313

285

715

691

9,195

9,104

253

265

162

164

102

118

116

757

760

2,578

2,577

Deferred Income Taxes and Other Tax Liabilities, Noncurrent

1,286

1,244

199

202

1,083

1,101

2,643

2,626

5,978

5,963

1,605

1,612

1,536

3,217

3,141

9,195

9,104

484

486

210

206

152

151

507

554

1,493

1,551

12,688

12,498

2,453

2,493

Notes, Loans and Financing Receivable, Gross, Noncurrent

132

4,005

527

490

Deferred income taxes

7,194

7,198

^[3]

21,375

21,247

407

350

385

396

469

348

246

261

Borrowings from Exelon intercompany money pool

100

162

188

Merger related obligation

114

119

2,067

1,931

5,464

5,478

Deferred Income Taxes and Other Tax Liabilities, Noncurrent

2,103

2,070

102

105

1,888

1,872

539

561

377

389

5,025

5,013

^[3]

12,556

12,422

(16)

(10)

Membership Interest

8,835

Total members' equity

8,819

8,825

Total equity

8,819

8,825

Variable Interest Entity, Consolidated, Liabilities, No Recourse

21,375

21,247

102

Variable Interest Entity, Consolidated, Assets, Not Pledged

246

250

Inventories, net

207

213

696

710

6,095

6,001

656

678

104

102

323

322

1,105

1,121

7,896

7,832

181

139

145

137

Merger related obligation

Current portion of DC PLUG obligation

600

550

2,521

Deferred Income Taxes and Other Tax Liabilities, Noncurrent

1,076

1,063

838

829

288

300

2,236

2,228

5,357

5,299

1,470

1,069

1,063

2,539

2,533

7,896

7,832

141

146

314

325

3,620

3,579

242

245

192

193

449

453

4,383

4,357

211

216

106

558

547

1,217

Deferred Income Taxes and Other Tax Liabilities, Noncurrent

618

603

598

593

1,278

1,258

3,053

3,022

764

566

571

1,330

1,335

4,383

4,357

Inventories, net

263

258

2,767

2,706

Notes, Loans and Financing Receivable, Gross, Noncurrent

377

359

500

481

^[4]

3,530

3,445

136

108

278

281

166

118

703

619

836

840

Deferred Income Taxes and Other Tax Liabilities, Noncurrent

496

493

416

411

950

943

^[4]

2,489

2,402

912

129

131

1,041

1,043

Variable Interest Entity, Consolidated, Liabilities, No Recourse

3,530

3,445

Variable Interest Entity, Consolidated, Assets, Not Pledged

$ 27

$ 29

[1]	Exelon’s consolidated assets include $9,727 million and $9,597 million at March 31, 2018 and December 31, 2017, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $3,556 million and $3,618 million at March 31, 2018 and December 31, 2017, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 3 — Variable Interest Entities.
[2]	Generation’s consolidated assets include $9,688 million and $9,556 million at March 31, 2018 and December 31, 2017, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $3,461 million and $3,516 million at March 31, 2018 and December 31, 2017, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 3 — Variable Interest Entities.
[3]	PHI’s consolidated total assets include $39 million and $41 million at March 31, 2018 and December 31, 2017, respectively, of PHI's consolidated VIE that can only be used to settle the liabilities of the VIE. PHI’s consolidated total liabilities include $95 million and $102 million at March 31, 2018 and December 31, 2017, respectively, of PHI's consolidated VIE for which the VIE creditors do not have recourse to PHI. See Note 3 — Variable Interest Entities.
[4]	ACE’s consolidated total assets include $27 million and $29 million at March 31, 2018 and December 31, 2017, respectively, of ACE's consolidated VIE that can only be used to settle the liabilities of the VIE. ACE’s consolidated total liabilities include $83 million and $90 million at March 31, 2018 and December 31, 2017, respectively, of ACE's consolidated VIE for which the VIE creditors do not have recourse to ACE. See Note 3 — Variable Interest Entities.

Consolidated Balance Sheets (Unaudited) (Parenthetical) - shares	Mar. 31, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Common Stock, Shares Authorized	2,000,000,000	2,000,000,000
Common Stock, Shares, Outstanding	965,381,919	963,335,888
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 Earnings, 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 Additional Capital [Member]

Commonwealth Edison Co [Member]

Retained Earnings, 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 Earnings, 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 at Dec. 31, 2016

^[1]

$ (2,660)

Beginning Balance at Dec. 31, 2016

^[1]

$ (54)

Beginning Balance at Dec. 31, 2016

^[1]

$ 1

Increase (Decrease) in Stockholders' Equity [Roll Forward]

Other Comprehensive Income (Loss), Net of Tax

$ 971

$ 399

$ 141

$ 127

$ 125

$ 140

$ 58

$ 57

$ 28

$ (12)

(10)

^[1]

Ending balance at Mar. 31, 2017

^[1]

(2,670)

Ending Balance at Mar. 31, 2017

^[1]

(41)

Ending Balance at Mar. 31, 2017

^[1]

Increase (Decrease) in Stockholders' Equity [Roll Forward]

Retained Earnings, Appropriated

(2,771)

Beginning Balance (in shares) at Dec. 31, 2017

965,168

Beginning balance at Dec. 31, 2017

$ 32,187

$ 18,964

$ (123)

$ 14,081

(3,026)

^[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

29,896

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, Share-based Compensation, Gross

$ 636

585

186

136

165

113

128

1,685

Stock Issued During Period, Value, Share-based Compensation, Gross

$ (3)

(3)

Stock Issued During Period, Shares, Employee Stock Purchase Plans

361

Stock Issued During Period, Value, Employee Stock Purchase Plan

$ 12

Noncontrolling Interest, Period Increase (Decrease)

(9)

Common stock dividends

(334)

(114)

(287)

(52)

(25)

(36)

(9)

Other Comprehensive Income (Loss), Net of Tax

^[1]

Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax

$ 4

(10)

(3)

(1)

Distribution Made to Limited Liability Company (LLC) Member, Cash Distributions Declared

(188)

(71)

Adjustments to Additional Paid in Capital, Other

113

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

967,214

Ending balance at Mar. 31, 2018

$ 32,565

$ 18,973

$ (123)

$ 14,346

$ (2,965)

^[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

$ 30,231

9,706

$ 1,588

$ 6,935

(1,639)

2,822

$ 3,403

$ 2,489

$ 914

$ 0

^[1]

$ 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]

Retained Earnings, Appropriated

$ (2,822)

$ (165)

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

Significant Accounting Policies

3 Months Ended

Mar. 31, 2018

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 through its principal subsidiaries in the energy generation and energy distribution and transmission businesses.



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.	Six reportable segments: Mid-Atlantic, Midwest, New England, 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.

The accompanying consolidated financial statements as of March 31, 2018 and 2017 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, 2017 revised 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, 2018. 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.

Prior Period Adjustments and Reclassifications (All Registrants)

In the second quarter of 2017, errors were identified related to the Exelon, Generation, ComEd, PECO and BGE Consolidated Statements of Cash Flows for the three months ended March 31, 2017. These classification errors related to the presentation of changes in Accounts payable and accrued expenses and Accounts receivable within Cash flows provided by operating activities and Capital expenditures and Proceeds from sale of long-lived assets within Cash flows used in investing activities. These errors have been corrected in Exelon's, Generation's, ComEd's, PECO's, and BGE's Consolidated Statements of Cash Flows for the three months ended March 31, 2017 that are presented in this first quarter 2018 Form 10-Q. As revised, the Cash flows provided by operating activities for the three months ended March 31, 2017 are $1,074 million, $420 million, $236 million, $106 million and $208 million for Exelon, Generation, ComEd, PECO and BGE, respectively, an increase (decrease) of $(127) million, $(320) million, $91 million, $42 million and $40 million for Exelon, Generation, ComEd, PECO and BGE, respectively, from the originally reported amounts. As revised, the Cash flows used in investing activities are $2,283 million, $910 million, $619 million, $69 million and $202 million for Exelon, Generation, ComEd, PECO and BGE, respectively, an increase (decrease) of $(127) million, $(320) million, $91 million, $42 million and $40 million for Exelon, Generation, ComEd, PECO and BGE, respectively, from the originally reported amounts. Management concluded that the errors are not material to the previously issued financial statements.

Certain prior year amounts in the Registrants' Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows, Consolidated Balance Sheets and Consolidated Statements of Changes in Shareholders' Equity have been recasted to reflect new accounting standards issued by the FASB and adopted as of January 1, 2018.

Beginning on January 1, 2018, Exelon adopted the following new accounting standards requiring reclassification or adjustments to previously reported information as follows:


•	Statement of Cash Flows: Classification of Restricted Cash. The Registrants applied the new guidance using the full retrospective method and, accordingly, have recasted the presentation of restricted cash in their Consolidated Statements of Cash Flows in the prior periods presented. See Note 18 — Supplemental Financial Information for further information.

•

Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. Exelon early adopted and retrospectively applied the new guidance to when the effects of the TCJA were recognized and, accordingly, recasted its December 31, 2017 AOCI and retained earnings in its Consolidated Balance Sheet and Consolidated Statement of Changes in Shareholders' Equity. Exelon's accounting policy is to release the stranded tax effects from AOCI related to its pension and OPEB plans under a portfolio (or aggregate) approach as an entire pension or OPEB plan is liquidated or terminated. See Note 2 — New Accounting Standards for further information.

•

Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. Exelon applied this guidance retrospectively for the presentation of the service and other non-service costs components of net benefit cost and, accordingly, have recasted those amounts, which were not material, in its Consolidated Statement of Operations and Comprehensive Income in prior periods presented. As part of the adoption, Exelon elected the practical expedient that permits an employer to use the amounts disclosed in its pension and other postretirement benefit plan note for the comparative periods as the estimation basis for applying the retrospective presentation requirements. See Note 14 — Retirement Benefits for further information.

•

Revenue from Contracts with Customers. The Registrants applied the new guidance using the full retrospective method and, accordingly, have recasted certain amounts in their Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows, Consolidated Balance Sheets, Consolidated Statements of Changes in Shareholders' Equity and Combined Notes to Consolidated Financial Statements in the prior periods presented. The amounts recasted in the Registrants' Consolidated Statements of Operations and Comprehensive Income are shown in the table below. The amounts recasted in the Registrants’ Consolidated Statements of Cash Flows, Consolidated Balance Sheets, Consolidated Statements of Changes in Shareholders' Equity and Combined Notes to Consolidated Financial Statements were not material. See Note 5 — Revenue from Contracts with Customers for further information.



Three Months Ended March 31, 2017	Exelon			Generation			ComEd			PECO		BGE			PHI			Pepco			DPL			ACE
Operating Revenues - As reported
Competitive business revenues	$	4,560		$	—		$	—		$	—	$	—		$	—		$	—		$	—		$	—
Rate-regulated utility revenues	4,197			—			—			—		—			—			—			—			—
Operating revenues	—			4,558			—			—		—			—			—			—			—
Electric operating revenues	—			—			1,293			589		665			1,097			529			294			274
Natural gas operating revenues	—			—			—			206		281			66			—			66			—
Operating revenues from affiliates	—			330			5			1		5			12			1			2			1
Total operating revenues	$	8,757		$	4,888		$	1,298		$	796	$	951		$	1,175		$	530		$	362		$	275

Operating Revenues - Adjustments
Competitive business revenues	$	(10	)	$	—		$	—		$	—	$	—		$	—		$	—		$	—		$	—
Rate-regulated utility revenues	(79		)	—			—			—		—			—			—			—			—
Operating revenues	—			(10		)	—			—		—			—			—			—			—
Electric operating revenues	—			—			(14		)	—		(25		)	(30		)	(15		)	(9		)	(6		)
Natural gas operating revenues	—			—			—			—		(10		)	—			—			—			—
Revenues from alternative revenue programs	79			—			14			—		35			30			15			9			6
Operating revenues from affiliates	—			—			—			—		—			—			—			—			—
Total operating revenues	$	(10	)	$	(10	)	$	—		$	—	$	—		$	—		$	—		$	—		$	—

Operating Revenues - Retrospective application
Competitive business revenues	$	4,550		$	—		$	—		$	—	$	—		$	—		$	—		$	—		$	—
Rate-regulated utility revenues	4,118			—			—			—		—			—			—			—			—
Operating revenues	—			4,548			—			—		—			—			—			—			—
Electric operating revenues	—			—			1,279			589		640			1,067			514			285			268
Natural gas operating revenues	—			—			—			206		271			66			—			66			—
Revenues from alternative revenue programs	79			—			14			—		35			30			15			9			6
Operating revenues from affiliates	—			330			5			1		5			12			1			2			1
Total operating revenues	$	8,747		$	4,878		$	1,298		$	796	$	951		$	1,175		$	530		$	362		$	275

Revenues (All Registrants)

Operating Revenues. The Registrants’ operating revenues generally consist of revenues from contracts with customers involving the sale and delivery of energy commodities and related products and services, utility revenues from alternative revenue programs (ARP), and realized and unrealized revenues recognized under mark-to-market energy commodity derivative contracts. The Registrants recognize revenue from contracts with customers to depict the transfer of goods or services to customers in an amount that the entities expect to be entitled to in exchange for those goods or services. Generation’s primary sources of revenue include competitive sales of power, natural gas, and other energy-related products and services. The Utility Registrants’ primary sources of revenue include regulated electric and natural gas tariff sales, distribution and transmission services. At the end of each month, the Registrants accrue an estimate for the unbilled amount of energy delivered or services provided to customers.

ComEd records ARP revenue for its best estimate of the electric distribution, energy efficiency, and transmission revenue impacts resulting from future changes in rates that ComEd believes are probable of approval by the ICC and FERC in accordance with its formula rate mechanisms. BGE, Pepco and DPL record ARP revenue for their best estimate of the electric and natural gas distribution revenue impacts resulting from future changes in rates that they believe are probable of approval by the MDPSC and/or DCPSC in accordance with their revenue decoupling mechanisms. PECO, BGE, Pepco, DPL and ACE record ARP revenue for their best estimate of the transmission revenue impacts resulting from future changes in rates that they believe are probable of approval by FERC in accordance with their formula rate mechanisms. See Note 5 — Revenue from Contracts with Customers and Note 6 —Regulatory Matters for further information.

RTOs and ISOs. In RTO and ISO markets that facilitate the dispatch of energy and energy-related products, the Registrants generally report sales and purchases conducted on a net hourly basis in either revenues or purchased power on their Consolidated Statements of Operations and Comprehensive Income, the classification of which depends on the net hourly sale or purchase position. In addition, capacity revenue and expense classification is based on the net sale or purchase position of the Registrants in the different RTOs and ISOs.

Option Contracts, Swaps and Commodity Derivatives. Certain option contracts and swap arrangements that meet the definition of derivative instruments are recorded at fair value with subsequent changes in fair value recognized as revenue or expense. The classification of revenue or expense is based on the intent of the transaction. For example, gas transactions may be used to hedge the sale of power. This will result in the change in fair value recorded through revenue. To the extent a Utility Registrant receives full cost recovery for energy procurement and related costs from retail customers, it records the fair value of its energy swap contracts with unaffiliated suppliers as well as an offsetting regulatory asset or liability on its Consolidated Balance Sheets. Refer to Note 6 — Regulatory Matters and Note 10 — Derivative Financial Instruments for further information.

Taxes Directly Imposed on Revenue-Producing Transactions. The Registrants collect certain taxes from customers such as sales and gross receipts taxes, along with other taxes, surcharges and fees that are levied by state or local governments on the sale or distribution of natural gas and electricity. Some of these taxes are imposed on the customer, but paid by the Registrants, while others are imposed directly on the Registrants. The Registrants do not recognize revenue or expense in their Consolidated Statements of Operations and Comprehensive Income when these taxes are imposed on the customer, such as sales taxes. However, when these taxes are imposed directly on the Registrants, such as gross receipts taxes or other surcharges or fees, the Registrants recognize revenue for the taxes collected from customers along with an offsetting expense. See Note 18 — Supplemental Financial Information for Generation’s, ComEd’s, PECO’s, BGE’s, Pepco’s, DPL’s and ACE’s utility taxes that are presented on a gross basis.

New Accounting Standards (All Registrants)

3 Months Ended

Mar. 31, 2018

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Description of New Accounting Pronouncements Not yet Adopted [Text Block]

New Accounting Standards Issued and Not Yet Adopted as of March 31, 2018: 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, 2018. Unless otherwise indicated, the Registrants are currently assessing the impacts such guidance may have (which could be material) on 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.

Leases (Issued February 2016): Increases transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The standard is effective January 1, 2019. Early adoption is permitted, however the Registrants will not early adopt the standard. The issued guidance required a modified retrospective transition approach, which requires lessees and lessors to recognize and measure leases at the beginning of the earliest period presented (January 1, 2017). In January 2018, the FASB proposed amending the standard to give entities another option for transition. The proposed transition method would allow entities to initially apply the requirements of the standard in the period of adoption (January 1, 2019). The Registrants will assess this transition option when the FASB issues the standard.

The new guidance requires lessees to recognize both the right-of-use assets and lease liabilities in the balance sheet for most leases, whereas today only finance lease liabilities (referred to as capital leases) are recognized in the balance sheet. In addition, the definition of a lease has been revised which may result in changes to the classification of an arrangement as a lease. Under the new guidance, an arrangement that conveys the right to control the use of an identified asset by obtaining substantially all of its economic benefits and directing how it is used is a lease, whereas the current definition focuses on the ability to control the use of the asset or to obtain its output. Quantitative and qualitative disclosures related to the amount, timing and judgments of an entity’s accounting for leases and the related cash flows are expanded. Disclosure requirements apply to both lessees and lessors, whereas current disclosures relate only to lessees. Significant changes to lease systems, processes and procedures are required to implement the requirements of the new standard. The recognition, measurement, and presentation of expenses and cash flows arising from a lease by a lessee have not significantly changed from current GAAP. Lessor accounting is also largely unchanged.

The standard provides a number of transition practical expedients that entities may elect. These include 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. The Registrants expect to elect this practical expedient.

In January 2018, the FASB issued additional guidance which provides another optional transition practical expedient. This practical expedient allows entities to not evaluate land easements under the new guidance at adoption if they were not previously accounted for as leases.

The Registrants have assessed the lease standard and are executing a detailed implementation plan in preparation for adoption on January 1, 2019. Key activities in the implementation plan include:


•	Developing a complete lease inventory and abstracting the required data attributes into a lease accounting system that supports the Registrants' lease portfolios and integrates with existing systems.


•	Evaluating the transition practical expedients available under the guidance.


•	Identifying, assessing and documenting technical accounting issues, policy considerations and financial reporting implications which includes completing a detailed contract assessment for a sample of transactions to determine whether they are leases under the new guidance.


•	Identifying and implementing changes to processes and controls to ensure all impacts of the new guidance are effectively addressed.

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.

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, 2018. 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.

Derivatives and Hedging (Issued September 2017): Allows more financial and nonfinancial hedging strategies to be eligible for hedge accounting. The amendments are intended to more closely align hedge accounting with companies’ risk management strategies, simplify the application of hedge accounting, and increase transparency as to the scope and results of hedging programs. There are also amendments related to effectiveness testing and disclosure requirements. The guidance is effective January 1, 2019 and early adoption is permitted with a modified retrospective transition approach. The Registrants are currently assessing this standard but do not currently expect a significant impact given the limited activity for which the Registrants elect hedge accounting and because the Registrants do not anticipate increasing their use of hedge accounting as a result of this standard.

New Accounting Pronouncements and Changes in Accounting Principles [Text Block]

New Accounting Standards (All Registrants)

New Accounting Standards Adopted: In 2018, the Registrants have adopted the following new authoritative accounting guidance issued by the FASB.

Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income (Issued February 2018): Provides an election for a reclassification from AOCI to Retained earnings to eliminate the stranded tax effects resulting from the TCJA. This standard is effective January 1, 2019, with early adoption permitted, and may be applied either in the period of adoption or retrospective to each period in which the effects of the TCJA were recognized. Exelon early adopted this standard during the first quarter 2018 and elected to apply the guidance retrospectively as of December 31, 2017, which resulted in an increase to Exelon’s Retained earnings and Accumulated other comprehensive loss of $539 million related to deferred income taxes associated with Exelon’s pension and OPEB obligations. There was no impact for Generation, ComEd, PECO, BGE, PHI, Pepco, DPL or ACE.

See Note 1 — Significant Accounting Policies of the Exelon 2017 Form 10-K for information on other new accounting standards issued and adopted as of January 1, 2018.

Variable Interest Entities (All Registrants)

3 Months Ended

Mar. 31, 2018

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, 2018 and December 31, 2017, 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, 2018 and December 31, 2017, 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, 2018 and December 31, 2017, 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, 2018 and December 31, 2017, 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, 2018 and December 31, 2017, ComEd, PECO, BGE, Pepco and DPL did not have any material consolidated VIEs.

As of March 31, 2018 and December 31, 2017, 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 operating and capital funding to one of the energy related companies involved in backup generation.


•	Generation provides approximately $30 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 (see Note 26 — Related Party Transactions of the Exelon 2017 Form 10-K for additional information regarding Generation's and Exelon’s transactions with CENG):

•

under power purchase agreements 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 Reliability Support Services Agreement (RSSA), through the end of March 31, 2017. With the expiration of the RSSA, the PPA was reinstated beginning April 1, 2017 (see Note 6 — Regulatory Matters for additional details),


•	Generation provided a $400 million loan to CENG. As of March 31, 2018, the remaining obligation is $337 million, including accrued interest, which reflects the principal payment made in January 2015,

•

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 17 — Commitments and Contingencies for more details),


•	Generation and EDF share in the $637 million of contingent payment obligations for the payment of contingent retrospective premium adjustments for the nuclear liability insurance,


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

As of March 31, 2018 and December 31, 2017, 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, 2018, ACE transferred $8 million to ATF. During the three months ended March 31, 2017, ACE transferred $19 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, 2018 and December 31, 2017 are as follows:



	March 31, 2018								December 31, 2017
	Exelon^(a)		Generation		PHI^(a)		ACE		Exelon^(a)		Generation		PHI^(a)		ACE
Current assets	$	823	$	812	$	11	$	7	$	662	$	652	$	10	$	6
Noncurrent assets	9,279		9,251		28		20		9,317		9,286		31		23
Total assets	$	10,102	$	10,063	$	39	$	27	$	9,979	$	9,938	$	41	$	29
Current liabilities	$	269	$	236	$	33	$	29	$	308	$	272	$	36	$	32
Noncurrent liabilities	3,292		3,230		62		54		3,316		3,250		66		58
Total liabilities	$	3,561	$	3,466	$	95	$	83	$	3,624	$	3,522	$	102	$	90

_________


(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, 2018 and December 31, 2017, these assets and liabilities primarily consisted of the following:



	March 31, 2018								December 31, 2017
	Exelon ^(a)		Generation		PHI ^(a)		ACE		Exelon^(a)		Generation		PHI^(a)		ACE
Cash and cash equivalents	$	280	$	280	$	—	$	—	$	126	$	126	$	—	$	—
Restricted cash	73		66		7		7		64		58		6		6
Accounts receivable, net
Customer	154		154		—		—		170		170		—		—
Other	29		29		—		—		25		25		—		—
Inventory
Materials and supplies	202		202		—		—		205		205		—		—
Other current assets	55		51		4		—		45		41		4		—
Total current assets	793		782		11		7		635		625		10		6
Property, plant and equipment, net	6,181		6,181		—		—		6,186		6,186		—		—
Nuclear decommissioning trust funds	2,483		2,483		—		—		2,502		2,502		—		—
Other noncurrent assets	270		242		28		20		274		243		31		23
Total noncurrent assets	8,934		8,906		28		20		8,962		8,931		31		23
Total assets	$	9,727	$	9,688	$	39	$	27	$	9,597	$	9,556	$	41	$	29
Long-term debt due within one year	$	102	$	70	$	32	$	28	$	102	$	67	$	35	$	31
Accounts payable	93		93		—		—		114		114		—		—
Accrued expenses	52		51		1		1		67		66		1		1
Unamortized energy contract liabilities	17		17		—		—		18		18		—		—
Other current liabilities	5		5		—		—		7		7		—		—
Total current liabilities	269		236		33		29		308		272		36		32
Long-term debt	1,125		1,063		62		54		1,154		1,088		66		58
Asset retirement obligations	2,062		2,062		—		—		2,035		2,035		—		—
Unamortized energy contract liabilities	1		1		—		—		5		5		—		—
Other noncurrent liabilities	99		99		—		—		116		116		—		—
Total noncurrent liabilities	3,287		3,225		62		54		3,310		3,244		66		58
Total liabilities	$	3,556	$	3,461	$	95	$	83	$	3,618	$	3,516	$	102	$	90

_________


(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 on 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, 2018 and December 31, 2017, 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, 2018 and December 31, 2017, ComEd, PECO, BGE, PHI, Pepco, ACE and DPL did not have any material unconsolidated VIEs.

As of March 31, 2018 and December 31, 2017, 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, Generation has several individually immaterial VIEs that in aggregate represent a total investment of $9 million. These immaterial VIEs are equity and debt securities in energy development companies. The maximum exposure to loss related to these securities is limited to the $9 million included in Investments on Exelon’s and Generation’s Consolidated Balance Sheets. 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, 2018	Commercial Agreement VIEs		Equity Investment VIEs		Total
Total assets^(a)	$	626	$	501	$	1,127
Total liabilities^(a)	37		225		262
Exelon's ownership interest in VIE^(a)	—		246		246
Other ownership interests in VIE^(a)	588		30		618
Registrants’ maximum exposure to loss:
Carrying amount of equity method investments	—		246		246
Contract intangible asset	8		—		8
Net assets pledged for Zion Station decommissioning^(b)	2		—		2



December 31, 2017	Commercial Agreement VIEs		Equity Investment VIEs		Total
Total assets^(a)	$	625	$	509	$	1,134
Total liabilities^(a)	37		228		265
Exelon's ownership interest in VIE^(a)	—		251		251
Other ownership interests in VIE^(a)	588		30		618
Registrants’ maximum exposure to loss:
Carrying amount of equity method investments	—		251		251
Contract intangible asset	8		—		8
Net assets pledged for Zion Station decommissioning^(b)	2		—		2

_________


(a)	These items represent amounts on the unconsolidated VIE balance sheets, not on Exelon’s or Generation’s Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs.

(b)

These items represent amounts on Exelon’s and Generation’s Consolidated Balance Sheets related to the asset sale agreement with ZionSolutions, LLC. The net assets pledged for Zion Station decommissioning includes gross pledged assets of $30 million and $39 million as of March 31, 2018 and December 31, 2017, respectively; offset by payables to ZionSolutions, LLC of $28 million and $37 million as of March 31, 2018 and December 31, 2017, respectively. These items are included to provide information regarding the relative size of the ZionSolutions, LLC unconsolidated VIE. See Note 13 — Nuclear Decommissioning for additional details.

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

3 Months Ended

Mar. 31, 2018

Business Combinations [Abstract]

Mergers, Acquisitions and Dispositions

Mergers, Acquisitions and Dispositions (Exelon and Generation)

Acquisition of Handley Generating Station (Exelon and Generation)

On November 7, 2017, EGTP and all of its wholly owned subsidiaries filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Code in the United States Bankruptcy Court for the District of Delaware, which resulted in Exelon and Generation deconsolidating EGTP's assets and liabilities from their consolidated financial statements in the fourth quarter of 2017. Concurrently with the Chapter 11 filings, Generation entered into an asset purchase agreement to acquire one of EGTP's generating plants, the Handley Generating Station, subject to a potential adjustment for fuel oil and assumption of certain liabilities. In the Chapter 11 Filings, EGTP requested that the proposed acquisition of the Handley Generating Station be consummated through a court-approved and supervised sales process. The acquisition was approved by the Bankruptcy Court in January 2018 and closed on April 4, 2018 for a purchase price of $62 million. The Chapter 11 bankruptcy proceedings were finalized on April 17, 2018, resulting in the ownership of EGTP assets (other than the Handley Generating Station) being transferred to EGTP's lenders.

Acquisition of James A. FitzPatrick Nuclear Generating Station (Exelon and Generation)

On March 31, 2017, Generation acquired the 842 MW single-unit James A. FitzPatrick (FitzPatrick) nuclear generating station located in Scriba, New York from Entergy Nuclear FitzPatrick LLC (Entergy) for a total purchase price of $289 million, which consisted of a cash purchase price of $110 million and a net cost reimbursement to and on behalf of Entergy of $179 million. As part of the acquisition agreements, Generation provided nuclear fuel and reimbursed Entergy for incremental costs to prepare for and conduct a plant refueling outage; and Generation reimbursed Entergy for incremental costs to operate and maintain the plant for the period after the refueling outage through the acquisition closing date. These reimbursements covered costs that Entergy otherwise would have avoided had it shut down the plant as originally intended in January 2017. The amounts reimbursed by Generation were offset by FitzPatrick's electricity and capacity sales revenues for this same post-outage period. As part of the transaction, Generation received the FitzPatrick NDT fund assets and assumed the obligation to decommission FitzPatrick. The NRC license for FitzPatrick expires in 2034.

The fair values of FitzPatrick’s assets and liabilities were determined based on significant estimates and assumptions that are judgmental in nature, including projected future cash flows (including timing), discount rates reflecting risk inherent in the future cash flows and future power and fuel market prices. The valuations performed in the first quarter of 2017 to determine the fair value of the FitzPatrick assets acquired and liabilities assumed were updated in the third quarter of 2017. The purchase price allocation is now final.

For the three months ended March 31, 2017, an after-tax bargain purchase gain of $226 million is included within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income and primarily reflects differences in strategies between Generation and Entergy for the intended use and ultimate decommissioning of the plant. During the third quarter of 2017, Exelon and Generation recorded an additional after-tax bargain purchase gain of $7 million for the three months ended September 30, 2017. The total after-tax bargain purchase gain recorded at Exelon and Generation was $233 million for the twelve months ended December 31, 2017. See Note 13 — Nuclear Decommissioning and Note 14 — Retirement Benefits for additional information regarding the FitzPatrick decommissioning ARO and pension and OPEB updates.

The following table summarizes the acquisition-date fair value of the consideration transferred and the assets and liabilities assumed for the FitzPatrick acquisition by Generation:



Cash paid for purchase price	$	110
Cash paid for net cost reimbursement	125
Nuclear fuel transfer	54
Total consideration transferred	$	289

Identifiable assets acquired and liabilities assumed
Current assets	$	60
Property, plant and equipment	298
Nuclear decommissioning trust funds	807
Other assets^(a)	114
Total assets	$	1,279

Current liabilities	$	6
Nuclear decommissioning ARO	444
Pension and OPEB obligations	33
Deferred income taxes	149
Spent nuclear fuel obligation	110
Other liabilities	15
Total liabilities	$	757
Total net identifiable assets, at fair value	$	522

Bargain purchase gain (after-tax)	$	233

_________


(a)	Includes a $110 million asset associated with a contractual right to reimbursement from the New York Power Authority (NYPA), a prior owner of FitzPatrick, associated with the DOE one-time fee obligation. See Note 23-Commitments and Contingencies of the Exelon 2017 Form 10-K for additional background regarding SNF obligations to the DOE.

Exelon and Generation incurred $32 million of merger and integration costs related to FitzPatrick for the three months ended March 31, 2017, which are included within Operating and maintenance expense in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. Exelon and Generation did not incur any merger and integration costs related to FitzPatrick for the three months ended March 31, 2018.

Asset Dispositions

In December 2017, Generation entered into an agreement to sell its interest in an electrical contracting business that primarily installs, maintains and repairs underground and high-voltage cable transmission and distribution systems. As a result, as of December 31, 2017, certain assets and liabilities were classified as held for sale and included in the Other current assets and Other current liabilities balances on Exelon's and Generations' Consolidated Balance Sheet. On February 28, 2018, Generation completed the sale of its interest for $87 million, resulting in a pre-tax gain which is included in Gain on sales of assets and businesses on Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income for the three months ended March 31, 2018.

Revenue from Contracts with Customers Revenue from Contracts with Customers (All Registrants)

3 Months Ended

Mar. 31, 2018

Revenue from Contract with Customer [Abstract]

Revenue from Contract with Customer [Text Block]



Three Months Ended March 31, 2017	Exelon			Generation			ComEd			PECO		BGE			PHI			Pepco			DPL			ACE
Operating Revenues - As reported
Competitive business revenues	$	4,560		$	—		$	—		$	—	$	—		$	—		$	—		$	—		$	—
Rate-regulated utility revenues	4,197			—			—			—		—			—			—			—			—
Operating revenues	—			4,558			—			—		—			—			—			—			—
Electric operating revenues	—			—			1,293			589		665			1,097			529			294			274
Natural gas operating revenues	—			—			—			206		281			66			—			66			—
Operating revenues from affiliates	—			330			5			1		5			12			1			2			1
Total operating revenues	$	8,757		$	4,888		$	1,298		$	796	$	951		$	1,175		$	530		$	362		$	275

Operating Revenues - Adjustments
Competitive business revenues	$	(10	)	$	—		$	—		$	—	$	—		$	—		$	—		$	—		$	—
Rate-regulated utility revenues	(79		)	—			—			—		—			—			—			—			—
Operating revenues	—			(10		)	—			—		—			—			—			—			—
Electric operating revenues	—			—			(14		)	—		(25		)	(30		)	(15		)	(9		)	(6		)
Natural gas operating revenues	—			—			—			—		(10		)	—			—			—			—
Revenues from alternative revenue programs	79			—			14			—		35			30			15			9			6
Operating revenues from affiliates	—			—			—			—		—			—			—			—			—
Total operating revenues	$	(10	)	$	(10	)	$	—		$	—	$	—		$	—		$	—		$	—		$	—

Operating Revenues - Retrospective application
Competitive business revenues	$	4,550		$	—		$	—		$	—	$	—		$	—		$	—		$	—		$	—
Rate-regulated utility revenues	4,118			—			—			—		—			—			—			—			—
Operating revenues	—			4,548			—			—		—			—			—			—			—
Electric operating revenues	—			—			1,279			589		640			1,067			514			285			268
Natural gas operating revenues	—			—			—			206		271			66			—			66			—
Revenues from alternative revenue programs	79			—			14			—		35			30			15			9			6
Operating revenues from affiliates	—			330			5			1		5			12			1			2			1
Total operating revenues	$	8,747		$	4,878		$	1,298		$	796	$	951		$	1,175		$	530		$	362		$	275

Revenue from Contracts with Customers (All Registrants)

The Registrants recognize revenue from contracts with customers to depict the transfer of goods or services to customers at an amount that the entities expect to be entitled to in exchange for those goods or services. Generation’s primary sources of revenue include competitive sales of power, natural gas, and other energy-related products and services. The Utility Registrants’ primary sources of revenue include regulated electric and gas tariff sales, distribution and transmission services. The performance obligations associated with these sources of revenue are further discussed below.

Unless otherwise noted, for each of the significant revenue categories and related performance obligations described below, the Registrants have the right to consideration from the customer in an amount that corresponds directly with the value transferred to the customer for the performance completed to date. Therefore, the Registrant's have elected to use the right to invoice practical expedient for the contracts within these revenue categories and generally recognize revenue in the amount for which they have the right to invoice the customer. As a result, there are generally no significant judgments used in determining or allocating the transaction price.

Competitive Power Sales (Exelon and Generation)

Generation sells power and other energy-related commodities to both wholesale and retail customers across multiple geographic regions through its customer-facing business, Constellation. Power sale contracts generally contain various performance obligations including the delivery of power and other energy-related commodities such as capacity, ZECs, RECs or other ancillary services. Revenues related to such contracts are generally recognized over time as the power is generated and simultaneously delivered to the customer. However, revenues related to the sale of any goods or services that are not simultaneously received and consumed by the customer are recognized as the performance obligations are satisfied at a point in time. Payment terms generally require that the customers pay for the power or the energy-related commodity within the month following delivery to the customer and there are generally no significant financing components.

Certain contracts may contain limits on the total amount of revenue we are able to collect over the entire term of the contract. In such cases, the Registrants estimate the total consideration expected to be received over the term of the contract net of the constraint, and allocate the expected consideration to the performance obligations in the contract such that revenue is recognized ratably over the term of the entire contract as the performance obligations are satisfied.

Competitive Natural Gas Sales (Exelon and Generation)

Generation sells natural gas on a full requirements basis or for an agreed upon volume to both commercial and residential customers. The primary performance obligation associated with natural gas sale contracts is the delivery of the natural gas to the customer. Revenues related to the sale of natural gas are recognized over time as the natural gas is delivered to and consumed by the customer. Payment from customers is typically due within the month following delivery of the natural gas to the customer and there are generally no significant financing components.

Other Competitive Products and Services (Exelon and Generation)

Generation also sells other energy-related products and services such as long-term construction and installation of energy efficiency assets and new power generating facilities, primarily to commercial and industrial customers. These contracts generally contain a single performance obligation, which is the construction and/or installation of the asset for the customer. The average contract term for these projects is approximately 18 months. Revenues, and associated costs, are recognized throughout the contract term using an input method to measure progress towards completion. The method recognizes revenue based on the various inputs used to satisfy the performance obligation, such as costs incurred and total labor hours expended. The total amount of revenue that will be recognized is based on the agreed upon contractually-stated amount. Payments from customers are typically due within 30 or 45 days from the date the invoice is generated and sent to the customer.

Regulated Electric and Gas Tariff Sales (Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE)

The Utility Registrants sell electricity and electricity distribution services to residential, commercial, industrial and governmental customers through regulated tariff rates approved by their state regulatory commissions. PECO, BGE and DPL also sell natural gas and gas distribution services to residential, commercial, and industrial customers through regulated tariff rates approved by their state regulatory commissions. The performance obligation associated with these tariff sale contracts is the delivery of electricity and/or natural gas. Tariff sales are generally considered daily contracts given that customers can discontinue service at any time. Revenues are generally recognized over time (each day) as the electricity and/or natural gas is delivered to customers. Payment terms generally require that customers pay for the services within the month following delivery of the electricity or natural gas to the customer and there are generally no significant financing components or variable consideration.

Electric and natural gas utility customers have the choice to purchase electricity or natural gas from competitive electric generation and natural gas suppliers. While the Utility Registrants are required under state legislation to bill their customers for the supply and distribution of electricity and/or natural gas, they recognize revenue related only to the distribution services when customers purchase their electricity or natural gas from competitive suppliers.

Regulated Transmission Services (Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE)

Under FERC’s open access transmission policy, the Utility Registrants, as owners of transmission facilities, are required to provide open access to their transmission facilities under filed tariffs at cost-based rates approved by FERC. The Utility Registrants are members of PJM, the regional transmission organization designated by FERC to coordinate the movement of wholesale electricity in PJM’s region, which includes portions of the mid-Atlantic and Midwest. In accordance with FERC-approved rules, the Utility Registrants and other transmission owners in the PJM region make their transmission facilities available to PJM, which directs and controls the operation of these transmission facilities and accordingly compensates the Utility Registrants and other transmission owners. The performance obligations associated with the Utility Registrants’ contract with PJM include (i) Network Integration Transmission Services (NITS), (ii) scheduling, system control and dispatch services, and (iii) access to the wholesale grid. These performance obligations are satisfied over time, and Utility Registrants utilize output methods to measure the progress towards their completion. Passage of time is used for NITS and access to the wholesale grid and MWhs of energy transported over the wholesale grid is used for scheduling, system control and dispatch services. PJM pays the Utility Registrants for these services on a weekly basis and there are no financing components or variable consideration.

Costs to Obtain or Fulfill a Contract with a Customer (Exelon and Generation)

Generation incurs incremental costs in order to execute certain retail power and gas sales contracts. These costs primarily relate to retail broker fees and sales commissions. Generation has capitalized such contract acquisition costs in the amount of $25 million and $26 million as of March 31, 2018 and December 31, 2017, respectively, within Other current assets and Other deferred debits in Exelon’s and Generation’s Consolidated Balance Sheets. These costs are capitalized when incurred and amortized using the straight-line method over the average length of such retail contracts, which is approximately 2 years. Exelon and Generation recognized amortization expense associated with these costs in the amount of $5 million and $9 million for the three months ended March 31, 2018 and 2017, respectively, within Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. Generation does not incur material costs to fulfill contracts with customers that are not already capitalized under existing guidance. In addition, the Utility Registrants do not incur any material costs to obtain or fulfill contracts with customers.

Contract Balances (All Registrants)

Contract Assets

Generation records contract assets for the revenue recognized on the construction and installation of energy efficiency assets and new power generating facilities before Generation has an unconditional right to bill for and receive the consideration from the customer. These contract assets are subsequently reclassified to receivables when the right to payment becomes unconditional. Generation records contract assets and contract receivables within Other current assets and Accounts receivable, net - Customer, respectively, within Exelon’s and Generation’s Consolidated Balance Sheets. The following table provides a rollforward of the contract assets reflected on Exelon's and Generation's Consolidated Balance Sheets from January 1, 2018 to March 31, 2018:



Contract Assets	Exelon and Generation
Balance as of January 1, 2018	$	283
Increases as a result of changes in the estimate of the stage of completion	28
Amounts reclassified to receivables	(9		)
Balance at March 31, 2018	$	302

The Utility Registrants do not have any contract assets.

Contract Liabilities

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 liabilities reflected on Exelon's and Generation's Consolidated Balance Sheet from January 1, 2018 to March 31, 2018:



Contract Liabilities	Exelon and Generation
Balance as of January 1, 2018	$	35
Increases as a result of additional cash received or due	227
Amounts recognized into revenues	(216		)
Balance at March 31, 2018	$	46

The Utility Registrants also record contract liabilities when consideration is received prior to the satisfaction of the performance obligations. As of March 31, 2018 and December 31, 2017, 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, 2018. Generation has elected the exemption which permits the exclusion from this disclosure of certain variable contract consideration. As such, the majority of Generation’s power and gas sales contracts are excluded from this disclosure as they contain variable volumes and/or variable pricing. Thus, 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.

The majority of the Utility Registrants’ tariff sale contracts are generally day-to-day contracts and, therefore, do not contain any future, unsatisfied performance obligations to be included in this disclosure. Further, the Utility Registrants have elected the exemption to not disclose the transaction price allocation to remaining performance obligations for contracts with an original expected duration of one year or less. As such, gas and electric tariff sales contracts and transmission revenue contracts are excluded from this disclosure.



	2019		2020		2021		2022		2023 and thereafter		Total
Exelon	$	544	$	264	$	104	$	46	$	128	$	1,086
Generation	544		264		104		46		128		$	1,086

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

Regulatory Matters (All Registrants)

3 Months Ended

Mar. 31, 2018

Regulated Operations [Abstract]

Regulatory Matters (All Registrants)

Except for the matters noted below, the disclosures set forth in Note 3 — Regulatory Matters of the Exelon 2017 Form 10-K reflect, in all material respects, the current status of regulatory and legislative proceedings of the Registrants. The following is an update to that discussion.

Illinois Regulatory Matters

Tax Cuts and Jobs Act (Exelon and ComEd). On January 18, 2018, the ICC approved ComEd's petition filed on January 5, 2018 seeking approval to pass back to customers beginning February 1, 2018 $201 million in tax savings resulting from the enactment of the TCJA through a reduction in electric distribution rates. The amounts being passed back to customers reflect the benefit of lower income tax rates beginning January 1, 2018 and the settlement of a portion of deferred income tax regulatory liabilities established upon enactment of the TCJA. Refer to Note 12 — Income Taxes for more detail on Corporate Tax Reform.

Electric Distribution Formula Rate (Exelon and ComEd). On April 16, 2018, ComEd filed its annual distribution formula rate update with the ICC. The filing establishes the revenue requirement used to set the rates that will take effect in January 2019 after the ICC’s review and approval, which is due by December 2018. The revenue requirement requested is based on 2017 actual costs plus projected 2018 capital additions as well as an annual reconciliation of the revenue requirement in effect in 2017 to the actual costs incurred that year. ComEd's 2018 filing request includes a total decrease to the revenue requirement of $23 million, reflecting a decrease of $58 million for the initial revenue requirement for 2018 and an increase of $35 million related to the annual reconciliation for 2017. The revenue requirement for 2018 provides for a weighted average debt and equity return on distribution rate base of 6.52% inclusive of an allowed ROE of 8.69%, reflecting the average rate on 30-year treasury notes plus 580 basis points. The annual reconciliation for 2017 provided for a weighted average debt and equity return on distribution rate base of 6.52% inclusive of an allowed ROE of 8.69%, reflecting the average rate on 30-year treasury notes plus 580 basis points. See table below for ComEd's regulatory assets associated with its electric distribution formula rate. For additional information on ComEd's distribution formula rate filings see Note 3 — Regulatory Matters of the Exelon 2017 Form 10-K.

During the first quarter 2018, ComEd revised its electric distribution formula rate, as provided for by FEJA, to reduce the ROE collar calculation from plus or minus 50 basis points to 0 basis points beginning with the reconciliation filed in 2018 for the 2017 calendar year. This revision effectively offsets the favorable or unfavorable impacts to ComEd's electric distribution formula rate revenues associated with variations in delivery volumes associated with above or below normal weather, numbers of customers or usage per customer. ComEd began reflecting the impacts of this change in its electric distribution services costs regulatory asset in the first quarter 2017.

Zero Emission Standard (Exelon, Generation and ComEd). 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. Winning bidders are entitled to compensation for the sale of ZECs retroactive to the June 1, 2017 effective date of FEJA. In the first quarter of 2018, Generation recognized approximately $202 million of revenue, of which $150 million related to ZECs generated from June 1, 2017 through December 31, 2017.

ComEd recovers all costs associated with purchasing ZECs through a rate rider that provides for an annual reconciliation and true-up to actual costs incurred by ComEd to purchase ZECs, with any difference to be credited to or collected from ComEd’s retail customers in subsequent periods with interest. ComEd began billing its retail customers under its new ZEC rate rider on June 1, 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. One lawsuit was filed by customers of ComEd, led by the Village of Old Mill Creek, and the other was brought by the EPSA and three other electric suppliers. Both lawsuits argue that the Illinois ZEC program will distort PJM's FERC-approved energy and capacity market auction system of setting wholesale prices, and seek a permanent injunction preventing the implementation of the program. Exelon intervened and filed motions to dismiss in both lawsuits. In addition, on March 31, 2017, plaintiffs in both lawsuits filed motions for preliminary injunction with the court; the court stayed briefing on the motions for preliminary injunction until the resolution of the motions to dismiss. On July 14, 2017, the district court granted the motions to dismiss. On July 17, 2017, the plaintiffs appealed the decision to the Seventh Circuit. Briefs were fully submitted on December 12, 2017, the Court heard oral argument on January 3, 2018. At the argument, the Court asked for supplemental briefing, which was filed on January 26, 2018. On February 21, 2018, the Seventh Circuit issued an order inviting the Solicitor General to express the views of the United States on the matter, however the timing of that response is currently uncertain. Exelon cannot predict the outcome of these lawsuits. It is possible that resolution of these matters could have a material, unfavorable impact on Exelon’s and Generation’s results of operations, cash flows, and financial positions.

See Note 8 — Early Plant Retirements for additional information regarding the economic challenges facing Generation’s Clinton and Quad Cities nuclear plants and the expected benefits of the ZES.

Pennsylvania Regulatory Matters

2018 Pennsylvania Electric Distribution Base Rate Case (Exelon and PECO). On March 29, 2018, PECO filed a request with the PAPUC seeking approval to increase its electric distribution base rates by $82 million beginning January 1, 2019. This requested amount includes the effect of an approximately $71 million reduction as a result of the ongoing annual tax savings beginning January 1, 2019 associated with the TCJA. The requested ROE is 10.95%. PECO expects a decision on its electric distribution rate case proceeding in the fourth quarter of 2018 but cannot predict what increase, if any, the PAPUC will approve.

Tax Cuts and Jobs Act (Exelon and PECO). As part of the rate case filing referenced above, PECO is seeking approval to pass back to electric distribution customers $68 million in 2018 TCJA tax savings, which would be an additional offset to the proposed increase to its electric distribution rates. PECO will file with the PAPUC in 2018 seeking approval to pass back to gas distribution customers $4 million in TCJA tax savings beginning January 1, 2019. The amounts being proposed to be passed back to customers reflect the annual benefit of lower income tax rates established upon enactment of the TCJA. PECO cannot predict the amount or timing of the refunds the PAPUC will ultimately approve. See Note 12 — Income Taxes for more detail on Corporate Tax Reform and the table below for regulatory liabilities recognized during 2018 associated with TCJA tax savings that will be passed through future customer rates.

Maryland Regulatory Matters

Tax Cuts and Jobs Act (Exelon, BGE, PHI, Pepco and DPL). On January 12, 2018, the MDPSC issued an order that directed each of BGE, Pepco and DPL to track the impacts of the TCJA beginning January 1, 2018 and file by February 15, 2018 how and when they expect to pass through such impacts to their customers.

On January 31, 2018, the MDPSC approved BGE’s petition to pass back to customers $103 million in ongoing annual tax savings resulting from the enactment of the TCJA through a reduction in distribution base rates beginning February 1, 2018, of which $72 million and $31 million were related to electric and natural gas, respectively. The amounts being passed back to customers reflect the ongoing annual benefit of lower income tax rates and the settlement of a portion of deferred income tax regulatory liabilities established upon enactment of the TCJA. It is expected that the MDPSC will address later in 2018 the treatment of BGE's TCJA tax savings for the period January 1, 2018 through February 1, 2018.

On April 20, 2018, Pepco entered into a settlement agreement with several parties to resolve all issues in its pending electric distribution base rate case, including the treatment of the annual ongoing TCJA tax savings as well as the TCJA tax savings from January 1, 2018 through the expected effective date of the rate change. See discussion below for further details.

On February 9, 2018, DPL filed with the MDPSC seeking approval to pass back to customers $13 million in ongoing annual TCJA tax savings through a reduction in electric distribution base rates beginning in 2018. On April 18, 2018, the MDPSC approved a settlement agreement to pass back to customers $14 million in ongoing annual TCJA tax savings through a reduction in electric distribution base rates beginning April 20, 2018. The amounts being passed back to customers reflect the ongoing annual benefit of lower income tax rates and the settlement of a portion of deferred income tax regulatory liabilities established upon enactment of the TCJA. In addition, the MDPSC separately ordered DPL to provide a one-time bill credit to customers of $2 million in June 2018 representing the TCJA tax savings from January 1, 2018 through March 31, 2018.

See Note 12 — Income Taxes for more detail on Corporate Tax Reform and the table below for regulatory liabilities recognized during 2018 associated with TCJA tax savings that will be passed through future customer rates.

2018 Maryland Electric Distribution Base Rates (Exelon, PHI and Pepco). On January 2, 2018, Pepco filed an application with the MDPSC to increase its annual electric distribution base rates by $41 million, reflecting a requested ROE of 10.1%. On February 5, 2018, Pepco filed with the MDPSC an update to its current distribution base rate case to reflect $31 million in ongoing annual TCJA tax savings, thereby reducing the requested annual base rate increase to $11 million. On March 8, 2018, Pepco filed with the MDPSC a subsequent update to its electric distribution base rate case, which further reduced the requested annual base rate increase to $3 million. On April 20, 2018, Pepco entered into a settlement agreement with several parties to resolve all issues in the rate case and filed the settlement agreement with the MDPSC. The settlement agreement provides for a net decrease to annual electric distribution base rates of $15 million, which includes annual ongoing TCJA tax savings, and reflects a ROE of 9.5%. The parties to the settlement agreement have requested that Pepco’s new rates be effective on June 1, 2018. In addition, the settlement agreement separately provides a one-time bill credit to customers of approximately $10 million representing the TCJA tax savings from January 1, 2018 through the expected rate effective date of June 1, 2018. Pepco expects a decision in the matter in the second quarter of 2018.

2017 Maryland Electric Distribution Base Rates (Exelon, PHI and DPL). On July 14, 2017, DPL filed an application with the MDPSC to increase its annual electric distribution base rates by $27 million, which was updated to $19 million on November 16, 2017, reflecting a requested ROE of 10.1%. On December 18, 2017, a settlement agreement was filed with the MDPSC wherein DPL will be granted a base rate increase of $13 million, and a ROE of 9.5% solely for purposes of calculating AFUDC and regulatory asset carrying costs. On February 9, 2018, the MDPSC approved the settlement agreement and the new rates became effective.

Delaware Regulatory Matters

Tax Cuts and Jobs Act (Exelon, PHI and DPL). On January 16, 2018, the DPSC opened a docket indicating that DPL’s TCJA tax savings would be addressed in its pending rate cases. See discussion below for more details.

2017 Delaware Electric and Natural Gas Distribution Base Rates (Exelon, PHI and DPL). On August 17, 2017, DPL filed applications with the DPSC to increase its annual electric and natural gas distribution base rates by $24 million and $13 million, respectively, reflecting a requested ROE of 10.1%. DPL filed updated testimony on October 18, 2017, to request a $31 million increase in electric distribution base rates, and updated testimony on November 7, 2017, to request an $11 million increase in natural gas distribution base rates. On October 16, 2017 and November 1, 2017, $2.5 million of the proposed rate increases for electric and natural gas, respectively, were put into effect, subject to refund, based on the final DPSC order. On February 9, 2018, DPL filed with the DPSC updates to its distribution base rate cases to reflect $26 million in ongoing annual TCJA tax savings, of which $19 million and $7 million is related to electric and natural gas, respectively. The proposed distribution base rate increase in each rate case were lowered by those amounts, which reflect the ongoing annual benefit of lower income tax rates and the settlement of a portion of deferred income tax regulatory liabilities established upon enactment of the TCJA. It is expected that the DPSC will address in a future rate proceeding DPL's treatment of the TCJA tax savings for the period February 1, 2018 through the effective date of any final customer rate adjustments in the pending rate proceedings. On March 17, 2018, an additional $3 million of the proposed rate increase in the electric distribution base rate case and $1 million in the natural gas distribution base rate case was put into effect subject to refund based on the final DPSC order. DPL expects decisions on its electric and natural gas distribution base rate proceedings in the third and fourth quarters of 2018, respectively, but cannot predict how much of the requested increases the DPSC will approve.

District of Columbia Regulatory Matters

Tax Cuts and Jobs Act (Exelon, PHI and Pepco). On January 23, 2018, the DCPSC opened a rate proceeding directing Pepco to track the impacts of the TCJA beginning January 1, 2018 and file its plan to reduce the current revenue requirement by customer class by February 12, 2018. The DCPSC stated it will address the impact of the TCJA on future rates within Pepco's pending electric distribution base rate case discussed below.

On February 6, 2018, Pepco filed with the DCPSC seeking approval to pass back to customers $39 million in ongoing annual tax savings resulting from the enactment of the TCJA through a reduction to existing electric distribution base rates beginning in 2018. On April 17, 2018, Pepco entered into a settlement agreement with several parties to resolve all issues in its pending electric distribution base rate case, including the treatment of the annual ongoing TCJA tax savings as well as the TCJA tax savings from January 1, 2018 through the expected effective date of the rate change. See discussion below for more details.

2017 District of Columbia Electric Distribution Base Rates (Exelon, PHI and Pepco). On December 19, 2017 (and updated on February 9, 2018), Pepco filed an application with the DCPSC to increase its annual electric distribution base rates by $66 million, reflecting a requested ROE of 10.1%. On April 17, 2018, Pepco entered into a settlement agreement with several parties to resolve both the pending electric distribution base rate case and the $39 million rate reduction request in the TCJA proceeding discussed above, and filed the settlement agreement with the DCPSC. The settlement agreement provides for a net decrease to annual electric distribution rates of $24 million, which includes annual ongoing TCJA tax savings, and a ROE of 9.525%. The parties to the settlement agreement have requested that Pepco’s new rates be effective on July 1, 2018. In addition, the settlement agreement separately provides a one-time bill credit to customers of approximately $19 million representing the TCJA benefits for the period January 1, 2018 through the expected rate effective date of July 1, 2018. Pepco expects a decision in the matter in the second quarter of 2018.

New Jersey Regulatory Matters

Tax Cuts and Jobs Act (Exelon, PHI and ACE). On January 31, 2018, the NJBPU issued an order mandating that New Jersey utility companies, including ACE, pass any economic benefit from the TCJA to rate payers. The order directed New Jersey utility companies to file by March 2, 2018 proposed tariff sheets reflecting TCJA benefits, with new rates to be implemented in two phases effective April 1, 2018 and July 1, 2018. In addition, the NJBPU directed New Jersey utility companies to file by March 2, 2018 a Petition with the NJBPU outlining how they propose to refund any over-collection associated with revised rates not being in place from January 1, 2018 through March 31, 2018, with interest.

On March 2, 2018, ACE filed with the NJBPU seeking approval to pass back to customers $23 million in ongoing annual TCJA tax savings through a reduction in electric distribution base rates beginning in 2018. The amounts being passed back to customers would reflect the ongoing annual benefit of lower income tax rates and the settlement of a portion of deferred income tax regulatory liabilities established upon enactment of the TCJA. On March 26, 2018, the NJBPU issued an order accepting ACE’s proposed bill reduction. A portion of the annual decrease in electric distribution base rates totaling approximately $13 million was effective as of April 1, 2018, but considered interim, with the proposed final electric distribution base rates, representing the full $23 million decrease to be effective on July 1, 2018. It is expected that the NJBPU will address in a future rate proceeding ACE's treatment of the TCJA tax savings for the period January 1, 2018 through the effective date of any final customer rate adjustments. See Note 12 — Income Taxes for more detail on Corporate Tax Reform and the table below for regulatory liabilities recognized during 2018 associated with TCJA tax savings that will be passed through future customer rates.

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 through a new rider mechanism a series of investments, totaling $338 million, between 2019-2022 to provide safe and reliable service for its customers. The IIP will allow for more timely recovery of investments made to modernize and enhance ACE’s electric system. An NJBPU decision has been requested by the fourth quarter of 2018.

Update and Reconciliation of Certain Under-Recovered Balances (Exelon, PHI and ACE). On February 5, 2018, ACE submitted its 2018 annual petition with the NJBPU seeking to reconcile and update (i) charges related to the recovery of above-market costs associated with ACE’s long-term power purchase contracts with the non-utility generators and (ii) costs related to surcharges for the New Jersey Societal Benefit Program (a statewide public interest program that is intended to benefit low income customers and address other public policy goals) and ACE’s uncollectible accounts. The net impact of adjusting the charges as proposed is an overall annual rate decrease of approximately $19 million, including New Jersey sales and use tax. The matter is pending at the NJBPU. ACE has requested that the NJBPU place the new rates into effect by June 1, 2018. An NJBPU decision has been requested by the fourth quarter of 2018.

New York Regulatory Matters

New York Clean Energy Standard (Exelon and Generation). On August 1, 2016, the New York Public Service Commission (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. The ZEC price for the first tranche has been set at $17.48 per MWh of production. Following the first tranche, the price will be updated bi-annually.

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. On December 9, 2016, Generation and CENG filed a motion to intervene in the case and to dismiss the lawsuit. The State also filed a motion to dismiss. On July 25, 2017, the court granted both motions to dismiss. On August 24, 2017, plaintiffs appealed the decision to the Second Circuit. Plaintiffs-Appellants' initial brief was filed on October 13, 2017. Briefing in the appeal was completed in December 2017 and oral argument was held on March 12, 2018.

In addition, on November 30, 2016, a group of parties, including certain environmental groups and individuals, filed a Petition in New York State court seeking to invalidate the ZEC program. The Petition, which was amended on January 13, 2017, 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 (SAPA) when adopting the ZEC program. On February 15, 2017, Generation and CENG filed a motion to dismiss the state court action. The NYPSC also filed a motion to dismiss the state court action. On March 24, 2017, the plaintiffs filed a memorandum of law opposing the motions to dismiss, and Generation and CENG filed a reply brief on April 28, 2017. Oral argument was held on June 19, 2017. 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. The case is now proceeding to summary judgment with the full record. Exelon’s and the state’s answers and briefs were filed on March 30, 2018. Plaintiffs’ responses are due on May 11, 2018.

Other legal challenges remain possible, the outcomes of which remain uncertain. See Note 8 — Early Plant Retirements for additional information relative to Ginna and Nine Mile Point.

Federal Regulatory Matters

Tax Cuts and Jobs Act and Transmission-Related Income Tax Regulatory Assets (Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE). Pursuant to their respective transmission formula rates, ComEd, BGE, Pepco, DPL and ACE will begin passing back to customers on June 1, 2018, the benefit of lower income tax rates effective January 1, 2018. 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. 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. On December 18, 2017, BGE filed for clarification and rehearing of FERC’s order, still seeking full recovery of its existing transmission-related income tax regulatory asset amounts.

On February 27, 2018 (and updated on March 26, 2018), BGE submitted a letter to FERC advising that the lower federal corporate income tax rate effective January 1, 2018 provided for in TCJA will be reflected in BGE’s annual formula rate update effective June 1, 2018, but that the deferred income tax benefits will not be passed back to customers unless BGE’s formula rate is revised to provide for pass back and recovery of transmission-related income tax-related regulatory liabilities and assets.

ComEd, Pepco, DPL and ACE have similar transmission-related income tax regulatory liabilities and assets also requiring FERC approval separate from their transmission formula rate mechanisms. On February 23, 2018, ComEd, Pepco, DPL, and ACE each filed with FERC to revise their transmission formula rate mechanisms to facilitate passing back to customers ongoing annual TCJA tax savings and to permit recovery of transmission-related income tax regulatory assets. The companies requested the revisions be effective as of April 24, 2018. On April 24, 2018, the FERC issued a letter order neither approving or rejecting the filings, but rather indicating that the filings were deficient and requiring the parties to file additional information within 30 days. Similar regulatory assets and liabilities at PECO are not subject to the same FERC transmission rate recovery formula and, thus, are not impacted by BGE’s November 16, 2017 FERC order. As discussed below, PECO is currently in settlement discussions regarding its transmission formula rate and expects to pass back TCJA benefits to customers through its annual formula rate update.

Each of BGE, ComEd, Pepco, DPL and ACE believe there is sufficient basis to support full recovery of their existing transmission-related income tax regulatory assets, as evidenced by the further pursuit of full recovery with FERC. However, upon further consideration of the November 16, 2017 FERC order, management of each company concluded that the portion of the total transmission-related income tax regulatory assets that would have been previously amortized and recovered through rates had the transmission formula rate provided for such recovery was no longer probable of recovery. As a result, Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE recorded charges to Income tax expense within their Consolidated Statements of Operations and Comprehensive Income in the fourth quarter 2017, reducing their associated transmission-related income tax regulatory assets.

If any of the companies are ultimately successful with FERC allowing future recovery of these amounts, the associated regulatory assets will be reestablished, with corresponding decreases to Income tax expense. To the extent all or a portion of the prospective amortization amounts were no longer considered probable of recovery, Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE would record additional charges to Income tax expense, which could be up to approximately $82 million, $41 million, $22 million, $19 million, $9 million, $7 million and $3 million, respectively, as of March 31, 2018.

The Utility Registrants cannot predict the outcome of these FERC proceedings.

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 would 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. PECO cannot predict the final outcome of the settlement or hearing proceedings, or the transmission formula FERC may approve.

DOE Notice of Proposed Rulemaking (Exelon and Generation). On August 23, 2017, the DOE staff released its report on the reliability of the electric grid. One aspect of the wide-ranging report is the DOE’s recognition that the electricity markets do not currently value the resiliency provided by baseload generation, such as nuclear plants. On September 28, 2017, the DOE issued a Notice of Proposed Rulemaking (NOPR) that would entitle certain eligible resilient generating units (i.e., those located in organized markets, with a 90-day supply of fuel on site, not already subject to state cost of service regulation and satisfying certain other requirements) to recover fully allocated costs and earn a fair return on equity on their investment. The DOE's NOPR recommended that the FERC take comments for 45 days after publication in the Federal Register and issue a final order 60 days after such publication. On January 8, 2018, the FERC issued an order terminating the rulemaking docket that was initiated to address the proposed rule in the DOE NOPR, concluding the proposed rule did not sufficiently demonstrate there is a resiliency issue and that it proposed a remedy that did not appear to be just, reasonable and nondiscriminatory as required under the Federal Power Act. At the same time, the FERC initiated a new proceeding to consider resiliency challenges to the bulk power system and evaluate whether additional FERC action to address resiliency would be appropriate. The FERC directed each RTO and ISO to respond within 60 days to 24 specific questions about how they assess and mitigate threats to resiliency. Interested parties may submit reply comments through May 9, 2018. Exelon has been and will continue to be an active participant in these proceedings, but cannot predict the final outcome or its potential financial impact, if any, on Exelon or Generation.

Operating License Renewals (Exelon and Generation). On August 29, 2012, Generation submitted a hydroelectric license application to FERC for a 46-year 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 21, 2016, Exelon and the US Fish and Wildlife Service of the US Department of the Interior executed a Settlement Agreement resolving all fish passage issues between the parties. The financial impact of the Settlement Agreement is estimated to be $3 million to $7 million per year, on average, over the 46-year life of the new license, including both capital and operating costs. The actual timing and amount of these costs are not currently fixed and may vary significantly from year to year throughout the life of the new license.

On April 27, 2018, MDE issued its 401 certification for Conowingo. As issued, the 401 certification imposes requirements and conditions which could have a material, unfavorable impact on Exelon’s and Generation’s results of operations, cash flows and financial positions through an increase in capital expenditures and operating costs if implemented. Generation is reviewing the certification and will determine next steps to ensure the long-term viability of the Conowingo Dam.

As of March 31, 2018, $32 million of direct costs associated with Conowingo licensing efforts have been capitalized. See Note 3 — Regulatory Matters of the Exelon 2017 Form 10-K for additional information on Generation's operating license renewal efforts.

Regulatory Assets and Liabilities (Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE)

Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE each prepare their consolidated financial statements in accordance with the authoritative guidance for accounting for certain types of regulation. Under this guidance, regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent the excess recovery of costs or accrued credits that have been deferred because it is probable such amounts will be returned to customers through future regulated rates or represent billings in advance of expenditures for approved regulatory programs.

The following tables provide information about the regulatory assets and liabilities of Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE as of March 31, 2018 and December 31, 2017. For additional information on the specific regulatory assets and liabilities, refer to Note 3 — Regulatory Matters of the Exelon 2017 Form 10-K.



March 31, 2018	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory assets
Pension and other postretirement benefits^(a)	$	3,844	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Deferred income taxes	336		—		327		—		9		9		—		—
AMI programs^(c)	621		151		33		208		229		154		75		—
Electric distribution formula rate^(d)	256		256		—		—		—		—		—		—
Energy efficiency costs	220		220		—		—		—		—		—		—
Debt costs	108		36		1		11		71		15		7		5
Fair value of long-term debt	745		—		—		—		607		—		—		—
Fair value of PHI's unamortized energy contracts	701		—		—		—		701		—		—		—
Asset retirement obligations	111		75		22		14		—		—		—		—
MGP remediation costs	284		263		21		—		—		—		—		—
Under-recovered uncollectible accounts	69		69		—		—		—		—		—		—
Renewable energy	268		267		—		—		1		—		—		1
Energy and transmission programs^{(e)(f)(g)(h)(i)(j)}	117		8		43		21		45		7		14		24
Deferred storm costs	46		—		—		—		46		12		5		29
Energy efficiency and demand response programs	559		—		1		269		289		212		77		—
Merger integration costs^(k)(l)(m)	46		—		—		5		41		20		11		10
Under-recovered revenue decoupling⁽ⁿ⁾	44		—		—		6		38		38		—		—
COPCO acquisition adjustment	5		—		—		—		5		—		5		—
Workers compensation and long-term disability costs	33		—		—		—		33		33		—		—
Vacation accrual	27		—		14		—		13		—		8		5
Securitized stranded costs	71		—		—		—		71		—		—		71
CAP arrearage	12		—		12		—		—		—		—		—
Removal costs	535		—		—		—		535		150		94		292
DC PLUG charge	187		—		—		—		187		187		—		—
Other	63		6		12		6		39		26		9		4
Total regulatory assets	9,308		1,351		486		540		2,960		863		305		441
Less: current portion	1,245		226		78		149		507		207		63		64
Total noncurrent regulatory assets	$	8,063	$	1,125	$	408	$	391	$	2,453	$	656	$	242	$	377



March 31, 2018	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory liabilities
Other postretirement benefits	$	26	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Deferred income taxes^(b)	5,189		2,458		—		1,011		1,720		804		506		410
Nuclear decommissioning	2,969		2,464		505		—		—		—		—		—
Removal costs	1,570		1,348		—		92		130		20		110		—
Deferred rent	35		—		—		—		35		—		—		—
Energy efficiency and demand response programs	16		4		11		—		1		—		—		1
DLC program costs	7		—		7		—		—		—		—		—
Electric distribution tax repairs	27		—		27		—		—		—		—		—
Gas distribution tax repairs	8		—		8		—		—		—		—		—
Energy and transmission programs^{(e)(f)(g)(h)(i)(j)}	153		53		56		22		22		4		6		12
Over-recovered revenue decoupling⁽ⁿ⁾	14		—		—		11		3		—		3		—
Renewable portfolio standards costs	81		81		—		—		—		—		—		—
Zero emission credit costs	8		8		—		—		—		—		—		—
Over-recovered uncollectible accounts	4		—		—		—		4		—		—		4
Merger integration costs^(l)	1		—		—		—		1		—		1		—
TCJA income tax benefit over-recoveries^(o)	54		—		10		17		27		14		7		6
Other	84		8		22		32		22		3		13		4
Total regulatory liabilities	10,246		6,424		646		1,185		1,965		845		646		437
Less: current portion	522		212		117		102		77		7		48		21
Total noncurrent regulatory liabilities	$	9,724	$	6,212	$	529	$	1,083	$	1,888	$	838	$	598	$	416



December 31, 2017	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory assets
Pension and other postretirement benefits^(a)	$	3,848	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Deferred income taxes	306		—		297		—		9		9		—		—
AMI programs^(c)	640		155		36		214		235		158		77		—
Electric distribution formula rate^(d)	244		244		—		—		—		—		—		—
Energy efficiency costs	166		166		—		—		—		—		—		—
Debt costs	116		37		1		11		73		15		8		5
Fair value of long-term debt	758		—		—		—		619		—		—		—
Fair value of PHI's unamortized energy contracts	750		—		—		—		750		—		—		—
Asset retirement obligations	109		73		22		14		—		—		—		—
MGP remediation costs	295		273		22		—		—		—		—		—
Under-recovered uncollectible accounts	61		61		—		—		—		—		—		—
Renewable energy	258		256		—		—		2		—		1		1
Energy and transmission programs^{(e)(g)(h)(i)(j)}	82		6		1		23		52		11		15		26
Deferred storm costs	27		—		—		—		27		7		5		15
Energy efficiency and demand response programs	596		—		1		285		310		229		81		—
Merger integration costs^(k)(l)(m)	45		—		—		6		39		20		10		9
Under-recovered revenue decoupling⁽ⁿ⁾	55		—		—		14		41		38		3		—
COPCO acquisition adjustment	5		—		—		—		5		—		5		—
Workers compensation and long-term disability costs	35		—		—		—		35		35		—		—
Vacation accrual	19		—		6		—		13		—		8		5
Securitized stranded costs	79		—		—		—		79		—		—		79
CAP arrearage	8		—		8		—		—		—		—		—
Removal costs	529		—		—		—		529		150		93		286
DC PLUG charge	190		—		—		—		190		190		—		—
Other	67		8		16		4		39		29		8		4
Total regulatory assets	9,288		1,279		410		571		3,047		891		314		430
Less: current portion	1,267		225		29		174		554		213		69		71
Total noncurrent regulatory assets	$	8,021	$	1,054	$	381	$	397	$	2,493	$	678	$	245	$	359



December 31, 2017	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory liabilities
Other postretirement benefits	$	30	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Deferred income taxes^(b)	5,241		2,479		—		1,032		1,730		809		510		411
Nuclear decommissioning	3,064		2,528		536		—		—		—		—		—
Removal costs	1,573		1,338		—		105		130		20		110		—
Deferred rent	36		—		—		—		36		—		—		—
Energy efficiency and demand response programs	23		4		19		—		—		—		—		—
DLC program costs	7		—		7		—		—		—		—		—
Electric distribution tax repairs	35		—		35		—		—		—		—		—
Gas distribution tax repairs	9		—		9		—		—		—		—		—
Energy and transmission programs^(e)(f)(i)(j)	111		47		60		—		4		—		1		3
Renewable portfolio standard costs	63		63		—		—		—		—		—		—
Zero emission credit costs	112		112		—		—		—		—		—		—
Over-recovered uncollectible accounts	2		—		—		—		2		—		—		2
Other	82		6		24		26		26		3		14		6
Total regulatory liabilities	10,388		6,577		690		1,163		1,928		832		635		422
Less: current portion	523		249		141		62		56		3		42		11
Total noncurrent regulatory liabilities	$	9,865	$	6,328	$	549	$	1,101	$	1,872	$	829	$	593	$	411

_________

(a)

Includes regulatory regulatory assets established at the Constellation and PHI merger dates of $427 million and $934 million, respectively, as of March 31, 2018 and $440 million and $953 million, respectively, as of December 31, 2017 related to the rate regulated portions of the deferred costs associated with legacy Constellation’s and PHI’s pension and other postretirement benefit plans that are being amortized and recovered over approximately 12 years and 3 to 15 years, respectively (as established at the respective acquisition dates). The Utility Registrants are not earning or paying a return on these amounts.

(b)

As of March 31, 2018, includes transmission-related income tax regulatory liabilities that require FERC approval separate from the transmission formula rate of $479 million, $135 million, $146 million, $147 million and $147 million for ComEd, BGE, Pepco, DPL and ACE, respectively. As of December 31, 2017, includes transmission-related income tax regulatory liabilities that require FERC approval separate from the transmission formula rate of $484 million, $137 million, $147 million, $148 million and $147 million for ComEd, BGE, Pepco, DPL and ACE, respectively.

(c)

As of March 31, 2018, BGE's regulatory asset of $208 million includes $125 million of unamortized incremental deployment costs under the program, $51 million of unamortized costs of the non-AMI meters replaced under the AMI program, and $32 million related to post-test year incremental program deployment costs incurred prior to approval became effective June 2016. As of December 31, 2017, BGE's regulatory asset of $214 million includes $129 million of unamortized incremental deployment costs under the program, $53 million of unamortized costs of the non-AMI meters replaced under the AMI program, and $32 million related to post-test year incremental program deployment costs incurred prior to approval became effective June 2016. Recovery of the post-test year incremental deployment costs will be addressed in a future base rate proceeding.

(d)

As of March 31, 2018, ComEd’s regulatory asset of $256 million was comprised of $195 million for the 2016, 2017 and 2018 annual reconciliations and $61 million related to significant one-time events. As of December 31, 2017, ComEd’s regulatory asset of $244 million was comprised of $186 million for the 2016 and 2017 annual reconciliations and $58 million related to significant one-time events.

(e)

As of March 31, 2018, ComEd’s regulatory asset of $8 million represents transmission costs recoverable through its FERC approved formula rate. As of March 31, 2018, ComEd’s regulatory liability of $53 million included $21 million related to over-recovered energy costs and $32 million associated with revenues received for renewable energy requirements. As of December 31, 2017, ComEd’s regulatory asset of $6 million represents transmission costs recoverable through its FERC approved formula rate. As of December 31, 2017, ComEd’s regulatory liability of $47 million included $14 million related to over-recovered energy costs and $33 million associated with revenues received for renewable energy requirements.

(f)

As of March 31, 2018, PECO's regulatory liability of $56 million included $44 million related to over-recovered costs under the DSP program, $3 million related to the over-recovered transmission service charges and $9 million related to over-recovered non-bypassable transmission service charges. As of December 31, 2017, PECO's regulatory liability of $60 million included $36 million related to over-recovered costs under the DSP program, $12 million related to over-recovered non-bypassable transmission service charges and $12 million related to the over-recovered natural gas costs under the PGC.

(g)

As of March 31, 2018, BGE's regulatory asset of $21 million included $13 million of costs associated with transmission costs recoverable through its FERC approved formula rate, $5 million related to under-recovered electric energy costs and $3 million of abandonment costs to be recovered upon FERC approval. As of March 31, 2018, BGE's regulatory liability of $22 million related to over-recovered natural gas costs. As of December 31, 2017, BGE’s regulatory asset of $23 million included $7 million of costs associated with transmission costs recoverable through its FERC approved formula rate, $5 million related to under-recovered electric energy costs, $3 million of abandonment costs to be recovered upon FERC approval and $8 million of under-recovered natural gas costs.

(h)

As of March 31, 2018, Pepco's regulatory asset of $7 million included $4 million of transmission costs recoverable through its FERC approved formula rate and $3 million related to under-recovered electric energy costs. As of March 31, 2018, Pepco's regulatory liability of $4 million related to over-recovered electric energy costs. As of December 31, 2017, Pepco's regulatory asset of $11 million included $3 million of transmission costs recoverable through its FERC approved formula rate and $8 million of under-recovered electric energy costs.

(i)

As of March 31, 2018, DPL's regulatory asset of $14 million included $11 million of transmission costs recoverable through its FERC approved formula rate and $3 million related to under-recovered electric energy costs. As of March 31, 2018, DPL's regulatory liability of $6 million related to over-recovered electric energy and gas fuel costs. As of December 31, 2017, DPL's regulatory asset of $15 million included $8 million of transmission costs recoverable through its FERC approved formula rate and $7 million related to under-recovered electric energy costs. As of December 31, 2017, DPL's regulatory liability of $1 million related to over-recovered electric energy costs.

(j)

As of March 31, 2018, ACE's regulatory asset of $24 million included $9 million of transmission costs recoverable through its FERC approved formula rate and $15 million of under-recovered electric energy costs. As of March 31, 2018, ACE's regulatory liability of $12 million related to over-recovered electric energy costs. As of December 31, 2017, ACE's regulatory asset of $26 million included $11 million of transmission costs recoverable through its FERC approved formula rate and $15 million of under-recovered electric energy costs. As of December 31, 2017, ACE's regulatory liability of $3 million related to over-recovered electric energy costs.


(k)	As of March 31, 2018 and December 31, 2017, Pepco’s regulatory asset of $20 million represents previously incurred PHI integration costs, including $11 million authorized for recovery in Maryland and $9 million expected to be recovered in the District of Columbia service territory.

(l)

As of March 31, 2018, DPL’s regulatory asset of $11 million represents previously incurred PHI integration costs, including $4 million authorized for recovery in Maryland, $5 million authorized for recovery in Delaware electric rates and $2 million authorized for recovery in Delaware gas rates. As of March 31, 2018, DPL’s regulatory liability of $1 million represents net synergy savings incurred related to PHI integration costs that are expected to be returned in electric and gas rates in the Delaware service territory. As of December 31, 2017, DPL’s regulatory asset of $10 million represents previously incurred PHI integration costs, including $4 million authorized for recovery in Maryland, $5 million authorized for recovery in Delaware electric rates, and $1 million expected to be recovered in electric and gas rates in the Maryland and Delaware service territories.


(m)	As of March 31, 2018 and December 31, 2017, ACE’s regulatory asset of $10 million and $9 million, respectively, represents previously incurred PHI integration costs expected to be recovered in the New Jersey service territory.

(n)

Represents the electric and natural gas distribution costs recoverable from customers under BGE’s decoupling mechanism. As of March 31, 2018, BGE had a regulatory asset of $6 million related to under-recovered electric revenue decoupling and a regulatory liability of $11 million related to over-recovered natural gas revenue decoupling. As of December 31, 2017, BGE had a regulatory asset of $10 million related to under-recovered electric revenue decoupling and $4 million related to under-recovered natural gas revenue decoupling.


(o)	Represents over-recoveries related to the change in the federal income tax rate with the enactment of the TCJA. These regulatory liabilities will be amortized as the TCJA income tax benefits are passed back to customers. See Tax Cuts and Jobs Act disclosures above for further details on the regulatory proceedings.

Capitalized Ratemaking Amounts Not Recognized (Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE)

The following table illustrates our authorized amounts capitalized for ratemaking purposes related to earnings on shareholders’ investment that are not recognized for financial reporting purposes on our Consolidated Balance Sheets. These amounts will be recognized as revenues in our 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, 2018	$	69	$	7	$	—	$	52	$	10	$	6	$	4	$	—

	Exelon		ComEd^(a)		PECO		BGE^(b)		PHI		Pepco^(c)		DPL^(c)		ACE
December 31, 2017	$	69	$	6	$	—	$	53	$	10	$	6	$	4	$	—

_________


(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.

Purchase of Receivables Programs (Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE)

ComEd, PECO, BGE, Pepco, DPL and ACE are required, under separate legislation and regulations in Illinois, Pennsylvania, Maryland, District of Columbia and New Jersey, to purchase certain receivables from retail electric and 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 is required to purchase receivables at face value and is permitted to recover uncollectible accounts expense, including those from Third Party Suppliers, from customers through distribution rates. ACE purchases receivables at face value. ACE recovers all uncollectible accounts expense, including those from Third Party Suppliers, through the Societal Benefits Charge (SBC) rider, which includes uncollectible accounts expense as a component. The SBC is filed annually with the NJBPU. Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE do not record unbilled commodity receivables under the POR programs. Purchased billed receivables are classified in Other accounts receivable, net on Exelon’s, ComEd’s, PECO’s, BGE’s, PHI's, Pepco's, DPL's and ACE's Consolidated Balance Sheets. The following tables provide information about the purchased receivables of those companies as of March 31, 2018 and December 31, 2017.



As of March 31, 2018	Exelon			ComEd			PECO			BGE			PHI			Pepco			DPL			ACE
Purchased receivables	$	317		$	88		$	73		$	64		$	92		$	55		$	17		$	20
Allowance for uncollectible accounts^(a)	(35		)	(16		)	(6		)	(4		)	(9		)	(5		)	(1		)	(3		)
Purchased receivables, net	$	282		$	72		$	67		$	60		$	83		$	50		$	16		$	17



As of December 31, 2017	Exelon			ComEd			PECO			BGE			PHI			Pepco			DPL			ACE
Purchased receivables	$	298		$	87		$	70		$	58		$	83		$	56		$	9		$	18
Allowance for uncollectible accounts^(a)	(31		)	(14		)	(5		)	(3		)	(9		)	(5		)	(1		)	(3		)
Purchased receivables, net	$	267		$	73		$	65		$	55		$	74		$	51		$	8		$	15

_________


(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 its Purchase of Receivables with Consolidated Billing tariff.

Impairment of Long-lived Assets (Exelon and Generation)	3 Months Ended
Impairment of Long-lived Assets (Exelon and Generation)	Mar. 31, 2018
Property, Plant and Equipment [Abstract]
Asset Impairment Charges [Text Block]	7. Impairment of Long-Lived Assets (Exelon and Generation) During the first quarter of 2018, Mystic Unit 9 did not clear in the ISO-NE capacity auction for the 2021 - 2022 planning year. On March 29, 2018, Generation announced it had formally notified ISO-NE of the early retirement of its Mystic Generating Station's Units 7, 8, 9 and the Mystic Jet Unit (Mystic Generating Station assets) absent regulatory reforms. These events suggested that the carrying value of its New England asset group may be impaired. As a result, Generation completed a comprehensive review of the estimated undiscounted future cash flows of the New England asset group and no impairment charge was required. Further developments such as the failure of ISO-NE to adopt interim and long-term solutions for reliability and fuel security could potentially result in future impairments of the New England asset group, which could be material. See Note 8 — Early Plant Retirements for additional information on the early retirement of the Mystic Generating Station assets.

Early Nuclear Plant Retirements Early Nuclear Plant Retirements (Exelon, Generation)

3 Months Ended

Mar. 31, 2018

Property, Plant and Equipment [Abstract]

Implications Of Potential Early Retirement Disclosure [Text Block]

8. Early Plant Retirements (Exelon and Generation)

Exelon and Generation continue to evaluate the current and expected economic value of each of Generation’s plants. Factors that will continue to affect the economic value of Generation’s plants include, but are 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 decommissioning trust 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.

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.

Assuming the continued effectiveness of the Illinois ZES and the New York CES, Generation and CENG, through its ownership of Ginna and Nine Mile Point, no longer consider Clinton, Quad Cities, Ginna or Nine Mile Point to be at heightened risk for early retirement. However, to the extent either the Illinois ZES 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 results of operations, cash flows and financial positions. Refer to Note 6 — Regulatory Matters for additional discussion on the New York CES and the Illinois ZES.

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. The plant is currently committed to operate through May 2019 and is licensed to operate through 2034. 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. 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 February 2, 2018, Exelon announced that Generation will permanently cease generation operations at Oyster Creek at the end of its current operating cycle by October 2018. In 2010, Generation announced that Oyster Creek would retire by the end of 2019 as part of an agreement with the State of New Jersey to avoid significant costs associated with the construction of cooling towers to meet the State’s then new environmental regulations. Since then, like other nuclear sites, Oyster Creek has continued to face rising operating costs amid a historically low wholesale power price environment. The decision to retire Oyster Creek in 2018 at the end of its current operating cycle involved consideration of several factors, including economic and operating efficiencies, and avoids a refueling outage scheduled for the fall of 2018 that would have required advanced purchasing of fuel fabrication and materials beginning in late February 2018. 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 Oyster Creek as proposed.

As a result of these plant retirement decisions, Exelon and Generation recognized one-time charges in Operating and maintenance expense related to materials and supplies inventory reserve adjustments, employee-related costs and CWIP impairments, among other items. In addition to these one-time charges, annual 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), accelerated amortization of nuclear fuel, and additional ARO accretion expense associated with the changes in decommissioning timing and cost assumptions were also recorded. See Note 13 — Nuclear Decommissioning for additional detail on changes to the nuclear decommissioning ARO balance.

Exelon's and Generation's first quarter 2018 results included a net incremental $178 million of total pre-tax expense associated with the early retirement decisions for TMI and Oyster Creek, as summarized in the table below.



Income statement expense (pre-tax)	Q1 2018
Depreciation and amortization^(a)
Accelerated depreciation^(b)	$	137
Accelerated nuclear fuel amortization	15
Operating and maintenance^(c)	26
Total	$	178

_________


(a)	Reflects incremental accelerated depreciation and amortization for TMI for the quarter ended March 31, 2018, and for Oyster Creek from February 2, 2018 through March 31, 2018.


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


(c)	Primarily includes materials and supplies inventory reserve adjustments, employee related costs and CWIP impairments.

Exelon's and Generation's 2017 results included a net incremental $339 million of total pre-tax expense associated with the early retirement decision for TMI, as summarized in the table below.



Income statement expense (pre-tax)	Q2 2017		Q3 2017		Q4 2017		YTD 2017
Depreciation and amortization^(a)
Accelerated depreciation^(b)	$	35	$	106	$	109	$	250
Accelerated Nuclear Fuel amortization	2		6		4		12
Operating and maintenance^(c)	71		5		1		77
Total	$	108	$	117	$	114	$	339

_________


(a)	Reflects incremental charges for TMI including incremental accelerated depreciation and amortization from May 30, 2017 through December 31, 2017.


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


(c)	Primarily includes materials and supplies inventory reserve adjustments, employee related costs and CWIP impairments.

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. Although Salem is committed to operate through May 2021, the plant faces continued economic challenges and PSEG, as the operator of the plant, is exploring all options.

On April 12, 2018, a bill was passed by both Houses of the New Jersey legislature that would establish a ZEC program providing 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. The program provides transparency and includes robust customer protections. The New Jersey Governor has up to 45 days to sign the bill, with the bill becoming effective immediately upon signing. The NJBPU then has 180 days from the effective date to establish procedures for implementation of the ZEC program and 330 days from the effective date to determine which nuclear power plants are selected to receive ZECs under the program. Selected nuclear plants will receive ZEC payments for each energy year (12-month period from June 1 through May 31) within 90 days after the completion of such energy year. Exelon and Generation continue to work with stakeholders.

The following table provides the balance sheet amounts as of March 31, 2018 for Generation’s ownership share of the significant assets and liabilities associated with Salem.



	March 31, 2018
Asset Balances
Materials and supplies inventory	$	45
Nuclear fuel inventory, net	102
Completed plant, net	618
Construction work in progress	27
Liability Balances
Asset retirement obligation	(446		)

NRC License Renewal Term	2036 (Unit 1)
	2040 (Unit 2)

On March 29, 2018, Generation announced it had formally 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 & 8. Mystic Unit 9 is currently committed through May 2021. Absent any regulatory reforms to properly value reliability and regional fuel security, these units will not participate in the Forward Capacity Auction (FCA) scheduled for February 2019 for the 2022 - 2023 planning year.

The ISO-NE recently announced that it would take a three-step approach to fuel security. First, ISO-NE will make a filing soon to obtain tariff waivers to allow it to retain Mystic 8 and 9 for fuel security for the 2022 - 2024 planning years. Second, ISO-NE will file tariff revisions to allow it to retain other resources for fuel security in the capacity market if necessary in the future. Third, ISO-NE will work with stakeholders to develop long-term market rule changes to address system resiliency considering significant reliability risks identified in ISO-NE’s January 2018 fuel security report. Changes to market rules are necessary because critical units to the region, such as Mystic Units 8 and 9, cannot recover future operating costs, including the cost of procuring fuel. On April 3, 2018, ISO-NE issued a memorandum to the NEPOOL Participants’ Committee announcing its intention to seek FERC approval for waiver of certain tariff provisions in order to allow it to retain Mystic Units 8 and 9 for fuel security reasons. On April 4, 2018, Generation issued a letter indicating its willingness to cooperate and submit to full cost-of-service compensation for the Mystic Units 8 and 9, provided that the cost-of-service rate is determined before it commits to any future capacity obligation.

The following table provides the balance sheet amounts as of March 31, 2018 for Generation’s significant assets and liabilities associated with the Mystic Generating Station assets.



	March 31, 2018
Asset Balances
Materials and supplies inventory	$	26
Fuel inventory	18
Completed plant, net	896
Construction work in progress	4
Prepaid expense^(a)	9
Liability Balances
Asset retirement obligation	(5		)
Accrued expense^(a)	(2		)

_________


(a)	Reflects ending balances only as they relate to Mystic's Long-term Service Agreement.

Intangibles Intangibles (Exelon and Generation)	3 Months Ended
Intangibles Intangibles (Exelon and Generation)	Mar. 31, 2018
Goodwill and Intangible Assets Disclosure [Abstract]
Intangible Assets Disclosure [Text Block]	Intangible Assets (Exelon and PHI) In the third quarter of 2015, PHI entered into a sponsorship agreement with the District of Columbia for future sponsorship rights associated with public property within the District of Columbia and paid the District of Columbia $25 million. The specific sponsorship rights were to be determined over time through future negotiations. As of March 31, 2018, PHI has recorded the sponsorship agreement as a finite-lived intangible asset with a $25 million carrying amount.

Fair Value of Financial Assets and Liabilities (All Registrants)

3 Months Ended

Mar. 31, 2018

Fair Value Disclosures [Abstract]

Fair Value of Financial Assets and Liabilities (All Registrants)

9. 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, 2018 and December 31, 2017:

Exelon



	March 31, 2018
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities^(a)	$	1,654	$	—	$	1,654	$	—	$	1,654
Long-term debt (including amounts due within one year)^(b)(c)	34,108		—		33,091		1,893		34,984
Long-term debt to financing trusts^(d)	389		—		—		421		421
SNF obligation	1,151		—		922		—		922



	December 31, 2017
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities^(a)	$	929	$	—	$	929	$	—	$	929
Long-term debt (including amounts due within one year)^(b)(c)	34,264		—		34,735		1,970		36,705
Long-term debt to financing trusts^(d)	389		—		—		431		431
SNF obligation	1,147		—		936		—		936

Generation



	March 31, 2018
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities^(a)	$	166	$	—	$	166	$	—	$	166
Long-term debt (including amounts due within one year)^(b)(c)	8,965		—		7,585		1,610		9,195
SNF obligation	1,151		—		922		—		922



	December 31, 2017
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities^(a)	$	2	$	—	$	2	$	—	$	2
Long-term debt (including amounts due within one year)^(b)(c)	8,990		—		7,839		1,673		9,512
SNF obligation	1,147		—		936		—		936

ComEd



	March 31, 2018
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities^(a)	$	317	$	—	$	317	$	—	$	317
Long-term debt (including amounts due within one year)^(b)(c)	7,694		—		8,061		—		8,061
Long-term debt to financing trusts^(d)	205		—		—		222		222



	December 31, 2017
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year)^(b)(c)	$	7,601	$	—	$	8,418	$	—	$	8,418
Long-term debt to financing trusts^(d)	205		—		—		227		227

PECO



	March 31, 2018
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities^(a)	$	220	$	—	$	220	$	—	$	220
Long-term debt (including amounts due within one year)^(b)(c)	2,723		—		2,870		—		2,870
Long-term debt to financing trusts^(d)	184		—		—		199		199



	December 31, 2017
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year)^(b)(c)	$	2,903	$	—	$	3,194	$	—	$	3,194
Long-term debt to financing trusts^(d)	184		—		—		204		204

BGE



	March 31, 2018
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities^(a)	$	45	$	—	$	45	$	—	$	45
Long-term debt (including amounts due within one year)^(b)(c)	$	2,578	$	—	$	2,689	$	—	$	2,689



	December 31, 2017
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities^(a)	$	77	$	—	$	77	$	—	$	77
Long-term debt (including amounts due within one year)^(b)(c)	2,577		—		2,825		—		2,825

PHI



	March 31, 2018
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities^(a)	$	407	$	—	$	407	$	—	$	407
Long-term debt (including amounts due within one year)^(b)(c)	5,849		—		5,423		283		5,706



	December 31, 2017
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities^(a)	$	350	$	—	$	350	$	—	$	350
Long-term debt (including amounts due within one year)^(b)(c)	5,874		—		5,722		297		6,019

Pepco



	March 31, 2018
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities^(a)	$	60	$	—	$	60	$	—	$	60
Long-term debt (including amounts due within one year)^(b)(c)	2,540		—		2,933		9		2,942



	December 31, 2017
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities^(a)	$	26	$	—	$	26	$	—	$	26
Long-term debt (including amounts due within one year)^(b)(c)	2,540		—		3,114		9		3,123

DPL



	March 31, 2018
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities^(a)	$	211	$	—	$	211	$	—	$	211
Long-term debt (including amounts due within one year)^(b)(c)	1,296		—		1,320		—		1,320



	December 31, 2017
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities^(a)	$	216	$	—	$	216	$	—	$	216
Long-term debt (including amounts due within one year)^(b)(c)	1,300		—		1,393		—		1,393

ACE



	March 31, 2018
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities^(a)	$	136	$	—	$	136	$	—	$	136
Long-term debt (including amounts due within one year)^(b)(c)	1,114		—		916		274		1,190



	December 31, 2017
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities^(a)	$	108	$	—	$	108	$	—	$	108
Long-term debt (including amounts due within one year)^(b)(c)	1,121		—		949		288		1,237

_________


(a)	Level 1 securities consist of dividends payable (included in other current liabilities). Level 2 securities consist of short term borrowings.

(b)

Includes unamortized debt issuance costs which are not fair valued of $213 million, $57 million, $60 million, $20 million, $16 million, $6 million, $32 million, $11 million and $5 million for Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, as of March 31, 2018. Includes unamortized debt issuance costs which are not fair valued of $201 million, $60 million, $52 million, $17 million, $17 million, $6 million, $32 million, $11 million and $5 million for Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, as of December 31, 2017.


(c)	Level 2 securities consist of fixed-rate taxable debt securities, fixed-rate tax-exempt debt, variable rate tax-exempt debt and variable rate non-recourse debt. Level 3 securities consist of fixed-rate private placement taxable debt securities, fixed rate nonrecourse debt and government-backed fixed rate non-recourse debt.


(d)	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, 2018 and December 31, 2017.

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.

Transfers in and out of levels are recognized as of the end of the reporting period when the transfer occurred. Given derivatives categorized within Level 1 are valued using exchange-based quoted prices within observable periods, transfers between Level 2 and Level 1 were not material. Additionally, there were no material transfers between Level 1 and Level 2 during the three months ended March 31, 2018 for cash equivalents, nuclear decommissioning trust fund investments, Pledged assets for Zion Station decommissioning, Rabbi trust investments, and Deferred compensation obligations. For derivative contracts, transfers into Level 2 from Level 3 generally occur when the contract tenor becomes more observable and due to changes in market liquidity or assumptions for certain commodity contracts.

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 on Exelon's and Generation’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of March 31, 2018 and December 31, 2017:



	Generation					Exelon
As of March 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)	343	—	—	—	343	517	—	—	—	517
NDT fund investments
Cash equivalents^(b)	222	105	—	—	327	222	105	—	—	327
Equities	4,002	983	—	2,119	7,104	4,002	983	—	2,119	7,104
Fixed income
Corporate debt	—	1,583	240	—	1,823	—	1,583	240	—	1,823
U.S. Treasury and agencies	1,869	88	—	—	1,957	1,869	88	—	—	1,957
Foreign governments	—	86	—	—	86	—	86	—	—	86
State and municipal debt	—	254	—	—	254	—	254	—	—	254
Other^(c)	—	39	—	532	571	—	39	—	532	571
Fixed income subtotal	1,869	2,050	240	532	4,691	1,869	2,050	240	532	4,691
Middle market lending	—	—	369	127	496	—	—	369	127	496
Private equity	—	—	—	253	253	—	—	—	253	253
Real estate	—	—	—	488	488	—	—	—	488	488
NDT fund investments subtotal^(d)	6,093	3,138	609	3,519	13,359	6,093	3,138	609	3,519	13,359
Pledged assets for Zion Station decommissioning
Cash equivalents	13	—	—	—	13	13	—	—	—	13



	Generation									Exelon
As of March 31, 2018	Level 1		Level 2		Level 3		Not subject to leveling	Total		Level 1		Level 2		Level 3		Not subject to leveling	Total
Middle market lending	—		—		16		—	16		—		—		16		—	16
Pledged assets for Zion Station decommissioning subtotal^(e)	13		—		16		—	29		13		—		16		—	29
Rabbi trust investments
Cash equivalents	5		—		—		—	5		77		—		—		—	77
Mutual funds	24		—		—		—	24		59		—		—		—	59
Fixed income	—		—		—		—	—		—		10		—		—	10
Life insurance contracts	—		22		—		—	22		—		71		23		—	94
Rabbi trust investments subtotal^(f)	29		22		—		—	51		136		81		23		—	240
Commodity derivative assets
Economic hedges	286		2,923		1,892		—	5,101		286		2,923		1,892		—	5,101
Proprietary trading	—		151		58		—	209		—		151		58		—	209
Effect of netting and allocation of collateral^{(g) (h)}	(335	)	(2,589	)	(895	)	—	(3,819	)	(335	)	(2,589	)	(895	)	—	(3,819	)
Commodity derivative assets subtotal	(49	)	485		1,055		—	1,491		(49	)	485		1,055		—	1,491
Interest rate and foreign currency derivative assets
Derivatives designated as hedging instruments	—		12		—		—	12		—		12		—		—	12
Economic hedges	—		6		—		—	6		—		6		—		—	6
Effect of netting and allocation of collateral	(1	)	(3	)	—		—	(4	)	(1	)	(3	)	—		—	(4	)
Interest rate and foreign currency derivative assets subtotal	(1	)	15		—		—	14		(1	)	15		—		—	14
Other investments	—		—		36		—	36		—		—		36		—	36
Total assets	6,428		3,660		1,716		3,519	15,323		6,709		3,719		1,739		3,519	15,686
Liabilities
Commodity derivative liabilities
Economic hedges	(415	)	(3,317	)	(1,203	)	—	(4,935	)	(415	)	(3,317	)	(1,470	)	—	(5,202	)
Proprietary trading	—		(164	)	(15	)	—	(179	)	—		(164	)	(15	)	—	(179	)
Effect of netting and allocation of collateral^{(g) (h)}	415		3,007		1,081		—	4,503		415		3,007		1,081		—	4,503
Commodity derivative liabilities subtotal	—		(474	)	(137	)	—	(611	)	—		(474	)	(404	)	—	(878	)
Interest rate and foreign currency derivative liabilities
Derivatives designated as hedging instruments	—		—		—		—	—		—		(4	)	—		—	(4	)



	Generation														Exelon
As of March 31, 2018	Level 1			Level 2			Level 3			Not subject to leveling		Total			Level 1			Level 2			Level 3			Not subject to leveling		Total
Economic hedges	(1		)	(4		)	—			—		(5		)	(1		)	(4		)	—			—		(5		)
Effect of netting and allocation of collateral	1			3			—			—		4			1			3			—			—		4
Interest rate and foreign currency derivative liabilities subtotal	—			(1		)	—			—		(1		)	—			(5		)	—			—		(5		)
Deferred compensation obligation	—			(35		)	—			—		(35		)	—			(138		)	—			—		(138		)
Total liabilities	—			(510		)	(137		)	—		(647		)	—			(617		)	(404		)	—		(1,021		)
Total net assets	$	6,428		$	3,150		$	1,579		$	3,519	$	14,676		$	6,709		$	3,102		$	1,335		$	3,519	$	14,665



	Generation														Exelon
As of December 31, 2017	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)	$	168		$	—		$	—		$	—	$	168		$	656		$	—		$	—		$	—	$	656
NDT fund investments
Cash equivalents^(b)	135			85			—			—		220			135			85			—			—		220
Equities	4,163			915			—			2,176		7,254			4,163			915			—			2,176		7,254
Fixed income
Corporate debt	—			1,614			251			—		1,865			—			1,614			251			—		1,865
U.S. Treasury and agencies	1,917			52			—			—		1,969			1,917			52			—			—		1,969
Foreign governments	—			82			—			—		82			—			82			—			—		82
State and municipal debt	—			263			—			—		263			—			263			—			—		263
Other^(c)	—			47			—			510		557			—			47			—			510		557
Fixed income subtotal	1,917			2,058			251			510		4,736			1,917			2,058			251			510		4,736
Middle market lending	—			—			397			131		528			—			—			397			131		528
Private equity	—			—			—			222		222			—			—			—			222		222
Real estate	—			—			—			471		471			—			—			—			471		471
NDT fund investments subtotal^(d)	6,215			3,058			648			3,510		13,431			6,215			3,058			648			3,510		13,431
Pledged assets for Zion Station decommissioning
Cash equivalents	2			—			—			—		2			2			—			—			—		2
Equities	—			1			—			—		1			—			1			—			—		1
Middle market lending	—			—			12			24		36			—			—			12			24		36
Pledged assets for Zion Station decommissioning subtotal^(e)	2			1			12			24		39			2			1			12			24		39
Rabbi trust investments
Cash equivalents	5			—			—			—		5			77			—			—			—		77
Mutual funds	23			—			—			—		23			58			—			—			—		58
Fixed income	—			—			—			—		—			—			12			—			—		12
Life insurance contracts	—			22			—			—		22			—			71			22			—		93
Rabbi trust investments subtotal^(f)	28			22			—			—		50			135			83			22			—		240
Commodity derivative assets
Economic hedges	557			2,378			1,290			—		4,225			557			2,378			1,290			—		4,225
Proprietary trading	2			31			35			—		68			2			31			35			—		68
Effect of netting and allocation of collateral^{(g) (h)}	(585		)	(1,769		)	(635		)	—		(2,989		)	(585		)	(1,769		)	(635		)	—		(2,989		)
Commodity derivative assets subtotal	(26		)	640			690			—		1,304			(26		)	640			690			—		1,304
Interest rate and foreign currency derivative assets
Derivatives designated as hedging instruments	—			3			—			—		3			—			6			—			—		6
Economic hedges	—			10			—			—		10			—			10			—			—		10



	Generation														Exelon
As of December 31, 2017	Level 1			Level 2			Level 3			Not subject to leveling		Total			Level 1			Level 2			Level 3			Not subject to leveling		Total
Effect of netting and allocation of collateral	(2		)	(5		)	—			—		(7		)	(2		)	(5		)	—			—		(7		)
Interest rate and foreign currency derivative assets subtotal	(2		)	8			—			—		6			(2		)	11			—			—		9
Other investments	—			—			37			—		37			—			—			37			—		37
Total assets	6,385			3,729			1,387			3,534		15,035			6,980			3,793			1,409			3,534		15,716
Liabilities
Commodity derivative liabilities
Economic hedges	(712		)	(2,226		)	(845		)	—		(3,783		)	(713		)	(2,226		)	(1,101		)	—		(4,040		)
Proprietary trading	(2		)	(42		)	(9		)	—		(53		)	(2		)	(42		)	(9		)	—		(53		)
Effect of netting and allocation of collateral^{(g) (h)}	650			2,089			716			—		3,455			651			2,089			716			—		3,456
Commodity derivative liabilities subtotal	(64		)	(179		)	(138		)	—		(381		)	(64		)	(179		)	(394		)	—		(637		)
Interest rate and foreign currency derivative liabilities
Derivatives designated as hedging instruments	—			(2		)	—			—		(2		)	—			(2		)	—			—		(2		)
Economic hedges	(1		)	(8		)	—			—		(9		)	(1		)	(8		)	—			—		(9		)
Effect of netting and allocation of collateral	2			5			—			—		7			2			5			—			—		7
Interest rate and foreign currency derivative liabilities subtotal	1			(5		)	—			—		(4		)	1			(5		)	—			—		(4		)
Deferred compensation obligation	—			(38		)	—			—		(38		)	—			(145		)	—			—		(145		)
Total liabilities	(63		)	(222		)	(138		)	—		(423		)	(63		)	(329		)	(394		)	—		(786		)
Total net assets	$	6,322		$	3,507		$	1,249		$	3,534	$	14,612		$	6,917		$	3,464		$	1,015		$	3,534	$	14,930

_________

(a)

Generation excludes cash of $371 million and $259 million at March 31, 2018 and December 31, 2017 and restricted cash of $23 million and $127 million at March 31, 2018 and December 31, 2017. Exelon excludes cash of $531 million and $389 million at March 31, 2018 and December 31, 2017 and restricted cash of $51 million and $145 million at March 31, 2018 and December 31, 2017 and includes long-term restricted cash of $103 million and $85 million at March 31, 2018 and December 31, 2017, which is reported in Other deferred debits on the Consolidated Balance Sheets.


(b)	Includes $53 million and $77 million of cash received from outstanding repurchase agreements at March 31, 2018 and December 31, 2017, respectively, and is offset by an obligation to repay upon settlement of the agreement as discussed in (d) below.

(c)

Includes derivative instruments of $2 million and less than $1 million, which have a total notional amount of $949 million and $811 million at March 31, 2018 and December 31, 2017, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not represent the amount of the company's exposure to credit or market loss.

(d)

Excludes net liabilities of $84 million and $82 million at March 31, 2018 and December 31, 2017, 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)	Excludes net assets of $1 million at March 31, 2018. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases.


(f)	The amount of unrealized gains/(losses) at Generation totaled less than $1 million and $1 million for the three months ended March 31, 2018 and March 31, 2017, respectively. The amount of unrealized gains/(losses) at Exelon totaled $1 million and $2 million for the three months ended March 31, 2018 and March 31, 2017, respectively.

(g)

Collateral posted/(received) from counterparties totaled $80 million, $418 million and $186 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of March 31, 2018. Collateral posted/(received) from counterparties, net of collateral paid to counterparties, totaled $65 million, $320 million and $81 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2017.


(h)	Of the collateral posted/(received), $156 million represents variation margin on the exchanges as of March 31, 2018. Of the collateral posted/(received), $(117) million represents variation margin on the exchanges as of December 31, 2017.

Exelon and Generation hold investments without readily determinable fair values with carrying amounts of $68 million as of March 31, 2018. Changes were immaterial in fair value, cumulative adjustments and impairments for the three months ended March 31, 2018.

ComEd, PECO and BGE

The following tables present assets and liabilities measured and recorded at fair value on 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, 2018 and December 31, 2017:



	ComEd											PECO										BGE
As of March 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)	$	93	$	—		$	—		$	93		$	6	$	—		$	—	$	6		$	—	$	—		$	—	$	—
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	93		—			—			93			13		10			—		23			6		—			—		6
Liabilities
Deferred compensation obligation	—		(8		)	—			(8		)	—		(11		)	—		(11		)	—		(4		)	—		(4		)
Mark-to-market derivative liabilities^(c)	—		—			(267		)	(267		)	—		—			—		—			—		—			—		—
Total liabilities	—		(8		)	(267		)	(275		)	—		(11		)	—		(11		)	—		(4		)	—		(4		)
Total net assets (liabilities)	$	93	$	(8	)	$	(267	)	$	(182	)	$	13	$	(1	)	$	—	$	12		$	6	$	(4	)	$	—	$	2



	ComEd											PECO										BGE
As of December 31, 2017	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)	$	98	$	—		$	—		$	98		$	228	$	—		$	—	$	228		$	—	$	—		$	—	$	—
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	98		—			—			98			235		10			—		245			6		—			—		6
Liabilities
Deferred compensation obligation	—		(8		)	—			(8		)	—		(11		)	—		(11		)	—		(5		)	—		(5		)
Mark-to-market derivative liabilities^(c)	—		—			(256		)	(256		)	—		—			—		—			—		—			—		—
Total liabilities	—		(8		)	(256		)	(264		)	—		(11		)	—		(11		)	—		(5		)	—		(5		)
Total net assets (liabilities)	$	98	$	(8	)	$	(256	)	$	(166	)	$	235	$	(1	)	$	—	$	234		$	6	$	(5	)	$	—	$	1

_________

(a)

ComEd excludes cash of $69 million and $45 million at March 31, 2018 and December 31, 2017 and includes long-term restricted cash of $83 million and $62 million at March 31, 2018 and December 31, 2017, which is reported in Other deferred debits on the Consolidated Balance Sheets. PECO excludes cash of $20 million and $47 million at March 31, 2018 and December 31, 2017. BGE excludes cash of $22 million and $17 million at March 31, 2018 and December 31, 2017 and restricted cash of $2 million and $1 million at March 31, 2018 and December 31, 2017.


(b)	The amount of unrealized gains/(losses) at ComEd, PECO and BGE totaled less than $1 million for the three months ended March 31, 2018 and March 31, 2017, respectively.


(c)	The Level 3 balance consists of the current and noncurrent liability of $24 million and $243 million, respectively, at March 31, 2018, and $21 million and $235 million, respectively, at December 31, 2017, 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 on 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, 2018 and December 31, 2017:




	As of March 31, 2018										As of December 31, 2017
PHI	Level 1		Level 2			Level 3		Total			Level 1			Level 2			Level 3		Total
Assets
Cash equivalents^(a)	$	67	$	—		$	—	$	67		$	83		$	—		$	—	$	83
Rabbi trust investments
Cash equivalents	72		—			—		72			72			—			—		72
Fixed income	—		10			—		10			—			12			—		12
Life insurance contracts	—		23			23		46			—			23			22		45
Rabbi trust investments subtotal^(b)	72		33			23		128			72			35			22		129
Total assets	139		33			23		195			155			35			22		212
Liabilities
Deferred compensation obligation	—		(23		)	—		(23		)	—			(25		)	—		(25		)
Mark-to-market derivative liabilities^(c)	—		—			—		—			(1		)	—			—		(1		)
Effect of netting and allocation of collateral	—		—			—		—			1			—			—		1
Mark-to-market derivative liabilities subtotal	—		—			—		—			—			—			—		—
Total liabilities	—		(23		)	—		(23		)	—			(25		)	—		(25		)
Total net assets	$	139	$	10		$	23	$	172		$	155		$	10		$	22	$	187



	Pepco										DPL										ACE
As of March 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)	$	33	$	—		$	—	$	33		$	—	$	—		$	—	$	—		$	27	$	—	$	—	$	27
Rabbi trust investments
Cash equivalents	44		—			—		44			—		—			—		—			—		—		—		—
Fixed income	—		10			—		10			—		—			—		—			—		—		—		—
Life insurance contracts	—		23			23		46			—		—			—		—			—		—		—		—
Rabbi trust investments subtotal^(b)	44		33			23		100			—		—			—		—			—		—		—		—
Total assets	77		33			23		133			—		—			—		—			27		—		—		27
Liabilities
Deferred compensation obligation	—		(4		)	—		(4		)	—		(1		)	—		(1		)	—		—		—		—
Total liabilities	—		(4		)	—		(4		)	—		(1		)	—		(1		)	—		—		—		—
Total net assets (liabilities)	$	77	$	29		$	23	$	129		$	—	$	(1	)	$	—	$	(1	)	$	27	$	—	$	—	$	27



	Pepco										DPL											ACE
As of December 31, 2017	Level 1		Level 2			Level 3		Total			Level 1			Level 2			Level 3		Total			Level 1		Level 2		Level 3		Total
Assets
Cash equivalents^(a)	$	36	$	—		$	—	$	36		$	—		$	—		$	—	$	—		$	29	$	—	$	—	$	29
Rabbi trust investments
Cash equivalents	44		—			—		44			—			—			—		—			—		—		—		—
Fixed income	—		12			—		12			—			—			—		—			—		—		—		—
Life insurance contracts	—		23			22		45			—			—			—		—			—		—		—		—
Rabbi trust investments subtotal^(b)	44		35			22		101			—			—			—		—			—		—		—		—
Total assets	80		35			22		137			—			—			—		—			29		—		—		29
Liabilities
Deferred compensation obligation	—		(4		)	—		(4		)	—			(1		)	—		(1		)	—		—		—		—
Mark-to-market derivative liabilities^(c)	—		—			—		—			(1		)	—			—		(1		)	—		—		—		—
Effect of netting and allocation of collateral	—		—			—		—			1			—			—		1			—		—		—		—
Mark-to-market derivative liabilities subtotal	—		—			—		—			—			—			—		—			—		—		—		—
Total liabilities	—		(4		)	—		(4		)	—			(1		)	—		(1		)	—		—		—		—
Total net assets (liabilities)	$	80	$	31		$	22	$	133		$	—		$	(1	)	$	—	$	(1	)	$	29	$	—	$	—	$	29

_________

(a)

PHI excludes cash of $36 million and $12 million at March 31, 2018 and December 31, 2017, respectively, and includes long-term restricted cash of $20 million and $23 million at March 31, 2018 and December 31, 2017, respectively, which is reported in Other deferred debits on the Consolidated Balance Sheets. Pepco excludes cash of $15 million and $4 million at March 31, 2018 and December 31, 2017, respectively. DPL excludes cash of $7 million and $2 million at March 31, 2018 and December 31, 2017, respectively. ACE excludes cash of $10 million and $2 million at March 31, 2018 and December 31, 2017, respectively, and includes long-term restricted cash of $20 million and $23 million at March 31, 2018 and December 31, 2017, respectively, which is reported in Other deferred debits on the Consolidated Balance Sheets.


(b)	The amount of unrealized gains/(losses) at PHI, Pepco, DPL and ACE totaled less than $1 million for the three months ended March 31, 2018 and March 31, 2017.


(c)	Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC.

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, 2018 and 2017:





	Generation															ComEd				PHI					Exelon
Three Months Ended March 31, 2018	NDT Fund Investments			Pledged Assets for Zion Station Decommissioning		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		$	12	$	552			$	37		$	1,249		$	(256	)		$	22	$	—		$	1,015
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 payable for Zion Station decommissioning	—			4		—				—			4			—				—		—			4
Included in regulatory assets/liabilities	—			—		—				—			—			(11		)	^(b)	—		7			(4		)
Change in collateral	—			—		105				—			105			—				—		—			105
Purchases, sales, issuances and settlements
Purchases	2			—		88				—			90			—				—		—			90
Sales	—			—		(3		)		—			(3		)	—				—		—			(3		)
Settlements	(48		)	—		—				—			(48		)	—				—		—			(48		)
Transfers into Level 3	—			—		(8		)		—			(8		)	—				—		—			(8		)
Transfers out of Level 3	—			—		—				(2		)	(2		)	—				—		—			(2		)
Balance at March 31, 2018	$	609		$	16	$	918			$	36		$	1,579		$	(267	)		$	23	$	—		$	1,335
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




	Generation															ComEd				PHI						Exelon
Three Months Ended March 31, 2017	NDT Fund Investments			Pledged Assets for Zion Station Decommissioning		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, 2016	$	677		$	19	$	493			$	42		$	1,231		$	(258	)		$	20		$	—		$	993
Total realized / unrealized gains (losses)
Included in net income	3			—		(43		)	^(a)	1			(39		)	—				1			—			(38		)
Included in noncurrent payables to affiliates	9			—		—				—			9			—				—			(9		)	—
Included in regulatory assets/liabilities	—			—		—				—			—			(24		)	^(b)	—			9			(15		)
Change in collateral	—			—		38				—			38			—				—			—			38
Purchases, sales, issuances and settlements
Purchases	17			1		69				2			89			—				—			—			89
Sales	—			—		(2		)		—			(2		)	—				—			—			(2		)
Issuances	—			—		—				—			—			—				(1		)	—			(1		)
Settlements	(23		)	—		—				—			(23		)	—				—			—			(23		)
Transfers into Level 3	—			—		(1		)		—			(1		)	—				—			—			(1		)
Transfers out of Level 3	—			—		11				(5		)	6			—				—			—			6
Balance as of March 31, 2017	$	683		$	20	$	565			$	40		$	1,308		$	(282	)		$	20		$	—		$	1,046
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, 2017	$	2		$	—	$	59			$	—		$	61		$	—			$	1		$	—		$	62

________


(a)	Includes a reduction for the reclassification of $72 million and $102 million of realized gains due to the settlement of derivative contracts for the three months ended March 31, 2018 and March 31, 2017, respectively.

(b)

Includes $17 million of decreases 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. Includes $30 million of decreases 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, 2017.


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

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, 2018 and 2017:



	Generation							PHI		Exelon
	Operating Revenues		Purchased Power and Fuel			Other, net^(a)		Operating and Maintenance		Operating Revenues		Purchased Power and Fuel			Operating and Maintenance		Other, net^(a)
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



	Generation							PHI		Exelon
	Operating Revenues		Purchased Power and Fuel			Other, net^(a)		Other, net^(a)		Operating Revenues		Purchased Power and Fuel			Other, net^(a)
Total gains (losses) included in net income for the three months ended March 31, 2017	$	88	$	(131	)	$	3	$	1	$	88	$	(131	)	$	4
Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended March 31, 2017	140		(81		)	2		1		140		(81		)	3

_________


(a)	Other, net activity consists of realized and unrealized gains (losses) included in income for the NDT funds held by Generation, accrued interest on a convertible promissory note at Generation and the life insurance contracts held by PHI and Pepco.

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 (Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE). 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.

Nuclear Decommissioning Trust Fund Investments and Pledged Assets for Zion Station Decommissioning (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, 2018, Generation has outstanding commitments to invest in equities, fixed income, middle market lending, private equity and real estate investments of approximately $208 million, $65 million, $386 million, $194 million, and $107 million, respectively. These commitments will be funded by Generation’s existing nuclear decommissioning trust funds.

Concentrations of Credit Risk. Generation evaluated its NDT portfolios for the existence of significant concentrations of credit risk as of March 31, 2018. 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, 2018, 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 further discussion on the NDT fund investments.

Rabbi Trust Investments (Exelon, Generation, PECO, BGE, PHI, Pepco, DPL and ACE). The Rabbi trusts were established to hold assets related to deferred compensation plans existing for certain active and retired members of Exelon’s executive management and directors. The Rabbi trusts assets are included in investments in the Registrants’ Consolidated Balance Sheets and consist primarily of money market funds, mutual funds, fixed income securities and life insurance policies. 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, which are typically designated as fair value hedges, 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. These interest rate derivatives are typically designated as cash flow hedges. 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 further discussion on mark-to-market derivatives.

Deferred Compensation Obligations (Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE). 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)

Nuclear Decommissioning Trust Fund Investments and Pledged Assets for Zion Station Decommissioning (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. Generation gains an understanding of the fund managers’ inputs and assumptions used in preparing the valuations. Generation performed procedures to assess the reasonableness of the valuations.

Rabbi Trust Investments - Life insurance contracts (Exelon, PHI, Pepco, DPL and ACE). 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. Exelon gains an understanding of the types of inputs and assumptions used in preparing the valuations and performs procedures to assess the reasonableness of the valuations.

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. Exelon’s RMC approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk exposures. The RMC is chaired by the chief executive officer and includes the chief risk officer, chief strategy officer, chief executive officer of Exelon Utilities, chief commercial officer, chief financial officer and chief executive officer of Constellation. The RMC reports to the Finance and Risk Committee of the Exelon Board of Directors on the scope of the risk management activities. 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 $2.99 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 more 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, 2018			Valuation Technique	Unobservable Input	Range
Mark-to-market derivatives — Economic Hedges (Exelon and Generation)^(a)(b)	$	689		Discounted Cash Flow	Forward power price	$1	-	$202
					Forward gas price	$1.12	-	$12.80
				Option Model	Volatility percentage	10%	-	227%

Mark-to-market derivatives — Proprietary trading (Exelon and Generation)^(a)(b)	$	43		Discounted Cash Flow	Forward power price	$4	-	$202

Mark-to-market derivatives (Exelon and ComEd)	$	(267	)	Discounted Cash Flow	Forward heat rate^(c)	9x	-	10x
					Marketability reserve	4%	-	8%
					Renewable factor	87%	-	122%



Type of trade	Fair Value at December 31, 2017			Valuation Technique	Unobservable Input	Range
Mark-to-market derivatives — Economic Hedges (Exelon and Generation)^(a)(b)	$	445		Discounted Cash Flow	Forward power price	$3	-	$124
					Forward gas price	$1.27	-	$12.80
				Option Model	Volatility percentage	11%	-	139%

Mark-to-market derivatives — Proprietary trading (Exelon and Generation)^(a)(b)	$	26		Discounted Cash Flow	Forward power price	$14	-	$94

Mark-to-market derivatives (Exelon and ComEd)	$	(256	)	Discounted Cash Flow	Forward heat rate^(c)	9x	-	10x
					Marketability reserve	4%	-	8%
					Renewable factor	88%	-	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 $186 million and $81 million as of March 31, 2018 and December 31, 2017, 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 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, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments (All Registrants)

10. 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, 2018 and December 31, 2017, $8 million and $4 million of cash collateral held, respectively, 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.

In the table below, DPL's economic hedges 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.

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



	Generation												ComEd			DPL						Exelon
Derivatives	Economic Hedges			Proprietary Trading			Collateral and Netting^(a)(e)			Subtotal^(b)			Economic Hedges^(c)			Economic Hedges^(d)		Collateral and Netting^(a)		Subtotal		Total Derivatives
Mark-to-market derivative assets (current assets)	$	3,343		$	166		$	(2,533	)	$	976		$	—		$	—	$	—	$	—	$	976
Mark-to-market derivative assets (noncurrent assets)	1,758			43			(1,286		)	515			—			—		—		—		515
Total mark-to-market derivative assets	5,101			209			(3,819		)	1,491			—			—		—		—		1,491
Mark-to-market derivative liabilities (current liabilities)	(3,185		)	(151		)	2,945			(391		)	(24		)	—		—		—		(415		)
Mark-to-market derivative liabilities (noncurrent liabilities)	(1,750		)	(28		)	1,558			(220		)	(243		)	—		—		—		(463		)
Total mark-to-market derivative liabilities	(4,935		)	(179		)	4,503			(611		)	(267		)	—		—		—		(878		)
Total mark-to-market derivative net assets (liabilities)	$	166		$	30		$	684		$	880		$	(267	)	$	—	$	—	$	—	$	613

_________

(a)

Exelon, Generation and DPL net all available amounts allowed under the derivative authoritative guidance on 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 $192 million and $103 million, respectively, and current and noncurrent liabilities are shown net of collateral of $220 million and $169 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $684 million at March 31, 2018.


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


(d)	Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC.


(e)	Of the collateral posted/(received), $156 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, 2017:



	Generation												ComEd			DPL							Exelon
Description	Economic Hedges			Proprietary Trading			Collateral and Netting^(a)(e)			Subtotal^(b)			Economic Hedges^(c)			Economic Hedges^(d)			Collateral and Netting^(a)		Subtotal		Total Derivatives
Mark-to-market derivative assets (current assets)	$	3,061		$	56		$	(2,144	)	$	973		$	—		$	—		$	—	$	—	$	973
Mark-to-market derivative assets (noncurrent assets)	1,164			12			(845		)	331			—			—			—		—		331
Total mark-to-market derivative assets	4,225			68			(2,989		)	1,304			—			—			—		—		1,304
Mark-to-market derivative liabilities (current liabilities)	(2,646		)	(43		)	2,480			(209		)	(21		)	(1		)	1		—		(230		)
Mark-to-market derivative liabilities (noncurrent liabilities)	(1,137		)	(10		)	975			(172		)	(235		)	—			—		—		(407		)
Total mark-to-market derivative liabilities	(3,783		)	(53		)	3,455			(381		)	(256		)	(1		)	1		—		(637		)
Total mark-to-market derivative net assets (liabilities)	$	442		$	15		$	466		$	923		$	(256	)	$	(1	)	$	1	$	—	$	667

_________

(a)

Exelon, Generation and DPL net all available amounts allowed under the derivative authoritative guidance on 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 $169 million and $53 million, respectively, and current and noncurrent liabilities are shown net of collateral of $167 million and $77 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $466 million at December 31, 2017.


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


(d)	Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC.


(e)	Of the collateral posted/(received), $(117) 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, 2018 and 2017, 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" on the Consolidated Statements of Cash Flows.



	Three Months Ended March 31,
	2018			2017
Income Statement Location	Gain (Loss)
Operating revenues	$	(100	)	$	46
Purchased power and fuel	(167		)	(93		)
Total Exelon and Generation	$	(267	)	$	(47	)

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, 2018, the percentage of expected generation hedged is 91%-94%, 63%-66% and 33%-36% for 2018, 2019 and 2020, 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 on 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 3 — Regulatory Matters of the Exelon 2017 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 2016 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 2016 PGC settlement, 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, 2018 and 2017 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" on the Consolidated Statements of Cash Flows. The Utility Registrants do not execute derivatives for proprietary trading purposes.



	Three Months Ended March 31,
	2018		2017
Income Statement Location	Gain (Loss)
Operating revenues	$	2	$	(1	)

Interest Rate and Foreign Exchange Risk (All Registrants)

The Registrants use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. The Registrants utilize fixed-to-floating interest rate swaps, which are typically designated as fair value hedges, to manage their interest rate exposure. In addition, the Registrants may utilize interest rate derivatives to lock in rate levels, which are typically designated as cash flow hedges to manage interest rate risk. To manage foreign exchange rate exposure associated with international commodity purchases in currencies other than U.S. dollars, Generation utilizes foreign currency derivatives, which are treated as economic hedges. Below is a summary of the interest rate and foreign exchange hedge balances as of March 31, 2018:



	Generation											Exelon Corporate			Exelon
Description	Derivatives Designated as Hedging Instruments		Economic Hedges			Collateral and Netting^(a)			Subtotal			Derivatives Designated as Hedging Instruments			Total
Mark-to-market derivative assets (current assets)	$	—	$	5		$	(3	)	$	2		$	—		$	2
Mark-to-market derivative assets (noncurrent assets)	12		1			(1		)	12			—			12
Total mark-to-market derivative assets	12		6			(4		)	14			—			14
Mark-to-market derivative liabilities (current liabilities)	—		(3		)	3			—			—			—
Mark-to-market derivative liabilities (noncurrent liabilities)	—		(2		)	1			(1		)	(4		)	(5		)
Total mark-to-market derivative liabilities	—		(5		)	4			(1		)	(4		)	(5		)
Total mark-to-market derivative net assets (liabilities)	$	12	$	1		$	—		$	13		$	(4	)	$	9

__________

(a)

Exelon and Generation net all available amounts allowed under the derivative authoritative guidance on 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 counterparty exposures subject to a master netting or similar agreement, such as accrued interest, transactions that do not qualify as derivatives, letters of credit and other forms of non-cash collateral, which are not reflected in the table above.

The following table provides a summary of the interest rate and foreign exchange hedge balances recorded by the Registrants as of December 31, 2017:



	Generation												Exelon Corporate		Exelon
Description	Derivatives Designated as Hedging Instruments			Economic Hedges			Collateral and Netting^(a)			Subtotal			Derivatives Designated as Hedging Instruments		Total
Mark-to-market derivative assets (current assets)	$	—		$	10		$	(7	)	$	3		$	—	$	3
Mark-to-market derivative assets (noncurrent assets)	3			—			—			3			3		6
Total mark-to-market derivative assets	3			10			(7		)	6			3		9
Mark-to-market derivative liabilities (current liabilities)	(2		)	(7		)	7			(2		)	—		(2		)
Mark-to-market derivative liabilities (noncurrent liabilities)	—			(2		)	—			(2		)	—		(2		)
Total mark-to-market derivative liabilities	(2		)	(9		)	7			(4		)	—		(4		)
Total mark-to-market derivative net assets (liabilities)	$	1		$	1		$	—		$	2		$	3	$	5

__________

(a)

Fair Value Hedges (Interest Rate Risk)

For derivative instruments that qualify and are designated as fair value hedges, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedged risk are recognized in earnings immediately. Exelon and Generation include the gain or loss on the hedged items and the offsetting loss or gain on the related interest rate swaps as follows:



		Three Months Ended March 31,
	Income Statement Location	2018			2017			2018		2017
	Income Statement Location	Loss on Swaps						Gain on Borrowings
Exelon	Interest expense	$	(7	)	$	(4	)	$	13	$	8

The table below provides the notional amounts of fixed-to-floating hedges outstanding held by Exelon at March 31, 2018 and December 31, 2017:



	As of
	March 31, 2018		December 31, 2017
Fixed-to-floating hedges	$	800	$	800

During the three months ended March 31, 2018 and 2017, the impact on the results of operations as a result of ineffectiveness from fair value hedges was a $6 million gain and a $4 million gain, respectively.

Cash Flow Hedges (Interest Rate Risk)

For derivative instruments that qualify and are designated as cash flow hedges, the gain or loss on the effective portion of the derivative will be deferred in AOCI and reclassified into earnings when the underlying transaction occurs. To mitigate interest rate risk, Exelon and Generation enter into floating-to-fixed interest rate swaps to manage a portion of interest rate exposure associated with debt issuances. The table below provides the notional amounts of floating-to-fixed hedges outstanding held by Exelon and Generation as of March 31, 2018.



	As of
	March 31, 2018		December 31, 2017
Floating-to-fixed hedges	$	636	$	636

The tables below provide the activity of OCI related to cash flow hedges for the three months ended March 31, 2018 and 2017, containing information about the changes in the fair value of cash flow hedges and the reclassification from AOCI into results of operations. The amounts reclassified from OCI, when combined with the impacts of the hedged transactions, result in the ultimate recognition of net revenues or expenses at the contractual price.



		Total Cash Flow Hedge OCI Activity, Net of Income Tax
		Generation				Exelon
Three Months Ended March 31, 2018	Income Statement Location	Total Cash Flow Hedges				Total Cash Flow Hedges
AOCI derivative loss at December 31, 2017		$	(16	)		$	(14	)
Effective portion of changes in fair value		7				8
AOCI derivative loss at March 31, 2018		$	(9	)		$	(6	)

		Total Cash Flow Hedge OCI Activity, Net of Income Tax
		Generation				Exelon
Three Months Ended March 31, 2017	Income Statement Location	Total Cash Flow Hedges				Total Cash Flow Hedges
AOCI derivative loss at December 31, 2016		$	(19	)		$	(17	)
Effective portion of changes in fair value		2				2
Reclassifications from AOCI to net income	Interest Expense	4			^(a)	4			^(a)
AOCI derivative loss at March 31, 2017		$	(13	)		$	(11	)

_________


(a)	Amount is net of related income tax expense of $3 million for the three months ended March 31, 2017.

During the three months ended March 31, 2018 and 2017, the impact on the results of operations as a result of ineffectiveness from cash flow hedges in continuing designated hedge relationships was immaterial. The estimated amount of existing gains and losses that are reported in AOCI at the reporting date that are expected to be reclassified into earnings within the next twelve months is immaterial.

Economic Hedges (Interest Rate and Foreign Exchange Risk)

Exelon and Generation executes these instruments to mitigate exposure to fluctuations in interest rates or foreign exchange but for which the fair value or cash flow hedge elections were not made. Generation also enters into interest rate derivative contracts and foreign exchange currency swaps ("treasury") to manage the exposure related to the interest rate component of commodity positions and international purchases of commodities in currencies other than U.S. Dollars.

At March 31, 2018 and December 31, 2017, Generation had immaterial notional amounts of interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions. The following table provides notional amounts outstanding held by Exelon and Generation at March 31, 2018 and December 31, 2017 related to foreign currency exchange rate swaps that are marked-to-market to manage the exposure associated with international purchases of commodities in currencies other than U.S. dollars.



	As of
	March 31, 2018		December 31, 2017
Foreign currency exchange rate swaps	$	87	$	94

For the three months ended March 31, 2018 and 2017, Exelon and Generation recognized the following net pre-tax mark-to-market gains (losses) in the Consolidated Statements of Operations and Comprehensive Income and are included in “Net fair value changes related to derivatives” in Exelon’s and Generation’s Consolidated Statements of Cash Flows.



		Three Months Ended March 31,
		2018			2017
	Income Statement Location	Gain (Loss)
Generation	Operating Revenues	$	2		$	(2	)
Generation	Purchased Power and Fuel	(1		)	—
Total Generation		$	1		$	(2	)



		Three Months Ended March 31,
		2018			2017
	Income Statement Location	Gain (Loss)
Exelon	Operating Revenues	$	2		$	(2	)
Exelon	Purchased Power and Fuel	(1		)	—
Total Exelon		$	1		$	(2	)

Proprietary Trading (Interest Rate and Foreign Exchange Risk)

Generation also executes derivative contracts for proprietary trading purposes to hedge risk associated with the interest rate and foreign exchange components of underlying commodity positions. Gains and losses associated with proprietary trading are reported as Operating revenues in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income and are included in “Net fair value changes related to derivatives” in Exelon’s and Generation’s Consolidated Statements of Cash Flows. For the three months ended March 31, 2018 and 2017 Exelon and Generation recognized the following net pre-tax commodity mark-to-market gains (losses).



	Three Months Ended March 31,
	2018		2017
Income Statement Location	Gain (Loss)
Operating Revenues	$	—	$	(1	)

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, 2018. 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 $31 million, $21 million, $25 million, $34 million, $9 million, and $5 million as of March 31, 2018, respectively.



Rating as of March 31, 2018	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	$	986	$	1	$	985	2	$	412
Non-investment grade	112		46		66
No external ratings
Internally rated — investment grade	223		—		223
Internally rated — non-investment grade	100		17		83
Total	$	1,421	$	64	$	1,357	2	$	412



Net Credit Exposure by Type of Counterparty	As of March 31, 2018
Financial institutions	$	189
Investor-owned utilities, marketers, power producers	656
Energy cooperatives and municipalities	438
Other	74
Total	$	1,357

_________


(a)	As of March 31, 2018, credit collateral held from counterparties where Generation had credit exposure included $41 million of cash and $23 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, 2018, ComEd’s net credit exposure to suppliers was less than $1 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 3 — Regulatory Matters of the Exelon 2017 Form 10-K for additional information.

PECO’s unsecured credit used by the suppliers represents PECO’s net credit exposure. As of March 31, 2018, PECO had no material net credit exposure to 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. PECO does not obtain collateral from suppliers under its natural gas supply and asset management agreements. As of March 31, 2018, 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 3 — Regulatory Matters of the Exelon 2017 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, 2018, BGE's net credit exposure to suppliers was immaterial.

BGE’s regulated gas business is exposed to market-price risk. At March 31, 2018, BGE had credit exposure of approximately $12 million 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.

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, 2018, 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 3 — Regulatory Matters of the Exelon 2017 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, 2018, DPL had no credit exposure under its natural gas supply and asset management agreements with investment grade suppliers.

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 Feature	March 31, 2018			December 31, 2017
Gross fair value of derivative contracts containing this feature^(a)	$	(2,141	)	$	(926	)
Offsetting fair value of in-the-money contracts under master netting arrangements^(b)	1,562			577
Net fair value of derivative contracts containing this feature^(c)	$	(579	)	$	(349	)

_________


(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 $742 million and letters of credit posted of $493 million and cash collateral held of $66 million and letters of credit held of $46 million as of March 31, 2018 for external counterparties with derivative positions. Generation had cash collateral posted of $497 million and letters of credit posted of $293 million and cash collateral held of $35 million and letters of credit held of $33 million at December 31, 2017 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 $1.8 billion as of March 31, 2018 and December 31, 2017, respectively. These amounts represent the potential additional collateral required after giving consideration to offsetting derivative and non-derivative positions under master netting agreements.

Generation’s and Exelon’s interest rate swaps contain provisions that, in the event of a merger, if Generation’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, 2018, Generation's and Exelon's swaps were in an asset position of $13 million and $9 million, respectively.

See Note 25 — Segment Information of the Exelon 2017 Form 10-K for further 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, 2018, ComEd held approximately $9 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, 2018, ComEd held approximately $14 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, 2018, ComEd held approximately $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, 2018, it would have been required to post approximately $10 million of collateral to its counterparties. See Note 3 — Regulatory Matters of the Exelon 2017 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, 2018, PECO was not required to post collateral for any of these agreements. If PECO lost its investment grade credit rating as of March 31, 2018, PECO could have been required to post approximately $33 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, 2018, BGE was not required to post collateral for any of these agreements. If BGE lost its investment grade credit rating as of March 31, 2018, BGE could have been required to post approximately $49 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, 2018, DPL could have been required to post an additional amount of approximately $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, 2018

Debt Disclosure [Abstract]

Debt and Credit Agreements (All Registrants)

11. 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 Registrants had the following amounts of commercial paper borrowings outstanding as of March 31, 2018 and December 31, 2017:



Commercial Paper Borrowings	March 31, 2018		December 31, 2017
Exelon	$	1,154	$	427
Generation	165		—
ComEd	317		—
PECO	220		—
BGE	45		77
PHI^(a)	407		350
Pepco	60		26
DPL	211		216
ACE	136		108

_________


(a)	PHI reflects the commercial paper borrowings outstanding of Pepco, DPL and ACE.

Short-Term Loan Agreements

On January 13, 2016, PHI entered into a $500 million term loan agreement, which was amended on March 28, 2016. The net proceeds of the loan were used to repay PHI's outstanding commercial paper and for general corporate purposes. Pursuant to the loan agreement, as amended, loans made thereunder bear interest at a variable rate equal to LIBOR plus 1%, and all indebtedness thereunder is unsecured. On March 23, 2017, the aggregate principal amount of all loans, together with any accrued but unpaid interest due under the loan agreement was fully repaid and the loan terminated. On March 23, 2017, Exelon Corporate entered into a similar type term loan for $500 million which expired March 22, 2018. The loan agreement was renewed on March 22, 2018 and will expire on March 21, 2019. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 1% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon’s Consolidated Balance Sheet within Short-Term borrowings.

Credit Agreements

As of March 15, 2018, the credit agreement for Generation’s $30 million bilateral credit facility was amended to increase the overall facility size to $95 million. 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, 2018, the following long-term debt was issued:



Company	Type	Interest Rate		Maturity	Amount		Use of Proceeds
Generation	Energy Efficiency Project Financing	3.72	%	April 30, 2018	$	1	Funding to install energy conservation measures for the Smithsonian Zoo project.
Generation	Energy Efficiency Project Financing	3.17	%	April 30, 2018	$	1	Funding to install energy conservation measures in Brooklyn, NY.
Generation	Energy Efficiency Project Financing	2.61	%	September 30, 2018	$	2	Funding to install energy conservation measures for the Pensacola project.
ComEd	First Mortgage Bonds, Series 124	4.00	%	March 1, 2048	$	800	Refinance one series of maturing first mortgage bonds, to repay a portion of ComEd’s outstanding commercial paper obligations and to fund general corporate purposes.
PECO	First and Refunding Mortgage Bonds	3.90	%	March 1, 2048	$	325	Refinance a portion of maturing mortgage bonds.

Income Taxes (All Registrants)

3 Months Ended

Mar. 31, 2018

Income Tax Disclosure [Abstract]

Income Taxes (All Registrants)

Corporate Tax Reform (All Registrants)

On December 22, 2017, President Trump signed the TCJA into law. The TCJA makes many significant changes to the Internal Revenue Code, including, but not limited to, (1) reducing the U.S. federal corporate tax rate from 35% to 21%; (2) creating a 30% limitation on deductible interest expense (not applicable to regulated utilities); (3) allowing 100% expensing for the cost of qualified property (not applicable to regulated utilities); (4) eliminating the domestic production activities deduction; (5) eliminating the corporate alternative minimum tax and changing how existing alternative minimum tax credits can be realized; and (6) changing rules related to uses and limitations of net operating loss carryforwards created in tax years beginning after December 31, 2017. The most significant change that impacts the Registrants is the reduction of the corporate federal income tax rate from 35% to 21% beginning January 1, 2018.

Pursuant to the enactment of the TCJA, the Registrants remeasured their existing deferred income tax balances as of December 31, 2017 to reflect the decrease in the corporate income tax rate from 35% to 21%, which resulted in a material decrease to their net deferred income tax liability balances as shown in the table below. Generation recorded a corresponding net decrease to income tax expense, while the Utility Registrants recorded corresponding regulatory liabilities or assets to the extent such amounts are probable of settlement or recovery through customer rates and an adjustment to income tax expense for all other amounts. The amount and timing of potential settlements of the established net regulatory liabilities will be determined by the Utility Registrants’ respective rate regulators, subject to certain IRS “normalization” rules. See Note 6 — Regulatory Matters for further information.

The Registrants have completed their assessment of the majority of the applicable provisions in the TCJA and have recorded the associated impacts as of December 31, 2017. As discussed further below, under SAB 118 issued by the SEC in December 2017, the Registrants have recorded provisional income tax amounts as of December 31, 2017 for changes pursuant to the TCJA related to depreciation for which the impacts could not be finalized upon issuance of the Registrants’ financial statements, but for which reasonable estimates could be determined.

For property acquired and placed-in-service after September 27, 2017, the TCJA repeals 50% bonus depreciation for all taxpayers and in addition provides for 100% expensing for taxpayers other than regulated utilities. As a result, Generation will be required to evaluate the contractual terms of its fourth quarter 2017 capital additions and determine if they qualify for 100% expensing under the TCJA as compared to 50% bonus depreciation under prior tax law. Similarly, the Utility Registrants will be required to evaluate the contractual terms of their fourth quarter 2017 capital additions to determine whether they still qualify for the prior tax law’s 50% bonus depreciation as compared to no bonus depreciation pursuant to the TCJA.

At Generation, any required changes to the provisional estimates during the measurement period related to the above item would result in an adjustment to current income tax expense at 35% and a corresponding adjustment to deferred income tax expense at 21% and such changes could be material to Generation’s future results of operations. At the Utility Registrants, any required changes to the provisional estimates would result in the recording of regulatory assets or liabilities to the extent such amounts are probable of settlement or recovery through customer rates and a net change to income tax expense for any other amounts.

The Registrants expect any final adjustments to the provisional amounts to be recorded by the third quarter of 2018, which could be material to the Registrants’ future results of operations or financial positions. The accounting for all other applicable provisions of the TCJA is considered complete based on our current interpretation of the provisions of the TCJA as enacted as of December 31, 2017.

While the Registrants have recorded the impacts of the TCJA based on their interpretation of the provisions as enacted, it is expected that technical corrections or other forms of guidance will be issued during 2018, which could result in material changes to previously finalized provisions. At this time, most states have not provided guidance regarding TCJA impacts and may issue guidance in 2018 which may impact estimates.

The one-time impacts recorded by the Registrants to remeasure their deferred income tax balances at the 21% corporate federal income tax rate as of December 31, 2017 are presented below:



	Exelon^(b)		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Net Decrease to Deferred Income Tax Liability Balances	$	8,624	$	1,895	$	2,819	$	1,407	$	1,120	$	1,944	$	968	$	540	$	456



	Exelon	Generation	ComEd	PECO^(c)	BGE	PHI	Pepco	DPL	ACE
Net Regulatory Liability Recorded^(a)	7,315	N/A	2,818	1,394	1,124	1,979	976	545	458



	Exelon^(b)		Generation		ComEd		PECO		BGE			PHI			Pepco			DPL			ACE
Net Deferred Income Tax Benefit/(Expense) Recorded	$	1,309	$	1,895	$	1	$	13	$	(4	)	$	(35	)	$	(8	)	$	(5	)	$	(2	)

__________


(a)	Reflects the net regulatory liabilities recorded on a pre-tax basis before taking into consideration the income tax benefits associated with the ultimate settlement with customers.


(b)	Amounts do not sum across due to deferred tax adjustments recorded at the Exelon Corporation parent company, primarily related to certain employee compensation plans.


(c)	Given the regulatory treatment of income tax benefits related to electric and gas distribution repairs, PECO remains in an overall net regulatory asset position as of December 31, 2017 after recording the impacts related to the TCJA. Refer to Note 3 - Regulatory Matters for additional information.

The net regulatory liabilities above include (1) amounts subject to IRS “normalization” rules that are required to be passed back to customers generally over the remaining useful life of the underlying assets giving rise to the associated deferred income taxes, and (2) amounts for which the timing of settlement with customers is subject to determinations by the rate regulators. The table below sets forth the Registrants’ estimated categorization of their net regulatory liabilities as of December 31, 2017. The amounts in the table below are shown on an after-tax basis reflecting future net cash outflows after taking into consideration the income tax benefits associated with the ultimate settlement with customers.



	Exelon		ComEd		PECO^(a)		BGE		PHI		PEPCO		DPL		ACE
Subject to IRS Normalization Rules	$	3,040	$	1,400	$	533	$	459	$	648	$	299	$	195	$	153
Subject to Rate Regulator Determination	1,694		573		43		324		754		391		194		170
Net Regulatory Liabilities	$	4,734	$	1,973	$	576	$	783	$	1,402	$	690	$	389	$	323

__________

(a)

Given the regulatory treatment of income tax benefits related to electric and gas distribution repairs, PECO remains in an overall net regulatory asset position as of December 31, 2017 after recording the impacts related to the TCJA. As a result, the amount of customer benefits resulting from the TCJA subject to the discretion of PECO's rate regulators are lower relative to the other Utility Registrants. Refer to Note 3 - Regulatory Matters for additional information.

The net regulatory liability amounts subject to the IRS normalization rules generally relate to property, plant and equipment with remaining useful lives ranging from 30 to 40 years across the Utility Registrants. For the other amounts, rate regulators could require the passing back of amounts to customers over shorter time frames.

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, 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 nuclear decommissioning trust 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%



	Three Months Ended March 31, 2017^(a)
	Exelon	Generation	ComEd	PECO	BGE	PHI	Pepco	DPL	ACE
U.S. Federal statutory rate	35.0%	35.0%	35.0%	35.0%	35.0%	35.0%	35.0%	35.0%	35.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	0.9	1.0	4.9	0.1	5.2	4.9	4.6	5.3	5.6
Qualified nuclear decommissioning trust fund income	3.5	7.8	—	—	—	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(0.4)	(0.7)	(0.2)	(0.1)	(0.1)	(0.2)	(0.1)	(0.3)	(0.4)
Plant basis differences	(2.4)	—	(0.2)	(13.2)	(0.9)	(3.8)	(5.8)	(1.9)	(3.4)
Production tax credits and other credits	(0.7)	(1.5)	—	—	—	—	—	—	—
Noncontrolling interest	—	0.1	—	—	—	—	—	—	—
Merger expenses^(b)	(11.5)	(3.4)	—	—	—	(42.4)	(34.2)	(21.9)	(167.1)
Fitzpatrick bargain purchase gain	(6.6)	(14.8)	—	—	—	—	—	—	—
Other	(0.1)	(0.4)	—	0.3	(0.2)	(0.4)	0.5	—	(3.0)
Effective income tax rate	17.7%	23.1%	39.5%	22.1%	39.0%	(6.9)%	0.0%	16.2%	(133.3)%

_________


(a)	Exelon retrospectively adopted the new standard Revenue from Contracts with Customers. The standard was adopted as of January 1, 2018. The effective income tax rates are recast to reflect the impact of the new standard.


(b)	Includes a remeasurement of uncertain state income tax positions for Pepco and DPL.

Accounting for Uncertainty in Income Taxes

The Registrants have the following unrecognized tax benefits as of March 31, 2018 and December 31, 2017:



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
March 31, 2018	$	733	$	464	$	2	$	—	$	120	$	125	$	59	$	21	$	14



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
December 31, 2017	$	743	$	468	$	2	$	—	$	120	$	125	$	59	$	21	$	14

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

Like-Kind Exchange

As of March 31, 2018, Exelon and ComEd have approximately $33 million and $2 million, respectively, of unrecognized federal and state income tax benefits that could significantly decrease within the 12 months after the reporting date due to a final resolution of the like-kind exchange litigation described below. The recognition of these unrecognized tax benefits would decrease Exelon and ComEd's effective tax rate.

Settlement of Income Tax Audits, Refund Claims, and Litigation

As of March 31, 2018, Exelon, Generation, BGE, PHI, Pepco, DPL, and ACE have approximately $679 million, $465 million, $120 million, $94 million, $59 million, $21 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 $458 million that, if recognized, would decrease the effective tax rate. The unrecognized tax benefits related to BGE, Pepco, DPL, and ACE, if recognized, may be included in future regulated base rates and that portion would have no impact to the effective tax rate.

Other Income Tax Matters

Like-Kind Exchange (Exelon and ComEd)

Exelon, through its ComEd subsidiary, took a position on its 1999 income tax return to defer approximately $1.2 billion of tax gain on the sale of ComEd’s fossil generating assets. The gain was deferred by reinvesting a portion of the proceeds from the sale in qualifying replacement property under the like-kind exchange provisions of the IRC. The like-kind exchange replacement property purchased by Exelon included interests in three municipal-owned electric generation facilities which were properly leased back to the municipalities. As previously disclosed, Exelon terminated its investment in one of the leases in 2014 and the remaining two leases were terminated in 2016.

The IRS asserted that the Exelon purchase and leaseback transaction was substantially similar to a leasing transaction, known as a SILO, which is a listed transaction that the IRS has identified as a potentially abusive tax shelter. Thus, they disagreed with Exelon's position and asserted that the entire gain of approximately $1.2 billion was taxable in 1999. In 2013, the IRS issued a notice of deficiency to Exelon and Exelon filed a petition to initiate litigation in the United States Tax Court. In 2016, the Tax Court held that Exelon was not entitled to defer gain on the transaction. In addition to the tax and interest related to the gain deferral, the Tax Court also ruled that Exelon was liable for $90 million in penalties and interest on the penalties. Exelon has fully paid the amounts assessed resulting from the Tax Court decision.

In September 2017, Exelon appealed the Tax Court decision to the U.S. Court of Appeals for the Seventh Circuit and a decision is expected in 2018.

State Income Tax Law Changes

On April 24, 2018, Maryland enacted companion bills, House Bill 1794 and Senate Bill 1090, providing for a phase in of a single sales factor apportionment formula from the current three factor formula for determining an entity's Maryland state income taxes. The single sales factor will be fully phased by 2022.

In the second quarter of 2018, Exelon, Generation, PHI, DPL, and Pepco expect to record an estimated one-time increase to deferred income taxes of approximately $17 million, $5 million, $18 million, $1 million and $17 million, respectively. At PHI, DPL and Pepco, the increase to the Maryland deferred income tax liability will be offset by regulatory assets. Further, the change in tax law is not expected to have a material ongoing impact to Exelon's, Generation's, PHI's, DPL's or Pepco's future results of operations.

Nuclear Decommissioning (Exelon and Generation)

3 Months Ended

Mar. 31, 2018

Environmental Remediation Obligations [Abstract]

Nuclear Decommissioning (Exelon and Generation)

Nuclear Decommissioning Asset Retirement Obligations

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

The following table provides a rollforward of the nuclear decommissioning ARO reflected on Exelon’s and Generation’s Consolidated Balance Sheets from December 31, 2017 to March 31, 2018:



Nuclear decommissioning ARO at December 31, 2017^(a)	$	9,662
Accretion expense	117
Net increase due to changes in, and timing of, estimated future cash flows	32
Costs incurred related to decommissioning plants	(4		)
Nuclear decommissioning ARO at March 31, 2018^(a)	$	9,807

_________


(a)	Includes $64 million and $13 million for the current portion of the ARO at March 31, 2018 and December 31, 2017, respectively, which is included in Other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets.

During the three months ended March 31, 2018, Generation’s total nuclear ARO increased by approximately $145 million, primarily reflecting the accretion of the ARO liability due to the passage of time and the impact of the February 2, 2018 announcement to retire Oyster Creek at the end of its current operating cycle by October 2018. Refer to Note 8 — Early Plant Retirements for additional information regarding the announced early retirement of Oyster Creek.

Nuclear Decommissioning Trust Fund Investments

NDT funds have been established for each generation station unit to satisfy Generation’s nuclear decommissioning obligations. Generally, NDT funds established for a particular unit may not be used to fund the decommissioning obligations of any other unit.

The NDT funds associated with Generation’s nuclear units have been funded with amounts collected from the previous owners and their respective utility customers. PECO is authorized to collect funds, in revenues, for decommissioning the former PECO nuclear plants through regulated rates, and these collections are scheduled through the operating lives of the former PECO plants. The amounts collected from PECO customers are remitted to Generation and deposited into the NDT funds for the unit for which funds are collected. Every five years, PECO files a rate adjustment with the PAPUC that reflects PECO’s calculations of the estimated amount needed to decommission each of the former PECO units based on updated fund balances and estimated decommissioning costs. The rate adjustment is used to determine the amount collectible from PECO customers. The most recent rate adjustment occurred on January 1, 2018, and the effective rates currently yield annual collections of approximately $4 million. The next five-year adjustment is expected to be reflected in rates charged to PECO customers effective January 1, 2023. See Note 15 — Asset Retirement Obligations of Exelon's 2017 Form 10-K, for information regarding the amount collected from PECO ratepayers for decommissioning costs.

Exelon and Generation had NDT fund investments totaling $13,275 million and $13,349 million at March 31, 2018 and December 31, 2017, respectively.

The following table provides net unrealized gains (losses) on NDT funds for the three months ended March 31, 2018 and 2017:



	Exelon and Generation
	Three Months Ended March 31,
	2018			2017
Net unrealized gains (losses) on decommissioning trust funds — Regulatory Agreement Units^(a)	$	(75	)	$	222
Net unrealized gains (losses) on decommissioning trust funds — Non-Regulatory Agreement Units^(b)(c)	(96		)	166

_________


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


(b)	Excludes $(2) million and $(1) million of net unrealized losses related to the Zion Station pledged assets for the three months ended March 31, 2018 and 2017, respectively. Net unrealized losses related to Zion Station pledged assets are included in Other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets in 2018 and 2017, respectively.


(c)	Net unrealized gains (losses) related to Generation’s NDT funds with Non-Regulatory Agreement Units are included in Other, net on Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

Interest and dividends on NDT fund investments are recognized when earned and are included in Other, net on Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. Interest and dividends earned on the NDT fund investments for the Regulatory Agreement Units are eliminated in Other, net on Exelon’s and Generation’s Consolidated Statement of Operations and Comprehensive Income.

Refer to Note 3 — Regulatory Matters and Note 26 — Related Party Transactions of the Exelon 2017 Form 10-K for information regarding regulatory liabilities at ComEd and PECO and intercompany balances between Generation, ComEd and PECO reflecting the obligation to refund to customers any decommissioning-related assets in excess of the related decommissioning obligations.

Zion Station Decommissioning

On September 1, 2010, Generation completed an Asset Sale Agreement (ASA) with EnergySolutions Inc. and its wholly owned subsidiaries, EnergySolutions, LLC (EnergySolutions) and ZionSolutions, under which ZionSolutions has assumed responsibility for decommissioning Zion Station, which is located in Zion, Illinois and ceased operation in 1998. See Note 15 — Asset Retirement Obligations of the Exelon 2017 Form 10-K for information regarding the specific treatment of assets, including NDT funds, and decommissioning liabilities transferred in the transaction.

ZionSolutions is subject to certain restrictions on its ability to request reimbursements from the Zion Station NDT funds as defined within the ASA. Therefore, the transfer of the Zion Station assets did not qualify for asset sale accounting treatment and, as a result, the related NDT funds were reclassified to Pledged assets for Zion Station decommissioning within Generation’s and Exelon’s Consolidated Balance Sheets and will continue to be measured in the same manner as prior to the completion of the transaction. Additionally, the transferred ARO for decommissioning was replaced with a Payable for Zion Station decommissioning in Generation’s and Exelon’s Consolidated Balance Sheets. Changes in the value of the Zion Station NDT assets, net of applicable taxes, are recorded as a change in the payable to ZionSolutions. At no point will the payable to ZionSolutions exceed the project budget of the costs remaining to decommission Zion Station. Generation has retained its obligation for the SNF. Following ZionSolutions’ completion of its contractual obligations and transfer of the NRC license to Generation, Generation will store the SNF at Zion Station until it is transferred to the DOE for ultimate disposal, and will complete all remaining decommissioning activities associated with the SNF dry storage facility. Generation has a liability of approximately $115 million which is included within the nuclear decommissioning ARO at March 31, 2018. Generation also has retained NDT assets to fund its obligation to maintain the SNF at Zion Station until transfer to the DOE and to complete all remaining decommissioning activities for the SNF storage facility. Any shortage of funds necessary to maintain the SNF and decommission the SNF storage facility is ultimately required to be funded by Generation. Any Zion Station NDT funds remaining after the completion of all decommissioning activities will be returned to ComEd customers in accordance with the applicable orders. The following table provides the pledged assets and payables to ZionSolutions, and withdrawals by ZionSolutions at March 31, 2018 and December 31, 2017:



	Exelon and Generation
	March 31, 2018		December 31, 2017
Carrying value of Zion Station pledged assets^(a)	$	30	$	39
Payable to Zion Solutions^(b)(c)	28		37
Cumulative withdrawals by Zion Solutions to pay decommissioning costs^(d)	949		942

_________


(a)	Included in Other current assets within Exelon's and Generation's Consolidated Balance sheets.


(b)	Excludes a liability recorded within Exelon’s and Generation’s Consolidated Balance Sheets related to the tax obligation on the unrealized activity associated with the Zion Station NDT funds. The NDT funds will be utilized to satisfy the tax obligations as gains and losses are realized.


(c)	Included in Other current liabilities within Exelon’s and Generation’s Consolidated Balance Sheets.


(d)	Includes project expenses to decommission Zion Station and estimated tax payments on Zion Station NDT fund earnings.

NRC Minimum Funding Requirements

NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts to decommission the facility at the end of its life.

Generation filed its biennial decommissioning funding status report with the NRC on March 30, 2017 for all units except for Zion Station which is included in a separate report to the NRC submitted by ZionSolutions (see Zion Station Decommissioning above). The status report demonstrated adequate decommissioning funding assurance for all units except for Peach Bottom Unit 1. As a former PECO plant, financial assurance for decommissioning Peach Bottom Unit 1 is provided by the NDT fund in addition to collections from PECO ratepayers. As discussed under Nuclear Decommissioning Trust Fund Investments above, the amount collected from PECO ratepayers has been adjusted effective January 1, 2018.

On March 28, 2018, Generation submitted its annual decommissioning funding status report with the NRC for shutdown reactors, reactors within five years of shut down except for Zion Station which is included in a separate report to the NRC submitted by EnergySolutions (see Zion Station Decommissioning above), and reactor involved in an acquisition. This report reflected the status of decommissioning funding assurance as of December 31, 2017 and included an update for the acquisition of Fitzpatrick on March 31, 2017, the early retirement of TMI announced on May 30, 2017, an adjustment for the February 2, 2018 announced retirement date of Oyster Creek, and the updated status of Peach Bottom Unit 1 based on the new collections rate described above. As of December 31, 2017, Generation provided adequate decommissioning funding assurance for all of its shutdown reactors, reactors within five years of shutdown, and reactor involved in an acquisition.

Retirement Benefits (All Registrants)

3 Months Ended

Mar. 31, 2018

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.

During the first quarter of 2017, in connection with the acquisition of Fitzpatrick, Exelon established a new qualified pension plan and a new OPEB plan, and recorded a provisional obligation for Fitzpatrick employees based on information available at the merger date of $38 million and $11 million, respectively. As permitted by business combinations authoritative guidance, during the third quarter of 2017, Exelon updated those obligations based on a final valuation for Fitzpatrick employees as of the merger date of March 31, 2017. The updated obligations for pension and OPEB were $16 million and $17 million, respectively. Refer to Note 4 — Mergers, Acquisitions and Dispositions for additional discussion of the acquisition of FitzPatrick.

Defined Benefit Pension and Other Postretirement Benefits

During the first quarter of 2018, Exelon received an updated valuation of its pension and OPEB to reflect actual census data as of January 1, 2018. This valuation resulted in an increase to the pension and OPEB obligations of $23 million and $14 million, respectively. Additionally, accumulated other comprehensive loss decreased by $18 million (after tax) and regulatory assets and liabilities increased by $61 million and $1 million, respectively.

The majority of the 2018 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 3.62%. The majority of the 2018 other postretirement benefit cost is calculated using an expected long-term rate of return on plan assets of 6.60% for funded plans and a discount rate of 3.61%.

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, 2018 and 2017.



	Pension Benefits Three Months Ended March 31,						Other Postretirement Benefits Three Months Ended March 31,
	2018			2017^(a)			2018			2017^(a)
Components of net periodic benefit cost:
Service cost	$	101		$	95		$	28		$	26
Interest cost	201			210			43			45
Expected return on assets	(312		)	(299		)	(43		)	(41		)
Amortization of:
Prior service benefit	—			—			(46		)	(47		)
Actuarial loss	157			152			16			16
Net periodic benefit cost	$	147		$	158		$	(2	)	$	(1	)

_________


(a)	FitzPatrick net benefit costs are included for the period after the acquisition date of March 31, 2017.

The amounts below represent Exelon's, Generation's, ComEd's, PECO's, BGE's, BSC's, PHI's, Pepco's, DPL's, ACE's, and PHISCO's allocated portion of the pension and postretirement benefit plan costs. As a result of new pension guidance effective on January 1, 2018, certain balances have been reclassified on Exelon’s Consolidated Statements of Operations and Comprehensive Income for the three months ended March 31, 2017. The amounts below represent the Registrants’ as well as BSC's and PHISCO's pension and postretirement benefit plan net periodic benefit costs. For Exelon, the service cost component is included in Operating and maintenance expense and Property, plant and equipment for the three months ended March 31, 2018 and 2017, while the non-service cost components are included in Other, net and Regulatory assets for the three months ended March 31, 2018 and in Other, net and Property, plant and equipment for the three months ended March 31, 2017. 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 on their consolidated financial statements for the three months ended March 31, 2018 and 2017.



	Three Months Ended March 31,
Pension and Other Postretirement Benefit Costs	2018		2017
Exelon^(a)(b)	$	145	$	157
Generation^(b)	51		54
ComEd	45		44
PECO	5		7
BGE	15		16
BSC^(c)	14		12
PHI^(a)(d)	15		24
Pepco	4		7
DPL	—		3
ACE	3		3
PHISCO^(d)	8		11

_________


(a)	Exelon reflects the consolidated pension and other postretirement benefit costs of Generation, ComEd, PECO, BGE, BSC, and PHI. PHI reflects the consolidated pension and other postretirement benefit costs of Pepco, DPL, ACE, and PHISCO.


(b)	FitzPatrick net benefit costs are included for the period after the acquisition date of March 31, 2017.


(c)	These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO, BGE, PHI, Pepco, DPL or ACE amounts above.


(d)	These amounts represent amounts billed to Pepco, DPL and ACE through intercompany allocations. These amounts are not included in Pepco, DPL or ACE amounts above.

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, 2018 and 2017, respectively.



	Three Months Ended March 31,
Savings Plan Matching Contributions	2018		2017
Exelon^(a)(b)	$	32	$	30
Generation^(b)	15		14
ComEd	7		7
PECO	2		2
BGE	2		2
BSC^(c)	3		2
PHI^(a)(d)	3		3
Pepco	1		1
DPL	1		1
PHISCO^(d)	1		1

_________


(a)	Exelon reflects the consolidated savings plan matching contributions of Generation, ComEd, PECO, BGE, BSC, and PHI. PHI reflects the consolidated savings plan matching contributions of Pepco, DPL, and PHISCO.


(b)	FitzPatrick net benefit costs are included for the period after the acquisition date of March 31, 2017.


(c)	These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO, BGE, PHI, Pepco or DPL amounts above.


(d)	These amounts represent amounts billed to Pepco and DPL through intercompany allocations. These amounts are not included in Pepco or DPL amounts above.

Severance (All Registrants)

3 Months Ended

Mar. 31, 2018

Restructuring Charges [Abstract]

Severance (All Registrants)

The Registrants have an ongoing severance plan under which, in general, the longer an employee worked prior to termination the greater the amount of severance benefits. The Registrants record a liability and expense or regulatory asset for severance once terminations are probable of occurrence and the related severance benefits can be reasonably estimated. For severance benefits that are incremental to its ongoing severance plan (“one-time termination benefits”), the Registrants measure the obligation and record the expense at fair value at the communication date if there are no future service requirements, or, if future service is required to receive the termination benefit, ratably over the required service period.

Ongoing Severance Plans

The Registrants provide severance and health and welfare benefits under Exelon’s ongoing severance benefit plans to terminated employees in the normal course of business. These benefits are accrued for when the benefits are considered probable and can be reasonably estimated.

For the three months ended March 31, 2018 and 2017, the Registrants recorded the following severance costs associated with these ongoing severance benefits within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income:



	Exelon		Generation^(a)		ComEd^(a)		PECO^(a)		BGE^(a)		PHI^(a)		Pepco^(a)		DPL^(a)		ACE^(a)
Three Months Ended
March 31, 2018	$	8	$	2	$	1	$	—	$	1	$	4	$	2	$	1	$	1
March 31, 2017	4		3		1		—		—		—		—		—		—

_________


(a)	The amounts above for Generation, ComEd, PECO, BGE, and PHI include immaterial amounts billed by BSC the three months ended March 31, 2018 and 2017. Pepco, DPL and ACE include immaterial amounts billed by PHISCO for the three months ended March 31, 2018 and 2017.

Cost Management Program-Related Severance

In August 2015, Exelon announced a cost management program focused on cost savings of approximately $400 million at BSC and Generation. Additionally, in November 2017, Exelon announced a new commitment for an additional $250 million of cost savings, primarily at Generation, to be achieved by 2020. These actions are in response to the continuing economic challenges confronting all parts of Exelon’s business and industry, necessitating continued focus on cost management through enhanced efficiency and productivity. In connection with the program, certain positions have been identified for elimination and severance costs were recognized as both probable and estimable.

While there may be additional position eliminations identified leading to potential severance or other termination benefit changes, Exelon, Generation and BSC intend to manage any staff reductions through natural attrition to the extent possible to minimize impacts on employees. Any additional severance or other termination benefit charges related to this commitment will be recognized when such amounts are considered probable and can be reasonably estimated.

For the three months ended March 31, 2018 and 2017, these costs were immaterial.

Early Plant Retirement-Related Severance (Exelon and Generation)

As a result of the Three Mile Island and Oyster Creek plant retirement decision, Exelon and Generation have recognized severance costs as both probable and estimable. Severance costs will be provided to management employees that are eligible under Exelon’s severance policy and to union employees if specified within the respective collective bargaining agreements, to the extent that those employees are not redeployed to other locations.

The final amount of the severance cost will ultimately depend on the specific employees severed. See Note 8 - Early Plant Retirements for additional information regarding the announced early retirement of TMI and Oyster Creek.

For the three months ended March 31, 2018 and 2017, these costs were immaterial.

Severance Liability

Amounts included in the table below represent the severance liability recorded for employees of each Registrant and exclude amounts included at Exelon and billed through intercompany allocations:




Severance Liability	Exelon			Generation			ComEd			PECO		BGE		PHI			Pepco			DPL		ACE
Balance at December 31, 2017	$	94		$	58		$	3		$	—	$	—	$	20		$	—		$	—	$	—
Severance charges^(a)	9			3			1			—		1		2			1			—		—
Payments	(16		)	(5		)	(1		)	—		—		(6		)	(1		)	—		—
Balance at March 31, 2018	$	87		$	56		$	3		$	—	$	1	$	16		$	—		$	—	$	—

__________


(a)	Includes salary continuance and health and welfare severance benefits.

Changes in Accumulated Other Comprehensive Income (Exelon, Generation, PECO and PHI)

3 Months Ended

Mar. 31, 2018

Changes in Accumulated Other Comprehensive Income [Abstract]

Comprehensive Income (Loss) Note [Text Block]

Changes in Accumulated Other Comprehensive Income (Exelon, Generation and PECO)

The following tables present changes in accumulated other comprehensive income (loss) (AOCI) by component for the three months ended March 31, 2018 and 2017:



Three Months Ended March 31, 2018	Gains and (losses) on Cash Flow Hedges			Unrealized Gains and (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	—			(10		)	^(c)	—				—			—			(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^(b)	—			—				—				—			—			—
Net current-period OCI	7			—				—				(1		)	—			6
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard	—			(3		)	^(c)	—				—			—			(3		)
Ending balance	$	(9	)	$	—			$	—			$	(24	)	$	(1	)	$	(34	)
PECO^(a)
Beginning balance	$	—		$	1			$	—			$	—		$	—		$	1
OCI before reclassifications	—			—				—				—			—			—
Amounts reclassified from AOCI^(b)	—			—				—				—			—			—
Net current-period OCI	—			—				—				—			—			—
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard	—			(1		)	^(c)	—				—			—			(1		)
Ending balance	$	—		$	—			$	—			$	—		$	—		$	—



Three Months Ended March 31, 2017	Gains and (losses) on Cash Flow Hedges			Unrealized Gains and (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	$	(17	)	$	4	$	(2,610	)	$	(30	)	$	(7	)	$	(2,660	)
OCI before reclassifications	2			1		(59		)	1			5			(50		)
Amounts reclassified from AOCI^(b)	4			—		36			—			—			40
Net current-period OCI	6			1		(23		)	1			5			(10		)
Ending balance	$	(11	)	$	5	$	(2,633	)	$	(29	)	$	(2	)	$	(2,670	)
Generation^(a)
Beginning balance	$	(19	)	$	2	$	—		$	(30	)	$	(7	)	$	(54	)
OCI before reclassifications	2			—		—			1			6			9
Amounts reclassified from AOCI^(b)	4			—		—			—			—			4
Net current-period OCI	6			—		—			1			6			13
Ending balance	$	(13	)	$	2	$	—		$	(29	)	$	(1	)	$	(41	)
PECO^(a)
Beginning balance	$	—		$	1	$	—		$	—		$	—		$	1
OCI before reclassifications	—			—		—			—			—			—
Amounts reclassified from AOCI^(b)	—			—		—			—			—			—
Net current-period OCI	—			—		—			—			—			—
Ending balance	$	—		$	1	$	—		$	—		$	—		$	1

_________


(a)	All amounts are net of tax and noncontrolling interest. 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, $3 million and $1 million for Exelon, Generation and PECO, respectively. The amounts reclassified related to Rabbi Trusts. See Note 2 — New Accounting Standards 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 2 — New Accounting Standards for additional information.

ComEd, PECO, BGE, PHI, Pepco, DPL and ACE did not have any reclassifications out of AOCI to Net income during the three months ended March 31, 2018 and 2017. The following tables present amounts reclassified out of AOCI to Net income for Exelon and Generation during the three months ended March 31, 2018 and 2017.

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		)
Total before tax	(60		)
Tax benefit	16
Net of tax	$	(44	)

Total Reclassifications	$	(44	)	Comprehensive income

Three Months Ended March 31, 2017



Details about AOCI components	Items reclassified out of AOCI^(a)						Affected line item in the Statement of Operations and Comprehensive Income
	Exelon			Generation
Gains and (losses) on cash flow hedges
Other cash flow hedges	$	(7	)	$	(7	)	Interest expense
Total before tax	(7		)	(7		)
Tax benefit	3			3
Net of tax	$	(4	)	$	(4	)	Comprehensive income

Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)	$	23		$	—
Actuarial losses^(b)	(81		)	—
Total before tax	(58		)	—
Tax benefit	22			—
Net of tax	$	(36	)	$	—

Total Reclassifications	$	(40	)	$	(4	)	Comprehensive income

_________


(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 details).

The following table presents income tax expense (benefit) allocated to each component of other comprehensive income (loss) during the three months ended March 31, 2018 and 2017:



	Three Months Ended March 31,
	2018			2017
Exelon
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	$	6		$	10
Actuarial loss reclassified to periodic benefit cost	(22		)	(32		)
Pension and non-pension postretirement benefit plans valuation adjustment	(7		)	—
Change in unrealized (loss) on cash flow hedges	(3		)	(1		)
Change in unrealized (loss) on investments in unconsolidated affiliates	(1		)	(4		)
Change in unrealized (loss) on marketable securities	—			(1		)
Total	$	(27	)	$	(28	)

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

Earnings Per Share and Equity (Exelon)

3 Months Ended

Mar. 31, 2018

Earnings Per Share [Abstract]

Earnings Per Share and Equity (Exelon)

Earnings per Share

Basic earnings per share is computed by dividing net income attributable to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share is computed by dividing net income attributable to common shareholders by the weighted average number of common shares outstanding, including the effect of issuing common stock assuming (i) stock options are exercised, and (ii) performance share awards and restricted stock awards are fully vested under the treasury stock method.

The following table sets forth the components of basic and diluted earnings per share and shows the effect of these stock options, performance share awards and restricted stock awards on the weighted average number of shares outstanding used in calculating diluted earnings per share:



	Three Months Ended March 31,
	2018		2017
Exelon
Net income attributable to common shareholders	$	585	$	990
Weighted average common shares outstanding — basic	966		928
Assumed exercise and/or distributions of stock-based awards	2		2
Weighted average common shares outstanding — diluted	968		930

The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was approximately 5 million and 9 million for the three months ended March 31, 2018 and 2017, respectively. There were no equity units related to the PHI Merger not included in the calculation of diluted common shares outstanding due to their antidilutive effect for the three months ended March 31, 2018 and 2017. Refer to Note 19 — Shareholders' Equity of the Exelon 2017 Form 10-K for further information regarding the equity units.

Under share repurchase programs, 2 million shares of common stock are held as treasury stock with a cost of $123 million as of March 31, 2018.

Commitments and Contingencies (All Registrants)

3 Months Ended

Mar. 31, 2018

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 23 of the Exelon 2017 Form 10-K. See Note 4 — Mergers, Acquisitions and Dispositions of the Exelon 2017 Form 10-K for further discussion 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, 2018:



Description	Expected Payment Period	Pepco		DPL		ACE		PHI		Exelon
Rate credits	2016 - 2017	$	91	$	67	$	101	$	259	$	259
Energy efficiency	2016 - 2021	—		—		—		—		122
Charitable contributions	2016 - 2026	28		12		10		50		50
Delivery system modernization	Q2 2017	—		—		—		—		22
Green sustainability fund	Q2 2017	—		—		—		—		14
Workforce development	2016 - 2020	—		—		—		—		17
Other		1		5		—		6		29
Total commitments		$	120	$	84	$	111	$	315	$	513
Remaining commitments		$	75	$	12	$	8	$	95	$	165

In addition, Exelon is committed to develop or to assist in the commercial development of approximately 37 MWs of new generation in Maryland, District of Columbia, and Delaware, 27 MWs of which are expected to be completed by 2018. These investments are expected to total approximately $137 million, are expected to be primarily capital in nature, and will generate future earnings at Exelon and Generation. Investment costs will be recognized as incurred and recorded on Exelon's and Generation's financial statements. Exelon has also committed to purchase 100 MWs of wind energy in PJM, to procure 120 MWs of wind RECs for the purpose of meeting Delaware's renewable portfolio standards, and to maintain and promote energy efficiency and demand response programs in the PHI jurisdictions.

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.

Constellation Merger Commitments (Exelon and Generation)

In February 2012, the MDPSC issued an Order approving the Exelon and Constellation merger. As part of the MDPSC Order, Exelon agreed to develop or assist in the development of 285-300 MWs of new generation. Exelon and Generation have incurred $458 million towards satisfying the commitment for new generation development in the State of Maryland, with 220 MW of new generation in operations to date and 10 MW of this commitment satisfied through a liquidated damages payment made in the fourth quarter of 2016. The remaining 55MW is expected to be satisfied via payment of liquidated damages or execution of a third party PPA, rather than by Generation constructing renewable generating assets. As a result, as of March 31, 2018 Exelon’s and Generation’s Consolidated Balance Sheets include a $50 million liability within Deferred credits and other liabilities for this remaining commitment, to be paid on or before January 15, 2023 unless the period is extended by consent of Exelon and the State. Refer to Note 23 - Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in the Exelon 2017 Form 10-K for additional information regarding the Constellation Merger Commitments.

Commercial Commitments (All Registrants)

The Registrants’ commercial commitments as of March 31, 2018, representing commitments potentially triggered by future events were as follows:



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Letters of credit (non-debt)^(a)	$	1,586	$	1,533	$	2	$	1	$	5	$	1	$	1	$	—	$	—
Surety bonds^(b)	1,651		1,463		9		9		10		66		32		4		5
Financing trust guarantees	378		—		200		178		—		—		—		—		—
Guaranteed lease residual values^(c)	22		—		—		—		—		22		7		9		6
Total commercial commitments	$	3,637	$	2,996	$	211	$	188	$	15	$	89	$	40	$	13	$	11

_________


(a)	Letters of credit (non-debt) - Exelon and certain of its subsidiaries maintain non-debt letters of credit to provide credit support for certain transactions as requested by third parties. Includes letters of credits issued under credit facility agreements arranged at minority and community banks and nonrecourse debt letters of credits.


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

(c)

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 $58 million, $17 million of which is a guarantee by Pepco, $24 million by DPL and $16 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, 2018, the current liability limit per incident is $13.2 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors at least once every five years with the last adjustment effective September 10, 2013. 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 $13.0 billion per incident in funds available for public liability claims. Participation in this secondary financial protection pool requires the operator of each reactor to fund its proportionate share of costs for any single incident that exceeds the primary layer of financial protection. Exelon’s share of this secondary layer would be approximately $2.8 billion, however any amounts payable under this secondary layer would be capped at $420 million per year.

In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay public liability claims exceeding the $13.2 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 2017 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. In March 2018, NEIL declared a supplemental distribution. Generation's portion of the supplemental distribution declared by NEIL is estimated to be $31 million and was recorded as a reduction to Operating and maintenance expense within Exelon and Generation’s Consolidated Statements of Operations and Comprehensive Income for the three months ended March 31, 2018, with cash expected to be received during the second quarter 2018.

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 $360 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. The Registrants’ operations have in the past, and may in the future, require substantial expenditures to comply with environmental laws. Additionally, under Federal and state environmental laws, the Registrants are generally liable for the costs of remediating environmental contamination of property now or formerly owned by them and of property contaminated by hazardous substances generated by them. The Registrants own or lease a number of real estate parcels, including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. In addition, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future. Unless otherwise disclosed, the Registrants cannot reasonably estimate whether they will incur significant liabilities for additional investigation and remediation costs at these or additional sites identified by the Registrants, environmental agencies or others, or whether such costs will be recoverable from third parties, including customers. Additional costs could have a material, unfavorable impact on the Registrants' financial conditions, results of operations and cash flows.

MGP Sites

ComEd, PECO, BGE and DPL have identified sites where former MGP 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, 20 of which have been remediated and approved by the Illinois EPA or the U.S. EPA and 22 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 2022.


•	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 former gas manufacturing or purification sites, 9 of which the remediation has been completed and approved by the MDE and 4 that require some level of remediation and/or ongoing activity. BGE has determined that a loss associated with these sites is probable and has recorded an estimated liability, which is included in the table below. However, it is reasonably possible that BGE’s cost of remediation for one of its sites could be up to $13 million.


•	DPL has identified 3 sites, 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 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, 2018 and December 31, 2017, 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, 2018	Total environmental investigation and remediation reserve		Portion of total related to MGP investigation and remediation
Exelon	$	462	$	313
Generation	117		—
ComEd	283		281
PECO	29		28
BGE	5		4
PHI	28		—
Pepco	26		—
DPL	1		—
ACE	1		—



December 31, 2017	Total environmental investigation and remediation reserve		Portion of total related to MGP investigation and remediation
Exelon	$	466	$	315
Generation	117		—
ComEd	285		283
PECO	30		28
BGE	5		4
PHI	29		—
Pepco	27		—
DPL	1		—
ACE	1		—

Solid and Hazardous Waste

Cotter Corporation. 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. On May 29, 2008, the EPA issued a Record of Decision (ROD) approving a landfill cover remediation approach. Generation had previously recorded an estimated liability for its anticipated share of a landfill cover remedy that was estimated to cost approximately $90 million in total. By letter dated January 11, 2010, the EPA requested that the PRPs perform a supplemental feasibility study for a remediation alternative that would involve complete excavation of the radiological contamination. On September 30, 2011, the PRPs submitted the supplemental feasibility study to the EPA for review. Since June 2012, the EPA has requested that the PRPs perform a series of additional analyses and groundwater and soil sampling as part of the supplemental feasibility study. This further analysis was focused on a partial excavation remedial option. The PRPs provided the draft final Remedial Investigation and Feasibility Study (RI/FS) to the EPA in January 2018, which formed the basis for EPA’s proposed remedy selection, as further discussed below. There are currently 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.

On February 1, 2018, the EPA announced its proposed remedy involving partial excavation of the site with an enhanced landfill cover. The proposed remedy was open for public comment through April 23, 2018 and Generation currently expects that a ROD will be issued during the third quarter of 2018. Thereafter, the EPA will seek to enter into a Consent Decree with the PRPs to effectuate the remedy, which Generation currently expects will occur in late 2018 or early 2019. 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 $340 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 for the entire remediation effort. 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 ultimate 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 conditions, results of operations and cash flows.

On January 16, 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. The PRPs have been provided with a draft statement of work that will form the basis of an Administrative Settlement Agreement and Order on Consent for the performance by the PRPs of the groundwater RI/FS and reimbursement of EPA’s oversight costs. The purposes of this new RI/FS are to define the nature and extent of any groundwater contamination from the West Lake Landfill site, determine the potential risk posed to human health and the environment, and evaluate remedial alternatives. Generation estimates the undiscounted cost for the groundwater RI/FS for West Lake to be approximately $20 million and Generation 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 will be required and 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 results of operations and cash flows.

During December 2015, the EPA took two actions related to the West Lake Landfill designed to abate what it termed as imminent and dangerous conditions at the landfill. The first involved installation by the PRPs of a non-combustible surface cover to protect against surface fires in areas where radiological materials are believed to have been disposed. Generation has accrued what it believes to be an adequate amount to cover its anticipated liability for this interim action, and the work is expected to be completed in 2018. The second action involved EPA's public statement that it will require the PRPs to construct a barrier wall in an adjacent landfill to prevent a subsurface fire from spreading to those areas of the West Lake Landfill where radiological materials are believed to have been disposed. At this time, Generation believes that the requirement to build a barrier wall is remote in light of other technologies that have been employed by the adjacent landfill owner. Finally, one of the other PRPs, the landfill owner and operator of the adjacent landfill, has indicated that 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 conditions, results of operations and cash flows.

On August 8, 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. The DOJ and the PRPs agreed to toll the statute of limitations until August 2018 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. The complaints do not contain specific damage claims. In the event of a finding of liability against Cotter, it is reasonably possible 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, and that has been upheld on appeal. The parties have engaged in settlement discussions pursuant to court-ordered mediation and it is expected that resolution of this matter will not have a material, unfavorable impact on Exelon’s and Generation's financial conditions, results of operations and cash flows.

Benning Road Site. 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 May 6, 2019.

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. 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. DOEE has advised the Consultative Working Group that the federal and DOEE authorities conducted the remedial investigation and a draft of that report was released to the public on April 1, 2018. Written comments will be accepted by the Agencies until May 14, 2018 and a Public Meeting to present the finding of the RI is scheduled for April 24, 2018. Pepco intends to submit comments, participate in the Public Hearing, and continue its outreach efforts as appropriate to the agencies, governmental officials, community organizations and other key stakeholders. A feasibility study of potential remedies is being prepared by the Agencies and is scheduled to be released in the late summer or early fall of this year. DOEE currently is working under a statutorily mandated date to complete the Record of Decision selecting the final remedy for the project by June 30, 2018. However, on January 11, 2018 the DOEE requested at a hearing of the District of Columbia Council Committee of the Environment that this statutory deadline be extended until December 31, 2019 to reflect the time necessary to complete the investigation. A recommendation by the Committee to the DC Council is expected in the near future. The District of Columbia Council will make the final determination to extend the deadline. 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. It is anticipated that Pepco will likely be in a better position to estimate that range of loss when the draft Feasibility Study for the Project is released. The timing for that release is currently scheduled for late this summer or early fall.

Conectiv Energy Wholesale Power Generation Sites. In July 2010, PHI sold the wholesale power generation business of Conectiv Energy Holdings, Inc. and substantially all of its subsidiaries (Conectiv Energy) to Calpine Corporation (Calpine). Under New Jersey’s Industrial Site Recovery Act (ISRA), the transfer of ownership triggered an obligation on the part of Conectiv Energy to remediate any environmental contamination at each of the nine Conectiv Energy generating facility sites located in New Jersey. Under the terms of the sale, Calpine has assumed responsibility for performing the ISRA-required remediation and for the payment of all related ISRA compliance costs up to $10 million. Predecessor PHI was obligated to indemnify Calpine for any ISRA compliance remediation costs in excess of $10 million. According to PHI’s estimates, the costs of ISRA-required remediation activities at the nine generating facility sites located in New Jersey are in the range of approximately $7 million to $18 million, and predecessor PHI recorded an estimated liability for its share of the estimated clean-up costs. Pursuant to Exelon’s March 2016 acquisition of PHI, the Conectiv Energy legal entity was transferred to Generation and the liability for Predecessor PHI's share of the estimated clean- up costs was also transferred to Generation and is included in the table above as a liability of Generation. The responsibility to indemnify Calpine is shared by PHI and Generation.

Brandywine Fly Ash Disposal Site. In February 2013, Pepco received a letter from the MDE requesting that Pepco investigate the extent of waste on a Pepco right-of-way that traverses the Brandywine fly ash disposal site in Brandywine, Prince George’s County, Maryland, owned by NRG Energy, Inc. (as successor to GenOn MD Ash Management, LLC) (NRG). In July 2013, while reserving its rights and related defenses under a 2000 agreement covering the sale of this site, Pepco indicated its willingness to investigate the extent of, and propose an appropriate closure plan to address, ash on the right-of-way. Pepco submitted a schedule for development of a closure plan to MDE on September 30, 2013 and, by letter dated October 18, 2013, MDE approved the schedule.

Pepco has determined that a loss associated with this matter is probable and has recorded an estimated liability, which is included in the table above. Pepco believes that the costs incurred in this matter may be recoverable from NRG under the 2000 sale agreement, but has not recorded an associated receivable for any potential recovery.

Litigation and Regulatory Matters

PHI Merger

In July 2015, the OPC, Public Citizen, Inc., the Sierra Club and the Chesapeake Climate Action Network (CCAN) filed motions to stay the MDPSC order approving the Exelon and PHI merger. The Circuit Court judge issued an order denying the motions for stay on August 12, 2015. On January 8, 2016, the Circuit Court judge affirmed the MDPSC’s order approving the merger and denied the petitions for judicial review filed by the OPC, the Sierra Club, CCAN and Public Citizen, Inc. On January 19, 2016, the OPC filed a notice of appeal to the Maryland Court of Special Appeals, and on January 21, the Sierra Club and CCAN filed notices of appeal. On January 27, 2017, the Maryland Court of Special Appeals affirmed the Circuit Court's judgment that the MDPSC did not err in approving the merger. The OPC and Sierra Club filed petitions seeking further review in the Court of Appeals of Maryland, which is the highest court in Maryland. On June 21, 2017, the Court of Appeals granted discretionary review of the January 27, 2017 decision by the Maryland Court of Special Appeals. The Maryland Court of Appeals will review the OPC argument that the MDPSC did not properly consider the acquisition premium paid to PHI shareholders under Maryland’s merger approval standard and the Sierra Club’s argument that the merger would harm the renewable and distributed generation markets. The two lower courts examining these issues rejected these arguments, which Exelon believes are without merit. All briefs have been filed and oral arguments were presented to the court on October 10, 2017.

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, 2018 and December 31, 2017, Generation had recorded estimated liabilities of approximately $76 million and $78 million, respectively, in total for asbestos-related bodily injury claims. As of March 31, 2018, approximately $21 million of this amount related to 232 open claims presented to Generation, while the remaining $55 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.

On November 22, 2013, the Supreme Court of Pennsylvania held that the Pennsylvania Workers Compensation Act does not apply to an employee’s disability or death resulting from occupational disease, such as diseases related to asbestos exposure, which manifests more than 300 weeks after the employee’s last employment-based exposure, and that therefore the exclusivity provision of the Act does not preclude such employee from suing his or her employer in court. The Supreme Court’s ruling reverses previous rulings by the Pennsylvania Superior Court precluding current and former employees from suing their employers in court, despite the fact that the same employee was not eligible for workers compensation benefits for diseases that manifest more than 300 weeks after the employee’s last employment-based exposure to asbestos. Since the Pennsylvania Supreme Court's ruling in November 2013, Exelon, Generation, and PECO have experienced an increase in asbestos-related personal injury claims brought by former PECO employees, all of which have been accrued for on a claim by claim basis. Those additional claims are taken into account in projecting estimated future asbestos-related bodily injury claims.

On November 4, 2015, the Illinois Supreme Court found that the provisions of the Illinois' Workers' Compensation Act and the Workers' Occupational Diseases Act barred an employee from bringing a direct civil action against an employer for latent diseases, including asbestos-related diseases that fall outside the 25-year limit of the statute of repose. The Illinois Supreme Court's ruling reversed previous rulings by the Illinois Court of Appeals, which initially ruled that the Illinois Worker's Compensation law should not apply in cases where the diagnosis of an asbestos related disease occurred after the 25-year maximum time period for filing a Worker's Compensation claim. As a result of this ruling, Exelon, Generation, and ComEd have not recorded an increase to the asbestos-related bodily injury liability as of March 31, 2018.

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, Generation's and PECO's financial conditions, results of operations and cash flows.

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 8 & 9 on the grounds that the total investment in Mystic 8 & 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

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 a reasonable possibility, 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.

Income Taxes

See Note 12 — Income Taxes for information regarding the Registrants’ income tax refund claims and certain tax positions, including the 1999 sale of fossil generating assets.

Supplemental Financial Information (All Registrants)

3 Months Ended

Mar. 31, 2018

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, 2018 and 2017.



	Three Months Ended March 31, 2018
	Exelon			Generation			ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds^(a)
Regulatory agreement units	$	46		$	46		$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-regulatory agreement units	56			56			—		—		—		—		—		—		—
Net unrealized losses on decommissioning trust funds
Regulatory agreement units	(75		)	(75		)	—		—		—		—		—		—		—
Non-regulatory agreement units	(96		)	(96		)	—		—		—		—		—		—		—
Net unrealized losses on pledged assets
Zion Station decommissioning	(2		)	(2		)	—		—		—		—		—		—		—
Regulatory offset to decommissioning trust fund-related activities^(b)	24			24			—		—		—		—		—		—		—
Total decommissioning-related activities	(47		)	(47		)	—		—		—		—		—		—		—
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	5			—			2		—		—		5		3		1		1
Other, net	$	(28	)	$	(44	)	$	8	$	2	$	4	$	11	$	8	$	2	$	1



	Three Months Ended March 31, 2017
	Exelon			Generation			ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds^(a)
Regulatory agreement units	$	68		$	68		$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-regulatory agreement units	32			32			—		—		—		—		—		—		—
Net unrealized gains on decommissioning trust funds
Regulatory agreement units	222			222			—		—		—		—		—		—		—
Non-regulatory agreement units	166			166			—		—		—		—		—		—		—
Net unrealized losses on pledged assets
Zion Station decommissioning	(1		)	(1		)	—		—		—		—		—		—		—
Regulatory offset to decommissioning trust fund-related activities^(b)	(234		)	(234		)	—		—		—		—		—		—		—
Total decommissioning-related activities	253			253			—		—		—		—		—		—		—
Investment income	2			2			—		—		—		—		—		—		—
Interest income related to uncertain income tax positions	1			—			—		—		—		—		—		—		—
AFUDC — Equity	17			—			2		2		4		9		5		2		2
Non-service net periodic benefit cost	(26		)	—			—		—		—		—		—		—		—
Other	10			4			2		—		—		4		3		1		—
Other, net	$	257		$	259		$	4	$	2	$	4	$	13	$	8	$	3	$	2

_________


(a)	Includes investment income and realized gains and losses on sales of investments of the trust funds.


(b)	Includes the elimination of NDT fund activity 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 2017 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, 2018 and 2017. 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 on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.




	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	$	—



	Three Months Ended March 31, 2017
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Utility taxes	$	224	$	32	$	59	$	31	$	26	$	76	$	71	$	5	$	—

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, 2018 and 2017.



	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



	Three Months Ended March 31, 2017
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Depreciation, amortization and accretion
Property, plant and equipment^(a)	$	754	$	289	$	190	$	64	$	80	$	112	$	50	$	30	$	21
Amortization of regulatory assets^(a)	128		—		18		7		48		55		32		9		14
Amortization of intangible assets, net^(a)	14		13		—		—		—		—		—		—		—
Amortization of energy contract assets and liabilities^(b)	2		2		—		—		—		—		—		—		—
Nuclear fuel^(c)	264		264		—		—		—		—		—		—		—
ARO accretion^(d)	112		110		—		—		—		—		—		—		—
Total depreciation, amortization and accretion	$	1,274	$	678	$	208	$	71	$	128	$	167	$	82	$	39	$	35

_________


(a)	Included in Depreciation and amortization on the Registrants' Consolidated Statements of Operations and Comprehensive Income.


(b)	Included in Operating revenues or Purchased power and fuel expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.


(c)	Included in Purchased power and fuel expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.


(d)	Included in Operating and maintenance expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.



	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:
Increase (decrease) in capital expenditures not paid	$	(177	)	$	(131	)	$	(48	)	$	(25	)	$	(11	)	$	61	$	19		$	14	$	27
Increase in PPE related to ARO update	32			32			—			—			—			—		—			—		—
Dividends on stock compensation	1			—			—			—			—			—		—			—		—




	Three Months Ended March 31, 2017
	Exelon			Generation			ComEd			PECO			BGE			PHI			Pepco			DPL			ACE
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	157		$	54		$	44		$	7		$	16		$	24		$	7		$	3		$	3
Loss from equity method investments	10			10			—			—			—			—			—			—			—
Provision for uncollectible accounts	34			9			7			17			5			(4		)	(5		)	(1		)	1
Stock-based compensation costs	31			—			—			—			—			—			—			—			—
Other decommissioning-related activity^(a)	(84		)	(84		)	—			—			—			—			—			—			—
Energy-related options^(b)	(4		)	(4		)	—			—			—			—			—			—			—
Amortization of regulatory asset related to debt costs	2			—			1			—			—			1			—			—			—
Amortization of rate stabilization deferral	(14		)	—			—			—			7			(21		)	(15		)	(6		)	—
Amortization of debt fair value adjustment	(5		)	(3		)	—			—			—			(2		)	—			—			—
Discrete impacts from EIMA and FEJA ^(c)	(24		)	—			(24		)	—			—			—			—			—			—
Amortization of debt costs	9			4			1			—			—			—			—			—			—
Provision for excess and obsolete inventory	2			1			1			—			—			—			—			—			—
Other	4			3			1			(1		)	(4		)	(6		)	(2		)	(3		)	(2		)
Total other non-cash operating activities	$	118		$	(10	)	$	31		$	23		$	24		$	(8	)	$	(15	)	$	(7	)	$	2
Non-cash investing and financing activities:
Increase (decrease) in capital expenditures not paid	$	(193	)	$	(56	)	$	(66	)	$	(42	)	$	1		$	(5	)	$	(6	)	$	9		$	—
Non-cash financing of capital projects	10			10			—			—			—			—			—			—			—
Dividends on stock compensation	2			—			—			—			—			—			—			—			—

_________

(a)

Includes the elimination of NDT fund 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 2017 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.

(c)

Reflects the change in distribution rates pursuant to EIMA and FEJA, which allows for the recovery of distribution costs by a utility through a pre-established performance-based formula rate tariff. Beginning June 1, 2017, also reflects the change in energy efficiency rates pursuant to FEJA, which allows for the recovery of energy efficiency costs by a utility through a pre-established performance-based formula rate tariff. See Note 6 — Regulatory Matters for more 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, 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 shown in the statement of cash flows	$	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 shown in the statement of cash flows	$	1,190	$	554	$	144	$	275	$	18	$	95	$	40	$	2	$	31



March 31, 2017	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Cash and cash equivalents	$	609	$	400	$	31	$	28	$	11	$	109	$	8	$	44	$	54
Restricted cash	254		140		3		4		43		41		33		—		7
Restricted cash included in other long-term assets	26		—		—		—		3		23		—		—		23
Total cash, cash equivalents and restricted cash shown in the statement of cash flows	$	889	$	540	$	34	$	32	$	57	$	173	$	41	$	44	$	84



December 31, 2016	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Cash and cash equivalents	$	635	$	290	$	56	$	63	$	23	$	170	$	9	$	46	$	101
Restricted cash	253		158		2		4		24		43		33		—		9
Restricted cash included in other long-term assets	26		—		—		—		3		23		—		—		23
Total cash, cash equivalents and restricted cash shown in the statement of cash flows	$	914	$	448	$	58	$	67	$	50	$	236	$	42	$	46	$	133

For additional information on restricted cash see Note 1 — Significant Accounting Policies of the Exelon 2017 Form 10-K.

Supplemental Balance Sheet Information

The following tables provide additional information about assets and liabilities of the Registrants as of March 31, 2018 and December 31, 2017.



March 31, 2018	Exelon			Generation			ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Property, plant and equipment:
Accumulated depreciation and amortization	$	21,905	^(a)	$	11,936	^(a)	$	4,391	$	3,445	$	3,471	$	575	$	3,224	$	1,273	$	1,086
Accounts receivable:
Allowance for uncollectible accounts	$	369		$	115		$	89	$	68	$	31	$	66	$	24	$	22	$	20



December 31, 2017	Exelon			Generation			ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Property, plant and equipment:
Accumulated depreciation and amortization	$	21,064	^(b)	$	11,428	^(b)	$	4,269	$	3,411	$	3,405	$	487	$	3,177	$	1,247	$	1,066
Accounts receivable:
Allowance for uncollectible accounts	$	322		$	114		$	73	$	56	$	24	$	55	$	21	$	16	$	18

_________


(a)	Includes accumulated amortization of nuclear fuel in the reactor core of $3,263 million.


(b)	Includes accumulated amortization of nuclear fuel in the reactor core of $3,159 million.

PECO Installment Plan Receivables (Exelon and PECO)

PECO enters into payment agreements with certain delinquent customers, primarily residential, seeking to restore their service, as required by the PAPUC. Customers with past due balances that meet certain income criteria are provided the option to enter into an installment payment plan, some of which have terms greater than one year. The receivable balance for these payment agreement receivables is recorded in accounts receivable for the current portion and other deferred debits and other assets for the noncurrent portion. The net receivable balance for installment plans with terms greater than one year was $8 million and $11 million as of March 31, 2018 and December 31, 2017, respectively. The allowance for uncollectible accounts balance associated with these receivables at March 31, 2018 of $10 million consists of $3 million and $7 million for medium risk and high risk segments, respectively. The allowance for uncollectible accounts balance at December 31, 2017 of $11 million consists of $3 million and $8 million for medium risk and high risk segments, respectively. For further information regarding uncollectible accounts reserve methodology and assessment of the credit quality of the installment plan receivables, refer to Note 1 — Significant Accounting Policies of the Exelon 2017 Form 10-K.

Segment Information (All Registrants)

3 Months Ended

Mar. 31, 2018

Segment Reporting [Abstract]

Segment Information (All Registrants)

Operating segments for each of the Registrants are determined based on information used by the chief operating decision maker(s) (CODM) in deciding how to evaluate performance and allocate resources at each of the Registrants.

Exelon has twelve reportable segments, which include ComEd, PECO, BGE, PHI's three reportable segments consisting of Pepco, DPL, and ACE, and Generation’s six reportable segments consisting of the Mid-Atlantic, Midwest, New England, New York, ERCOT and all other power regions referred to collectively as “Other Power Regions”, which includes activities in the South, West and Canada. 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 and return on equity.

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 six 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, which includes portions of Illinois, Pennsylvania, Indiana, Ohio, Michigan, Kentucky and Tennessee, and the United States footprint of MISO, excluding MISO’s Southern Region, which covers all or most of North Dakota, South Dakota, Nebraska, Minnesota, Iowa, Wisconsin, the remaining parts of Illinois, Indiana, Michigan and Ohio not covered by PJM, and parts of Montana, Missouri and Kentucky.


•	New England represents the operations within ISO-NE covering the states of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont.


•	New York represents operations within ISO-NY, which covers the state of New York in its entirety.


•	ERCOT represents operations within Electric Reliability Council of Texas, covering most of the state of Texas.


•	Other Power Regions:

•

South represents operations in the FRCC, MISO’s Southern Region, and the remaining portions of the SERC not included within MISO or PJM, which includes all or most of Florida, Arkansas, Louisiana, Mississippi, Alabama, Georgia, Tennessee, North Carolina, South Carolina and parts of Missouri, Kentucky and Texas. Generation’s South region also includes operations in the SPP, covering Kansas, Oklahoma, most of Nebraska and parts of New Mexico, Texas, Louisiana, Missouri, Mississippi and Arkansas.


•	West represents operations in the WECC, which includes California ISO, and covers the states of California, Oregon, Washington, Arizona, Nevada, Utah, Idaho, Colorado and parts of New Mexico, Wyoming and South Dakota.


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

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

An analysis and reconciliation of the Registrants’ reportable segment information to the respective information in the consolidated financial statements for the three months ended March 31, 2018 and 2017 is as follows:

Three Months Ended March 31, 2018 and 2017



	Generation^(a)		ComEd		PECO		BGE		PHI		Other^(b)			Intersegment Eliminations			Exelon
Operating revenues^(c):
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
2017
Competitive businesses electric revenues	$	3,710	$	—	$	—	$	—	$	—	$	—		$	(328	)	$	3,382
Competitive businesses natural gas revenues	918		—		—		—		—		—			—			918
Competitive businesses other revenues	250		—		—		—		—		—			—			250
Rate-regulated electric revenues	—		1,298		590		667		1,097		—			(8		)	3,644
Rate-regulated natural gas revenues	—		—		206		284		66		—			(3		)	553
Shared service and other revenues	—		—		—		—		12		419			(431		)	—
Total operating revenues	4,878		1,298		796		951		1,175		419			(770		)	8,747
Shared service and other revenues
Intersegment revenues^(d):
2018	$	400	$	14	$	2	$	6	$	4	$	450		$	(876	)	$	—
2017	328		5		1		5		12		419			(770		)	—
Net income (loss):
2018	$	186	$	165	$	113	$	128	$	65	$	(21	)	$	—		$	636
2017	399		141		127		125		140		39			—			971
Total assets:
March 31, 2018	$	48,375	$	30,002	$	10,218	$	9,195	$	21,375	$	8,833		$	(10,980	)	$	117,018
December 31, 2017	48,457		29,726		10,170		9,104		21,247		8,618			(10,552		)	116,770

__________

(a)

Generation includes the six reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions. Intersegment revenues for Generation for the three months ended March 31, 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. For the three months ended March 31, 2017, intersegment revenues for Generation include revenue from sales to PECO of $45 million, sales to BGE of $134 million, sales to Pepco of $83 million, sales to DPL of $51 million and sales to ACE of $9 million in the Mid-Atlantic region, and sales to ComEd of $5 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 on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 18 — Supplemental Financial Information for total utility taxes for the three months ended March 31, 2018 and 2017.

(d)

PHI:



	Pepco		DPL		ACE		Other^(b)			Intersegment Eliminations			PHI
Operating revenues^(a):
Three Months Ended March 31, 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
Three Months Ended March 31, 2017
Rate-regulated electric revenues	$	530	$	296	$	275	$	—		$	(4	)	$	1,097
Rate-regulated natural gas revenues	—		66		—		—			—			66
Shared service and other revenues	—		—		—		12			—			12
Total operating revenues	530		362		275		12			(4		)	1,175
Intersegment revenues:
Three Months Ended March 31, 2018	$	2	$	2	$	1	$	112		$	(113	)	$	4
Three Months Ended March 31, 2017	1		2		1		13			(5		)	12
Net income (loss):
Three Months Ended March 31, 2018	$	31	$	31	$	7	$	(8	)	$	4		$	65
Three Months Ended March 31, 2017	58		57		28		(15		)	12			140
Total assets:
March 31, 2018	$	7,896	$	4,383	$	3,530	$	10,514		$	(4,948	)	$	21,375
December 31, 2017	7,832		4,357		3,445		10,600			(4,987		)	21,247

__________


(a)	Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 18 — Supplemental Financial Information for total utility taxes for the three months ended March 31, 2018 and 2017.


(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 three months ended March 31, 2018 and 2017. 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, 2018
	Revenues from external parties^(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 England	725		68			793		(1		)	792
New York	439		(29		)	410		(1		)	409
ERCOT	149		59			208		1			209
Other Power Regions	210		109			319		(31		)	288
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



	Three Months Ended March 31, 2017
	Revenues from external customers^(a)							Intersegment revenues			Total Revenues
	Contracts with customers		Other^(b)			Total		Intersegment revenues			Total Revenues
Mid-Atlantic	$	1,494	$	(65	)	$	1,429	$	(4	)	$	1,425
Midwest	980		71			1,051		2			1,053
New England	589		(40		)	549		(2		)	547
New York	303		(3		)	300		(3		)	297
ERCOT	168		24			192		(1		)	191
Other Power Regions	128		61			189		(5		)	184
Total Competitive Businesses Electric Revenues	3,662		48			3,710		(13		)	3,697
Competitive Businesses Natural Gas Revenues	768		150			918		12			930
Competitive Businesses Other Revenues^(c)	206		44			250		1			251
Total Generation Consolidated Operating Revenues	$	4,636	$	242		$	4,878	$	—		$	4,878

__________


(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 a $3 million decrease to revenues for the amortization of intangible assets and liabilities related to commodity contracts recorded at fair value for the three months ended March 31, 2017, unrealized mark-to-market losses of $98 million and gains of $44 million for the three months ended March 31, 2018 and 2017, respectively, and elimination of intersegment revenues.

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



	Three Months Ended March 31, 2018									Three Months Ended March 31, 2017
	RNF from external customers^(a)			Intersegment RNF			Total RNF			RNF from external customers^(a)		Intersegment RNF			Total RNF
Mid-Atlantic	$	836		$	14		$	850		$	755	$	18		$	773
Midwest	847			13			860			704		11			715
New England	122			(3		)	119			115		(4		)	111
New York	282			1			283			143		—			143
ERCOT	106			(70		)	36			94		(25		)	69
Other Power Regions	157			(40		)	117			108		(44		)	64
Total Revenues net of purchased power and fuel expense for Reportable Segments	2,350			(85		)	2,265			1,919		(44		)	1,875
Other^(b)	(131		)	85			(46		)	161		44			205
Total Generation Revenues net of purchased power and fuel expense	$	2,219		$	—		$	2,219		$	2,080	$	—		$	2,080

__________


(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 a $3 million decrease to RNF for the amortization of intangible assets and liabilities related to commodity contracts for the three months ended March 31, 2017, unrealized mark-to-market losses of $266 million and $49 million for the three months ended March 31, 2018 and 2017, respectively, accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 7 - Early Nuclear Plant Retirements of the Combined Notes to Consolidated Financial Statements of $15 million decrease to revenue net of purchased power and fuel expense for the three months ended March 31, 2018, and the elimination of intersegment revenue net of purchased power and fuel expense.

Electric and Gas Revenue by Customer Class (ComEd, PECO, BGE, PHI, PECO, DPL, ACE):



	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



	Three Months Ended March 31, 2017
Revenues from contracts with customers	ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Rate-regulated electric revenues
Residential	$	611	$	382	$	386	$	554	$	236	$	176	$	142
Small commercial & industrial	328		97		69		114		34		44		36
Large commercial & industrial	107		52		108		257		188		24		45
Public authorities & electric railroads	12		8		7		15		8		4		3
Other^(a)	218		48		68		126		48		38		43
Total rate-regulated electric revenues^(b)	$	1,276	$	587	$	638	$	1,066	$	514	$	286	$	269
Rate-regulated natural gas revenues
Residential	$	—	$	142	$	185	$	40	$	—	$	40	$	—
Small commercial & industrial	—		55		30		17		—		17		—
Large commercial & industrial	—		—		44		2		—		2		—
Transportation	—		6		—		5		—		5		—
Other^(c)	—		3		14		2		—		2		—
Total rate-regulated natural gas revenues^(d)	$	—	$	206	$	273	$	66	$	—	$	66	$	—
Total rate-regulated revenues from contracts with customers	$	1,276	$	793	$	911	$	1,132	$	514	$	352	$	269

Other revenues
Revenues from alternative revenue programs	14		—		35		30		15		9		6
Other rate-regulated electric revenues^(e)	8		3		4		2		1		1		—
Other rate-regulated natural gas revenues^(e)	—		—		1		—		—		—		—
Other revenues^(f)	—		—		—		11		—		—		—
Total other revenues	22		3		40		43		16		10		6
Total rate-regulated revenues for reportable segments	$	1,298	$	796	$	951	$	1,175	$	530	$	362	$	275

__________


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

(b)

Includes operating revenues from affiliates of $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, for the three months ended March 31, 2018 and $5 million, $1 million, $2 million, $1 million, $1 million, $2 million, and $1 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, for the three months ended March 31, 2017.


(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, for the three months ended March 31, 2018 and less than $1 million and $3 million at PECO and BGE, respectively, for the three months ended March 31, 2017.


(e)	Includes late payment charge revenues.


(f)	Includes operating revenues from affiliates of $11 million at PHI for the three months ended March 31, 2017.

Significant Accounting Policies (Policies)

3 Months Ended

Mar. 31, 2018

Accounting Policies [Abstract]

Business Description and Basis of Presentation [Text Block]

Description of Business (All Registrants)

Exelon is a utility services holding company engaged through its principal subsidiaries in the energy generation and energy distribution and transmission businesses.



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.	Six reportable segments: Mid-Atlantic, Midwest, New England, 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.

Earnings Per Share, Policy [Policy Text Block]

Reclassifications [Text Block]

Prior Period Adjustments and Reclassifications (All Registrants)

Beginning on January 1, 2018, Exelon adopted the following new accounting standards requiring reclassification or adjustments to previously reported information as follows:


•	Statement of Cash Flows: Classification of Restricted Cash. The Registrants applied the new guidance using the full retrospective method and, accordingly, have recasted the presentation of restricted cash in their Consolidated Statements of Cash Flows in the prior periods presented. See Note 18 — Supplemental Financial Information for further information.

•

Revenues [Policy Text Block]

Revenues (All Registrants)

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 further discussion on the NDT fund investments.

Significant Accounting Policies Revenue Initial Application Period Cumulative Effect Transition (Tables)

3 Months Ended

Mar. 31, 2018

Revenue, Initial Application Period Cumulative Effect Transition [Line Items]

Revenue from Contract with Customer [Text Block]



Three Months Ended March 31, 2017	Exelon			Generation			ComEd			PECO		BGE			PHI			Pepco			DPL			ACE
Operating Revenues - As reported
Competitive business revenues	$	4,560		$	—		$	—		$	—	$	—		$	—		$	—		$	—		$	—
Rate-regulated utility revenues	4,197			—			—			—		—			—			—			—			—
Operating revenues	—			4,558			—			—		—			—			—			—			—
Electric operating revenues	—			—			1,293			589		665			1,097			529			294			274
Natural gas operating revenues	—			—			—			206		281			66			—			66			—
Operating revenues from affiliates	—			330			5			1		5			12			1			2			1
Total operating revenues	$	8,757		$	4,888		$	1,298		$	796	$	951		$	1,175		$	530		$	362		$	275

Operating Revenues - Adjustments
Competitive business revenues	$	(10	)	$	—		$	—		$	—	$	—		$	—		$	—		$	—		$	—
Rate-regulated utility revenues	(79		)	—			—			—		—			—			—			—			—
Operating revenues	—			(10		)	—			—		—			—			—			—			—
Electric operating revenues	—			—			(14		)	—		(25		)	(30		)	(15		)	(9		)	(6		)
Natural gas operating revenues	—			—			—			—		(10		)	—			—			—			—
Revenues from alternative revenue programs	79			—			14			—		35			30			15			9			6
Operating revenues from affiliates	—			—			—			—		—			—			—			—			—
Total operating revenues	$	(10	)	$	(10	)	$	—		$	—	$	—		$	—		$	—		$	—		$	—

Operating Revenues - Retrospective application
Competitive business revenues	$	4,550		$	—		$	—		$	—	$	—		$	—		$	—		$	—		$	—
Rate-regulated utility revenues	4,118			—			—			—		—			—			—			—			—
Operating revenues	—			4,548			—			—		—			—			—			—			—
Electric operating revenues	—			—			1,279			589		640			1,067			514			285			268
Natural gas operating revenues	—			—			—			206		271			66			—			66			—
Revenues from alternative revenue programs	79			—			14			—		35			30			15			9			6
Operating revenues from affiliates	—			330			5			1		5			12			1			2			1
Total operating revenues	$	8,747		$	4,878		$	1,298		$	796	$	951		$	1,175		$	530		$	362		$	275

Revenue from Contracts with Customers (All Registrants)

Competitive Power Sales (Exelon and Generation)

Competitive Natural Gas Sales (Exelon and Generation)

Other Competitive Products and Services (Exelon and Generation)

Regulated Electric and Gas Tariff Sales (Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE)

Regulated Transmission Services (Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE)

Costs to Obtain or Fulfill a Contract with a Customer (Exelon and Generation)

Contract Balances (All Registrants)

Contract Assets



Contract Assets	Exelon and Generation
Balance as of January 1, 2018	$	283
Increases as a result of changes in the estimate of the stage of completion	28
Amounts reclassified to receivables	(9		)
Balance at March 31, 2018	$	302

The Utility Registrants do not have any contract assets.

Contract Liabilities



Contract Liabilities	Exelon and Generation
Balance as of January 1, 2018	$	35
Increases as a result of additional cash received or due	227
Amounts recognized into revenues	(216		)
Balance at March 31, 2018	$	46

Transaction Price Allocated to Remaining Performance Obligations (All Registrants)



	2019		2020		2021		2022		2023 and thereafter		Total
Exelon	$	544	$	264	$	104	$	46	$	128	$	1,086
Generation	544		264		104		46		128		$	1,086

Revenue Disaggregation (All Registrants)

Variable Interest Entities (Tables)

3 Months Ended

Mar. 31, 2018

Variable Interest Entity [Abstract]

Schedule of Variable Interest Entities



	March 31, 2018								December 31, 2017
	Exelon^(a)		Generation		PHI^(a)		ACE		Exelon^(a)		Generation		PHI^(a)		ACE
Current assets	$	823	$	812	$	11	$	7	$	662	$	652	$	10	$	6
Noncurrent assets	9,279		9,251		28		20		9,317		9,286		31		23
Total assets	$	10,102	$	10,063	$	39	$	27	$	9,979	$	9,938	$	41	$	29
Current liabilities	$	269	$	236	$	33	$	29	$	308	$	272	$	36	$	32
Noncurrent liabilities	3,292		3,230		62		54		3,316		3,250		66		58
Total liabilities	$	3,561	$	3,466	$	95	$	83	$	3,624	$	3,522	$	102	$	90

_________


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

As of March 31, 2018 and December 31, 2017, these assets and liabilities primarily consisted of the following:



	March 31, 2018								December 31, 2017
	Exelon ^(a)		Generation		PHI ^(a)		ACE		Exelon^(a)		Generation		PHI^(a)		ACE
Cash and cash equivalents	$	280	$	280	$	—	$	—	$	126	$	126	$	—	$	—
Restricted cash	73		66		7		7		64		58		6		6
Accounts receivable, net
Customer	154		154		—		—		170		170		—		—
Other	29		29		—		—		25		25		—		—
Inventory
Materials and supplies	202		202		—		—		205		205		—		—
Other current assets	55		51		4		—		45		41		4		—
Total current assets	793		782		11		7		635		625		10		6
Property, plant and equipment, net	6,181		6,181		—		—		6,186		6,186		—		—
Nuclear decommissioning trust funds	2,483		2,483		—		—		2,502		2,502		—		—
Other noncurrent assets	270		242		28		20		274		243		31		23
Total noncurrent assets	8,934		8,906		28		20		8,962		8,931		31		23
Total assets	$	9,727	$	9,688	$	39	$	27	$	9,597	$	9,556	$	41	$	29
Long-term debt due within one year	$	102	$	70	$	32	$	28	$	102	$	67	$	35	$	31
Accounts payable	93		93		—		—		114		114		—		—
Accrued expenses	52		51		1		1		67		66		1		1
Unamortized energy contract liabilities	17		17		—		—		18		18		—		—
Other current liabilities	5		5		—		—		7		7		—		—
Total current liabilities	269		236		33		29		308		272		36		32
Long-term debt	1,125		1,063		62		54		1,154		1,088		66		58
Asset retirement obligations	2,062		2,062		—		—		2,035		2,035		—		—
Unamortized energy contract liabilities	1		1		—		—		5		5		—		—
Other noncurrent liabilities	99		99		—		—		116		116		—		—
Total noncurrent liabilities	3,287		3,225		62		54		3,310		3,244		66		58
Total liabilities	$	3,556	$	3,461	$	95	$	83	$	3,618	$	3,516	$	102	$	90

_________


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

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



March 31, 2018	Commercial Agreement VIEs		Equity Investment VIEs		Total
Total assets^(a)	$	626	$	501	$	1,127
Total liabilities^(a)	37		225		262
Exelon's ownership interest in VIE^(a)	—		246		246
Other ownership interests in VIE^(a)	588		30		618
Registrants’ maximum exposure to loss:
Carrying amount of equity method investments	—		246		246
Contract intangible asset	8		—		8
Net assets pledged for Zion Station decommissioning^(b)	2		—		2



December 31, 2017	Commercial Agreement VIEs		Equity Investment VIEs		Total
Total assets^(a)	$	625	$	509	$	1,134
Total liabilities^(a)	37		228		265
Exelon's ownership interest in VIE^(a)	—		251		251
Other ownership interests in VIE^(a)	588		30		618
Registrants’ maximum exposure to loss:
Carrying amount of equity method investments	—		251		251
Contract intangible asset	8		—		8
Net assets pledged for Zion Station decommissioning^(b)	2		—		2

_________


(a)	These items represent amounts on the unconsolidated VIE balance sheets, not on Exelon’s or Generation’s Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs.

(b)

- 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

Mergers, Acquisitions and Dispositions (Tables)

3 Months Ended

Mar. 31, 2018

Business Combinations [Abstract]

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]

The following table summarizes the acquisition-date fair value of the consideration transferred and the assets and liabilities assumed for the FitzPatrick acquisition by Generation:



Cash paid for purchase price	$	110
Cash paid for net cost reimbursement	125
Nuclear fuel transfer	54
Total consideration transferred	$	289

Identifiable assets acquired and liabilities assumed
Current assets	$	60
Property, plant and equipment	298
Nuclear decommissioning trust funds	807
Other assets^(a)	114
Total assets	$	1,279

Current liabilities	$	6
Nuclear decommissioning ARO	444
Pension and OPEB obligations	33
Deferred income taxes	149
Spent nuclear fuel obligation	110
Other liabilities	15
Total liabilities	$	757
Total net identifiable assets, at fair value	$	522

Bargain purchase gain (after-tax)	$	233

_________


(a)	Includes a $110 million asset associated with a contractual right to reimbursement from the New York Power Authority (NYPA), a prior owner of FitzPatrick, associated with the DOE one-time fee obligation. See Note 23-Commitments and Contingencies of the Exelon 2017 Form 10-K for additional background regarding SNF obligations to the DOE.

Revenue from Contracts with Customers Revenue from Contracts with Customers (Tables)

3 Months Ended

Mar. 31, 2018

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 reflected on Exelon's and Generation's Consolidated Balance Sheets from January 1, 2018 to March 31, 2018:



Contract Assets	Exelon and Generation
Balance as of January 1, 2018	$	283
Increases as a result of changes in the estimate of the stage of completion	28
Amounts reclassified to receivables	(9		)
Balance at March 31, 2018	$	302

The following table provides a rollforward of the contract liabilities reflected on Exelon's and Generation's Consolidated Balance Sheet from January 1, 2018 to March 31, 2018:



Contract Liabilities	Exelon and Generation
Balance as of January 1, 2018	$	35
Increases as a result of additional cash received or due	227
Amounts recognized into revenues	(216		)
Balance at March 31, 2018	$	46

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



	2019		2020		2021		2022		2023 and thereafter		Total
Exelon	$	544	$	264	$	104	$	46	$	128	$	1,086
Generation	544		264		104		46		128		$	1,086

Regulatory Matters (Tables)

3 Months Ended

Mar. 31, 2018

Regulated Operations [Abstract]

Public Utilities General Disclosures [Table Text Block]



	Exelon		ComEd^(a)		PECO		BGE^(b)		PHI		Pepco^(c)		DPL^(c)		ACE
March 31, 2018	$	69	$	7	$	—	$	52	$	10	$	6	$	4	$	—

	Exelon		ComEd^(a)		PECO		BGE^(b)		PHI		Pepco^(c)		DPL^(c)		ACE
December 31, 2017	$	69	$	6	$	—	$	53	$	10	$	6	$	4	$	—

_________


(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.

Schedule of Regulatory Assets

he following tables provide information about the regulatory assets and liabilities of Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE as of March 31, 2018 and December 31, 2017. For additional information on the specific regulatory assets and liabilities, refer to Note 3 — Regulatory Matters of the Exelon 2017 Form 10-K.



March 31, 2018	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory assets
Pension and other postretirement benefits^(a)	$	3,844	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Deferred income taxes	336		—		327		—		9		9		—		—
AMI programs^(c)	621		151		33		208		229		154		75		—
Electric distribution formula rate^(d)	256		256		—		—		—		—		—		—
Energy efficiency costs	220		220		—		—		—		—		—		—
Debt costs	108		36		1		11		71		15		7		5
Fair value of long-term debt	745		—		—		—		607		—		—		—
Fair value of PHI's unamortized energy contracts	701		—		—		—		701		—		—		—
Asset retirement obligations	111		75		22		14		—		—		—		—
MGP remediation costs	284		263		21		—		—		—		—		—
Under-recovered uncollectible accounts	69		69		—		—		—		—		—		—
Renewable energy	268		267		—		—		1		—		—		1
Energy and transmission programs^{(e)(f)(g)(h)(i)(j)}	117		8		43		21		45		7		14		24
Deferred storm costs	46		—		—		—		46		12		5		29
Energy efficiency and demand response programs	559		—		1		269		289		212		77		—
Merger integration costs^(k)(l)(m)	46		—		—		5		41		20		11		10
Under-recovered revenue decoupling⁽ⁿ⁾	44		—		—		6		38		38		—		—
COPCO acquisition adjustment	5		—		—		—		5		—		5		—
Workers compensation and long-term disability costs	33		—		—		—		33		33		—		—
Vacation accrual	27		—		14		—		13		—		8		5
Securitized stranded costs	71		—		—		—		71		—		—		71
CAP arrearage	12		—		12		—		—		—		—		—
Removal costs	535		—		—		—		535		150		94		292
DC PLUG charge	187		—		—		—		187		187		—		—
Other	63		6		12		6		39		26		9		4
Total regulatory assets	9,308		1,351		486		540		2,960		863		305		441
Less: current portion	1,245		226		78		149		507		207		63		64
Total noncurrent regulatory assets	$	8,063	$	1,125	$	408	$	391	$	2,453	$	656	$	242	$	377



March 31, 2018	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory liabilities
Other postretirement benefits	$	26	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Deferred income taxes^(b)	5,189		2,458		—		1,011		1,720		804		506		410
Nuclear decommissioning	2,969		2,464		505		—		—		—		—		—
Removal costs	1,570		1,348		—		92		130		20		110		—
Deferred rent	35		—		—		—		35		—		—		—
Energy efficiency and demand response programs	16		4		11		—		1		—		—		1
DLC program costs	7		—		7		—		—		—		—		—
Electric distribution tax repairs	27		—		27		—		—		—		—		—
Gas distribution tax repairs	8		—		8		—		—		—		—		—
Energy and transmission programs^{(e)(f)(g)(h)(i)(j)}	153		53		56		22		22		4		6		12
Over-recovered revenue decoupling⁽ⁿ⁾	14		—		—		11		3		—		3		—
Renewable portfolio standards costs	81		81		—		—		—		—		—		—
Zero emission credit costs	8		8		—		—		—		—		—		—
Over-recovered uncollectible accounts	4		—		—		—		4		—		—		4
Merger integration costs^(l)	1		—		—		—		1		—		1		—
TCJA income tax benefit over-recoveries^(o)	54		—		10		17		27		14		7		6
Other	84		8		22		32		22		3		13		4
Total regulatory liabilities	10,246		6,424		646		1,185		1,965		845		646		437
Less: current portion	522		212		117		102		77		7		48		21
Total noncurrent regulatory liabilities	$	9,724	$	6,212	$	529	$	1,083	$	1,888	$	838	$	598	$	416



December 31, 2017	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory assets
Pension and other postretirement benefits^(a)	$	3,848	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Deferred income taxes	306		—		297		—		9		9		—		—
AMI programs^(c)	640		155		36		214		235		158		77		—
Electric distribution formula rate^(d)	244		244		—		—		—		—		—		—
Energy efficiency costs	166		166		—		—		—		—		—		—
Debt costs	116		37		1		11		73		15		8		5
Fair value of long-term debt	758		—		—		—		619		—		—		—
Fair value of PHI's unamortized energy contracts	750		—		—		—		750		—		—		—
Asset retirement obligations	109		73		22		14		—		—		—		—
MGP remediation costs	295		273		22		—		—		—		—		—
Under-recovered uncollectible accounts	61		61		—		—		—		—		—		—
Renewable energy	258		256		—		—		2		—		1		1
Energy and transmission programs^{(e)(g)(h)(i)(j)}	82		6		1		23		52		11		15		26
Deferred storm costs	27		—		—		—		27		7		5		15
Energy efficiency and demand response programs	596		—		1		285		310		229		81		—
Merger integration costs^(k)(l)(m)	45		—		—		6		39		20		10		9
Under-recovered revenue decoupling⁽ⁿ⁾	55		—		—		14		41		38		3		—
COPCO acquisition adjustment	5		—		—		—		5		—		5		—
Workers compensation and long-term disability costs	35		—		—		—		35		35		—		—
Vacation accrual	19		—		6		—		13		—		8		5
Securitized stranded costs	79		—		—		—		79		—		—		79
CAP arrearage	8		—		8		—		—		—		—		—
Removal costs	529		—		—		—		529		150		93		286
DC PLUG charge	190		—		—		—		190		190		—		—
Other	67		8		16		4		39		29		8		4
Total regulatory assets	9,288		1,279		410		571		3,047		891		314		430
Less: current portion	1,267		225		29		174		554		213		69		71
Total noncurrent regulatory assets	$	8,021	$	1,054	$	381	$	397	$	2,493	$	678	$	245	$	359



December 31, 2017	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory liabilities
Other postretirement benefits	$	30	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Deferred income taxes^(b)	5,241		2,479		—		1,032		1,730		809		510		411
Nuclear decommissioning	3,064		2,528		536		—		—		—		—		—
Removal costs	1,573		1,338		—		105		130		20		110		—
Deferred rent	36		—		—		—		36		—		—		—
Energy efficiency and demand response programs	23		4		19		—		—		—		—		—
DLC program costs	7		—		7		—		—		—		—		—
Electric distribution tax repairs	35		—		35		—		—		—		—		—
Gas distribution tax repairs	9		—		9		—		—		—		—		—
Energy and transmission programs^(e)(f)(i)(j)	111		47		60		—		4		—		1		3
Renewable portfolio standard costs	63		63		—		—		—		—		—		—
Zero emission credit costs	112		112		—		—		—		—		—		—
Over-recovered uncollectible accounts	2		—		—		—		2		—		—		2
Other	82		6		24		26		26		3		14		6
Total regulatory liabilities	10,388		6,577		690		1,163		1,928		832		635		422
Less: current portion	523		249		141		62		56		3		42		11
Total noncurrent regulatory liabilities	$	9,865	$	6,328	$	549	$	1,101	$	1,872	$	829	$	593	$	411

_________

(a)

(b)

(c)

(d)

(e)

(f)

(g)

(h)

(i)

(j)


(k)	As of March 31, 2018 and December 31, 2017, Pepco’s regulatory asset of $20 million represents previously incurred PHI integration costs, including $11 million authorized for recovery in Maryland and $9 million expected to be recovered in the District of Columbia service territory.

(l)


(m)	As of March 31, 2018 and December 31, 2017, ACE’s regulatory asset of $10 million and $9 million, respectively, represents previously incurred PHI integration costs expected to be recovered in the New Jersey service territory.

(n)

Schedule of Regulatory Liabilities



March 31, 2018	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory assets
Pension and other postretirement benefits^(a)	$	3,844	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Deferred income taxes	336		—		327		—		9		9		—		—
AMI programs^(c)	621		151		33		208		229		154		75		—
Electric distribution formula rate^(d)	256		256		—		—		—		—		—		—
Energy efficiency costs	220		220		—		—		—		—		—		—
Debt costs	108		36		1		11		71		15		7		5
Fair value of long-term debt	745		—		—		—		607		—		—		—
Fair value of PHI's unamortized energy contracts	701		—		—		—		701		—		—		—
Asset retirement obligations	111		75		22		14		—		—		—		—
MGP remediation costs	284		263		21		—		—		—		—		—
Under-recovered uncollectible accounts	69		69		—		—		—		—		—		—
Renewable energy	268		267		—		—		1		—		—		1
Energy and transmission programs^{(e)(f)(g)(h)(i)(j)}	117		8		43		21		45		7		14		24
Deferred storm costs	46		—		—		—		46		12		5		29
Energy efficiency and demand response programs	559		—		1		269		289		212		77		—
Merger integration costs^(k)(l)(m)	46		—		—		5		41		20		11		10
Under-recovered revenue decoupling⁽ⁿ⁾	44		—		—		6		38		38		—		—
COPCO acquisition adjustment	5		—		—		—		5		—		5		—
Workers compensation and long-term disability costs	33		—		—		—		33		33		—		—
Vacation accrual	27		—		14		—		13		—		8		5
Securitized stranded costs	71		—		—		—		71		—		—		71
CAP arrearage	12		—		12		—		—		—		—		—
Removal costs	535		—		—		—		535		150		94		292
DC PLUG charge	187		—		—		—		187		187		—		—
Other	63		6		12		6		39		26		9		4
Total regulatory assets	9,308		1,351		486		540		2,960		863		305		441
Less: current portion	1,245		226		78		149		507		207		63		64
Total noncurrent regulatory assets	$	8,063	$	1,125	$	408	$	391	$	2,453	$	656	$	242	$	377



March 31, 2018	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory liabilities
Other postretirement benefits	$	26	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Deferred income taxes^(b)	5,189		2,458		—		1,011		1,720		804		506		410
Nuclear decommissioning	2,969		2,464		505		—		—		—		—		—
Removal costs	1,570		1,348		—		92		130		20		110		—
Deferred rent	35		—		—		—		35		—		—		—
Energy efficiency and demand response programs	16		4		11		—		1		—		—		1
DLC program costs	7		—		7		—		—		—		—		—
Electric distribution tax repairs	27		—		27		—		—		—		—		—
Gas distribution tax repairs	8		—		8		—		—		—		—		—
Energy and transmission programs^{(e)(f)(g)(h)(i)(j)}	153		53		56		22		22		4		6		12
Over-recovered revenue decoupling⁽ⁿ⁾	14		—		—		11		3		—		3		—
Renewable portfolio standards costs	81		81		—		—		—		—		—		—
Zero emission credit costs	8		8		—		—		—		—		—		—
Over-recovered uncollectible accounts	4		—		—		—		4		—		—		4
Merger integration costs^(l)	1		—		—		—		1		—		1		—
TCJA income tax benefit over-recoveries^(o)	54		—		10		17		27		14		7		6
Other	84		8		22		32		22		3		13		4
Total regulatory liabilities	10,246		6,424		646		1,185		1,965		845		646		437
Less: current portion	522		212		117		102		77		7		48		21
Total noncurrent regulatory liabilities	$	9,724	$	6,212	$	529	$	1,083	$	1,888	$	838	$	598	$	416



December 31, 2017	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory assets
Pension and other postretirement benefits^(a)	$	3,848	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Deferred income taxes	306		—		297		—		9		9		—		—
AMI programs^(c)	640		155		36		214		235		158		77		—
Electric distribution formula rate^(d)	244		244		—		—		—		—		—		—
Energy efficiency costs	166		166		—		—		—		—		—		—
Debt costs	116		37		1		11		73		15		8		5
Fair value of long-term debt	758		—		—		—		619		—		—		—
Fair value of PHI's unamortized energy contracts	750		—		—		—		750		—		—		—
Asset retirement obligations	109		73		22		14		—		—		—		—
MGP remediation costs	295		273		22		—		—		—		—		—
Under-recovered uncollectible accounts	61		61		—		—		—		—		—		—
Renewable energy	258		256		—		—		2		—		1		1
Energy and transmission programs^{(e)(g)(h)(i)(j)}	82		6		1		23		52		11		15		26
Deferred storm costs	27		—		—		—		27		7		5		15
Energy efficiency and demand response programs	596		—		1		285		310		229		81		—
Merger integration costs^(k)(l)(m)	45		—		—		6		39		20		10		9
Under-recovered revenue decoupling⁽ⁿ⁾	55		—		—		14		41		38		3		—
COPCO acquisition adjustment	5		—		—		—		5		—		5		—
Workers compensation and long-term disability costs	35		—		—		—		35		35		—		—
Vacation accrual	19		—		6		—		13		—		8		5
Securitized stranded costs	79		—		—		—		79		—		—		79
CAP arrearage	8		—		8		—		—		—		—		—
Removal costs	529		—		—		—		529		150		93		286
DC PLUG charge	190		—		—		—		190		190		—		—
Other	67		8		16		4		39		29		8		4
Total regulatory assets	9,288		1,279		410		571		3,047		891		314		430
Less: current portion	1,267		225		29		174		554		213		69		71
Total noncurrent regulatory assets	$	8,021	$	1,054	$	381	$	397	$	2,493	$	678	$	245	$	359



December 31, 2017	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory liabilities
Other postretirement benefits	$	30	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Deferred income taxes^(b)	5,241		2,479		—		1,032		1,730		809		510		411
Nuclear decommissioning	3,064		2,528		536		—		—		—		—		—
Removal costs	1,573		1,338		—		105		130		20		110		—
Deferred rent	36		—		—		—		36		—		—		—
Energy efficiency and demand response programs	23		4		19		—		—		—		—		—
DLC program costs	7		—		7		—		—		—		—		—
Electric distribution tax repairs	35		—		35		—		—		—		—		—
Gas distribution tax repairs	9		—		9		—		—		—		—		—
Energy and transmission programs^(e)(f)(i)(j)	111		47		60		—		4		—		1		3
Renewable portfolio standard costs	63		63		—		—		—		—		—		—
Zero emission credit costs	112		112		—		—		—		—		—		—
Over-recovered uncollectible accounts	2		—		—		—		2		—		—		2
Other	82		6		24		26		26		3		14		6
Total regulatory liabilities	10,388		6,577		690		1,163		1,928		832		635		422
Less: current portion	523		249		141		62		56		3		42		11
Total noncurrent regulatory liabilities	$	9,865	$	6,328	$	549	$	1,101	$	1,872	$	829	$	593	$	411

_________

(a)

(b)

(c)

(d)

(e)

(f)

(g)

(h)

(i)

(j)


(k)	As of March 31, 2018 and December 31, 2017, Pepco’s regulatory asset of $20 million represents previously incurred PHI integration costs, including $11 million authorized for recovery in Maryland and $9 million expected to be recovered in the District of Columbia service territory.

(l)


(m)	As of March 31, 2018 and December 31, 2017, ACE’s regulatory asset of $10 million and $9 million, respectively, represents previously incurred PHI integration costs expected to be recovered in the New Jersey service territory.

(n)

Purchase Of Receivables

The following tables provide information about the purchased receivables of those companies as of March 31, 2018 and December 31, 2017.



As of March 31, 2018	Exelon			ComEd			PECO			BGE			PHI			Pepco			DPL			ACE
Purchased receivables	$	317		$	88		$	73		$	64		$	92		$	55		$	17		$	20
Allowance for uncollectible accounts^(a)	(35		)	(16		)	(6		)	(4		)	(9		)	(5		)	(1		)	(3		)
Purchased receivables, net	$	282		$	72		$	67		$	60		$	83		$	50		$	16		$	17



As of December 31, 2017	Exelon			ComEd			PECO			BGE			PHI			Pepco			DPL			ACE
Purchased receivables	$	298		$	87		$	70		$	58		$	83		$	56		$	9		$	18
Allowance for uncollectible accounts^(a)	(31		)	(14		)	(5		)	(3		)	(9		)	(5		)	(1		)	(3		)
Purchased receivables, net	$	267		$	73		$	65		$	55		$	74		$	51		$	8		$	15

_________


(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 its Purchase of Receivables with Consolidated Billing tariff.

Early Nuclear Plant Retirements Early Nuclear Plant Retirements (Tables)

3 Months Ended

Mar. 31, 2018

Property, Plant and Equipment [Abstract]

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

Exelon's and Generation's 2017 results included a net incremental $339 million of total pre-tax expense associated with the early retirement decision for TMI, as summarized in the table below.



Income statement expense (pre-tax)	Q2 2017		Q3 2017		Q4 2017		YTD 2017
Depreciation and amortization^(a)
Accelerated depreciation^(b)	$	35	$	106	$	109	$	250
Accelerated Nuclear Fuel amortization	2		6		4		12
Operating and maintenance^(c)	71		5		1		77
Total	$	108	$	117	$	114	$	339

_________


(a)	Reflects incremental charges for TMI including incremental accelerated depreciation and amortization from May 30, 2017 through December 31, 2017.


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


(c)	Primarily includes materials and supplies inventory reserve adjustments, employee related costs and CWIP impairments.



Income statement expense (pre-tax)	Q1 2018
Depreciation and amortization^(a)
Accelerated depreciation^(b)	$	137
Accelerated nuclear fuel amortization	15
Operating and maintenance^(c)	26
Total	$	178

_________


(a)	Reflects incremental accelerated depreciation and amortization for TMI for the quarter ended March 31, 2018, and for Oyster Creek from February 2, 2018 through March 31, 2018.


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


(c)	Primarily includes materials and supplies inventory reserve adjustments, employee related costs and CWIP impairments.

The following table provides the balance sheet amounts as of March 31, 2018 for Generation’s significant assets and liabilities associated with the Mystic Generating Station assets.



	March 31, 2018
Asset Balances
Materials and supplies inventory	$	26
Fuel inventory	18
Completed plant, net	896
Construction work in progress	4
Prepaid expense^(a)	9
Liability Balances
Asset retirement obligation	(5		)
Accrued expense^(a)	(2		)

In 2017, PSEG made public similar financial challenges facing its New Jersey nuclear plants including Salem, of which Generation owns a 42.59% ownersh

Fair Value of Financial Assets and Liabilities (Tables)

3 Months Ended

Mar. 31, 2018

Fair value of financial liabilities recorded at the carrying amount

Exelon



	March 31, 2018
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities^(a)	$	1,654	$	—	$	1,654	$	—	$	1,654
Long-term debt (including amounts due within one year)^(b)(c)	34,108		—		33,091		1,893		34,984
Long-term debt to financing trusts^(d)	389		—		—		421		421
SNF obligation	1,151		—		922		—		922



	December 31, 2017
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities^(a)	$	929	$	—	$	929	$	—	$	929
Long-term debt (including amounts due within one year)^(b)(c)	34,264		—		34,735		1,970		36,705
Long-term debt to financing trusts^(d)	389		—		—		431		431
SNF obligation	1,147		—		936		—		936

Generation



	March 31, 2018
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities^(a)	$	166	$	—	$	166	$	—	$	166
Long-term debt (including amounts due within one year)^(b)(c)	8,965		—		7,585		1,610		9,195
SNF obligation	1,151		—		922		—		922



	December 31, 2017
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities^(a)	$	2	$	—	$	2	$	—	$	2
Long-term debt (including amounts due within one year)^(b)(c)	8,990		—		7,839		1,673		9,512
SNF obligation	1,147		—		936		—		936

ComEd



	March 31, 2018
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities^(a)	$	317	$	—	$	317	$	—	$	317
Long-term debt (including amounts due within one year)^(b)(c)	7,694		—		8,061		—		8,061
Long-term debt to financing trusts^(d)	205		—		—		222		222



	December 31, 2017
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year)^(b)(c)	$	7,601	$	—	$	8,418	$	—	$	8,418
Long-term debt to financing trusts^(d)	205		—		—		227		227

PECO



	March 31, 2018
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities^(a)	$	220	$	—	$	220	$	—	$	220
Long-term debt (including amounts due within one year)^(b)(c)	2,723		—		2,870		—		2,870
Long-term debt to financing trusts^(d)	184		—		—		199		199



	December 31, 2017
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year)^(b)(c)	$	2,903	$	—	$	3,194	$	—	$	3,194
Long-term debt to financing trusts^(d)	184		—		—		204		204

BGE



	March 31, 2018
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities^(a)	$	45	$	—	$	45	$	—	$	45
Long-term debt (including amounts due within one year)^(b)(c)	$	2,578	$	—	$	2,689	$	—	$	2,689



	December 31, 2017
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities^(a)	$	77	$	—	$	77	$	—	$	77
Long-term debt (including amounts due within one year)^(b)(c)	2,577		—		2,825		—		2,825

PHI



	March 31, 2018
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities^(a)	$	407	$	—	$	407	$	—	$	407
Long-term debt (including amounts due within one year)^(b)(c)	5,849		—		5,423		283		5,706



	December 31, 2017
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities^(a)	$	350	$	—	$	350	$	—	$	350
Long-term debt (including amounts due within one year)^(b)(c)	5,874		—		5,722		297		6,019

Pepco



	March 31, 2018
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities^(a)	$	60	$	—	$	60	$	—	$	60
Long-term debt (including amounts due within one year)^(b)(c)	2,540		—		2,933		9		2,942



	December 31, 2017
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities^(a)	$	26	$	—	$	26	$	—	$	26
Long-term debt (including amounts due within one year)^(b)(c)	2,540		—		3,114		9		3,123

DPL



	March 31, 2018
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities^(a)	$	211	$	—	$	211	$	—	$	211
Long-term debt (including amounts due within one year)^(b)(c)	1,296		—		1,320		—		1,320



	December 31, 2017
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities^(a)	$	216	$	—	$	216	$	—	$	216
Long-term debt (including amounts due within one year)^(b)(c)	1,300		—		1,393		—		1,393

ACE



	March 31, 2018
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities^(a)	$	136	$	—	$	136	$	—	$	136
Long-term debt (including amounts due within one year)^(b)(c)	1,114		—		916		274		1,190



	December 31, 2017
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities^(a)	$	108	$	—	$	108	$	—	$	108
Long-term debt (including amounts due within one year)^(b)(c)	1,121		—		949		288		1,237

_________


(a)	Level 1 securities consist of dividends payable (included in other current liabilities). Level 2 securities consist of short term borrowings.

(b)


(c)	Level 2 securities consist of fixed-rate taxable debt securities, fixed-rate tax-exempt debt, variable rate tax-exempt debt and variable rate non-recourse debt. Level 3 securities consist of fixed-rate private placement taxable debt securities, fixed rate nonrecourse debt and government-backed fixed rate non-recourse debt.


(d)	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, 2018

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

PHI, Pepco, DPL and ACE




	As of March 31, 2018										As of December 31, 2017
PHI	Level 1		Level 2			Level 3		Total			Level 1			Level 2			Level 3		Total
Assets
Cash equivalents^(a)	$	67	$	—		$	—	$	67		$	83		$	—		$	—	$	83
Rabbi trust investments
Cash equivalents	72		—			—		72			72			—			—		72
Fixed income	—		10			—		10			—			12			—		12
Life insurance contracts	—		23			23		46			—			23			22		45
Rabbi trust investments subtotal^(b)	72		33			23		128			72			35			22		129
Total assets	139		33			23		195			155			35			22		212
Liabilities
Deferred compensation obligation	—		(23		)	—		(23		)	—			(25		)	—		(25		)
Mark-to-market derivative liabilities^(c)	—		—			—		—			(1		)	—			—		(1		)
Effect of netting and allocation of collateral	—		—			—		—			1			—			—		1
Mark-to-market derivative liabilities subtotal	—		—			—		—			—			—			—		—
Total liabilities	—		(23		)	—		(23		)	—			(25		)	—		(25		)
Total net assets	$	139	$	10		$	23	$	172		$	155		$	10		$	22	$	187



	Pepco										DPL										ACE
As of March 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)	$	33	$	—		$	—	$	33		$	—	$	—		$	—	$	—		$	27	$	—	$	—	$	27
Rabbi trust investments
Cash equivalents	44		—			—		44			—		—			—		—			—		—		—		—
Fixed income	—		10			—		10			—		—			—		—			—		—		—		—
Life insurance contracts	—		23			23		46			—		—			—		—			—		—		—		—
Rabbi trust investments subtotal^(b)	44		33			23		100			—		—			—		—			—		—		—		—
Total assets	77		33			23		133			—		—			—		—			27		—		—		27
Liabilities
Deferred compensation obligation	—		(4		)	—		(4		)	—		(1		)	—		(1		)	—		—		—		—
Total liabilities	—		(4		)	—		(4		)	—		(1		)	—		(1		)	—		—		—		—
Total net assets (liabilities)	$	77	$	29		$	23	$	129		$	—	$	(1	)	$	—	$	(1	)	$	27	$	—	$	—	$	27



	Pepco										DPL											ACE
As of December 31, 2017	Level 1		Level 2			Level 3		Total			Level 1			Level 2			Level 3		Total			Level 1		Level 2		Level 3		Total
Assets
Cash equivalents^(a)	$	36	$	—		$	—	$	36		$	—		$	—		$	—	$	—		$	29	$	—	$	—	$	29
Rabbi trust investments
Cash equivalents	44		—			—		44			—			—			—		—			—		—		—		—
Fixed income	—		12			—		12			—			—			—		—			—		—		—		—
Life insurance contracts	—		23			22		45			—			—			—		—			—		—		—		—
Rabbi trust investments subtotal^(b)	44		35			22		101			—			—			—		—			—		—		—		—
Total assets	80		35			22		137			—			—			—		—			29		—		—		29
Liabilities
Deferred compensation obligation	—		(4		)	—		(4		)	—			(1		)	—		(1		)	—		—		—		—
Mark-to-market derivative liabilities^(c)	—		—			—		—			(1		)	—			—		(1		)	—		—		—		—
Effect of netting and allocation of collateral	—		—			—		—			1			—			—		1			—		—		—		—
Mark-to-market derivative liabilities subtotal	—		—			—		—			—			—			—		—			—		—		—		—
Total liabilities	—		(4		)	—		(4		)	—			(1		)	—		(1		)	—		—		—		—
Total net assets (liabilities)	$	80	$	31		$	22	$	133		$	—		$	(1	)	$	—	$	(1	)	$	29	$	—	$	—	$	29

_________

(a)


(b)	The amount of unrealized gains/(losses) at PHI, Pepco, DPL and ACE totaled less than $1 million for the three months ended March 31, 2018 and March 31, 2017.


(c)	Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC.



	Generation					Exelon
As of March 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)	343	—	—	—	343	517	—	—	—	517
NDT fund investments
Cash equivalents^(b)	222	105	—	—	327	222	105	—	—	327
Equities	4,002	983	—	2,119	7,104	4,002	983	—	2,119	7,104
Fixed income
Corporate debt	—	1,583	240	—	1,823	—	1,583	240	—	1,823
U.S. Treasury and agencies	1,869	88	—	—	1,957	1,869	88	—	—	1,957
Foreign governments	—	86	—	—	86	—	86	—	—	86
State and municipal debt	—	254	—	—	254	—	254	—	—	254
Other^(c)	—	39	—	532	571	—	39	—	532	571
Fixed income subtotal	1,869	2,050	240	532	4,691	1,869	2,050	240	532	4,691
Middle market lending	—	—	369	127	496	—	—	369	127	496
Private equity	—	—	—	253	253	—	—	—	253	253
Real estate	—	—	—	488	488	—	—	—	488	488
NDT fund investments subtotal^(d)	6,093	3,138	609	3,519	13,359	6,093	3,138	609	3,519	13,359
Pledged assets for Zion Station decommissioning
Cash equivalents	13	—	—	—	13	13	—	—	—	13



	Generation									Exelon
As of March 31, 2018	Level 1		Level 2		Level 3		Not subject to leveling	Total		Level 1		Level 2		Level 3		Not subject to leveling	Total
Middle market lending	—		—		16		—	16		—		—		16		—	16
Pledged assets for Zion Station decommissioning subtotal^(e)	13		—		16		—	29		13		—		16		—	29
Rabbi trust investments
Cash equivalents	5		—		—		—	5		77		—		—		—	77
Mutual funds	24		—		—		—	24		59		—		—		—	59
Fixed income	—		—		—		—	—		—		10		—		—	10
Life insurance contracts	—		22		—		—	22		—		71		23		—	94
Rabbi trust investments subtotal^(f)	29		22		—		—	51		136		81		23		—	240
Commodity derivative assets
Economic hedges	286		2,923		1,892		—	5,101		286		2,923		1,892		—	5,101
Proprietary trading	—		151		58		—	209		—		151		58		—	209
Effect of netting and allocation of collateral^{(g) (h)}	(335	)	(2,589	)	(895	)	—	(3,819	)	(335	)	(2,589	)	(895	)	—	(3,819	)
Commodity derivative assets subtotal	(49	)	485		1,055		—	1,491		(49	)	485		1,055		—	1,491
Interest rate and foreign currency derivative assets
Derivatives designated as hedging instruments	—		12		—		—	12		—		12		—		—	12
Economic hedges	—		6		—		—	6		—		6		—		—	6
Effect of netting and allocation of collateral	(1	)	(3	)	—		—	(4	)	(1	)	(3	)	—		—	(4	)
Interest rate and foreign currency derivative assets subtotal	(1	)	15		—		—	14		(1	)	15		—		—	14
Other investments	—		—		36		—	36		—		—		36		—	36
Total assets	6,428		3,660		1,716		3,519	15,323		6,709		3,719		1,739		3,519	15,686
Liabilities
Commodity derivative liabilities
Economic hedges	(415	)	(3,317	)	(1,203	)	—	(4,935	)	(415	)	(3,317	)	(1,470	)	—	(5,202	)
Proprietary trading	—		(164	)	(15	)	—	(179	)	—		(164	)	(15	)	—	(179	)
Effect of netting and allocation of collateral^{(g) (h)}	415		3,007		1,081		—	4,503		415		3,007		1,081		—	4,503
Commodity derivative liabilities subtotal	—		(474	)	(137	)	—	(611	)	—		(474	)	(404	)	—	(878	)
Interest rate and foreign currency derivative liabilities
Derivatives designated as hedging instruments	—		—		—		—	—		—		(4	)	—		—	(4	)



	Generation														Exelon
As of March 31, 2018	Level 1			Level 2			Level 3			Not subject to leveling		Total			Level 1			Level 2			Level 3			Not subject to leveling		Total
Economic hedges	(1		)	(4		)	—			—		(5		)	(1		)	(4		)	—			—		(5		)
Effect of netting and allocation of collateral	1			3			—			—		4			1			3			—			—		4
Interest rate and foreign currency derivative liabilities subtotal	—			(1		)	—			—		(1		)	—			(5		)	—			—		(5		)
Deferred compensation obligation	—			(35		)	—			—		(35		)	—			(138		)	—			—		(138		)
Total liabilities	—			(510		)	(137		)	—		(647		)	—			(617		)	(404		)	—		(1,021		)
Total net assets	$	6,428		$	3,150		$	1,579		$	3,519	$	14,676		$	6,709		$	3,102		$	1,335		$	3,519	$	14,665



	Generation														Exelon
As of December 31, 2017	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)	$	168		$	—		$	—		$	—	$	168		$	656		$	—		$	—		$	—	$	656
NDT fund investments
Cash equivalents^(b)	135			85			—			—		220			135			85			—			—		220
Equities	4,163			915			—			2,176		7,254			4,163			915			—			2,176		7,254
Fixed income
Corporate debt	—			1,614			251			—		1,865			—			1,614			251			—		1,865
U.S. Treasury and agencies	1,917			52			—			—		1,969			1,917			52			—			—		1,969
Foreign governments	—			82			—			—		82			—			82			—			—		82
State and municipal debt	—			263			—			—		263			—			263			—			—		263
Other^(c)	—			47			—			510		557			—			47			—			510		557
Fixed income subtotal	1,917			2,058			251			510		4,736			1,917			2,058			251			510		4,736
Middle market lending	—			—			397			131		528			—			—			397			131		528
Private equity	—			—			—			222		222			—			—			—			222		222
Real estate	—			—			—			471		471			—			—			—			471		471
NDT fund investments subtotal^(d)	6,215			3,058			648			3,510		13,431			6,215			3,058			648			3,510		13,431
Pledged assets for Zion Station decommissioning
Cash equivalents	2			—			—			—		2			2			—			—			—		2
Equities	—			1			—			—		1			—			1			—			—		1
Middle market lending	—			—			12			24		36			—			—			12			24		36
Pledged assets for Zion Station decommissioning subtotal^(e)	2			1			12			24		39			2			1			12			24		39
Rabbi trust investments
Cash equivalents	5			—			—			—		5			77			—			—			—		77
Mutual funds	23			—			—			—		23			58			—			—			—		58
Fixed income	—			—			—			—		—			—			12			—			—		12
Life insurance contracts	—			22			—			—		22			—			71			22			—		93
Rabbi trust investments subtotal^(f)	28			22			—			—		50			135			83			22			—		240
Commodity derivative assets
Economic hedges	557			2,378			1,290			—		4,225			557			2,378			1,290			—		4,225
Proprietary trading	2			31			35			—		68			2			31			35			—		68
Effect of netting and allocation of collateral^{(g) (h)}	(585		)	(1,769		)	(635		)	—		(2,989		)	(585		)	(1,769		)	(635		)	—		(2,989		)
Commodity derivative assets subtotal	(26		)	640			690			—		1,304			(26		)	640			690			—		1,304
Interest rate and foreign currency derivative assets
Derivatives designated as hedging instruments	—			3			—			—		3			—			6			—			—		6
Economic hedges	—			10			—			—		10			—			10			—			—		10



	Generation														Exelon
As of December 31, 2017	Level 1			Level 2			Level 3			Not subject to leveling		Total			Level 1			Level 2			Level 3			Not subject to leveling		Total
Effect of netting and allocation of collateral	(2		)	(5		)	—			—		(7		)	(2		)	(5		)	—			—		(7		)
Interest rate and foreign currency derivative assets subtotal	(2		)	8			—			—		6			(2		)	11			—			—		9
Other investments	—			—			37			—		37			—			—			37			—		37
Total assets	6,385			3,729			1,387			3,534		15,035			6,980			3,793			1,409			3,534		15,716
Liabilities
Commodity derivative liabilities
Economic hedges	(712		)	(2,226		)	(845		)	—		(3,783		)	(713		)	(2,226		)	(1,101		)	—		(4,040		)
Proprietary trading	(2		)	(42		)	(9		)	—		(53		)	(2		)	(42		)	(9		)	—		(53		)
Effect of netting and allocation of collateral^{(g) (h)}	650			2,089			716			—		3,455			651			2,089			716			—		3,456
Commodity derivative liabilities subtotal	(64		)	(179		)	(138		)	—		(381		)	(64		)	(179		)	(394		)	—		(637		)
Interest rate and foreign currency derivative liabilities
Derivatives designated as hedging instruments	—			(2		)	—			—		(2		)	—			(2		)	—			—		(2		)
Economic hedges	(1		)	(8		)	—			—		(9		)	(1		)	(8		)	—			—		(9		)
Effect of netting and allocation of collateral	2			5			—			—		7			2			5			—			—		7
Interest rate and foreign currency derivative liabilities subtotal	1			(5		)	—			—		(4		)	1			(5		)	—			—		(4		)
Deferred compensation obligation	—			(38		)	—			—		(38		)	—			(145		)	—			—		(145		)
Total liabilities	(63		)	(222		)	(138		)	—		(423		)	(63		)	(329		)	(394		)	—		(786		)
Total net assets	$	6,322		$	3,507		$	1,249		$	3,534	$	14,612		$	6,917		$	3,464		$	1,015		$	3,534	$	14,930

_________

(a)


(b)	Includes $53 million and $77 million of cash received from outstanding repurchase agreements at March 31, 2018 and December 31, 2017, respectively, and is offset by an obligation to repay upon settlement of the agreement as discussed in (d) below.

(c)

(d)


(e)	Excludes net assets of $1 million at March 31, 2018. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases.


(f)	The amount of unrealized gains/(losses) at Generation totaled less than $1 million and $1 million for the three months ended March 31, 2018 and March 31, 2017, respectively. The amount of unrealized gains/(losses) at Exelon totaled $1 million and $2 million for the three months ended March 31, 2018 and March 31, 2017, respectively.

(g)


(h)	Of the collateral posted/(received), $156 million represents variation margin on the exchanges as of March 31, 2018. Of the collateral posted/(received), $(117) million represents variation margin on the exchanges as of December 31, 2017.

ComEd, PECO and BGE



	ComEd											PECO										BGE
As of March 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)	$	93	$	—		$	—		$	93		$	6	$	—		$	—	$	6		$	—	$	—		$	—	$	—
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	93		—			—			93			13		10			—		23			6		—			—		6
Liabilities
Deferred compensation obligation	—		(8		)	—			(8		)	—		(11		)	—		(11		)	—		(4		)	—		(4		)
Mark-to-market derivative liabilities^(c)	—		—			(267		)	(267		)	—		—			—		—			—		—			—		—
Total liabilities	—		(8		)	(267		)	(275		)	—		(11		)	—		(11		)	—		(4		)	—		(4		)
Total net assets (liabilities)	$	93	$	(8	)	$	(267	)	$	(182	)	$	13	$	(1	)	$	—	$	12		$	6	$	(4	)	$	—	$	2



	ComEd											PECO										BGE
As of December 31, 2017	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)	$	98	$	—		$	—		$	98		$	228	$	—		$	—	$	228		$	—	$	—		$	—	$	—
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	98		—			—			98			235		10			—		245			6		—			—		6
Liabilities
Deferred compensation obligation	—		(8		)	—			(8		)	—		(11		)	—		(11		)	—		(5		)	—		(5		)
Mark-to-market derivative liabilities^(c)	—		—			(256		)	(256		)	—		—			—		—			—		—			—		—
Total liabilities	—		(8		)	(256		)	(264		)	—		(11		)	—		(11		)	—		(5		)	—		(5		)
Total net assets (liabilities)	$	98	$	(8	)	$	(256	)	$	(166	)	$	235	$	(1	)	$	—	$	234		$	6	$	(5	)	$	—	$	1

_________

(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, 2018 and March 31, 2017, respectively.


(c)	The Level 3 balance consists of the current and noncurrent liability of $24 million and $243 million, respectively, at March 31, 2018, and $21 million and $235 million, respectively, at December 31, 2017, related to floating-to-fixed energy swap contracts with unaffiliated suppliers.

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, 2018 and 2017:





	Generation															ComEd				PHI					Exelon
Three Months Ended March 31, 2018	NDT Fund Investments			Pledged Assets for Zion Station Decommissioning		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		$	12	$	552			$	37		$	1,249		$	(256	)		$	22	$	—		$	1,015
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 payable for Zion Station decommissioning	—			4		—				—			4			—				—		—			4
Included in regulatory assets/liabilities	—			—		—				—			—			(11		)	^(b)	—		7			(4		)
Change in collateral	—			—		105				—			105			—				—		—			105
Purchases, sales, issuances and settlements
Purchases	2			—		88				—			90			—				—		—			90
Sales	—			—		(3		)		—			(3		)	—				—		—			(3		)
Settlements	(48		)	—		—				—			(48		)	—				—		—			(48		)
Transfers into Level 3	—			—		(8		)		—			(8		)	—				—		—			(8		)
Transfers out of Level 3	—			—		—				(2		)	(2		)	—				—		—			(2		)
Balance at March 31, 2018	$	609		$	16	$	918			$	36		$	1,579		$	(267	)		$	23	$	—		$	1,335
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




	Generation															ComEd				PHI						Exelon
Three Months Ended March 31, 2017	NDT Fund Investments			Pledged Assets for Zion Station Decommissioning		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, 2016	$	677		$	19	$	493			$	42		$	1,231		$	(258	)		$	20		$	—		$	993
Total realized / unrealized gains (losses)
Included in net income	3			—		(43		)	^(a)	1			(39		)	—				1			—			(38		)
Included in noncurrent payables to affiliates	9			—		—				—			9			—				—			(9		)	—
Included in regulatory assets/liabilities	—			—		—				—			—			(24		)	^(b)	—			9			(15		)
Change in collateral	—			—		38				—			38			—				—			—			38
Purchases, sales, issuances and settlements
Purchases	17			1		69				2			89			—				—			—			89
Sales	—			—		(2		)		—			(2		)	—				—			—			(2		)
Issuances	—			—		—				—			—			—				(1		)	—			(1		)
Settlements	(23		)	—		—				—			(23		)	—				—			—			(23		)
Transfers into Level 3	—			—		(1		)		—			(1		)	—				—			—			(1		)
Transfers out of Level 3	—			—		11				(5		)	6			—				—			—			6
Balance as of March 31, 2017	$	683		$	20	$	565			$	40		$	1,308		$	(282	)		$	20		$	—		$	1,046
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, 2017	$	2		$	—	$	59			$	—		$	61		$	—			$	1		$	—		$	62

________


(a)	Includes a reduction for the reclassification of $72 million and $102 million of realized gains due to the settlement of derivative contracts for the three months ended March 31, 2018 and March 31, 2017, respectively.

(b)


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

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^(a)		Operating and Maintenance		Operating Revenues		Purchased Power and Fuel			Operating and Maintenance		Other, net^(a)
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



	Generation							PHI		Exelon
	Operating Revenues		Purchased Power and Fuel			Other, net^(a)		Other, net^(a)		Operating Revenues		Purchased Power and Fuel			Other, net^(a)
Total gains (losses) included in net income for the three months ended March 31, 2017	$	88	$	(131	)	$	3	$	1	$	88	$	(131	)	$	4
Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended March 31, 2017	140		(81		)	2		1		140		(81		)	3

_________


(a)	Other, net activity consists of realized and unrealized gains (losses) included in income for the NDT funds held by Generation, accrued interest on a convertible promissory note at Generation and the life insurance contracts held by PHI and Pepco.

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

isk.

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



Type of trade	Fair Value at March 31, 2018			Valuation Technique	Unobservable Input	Range
Mark-to-market derivatives — Economic Hedges (Exelon and Generation)^(a)(b)	$	689		Discounted Cash Flow	Forward power price	$1	-	$202
					Forward gas price	$1.12	-	$12.80
				Option Model	Volatility percentage	10%	-	227%

Mark-to-market derivatives — Proprietary trading (Exelon and Generation)^(a)(b)	$	43		Discounted Cash Flow	Forward power price	$4	-	$202

Mark-to-market derivatives (Exelon and ComEd)	$	(267	)	Discounted Cash Flow	Forward heat rate^(c)	9x	-	10x
					Marketability reserve	4%	-	8%
					Renewable factor	87%	-	122%



Type of trade	Fair Value at December 31, 2017			Valuation Technique	Unobservable Input	Range
Mark-to-market derivatives — Economic Hedges (Exelon and Generation)^(a)(b)	$	445		Discounted Cash Flow	Forward power price	$3	-	$124
					Forward gas price	$1.27	-	$12.80
				Option Model	Volatility percentage	11%	-	139%

Mark-to-market derivatives — Proprietary trading (Exelon and Generation)^(a)(b)	$	26		Discounted Cash Flow	Forward power price	$14	-	$94

Mark-to-market derivatives (Exelon and ComEd)	$	(256	)	Discounted Cash Flow	Forward heat rate^(c)	9x	-	10x
					Marketability reserve	4%	-	8%
					Renewable factor	88%	-	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 $186 million and $81 million as of March 31, 2018 and December 31, 2017, 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.

Fair value of financial liabilities recorded at the carrying amount

Generation



	March 31, 2018
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities^(a)	$	166	$	—	$	166	$	—	$	166
Long-term debt (including amounts due within one year)^(b)(c)	8,965		—		7,585		1,610		9,195
SNF obligation	1,151		—		922		—		922



	December 31, 2017
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities^(a)	$	2	$	—	$	2	$	—	$	2
Long-term debt (including amounts due within one year)^(b)(c)	8,990		—		7,839		1,673		9,512
SNF obligation	1,147		—		936		—		936

Fair value of financial liabilities recorded at the carrying amount

ComEd



	March 31, 2018
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities^(a)	$	317	$	—	$	317	$	—	$	317
Long-term debt (including amounts due within one year)^(b)(c)	7,694		—		8,061		—		8,061
Long-term debt to financing trusts^(d)	205		—		—		222		222



	December 31, 2017
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year)^(b)(c)	$	7,601	$	—	$	8,418	$	—	$	8,418
Long-term debt to financing trusts^(d)	205		—		—		227		227

Fair value of financial liabilities recorded at the carrying amount

PECO



	March 31, 2018
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities^(a)	$	220	$	—	$	220	$	—	$	220
Long-term debt (including amounts due within one year)^(b)(c)	2,723		—		2,870		—		2,870
Long-term debt to financing trusts^(d)	184		—		—		199		199



	December 31, 2017
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year)^(b)(c)	$	2,903	$	—	$	3,194	$	—	$	3,194
Long-term debt to financing trusts^(d)	184		—		—		204		204

Fair value of financial liabilities recorded at the carrying amount

BGE



	March 31, 2018
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities^(a)	$	45	$	—	$	45	$	—	$	45
Long-term debt (including amounts due within one year)^(b)(c)	$	2,578	$	—	$	2,689	$	—	$	2,689



	December 31, 2017
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities^(a)	$	77	$	—	$	77	$	—	$	77
Long-term debt (including amounts due within one year)^(b)(c)	2,577		—		2,825		—		2,825

PEPCO Holdings Inc [Member]

Fair value of financial liabilities recorded at the carrying amount

PHI



	March 31, 2018
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities^(a)	$	407	$	—	$	407	$	—	$	407
Long-term debt (including amounts due within one year)^(b)(c)	5,849		—		5,423		283		5,706



	December 31, 2017
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities^(a)	$	350	$	—	$	350	$	—	$	350
Long-term debt (including amounts due within one year)^(b)(c)	5,874		—		5,722		297		6,019

Fair value of financial liabilities recorded at the carrying amount

Pepco



	March 31, 2018
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities^(a)	$	60	$	—	$	60	$	—	$	60
Long-term debt (including amounts due within one year)^(b)(c)	2,540		—		2,933		9		2,942



	December 31, 2017
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities^(a)	$	26	$	—	$	26	$	—	$	26
Long-term debt (including amounts due within one year)^(b)(c)	2,540		—		3,114		9		3,123

Fair value of financial liabilities recorded at the carrying amount

DPL



	March 31, 2018
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities^(a)	$	211	$	—	$	211	$	—	$	211
Long-term debt (including amounts due within one year)^(b)(c)	1,296		—		1,320		—		1,320



	December 31, 2017
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities^(a)	$	216	$	—	$	216	$	—	$	216
Long-term debt (including amounts due within one year)^(b)(c)	1,300		—		1,393		—		1,393

Fair value of financial liabilities recorded at the carrying amount

ACE



	March 31, 2018
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities^(a)	$	136	$	—	$	136	$	—	$	136
Long-term debt (including amounts due within one year)^(b)(c)	1,114		—		916		274		1,190



	December 31, 2017
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities^(a)	$	108	$	—	$	108	$	—	$	108
Long-term debt (including amounts due within one year)^(b)(c)	1,121		—		949		288		1,237

Derivative Financial Instruments (Tables)

3 Months Ended

Mar. 31, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Summary of the derivative fair value

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



	Generation												ComEd			DPL						Exelon
Derivatives	Economic Hedges			Proprietary Trading			Collateral and Netting^(a)(e)			Subtotal^(b)			Economic Hedges^(c)			Economic Hedges^(d)		Collateral and Netting^(a)		Subtotal		Total Derivatives
Mark-to-market derivative assets (current assets)	$	3,343		$	166		$	(2,533	)	$	976		$	—		$	—	$	—	$	—	$	976
Mark-to-market derivative assets (noncurrent assets)	1,758			43			(1,286		)	515			—			—		—		—		515
Total mark-to-market derivative assets	5,101			209			(3,819		)	1,491			—			—		—		—		1,491
Mark-to-market derivative liabilities (current liabilities)	(3,185		)	(151		)	2,945			(391		)	(24		)	—		—		—		(415		)
Mark-to-market derivative liabilities (noncurrent liabilities)	(1,750		)	(28		)	1,558			(220		)	(243		)	—		—		—		(463		)
Total mark-to-market derivative liabilities	(4,935		)	(179		)	4,503			(611		)	(267		)	—		—		—		(878		)
Total mark-to-market derivative net assets (liabilities)	$	166		$	30		$	684		$	880		$	(267	)	$	—	$	—	$	—	$	613

_________

(a)


(b)	Current and noncurrent assets are shown net of collateral of $192 million and $103 million, respectively, and current and noncurrent liabilities are shown net of collateral of $220 million and $169 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $684 million at March 31, 2018.


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


(d)	Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC.


(e)	Of the collateral posted/(received), $156 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, 2017:



	Generation												ComEd			DPL							Exelon
Description	Economic Hedges			Proprietary Trading			Collateral and Netting^(a)(e)			Subtotal^(b)			Economic Hedges^(c)			Economic Hedges^(d)			Collateral and Netting^(a)		Subtotal		Total Derivatives
Mark-to-market derivative assets (current assets)	$	3,061		$	56		$	(2,144	)	$	973		$	—		$	—		$	—	$	—	$	973
Mark-to-market derivative assets (noncurrent assets)	1,164			12			(845		)	331			—			—			—		—		331
Total mark-to-market derivative assets	4,225			68			(2,989		)	1,304			—			—			—		—		1,304
Mark-to-market derivative liabilities (current liabilities)	(2,646		)	(43		)	2,480			(209		)	(21		)	(1		)	1		—		(230		)
Mark-to-market derivative liabilities (noncurrent liabilities)	(1,137		)	(10		)	975			(172		)	(235		)	—			—		—		(407		)
Total mark-to-market derivative liabilities	(3,783		)	(53		)	3,455			(381		)	(256		)	(1		)	1		—		(637		)
Total mark-to-market derivative net assets (liabilities)	$	442		$	15		$	466		$	923		$	(256	)	$	(1	)	$	1	$	—	$	667

_________

(a)

Exelon, Generation and DPL net all available amounts allowed under the derivative authoritative guidance on 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 $169 million and $53 million, respectively, and current and noncurrent liabilities are shown net of collateral of $167 million and $77 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $466 million at December 31, 2017.


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


(d)	Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC.


(e)	Of the collateral posted/(received), $(117) million represents variation margin on the exchanges.

Exelon and Generation include the gain or loss on the hedged items and the offsetting loss or gain on the related interest rate swaps as follows:



		Three Months Ended March 31,
	Income Statement Location	2018			2017			2018		2017
	Income Statement Location	Loss on Swaps						Gain on Borrowings
Exelon	Interest expense	$	(7	)	$	(4	)	$	13	$	8

Below is a summary of the interest rate and foreign exchange hedge balances as of March 31, 2018:



	Generation											Exelon Corporate			Exelon
Description	Derivatives Designated as Hedging Instruments		Economic Hedges			Collateral and Netting^(a)			Subtotal			Derivatives Designated as Hedging Instruments			Total
Mark-to-market derivative assets (current assets)	$	—	$	5		$	(3	)	$	2		$	—		$	2
Mark-to-market derivative assets (noncurrent assets)	12		1			(1		)	12			—			12
Total mark-to-market derivative assets	12		6			(4		)	14			—			14
Mark-to-market derivative liabilities (current liabilities)	—		(3		)	3			—			—			—
Mark-to-market derivative liabilities (noncurrent liabilities)	—		(2		)	1			(1		)	(4		)	(5		)
Total mark-to-market derivative liabilities	—		(5		)	4			(1		)	(4		)	(5		)
Total mark-to-market derivative net assets (liabilities)	$	12	$	1		$	—		$	13		$	(4	)	$	9

__________

(a)

The following table provides a summary of the interest rate and foreign exchange hedge balances recorded by the Registrants as of December 31, 2017:



	Generation												Exelon Corporate		Exelon
Description	Derivatives Designated as Hedging Instruments			Economic Hedges			Collateral and Netting^(a)			Subtotal			Derivatives Designated as Hedging Instruments		Total
Mark-to-market derivative assets (current assets)	$	—		$	10		$	(7	)	$	3		$	—	$	3
Mark-to-market derivative assets (noncurrent assets)	3			—			—			3			3		6
Total mark-to-market derivative assets	3			10			(7		)	6			3		9
Mark-to-market derivative liabilities (current liabilities)	(2		)	(7		)	7			(2		)	—		(2		)
Mark-to-market derivative liabilities (noncurrent liabilities)	—			(2		)	—			(2		)	—		(2		)
Total mark-to-market derivative liabilities	(2		)	(9		)	7			(4		)	—		(4		)
Total mark-to-market derivative net assets (liabilities)	$	1		$	1		$	—		$	2		$	3	$	5

__________

(a)

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

For the three months ended March 31, 2018 and 2017, 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" on the Consolidated Statements of Cash Flows.



	Three Months Ended March 31,
	2018			2017
Income Statement Location	Gain (Loss)
Operating revenues	$	(100	)	$	46
Purchased power and fuel	(167		)	(93		)
Total Exelon and Generation	$	(267	)	$	(47	)



		Three Months Ended March 31,
		2018			2017
	Income Statement Location	Gain (Loss)
Generation	Operating Revenues	$	2		$	(2	)
Generation	Purchased Power and Fuel	(1		)	—
Total Generation		$	1		$	(2	)



		Three Months Ended March 31,
		2018			2017
	Income Statement Location	Gain (Loss)
Exelon	Operating Revenues	$	2		$	(2	)
Exelon	Purchased Power and Fuel	(1		)	—
Total Exelon		$	1		$	(2	)

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

For the three months ended March 31, 2018 and 2017 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" on the Consolidated Statements of Cash Flows. The Utility Registrants do not execute derivatives for proprietary trading purposes.



	Three Months Ended March 31,
	2018		2017
Income Statement Location	Gain (Loss)
Operating revenues	$	2	$	(1	)

For the three months ended March 31, 2018 and 2017 Exelon and Generation recognized the following net pre-tax commodity mark-to-market gains (losses).



	Three Months Ended March 31,
	2018		2017
Income Statement Location	Gain (Loss)
Operating Revenues	$	—	$	(1	)

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



Rating as of March 31, 2018	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	$	986	$	1	$	985	2	$	412
Non-investment grade	112		46		66
No external ratings
Internally rated — investment grade	223		—		223
Internally rated — non-investment grade	100		17		83
Total	$	1,421	$	64	$	1,357	2	$	412



Net Credit Exposure by Type of Counterparty	As of March 31, 2018
Financial institutions	$	189
Investor-owned utilities, marketers, power producers	656
Energy cooperatives and municipalities	438
Other	74
Total	$	1,357

_________


(a)	As of March 31, 2018, credit collateral held from counterparties where Generation had credit exposure included $41 million of cash and $23 million of letters of credit. The credit collateral does not include non-liquid collateral.



Credit-Risk Related Contingent Feature	March 31, 2018			December 31, 2017
Gross fair value of derivative contracts containing this feature^(a)	$	(2,141	)	$	(926	)
Offsetting fair value of in-the-money contracts under master netting arrangements^(b)	1,562			577
Net fair value of derivative contracts containing this feature^(c)	$	(579	)	$	(349	)

_________


(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.

Schedule of Notional Amounts of Outstanding Derivative Positions [Table Text Block]

The table below provides the notional amounts of fixed-to-floating hedges outstanding held by Exelon at March 31, 2018 and December 31, 2017:



	As of
	March 31, 2018		December 31, 2017
Fixed-to-floating hedges	$	800	$	800

The following table provides notional amounts outstanding held by Exelon and Generation at March 31, 2018 and December 31, 2017 related to foreign currency exchange rate swaps that are marked-to-market to manage the exposure associated with international purchases of commodities in currencies other than U.S. dollars.



	As of
	March 31, 2018		December 31, 2017
Foreign currency exchange rate swaps	$	87	$	94

The table below provides the notional amounts of floating-to-fixed hedges outstanding held by Exelon and Generation as of March 31, 2018.



	As of
	March 31, 2018		December 31, 2017
Floating-to-fixed hedges	$	636	$	636

Debt and Credit Agreements (Tables)

3 Months Ended

Mar. 31, 2018

Debt Disclosure [Abstract]

Commercial Paper Borrowings

The Registrants had the following amounts of commercial paper borrowings outstanding as of March 31, 2018 and December 31, 2017:



Commercial Paper Borrowings	March 31, 2018		December 31, 2017
Exelon	$	1,154	$	427
Generation	165		—
ComEd	317		—
PECO	220		—
BGE	45		77
PHI^(a)	407		350
Pepco	60		26
DPL	211		216
ACE	136		108

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

During the three months ended March 31, 2018, the following long-term debt was issued:



Company	Type	Interest Rate		Maturity	Amount		Use of Proceeds
Generation	Energy Efficiency Project Financing	3.72	%	April 30, 2018	$	1	Funding to install energy conservation measures for the Smithsonian Zoo project.
Generation	Energy Efficiency Project Financing	3.17	%	April 30, 2018	$	1	Funding to install energy conservation measures in Brooklyn, NY.
Generation	Energy Efficiency Project Financing	2.61	%	September 30, 2018	$	2	Funding to install energy conservation measures for the Pensacola project.
ComEd	First Mortgage Bonds, Series 124	4.00	%	March 1, 2048	$	800	Refinance one series of maturing first mortgage bonds, to repay a portion of ComEd’s outstanding commercial paper obligations and to fund general corporate purposes.
PECO	First and Refunding Mortgage Bonds	3.90	%	March 1, 2048	$	325	Refinance a portion of maturing mortgage bonds.

- 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, 2018

Income Tax Disclosure [Abstract]

ScheduleOfRemeasurementsOfDeferredIncomeTaxesDueToTaxReform [Table Text Block]

The one-time impacts recorded by the Registrants to remeasure their deferred income tax balances at the 21% corporate federal income tax rate as of December 31, 2017 are presented below:



	Exelon^(b)		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Net Decrease to Deferred Income Tax Liability Balances	$	8,624	$	1,895	$	2,819	$	1,407	$	1,120	$	1,944	$	968	$	540	$	456



	Exelon	Generation	ComEd	PECO^(c)	BGE	PHI	Pepco	DPL	ACE
Net Regulatory Liability Recorded^(a)	7,315	N/A	2,818	1,394	1,124	1,979	976	545	458



	Exelon^(b)		Generation		ComEd		PECO		BGE			PHI			Pepco			DPL			ACE
Net Deferred Income Tax Benefit/(Expense) Recorded	$	1,309	$	1,895	$	1	$	13	$	(4	)	$	(35	)	$	(8	)	$	(5	)	$	(2	)

__________


(a)	Reflects the net regulatory liabilities recorded on a pre-tax basis before taking into consideration the income tax benefits associated with the ultimate settlement with customers.


(b)	Amounts do not sum across due to deferred tax adjustments recorded at the Exelon Corporation parent company, primarily related to certain employee compensation plans.


(c)	Given the regulatory treatment of income tax benefits related to electric and gas distribution repairs, PECO remains in an overall net regulatory asset position as of December 31, 2017 after recording the impacts related to the TCJA. Refer to Note 3 - Regulatory Matters for additional information.

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, 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 nuclear decommissioning trust 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%



	Three Months Ended March 31, 2017^(a)
	Exelon	Generation	ComEd	PECO	BGE	PHI	Pepco	DPL	ACE
U.S. Federal statutory rate	35.0%	35.0%	35.0%	35.0%	35.0%	35.0%	35.0%	35.0%	35.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	0.9	1.0	4.9	0.1	5.2	4.9	4.6	5.3	5.6
Qualified nuclear decommissioning trust fund income	3.5	7.8	—	—	—	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(0.4)	(0.7)	(0.2)	(0.1)	(0.1)	(0.2)	(0.1)	(0.3)	(0.4)
Plant basis differences	(2.4)	—	(0.2)	(13.2)	(0.9)	(3.8)	(5.8)	(1.9)	(3.4)
Production tax credits and other credits	(0.7)	(1.5)	—	—	—	—	—	—	—
Noncontrolling interest	—	0.1	—	—	—	—	—	—	—
Merger expenses^(b)	(11.5)	(3.4)	—	—	—	(42.4)	(34.2)	(21.9)	(167.1)
Fitzpatrick bargain purchase gain	(6.6)	(14.8)	—	—	—	—	—	—	—
Other	(0.1)	(0.4)	—	0.3	(0.2)	(0.4)	0.5	—	(3.0)
Effective income tax rate	17.7%	23.1%	39.5%	22.1%	39.0%	(6.9)%	0.0%	16.2%	(133.3)%

_________


(a)	Exelon retrospectively adopted the new standard Revenue from Contracts with Customers. The standard was adopted as of January 1, 2018. The effective income tax rates are recast to reflect the impact of the new standard.


(b)	Includes a remeasurement of uncertain state income tax positions for Pepco and DPL.

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

The Registrants have the following unrecognized tax benefits as of March 31, 2018 and December 31, 2017:



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
March 31, 2018	$	733	$	464	$	2	$	—	$	120	$	125	$	59	$	21	$	14



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
December 31, 2017	$	743	$	468	$	2	$	—	$	120	$	125	$	59	$	21	$	14

Nuclear Decommissioning (Tables)

3 Months Ended

Mar. 31, 2018

Schedule Of Nuclear Decommissioning [Line Items]

Schedule of Financial Instruments Owned and Pledged as Collateral [Table Text Block]

The following table provides the pledged assets and payables to ZionSolutions, and withdrawals by ZionSolutions at March 31, 2018 and December 31, 2017:



	Exelon and Generation
	March 31, 2018		December 31, 2017
Carrying value of Zion Station pledged assets^(a)	$	30	$	39
Payable to Zion Solutions^(b)(c)	28		37
Cumulative withdrawals by Zion Solutions to pay decommissioning costs^(d)	949		942

_________


(a)	Included in Other current assets within Exelon's and Generation's Consolidated Balance sheets.


(b)	Excludes a liability recorded within Exelon’s and Generation’s Consolidated Balance Sheets related to the tax obligation on the unrealized activity associated with the Zion Station NDT funds. The NDT funds will be utilized to satisfy the tax obligations as gains and losses are realized.


(c)	Included in Other current liabilities within Exelon’s and Generation’s Consolidated Balance Sheets.


(d)	Includes project expenses to decommission Zion Station and estimated tax payments on Zion Station NDT fund earnings

^{[1],[2],[3],[4]}

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

The following table provides a rollforward of the nuclear decommissioning ARO reflected on Exelon’s and Generation’s Consolidated Balance Sheets from December 31, 2017 to March 31, 2018:



Nuclear decommissioning ARO at December 31, 2017^(a)	$	9,662
Accretion expense	117
Net increase due to changes in, and timing of, estimated future cash flows	32
Costs incurred related to decommissioning plants	(4		)
Nuclear decommissioning ARO at March 31, 2018^(a)	$	9,807

_________


(a)	Includes $64 million and $13 million for the current portion of the ARO at March 31, 2018 and December 31, 2017, respectively, which is included in Other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets.

^[5]

Unrealized Gain (Loss) on Investments [Table Text Block]

The following table provides net unrealized gains (losses) on NDT funds for the three months ended March 31, 2018 and 2017:



	Exelon and Generation
	Three Months Ended March 31,
	2018			2017
Net unrealized gains (losses) on decommissioning trust funds — Regulatory Agreement Units^(a)	$	(75	)	$	222
Net unrealized gains (losses) on decommissioning trust funds — Non-Regulatory Agreement Units^(b)(c)	(96		)	166

_________


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


(b)	Excludes $(2) million and $(1) million of net unrealized losses related to the Zion Station pledged assets for the three months ended March 31, 2018 and 2017, respectively. Net unrealized losses related to Zion Station pledged assets are included in Other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets in 2018 and 2017, respectively.


(c)	Net unrealized gains (losses) related to Generation’s NDT funds with Non-Regulatory Agreement Units are included in Other, net on Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

^[6],[7],[8]

[1]	Excludes a liability recorded within Exelon’s and Generation’s Consolidated Balance Sheets related to the tax obligation on the unrealized activity associated with the Zion Station NDT funds. The NDT funds will be utilized to satisfy the tax obligations as gains and losses are realized.
[2]	Included in Other current assets within Exelon's and Generation's Consolidated Balance sheets.
[3]	Included in Other current liabilities within Exelon’s and Generation’s Consolidated Balance Sheets.
[4]	Includes project expenses to decommission Zion Station and estimated tax payments on Zion Station NDT fund earnings
[5]	Includes $64 million and $13 million for the current portion of the ARO at March 31, 2018 and December 31, 2017, respectively, which is included in Other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets.
[6]	Excludes $(2) million and $(1) million of net unrealized losses related to the Zion Station pledged assets for the three months ended March 31, 2018 and 2017, respectively. Net unrealized losses related to Zion Station pledged assets are included in Other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets in 2018 and 2017, respectively.
[7]	Net unrealized gains (losses) related to Generation’s NDT funds associated with Regulatory Agreement Units are included in Regulatory liabilities on Exelon’s Consolidated Balance Sheets and Noncurrent payables to affiliates on Generation’s Consolidated Balance Sheets.
[8]	Net unrealized gains (losses) related to Generation’s NDT funds with Non-Regulatory Agreement Units are included in Other, net on Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

Retirement Benefits (Tables)

3 Months Ended

Mar. 31, 2018

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, 2018 and 2017.



	Pension Benefits Three Months Ended March 31,						Other Postretirement Benefits Three Months Ended March 31,
	2018			2017^(a)			2018			2017^(a)
Components of net periodic benefit cost:
Service cost	$	101		$	95		$	28		$	26
Interest cost	201			210			43			45
Expected return on assets	(312		)	(299		)	(43		)	(41		)
Amortization of:
Prior service benefit	—			—			(46		)	(47		)
Actuarial loss	157			152			16			16
Net periodic benefit cost	$	147		$	158		$	(2	)	$	(1	)

_________


(a)	FitzPatrick net benefit costs are included for the period after the acquisition date of March 31, 2017.

Schedule Of Pension And Other Postretirement Benefit Costs



	Three Months Ended March 31,
Pension and Other Postretirement Benefit Costs	2018		2017
Exelon^(a)(b)	$	145	$	157
Generation^(b)	51		54
ComEd	45		44
PECO	5		7
BGE	15		16
BSC^(c)	14		12
PHI^(a)(d)	15		24
Pepco	4		7
DPL	—		3
ACE	3		3
PHISCO^(d)	8		11

_________


(a)	Exelon reflects the consolidated pension and other postretirement benefit costs of Generation, ComEd, PECO, BGE, BSC, and PHI. PHI reflects the consolidated pension and other postretirement benefit costs of Pepco, DPL, ACE, and PHISCO.


(b)	FitzPatrick net benefit costs are included for the period after the acquisition date of March 31, 2017.


(c)	These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO, BGE, PHI, Pepco, DPL or ACE amounts above.


(d)	These amounts represent amounts billed to Pepco, DPL and ACE through intercompany allocations. These amounts are not included in Pepco, DPL or ACE amounts above.

Schedule Of Defined Contributions

The following table presents the matching contributions to the savings plans during the three months ended March 31, 2018 and 2017, respectively.



	Three Months Ended March 31,
Savings Plan Matching Contributions	2018		2017
Exelon^(a)(b)	$	32	$	30
Generation^(b)	15		14
ComEd	7		7
PECO	2		2
BGE	2		2
BSC^(c)	3		2
PHI^(a)(d)	3		3
Pepco	1		1
DPL	1		1
PHISCO^(d)	1		1

_________


(a)	Exelon reflects the consolidated savings plan matching contributions of Generation, ComEd, PECO, BGE, BSC, and PHI. PHI reflects the consolidated savings plan matching contributions of Pepco, DPL, and PHISCO.


(b)	FitzPatrick net benefit costs are included for the period after the acquisition date of March 31, 2017.


(c)	These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO, BGE, PHI, Pepco or DPL amounts above.


(d)	These amounts represent amounts billed to Pepco and DPL through intercompany allocations. These amounts are not included in Pepco or DPL amounts above.

Severance (Tables)

3 Months Ended

Mar. 31, 2018

Restructuring and Related Activities [Abstract]

Severance

For the three months ended March 31, 2018 and 2017, these costs were immaterial.



	Exelon		Generation^(a)		ComEd^(a)		PECO^(a)		BGE^(a)		PHI^(a)		Pepco^(a)		DPL^(a)		ACE^(a)
Three Months Ended
March 31, 2018	$	8	$	2	$	1	$	—	$	1	$	4	$	2	$	1	$	1
March 31, 2017	4		3		1		—		—		—		—		—		—

_________


(a)	The amounts above for Generation, ComEd, PECO, BGE, and PHI include immaterial amounts billed by BSC the three months ended March 31, 2018 and 2017. Pepco, DPL and ACE include immaterial amounts billed by PHISCO for the three months ended March 31, 2018 and 2017.

Severance Liability

Amounts included in the table below represent the severance liability recorded for employees of each Registrant and exclude amounts included at Exelon and billed through intercompany allocations:




Severance Liability	Exelon			Generation			ComEd			PECO		BGE		PHI			Pepco			DPL		ACE
Balance at December 31, 2017	$	94		$	58		$	3		$	—	$	—	$	20		$	—		$	—	$	—
Severance charges^(a)	9			3			1			—		1		2			1			—		—
Payments	(16		)	(5		)	(1		)	—		—		(6		)	(1		)	—		—
Balance at March 31, 2018	$	87		$	56		$	3		$	—	$	1	$	16		$	—		$	—	$	—

__________


(a)	Includes salary continuance and health and welfare severance benefits.

Changes in Accumulated Other Comprehensive Income (Tables)

3 Months Ended

Mar. 31, 2018

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, 2018 and 2017:



Three Months Ended March 31, 2018	Gains and (losses) on Cash Flow Hedges			Unrealized Gains and (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	—			(10		)	^(c)	—				—			—			(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^(b)	—			—				—				—			—			—
Net current-period OCI	7			—				—				(1		)	—			6
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard	—			(3		)	^(c)	—				—			—			(3		)
Ending balance	$	(9	)	$	—			$	—			$	(24	)	$	(1	)	$	(34	)
PECO^(a)
Beginning balance	$	—		$	1			$	—			$	—		$	—		$	1
OCI before reclassifications	—			—				—				—			—			—
Amounts reclassified from AOCI^(b)	—			—				—				—			—			—
Net current-period OCI	—			—				—				—			—			—
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard	—			(1		)	^(c)	—				—			—			(1		)
Ending balance	$	—		$	—			$	—			$	—		$	—		$	—



Three Months Ended March 31, 2017	Gains and (losses) on Cash Flow Hedges			Unrealized Gains and (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	$	(17	)	$	4	$	(2,610	)	$	(30	)	$	(7	)	$	(2,660	)
OCI before reclassifications	2			1		(59		)	1			5			(50		)
Amounts reclassified from AOCI^(b)	4			—		36			—			—			40
Net current-period OCI	6			1		(23		)	1			5			(10		)
Ending balance	$	(11	)	$	5	$	(2,633	)	$	(29	)	$	(2	)	$	(2,670	)
Generation^(a)
Beginning balance	$	(19	)	$	2	$	—		$	(30	)	$	(7	)	$	(54	)
OCI before reclassifications	2			—		—			1			6			9
Amounts reclassified from AOCI^(b)	4			—		—			—			—			4
Net current-period OCI	6			—		—			1			6			13
Ending balance	$	(13	)	$	2	$	—		$	(29	)	$	(1	)	$	(41	)
PECO^(a)
Beginning balance	$	—		$	1	$	—		$	—		$	—		$	1
OCI before reclassifications	—			—		—			—			—			—
Amounts reclassified from AOCI^(b)	—			—		—			—			—			—
Net current-period OCI	—			—		—			—			—			—
Ending balance	$	—		$	1	$	—		$	—		$	—		$	1

_________


(a)	All amounts are net of tax and noncontrolling interest. 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

The following tables present amounts reclassified out of AOCI to Net income for Exelon and Generation during the three months ended March 31, 2018 and 2017.

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		)
Total before tax	(60		)
Tax benefit	16
Net of tax	$	(44	)

Total Reclassifications	$	(44	)	Comprehensive income

Three Months Ended March 31, 2017



Details about AOCI components	Items reclassified out of AOCI^(a)						Affected line item in the Statement of Operations and Comprehensive Income
	Exelon			Generation
Gains and (losses) on cash flow hedges
Other cash flow hedges	$	(7	)	$	(7	)	Interest expense
Total before tax	(7		)	(7		)
Tax benefit	3			3
Net of tax	$	(4	)	$	(4	)	Comprehensive income

Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)	$	23		$	—
Actuarial losses^(b)	(81		)	—
Total before tax	(58		)	—
Tax benefit	22			—
Net of tax	$	(36	)	$	—

Total Reclassifications	$	(40	)	$	(4	)	Comprehensive income

_________


(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 details).

Schedule Of Other Comprehensive Income Loss Tax

The following table presents income tax expense (benefit) allocated to each component of other comprehensive income (loss) during the three months ended March 31, 2018 and 2017:



	Three Months Ended March 31,
	2018			2017
Exelon
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	$	6		$	10
Actuarial loss reclassified to periodic benefit cost	(22		)	(32		)
Pension and non-pension postretirement benefit plans valuation adjustment	(7		)	—
Change in unrealized (loss) on cash flow hedges	(3		)	(1		)
Change in unrealized (loss) on investments in unconsolidated affiliates	(1		)	(4		)
Change in unrealized (loss) on marketable securities	—			(1		)
Total	$	(27	)	$	(28	)

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

Earnings Per Share and Equity (Tables)

3 Months Ended

Mar. 31, 2018

Earnings Per Share [Abstract]

Reconciliation of basic and diluted earnings per share



	Three Months Ended March 31,
	2018		2017
Exelon
Net income attributable to common shareholders	$	585	$	990
Weighted average common shares outstanding — basic	966		928
Assumed exercise and/or distributions of stock-based awards	2		2
Weighted average common shares outstanding — diluted	968		930

Commitments and Contingencies (Tables)

3 Months Ended

Mar. 31, 2018

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, 2018:



Description	Expected Payment Period	Pepco		DPL		ACE		PHI		Exelon
Rate credits	2016 - 2017	$	91	$	67	$	101	$	259	$	259
Energy efficiency	2016 - 2021	—		—		—		—		122
Charitable contributions	2016 - 2026	28		12		10		50		50
Delivery system modernization	Q2 2017	—		—		—		—		22
Green sustainability fund	Q2 2017	—		—		—		—		14
Workforce development	2016 - 2020	—		—		—		—		17
Other		1		5		—		6		29
Total commitments		$	120	$	84	$	111	$	315	$	513
Remaining commitments		$	75	$	12	$	8	$	95	$	165

Commercial Commitments (All Registrants)

The Registrants’ commercial commitments as of March 31, 2018, representing commitments potentially triggered by future events were as follows:



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Letters of credit (non-debt)^(a)	$	1,586	$	1,533	$	2	$	1	$	5	$	1	$	1	$	—	$	—
Surety bonds^(b)	1,651		1,463		9		9		10		66		32		4		5
Financing trust guarantees	378		—		200		178		—		—		—		—		—
Guaranteed lease residual values^(c)	22		—		—		—		—		22		7		9		6
Total commercial commitments	$	3,637	$	2,996	$	211	$	188	$	15	$	89	$	40	$	13	$	11

_________


(a)	Letters of credit (non-debt) - Exelon and certain of its subsidiaries maintain non-debt letters of credit to provide credit support for certain transactions as requested by third parties. Includes letters of credits issued under credit facility agreements arranged at minority and community banks and nonrecourse debt letters of credits.


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

(c)

Accrued environmental liabilities

of March 31, 2018 and December 31, 2017, 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, 2018	Total environmental investigation and remediation reserve		Portion of total related to MGP investigation and remediation
Exelon	$	462	$	313
Generation	117		—
ComEd	283		281
PECO	29		28
BGE	5		4
PHI	28		—
Pepco	26		—
DPL	1		—
ACE	1		—



December 31, 2017	Total environmental investigation and remediation reserve		Portion of total related to MGP investigation and remediation
Exelon	$	466	$	315
Generation	117		—
ComEd	285		283
PECO	30		28
BGE	5		4
PHI	29		—
Pepco	27		—
DPL	1		—
ACE	1		—

Supplemental Financial Information (Tables)

3 Months Ended

Mar. 31, 2018

Supplemental Financial Information [Abstract]

Components of non-operating income and expenses

The following tables provide additional information about the Registrants’ Consolidated Statements of Operations and Comprehensive Income for the three months ended March 31, 2018 and 2017.



	Three Months Ended March 31, 2018
	Exelon			Generation			ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds^(a)
Regulatory agreement units	$	46		$	46		$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-regulatory agreement units	56			56			—		—		—		—		—		—		—
Net unrealized losses on decommissioning trust funds
Regulatory agreement units	(75		)	(75		)	—		—		—		—		—		—		—
Non-regulatory agreement units	(96		)	(96		)	—		—		—		—		—		—		—
Net unrealized losses on pledged assets
Zion Station decommissioning	(2		)	(2		)	—		—		—		—		—		—		—
Regulatory offset to decommissioning trust fund-related activities^(b)	24			24			—		—		—		—		—		—		—
Total decommissioning-related activities	(47		)	(47		)	—		—		—		—		—		—		—
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	5			—			2		—		—		5		3		1		1
Other, net	$	(28	)	$	(44	)	$	8	$	2	$	4	$	11	$	8	$	2	$	1



	Three Months Ended March 31, 2017
	Exelon			Generation			ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds^(a)
Regulatory agreement units	$	68		$	68		$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-regulatory agreement units	32			32			—		—		—		—		—		—		—
Net unrealized gains on decommissioning trust funds
Regulatory agreement units	222			222			—		—		—		—		—		—		—
Non-regulatory agreement units	166			166			—		—		—		—		—		—		—
Net unrealized losses on pledged assets
Zion Station decommissioning	(1		)	(1		)	—		—		—		—		—		—		—
Regulatory offset to decommissioning trust fund-related activities^(b)	(234		)	(234		)	—		—		—		—		—		—		—
Total decommissioning-related activities	253			253			—		—		—		—		—		—		—
Investment income	2			2			—		—		—		—		—		—		—
Interest income related to uncertain income tax positions	1			—			—		—		—		—		—		—		—
AFUDC — Equity	17			—			2		2		4		9		5		2		2
Non-service net periodic benefit cost	(26		)	—			—		—		—		—		—		—		—
Other	10			4			2		—		—		4		3		1		—
Other, net	$	257		$	259		$	4	$	2	$	4	$	13	$	8	$	3	$	2

_________


(a)	Includes investment income and realized gains and losses on sales of investments of the trust funds.


(b)	Includes the elimination of NDT fund activity 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 2017 Form 10-K for additional information regarding the accounting for nuclear decommissioning.

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




	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	$	—



	Three Months Ended March 31, 2017
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Utility taxes	$	224	$	32	$	59	$	31	$	26	$	76	$	71	$	5	$	—

Components of depreciation, amortization and accretion, and other, net

The following tables provide additional information regarding the Registrants’ Consolidated Statements of Cash Flows for the three months ended March 31, 2018 and 2017.



	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



	Three Months Ended March 31, 2017
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Depreciation, amortization and accretion
Property, plant and equipment^(a)	$	754	$	289	$	190	$	64	$	80	$	112	$	50	$	30	$	21
Amortization of regulatory assets^(a)	128		—		18		7		48		55		32		9		14
Amortization of intangible assets, net^(a)	14		13		—		—		—		—		—		—		—
Amortization of energy contract assets and liabilities^(b)	2		2		—		—		—		—		—		—		—
Nuclear fuel^(c)	264		264		—		—		—		—		—		—		—
ARO accretion^(d)	112		110		—		—		—		—		—		—		—
Total depreciation, amortization and accretion	$	1,274	$	678	$	208	$	71	$	128	$	167	$	82	$	39	$	35

_________


(a)	Included in Depreciation and amortization on the Registrants' Consolidated Statements of Operations and Comprehensive Income.


(b)	Included in Operating revenues or Purchased power and fuel expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.


(c)	Included in Purchased power and fuel expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.


(d)	Included in Operating and maintenance expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income

Cash Flow Supplemental Disclosures



	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:
Increase (decrease) in capital expenditures not paid	$	(177	)	$	(131	)	$	(48	)	$	(25	)	$	(11	)	$	61	$	19		$	14	$	27
Increase in PPE related to ARO update	32			32			—			—			—			—		—			—		—
Dividends on stock compensation	1			—			—			—			—			—		—			—		—




	Three Months Ended March 31, 2017
	Exelon			Generation			ComEd			PECO			BGE			PHI			Pepco			DPL			ACE
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	157		$	54		$	44		$	7		$	16		$	24		$	7		$	3		$	3
Loss from equity method investments	10			10			—			—			—			—			—			—			—
Provision for uncollectible accounts	34			9			7			17			5			(4		)	(5		)	(1		)	1
Stock-based compensation costs	31			—			—			—			—			—			—			—			—
Other decommissioning-related activity^(a)	(84		)	(84		)	—			—			—			—			—			—			—
Energy-related options^(b)	(4		)	(4		)	—			—			—			—			—			—			—
Amortization of regulatory asset related to debt costs	2			—			1			—			—			1			—			—			—
Amortization of rate stabilization deferral	(14		)	—			—			—			7			(21		)	(15		)	(6		)	—
Amortization of debt fair value adjustment	(5		)	(3		)	—			—			—			(2		)	—			—			—
Discrete impacts from EIMA and FEJA ^(c)	(24		)	—			(24		)	—			—			—			—			—			—
Amortization of debt costs	9			4			1			—			—			—			—			—			—
Provision for excess and obsolete inventory	2			1			1			—			—			—			—			—			—
Other	4			3			1			(1		)	(4		)	(6		)	(2		)	(3		)	(2		)
Total other non-cash operating activities	$	118		$	(10	)	$	31		$	23		$	24		$	(8	)	$	(15	)	$	(7	)	$	2
Non-cash investing and financing activities:
Increase (decrease) in capital expenditures not paid	$	(193	)	$	(56	)	$	(66	)	$	(42	)	$	1		$	(5	)	$	(6	)	$	9		$	—
Non-cash financing of capital projects	10			10			—			—			—			—			—			—			—
Dividends on stock compensation	2			—			—			—			—			—			—			—			—

_________

(a)


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

(c)

Supplemental Balance Sheet Disclosures



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 shown in the statement of cash flows	$	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 shown in the statement of cash flows	$	1,190	$	554	$	144	$	275	$	18	$	95	$	40	$	2	$	31



March 31, 2017	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Cash and cash equivalents	$	609	$	400	$	31	$	28	$	11	$	109	$	8	$	44	$	54
Restricted cash	254		140		3		4		43		41		33		—		7
Restricted cash included in other long-term assets	26		—		—		—		3		23		—		—		23
Total cash, cash equivalents and restricted cash shown in the statement of cash flows	$	889	$	540	$	34	$	32	$	57	$	173	$	41	$	44	$	84



December 31, 2016	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Cash and cash equivalents	$	635	$	290	$	56	$	63	$	23	$	170	$	9	$	46	$	101
Restricted cash	253		158		2		4		24		43		33		—		9
Restricted cash included in other long-term assets	26		—		—		—		3		23		—		—		23
Total cash, cash equivalents and restricted cash shown in the statement of cash flows	$	914	$	448	$	58	$	67	$	50	$	236	$	42	$	46	$	133

For additional information on restricted cash see Note 1 — Significant Accounting Policies of the Exelon 2017 Form 10-K.

Supplemental Balance Sheet Information

The following tables provide additional information about assets and liabilities of the Registrants as of March 31, 2018 and December 31, 2017.



March 31, 2018	Exelon			Generation			ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Property, plant and equipment:
Accumulated depreciation and amortization	$	21,905	^(a)	$	11,936	^(a)	$	4,391	$	3,445	$	3,471	$	575	$	3,224	$	1,273	$	1,086
Accounts receivable:
Allowance for uncollectible accounts	$	369		$	115		$	89	$	68	$	31	$	66	$	24	$	22	$	20



December 31, 2017	Exelon			Generation			ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Property, plant and equipment:
Accumulated depreciation and amortization	$	21,064	^(b)	$	11,428	^(b)	$	4,269	$	3,411	$	3,405	$	487	$	3,177	$	1,247	$	1,066
Accounts receivable:
Allowance for uncollectible accounts	$	322		$	114		$	73	$	56	$	24	$	55	$	21	$	16	$	18

_________


(a)	Includes accumulated amortization of nuclear fuel in the reactor core of $3,263 million.


(b)	Includes accumulated amortization of nuclear fuel in the reactor core of $3,159 million

Segment Information (Tables)

3 Months Ended

Mar. 31, 2018

Segment Reporting [Abstract]

Analysis and reconciliation of reportable segment information

Three Months Ended March 31, 2018 and 2017



	Generation^(a)		ComEd		PECO		BGE		PHI		Other^(b)			Intersegment Eliminations			Exelon
Operating revenues^(c):
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
2017
Competitive businesses electric revenues	$	3,710	$	—	$	—	$	—	$	—	$	—		$	(328	)	$	3,382
Competitive businesses natural gas revenues	918		—		—		—		—		—			—			918
Competitive businesses other revenues	250		—		—		—		—		—			—			250
Rate-regulated electric revenues	—		1,298		590		667		1,097		—			(8		)	3,644
Rate-regulated natural gas revenues	—		—		206		284		66		—			(3		)	553
Shared service and other revenues	—		—		—		—		12		419			(431		)	—
Total operating revenues	4,878		1,298		796		951		1,175		419			(770		)	8,747
Shared service and other revenues
Intersegment revenues^(d):
2018	$	400	$	14	$	2	$	6	$	4	$	450		$	(876	)	$	—
2017	328		5		1		5		12		419			(770		)	—
Net income (loss):
2018	$	186	$	165	$	113	$	128	$	65	$	(21	)	$	—		$	636
2017	399		141		127		125		140		39			—			971
Total assets:
March 31, 2018	$	48,375	$	30,002	$	10,218	$	9,195	$	21,375	$	8,833		$	(10,980	)	$	117,018
December 31, 2017	48,457		29,726		10,170		9,104		21,247		8,618			(10,552		)	116,770

__________

(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 on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 18 — Supplemental Financial Information for total utility taxes for the three months ended March 31, 2018 and 2017.

(d)

PHI:



	Pepco		DPL		ACE		Other^(b)			Intersegment Eliminations			PHI
Operating revenues^(a):
Three Months Ended March 31, 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
Three Months Ended March 31, 2017
Rate-regulated electric revenues	$	530	$	296	$	275	$	—		$	(4	)	$	1,097
Rate-regulated natural gas revenues	—		66		—		—			—			66
Shared service and other revenues	—		—		—		12			—			12
Total operating revenues	530		362		275		12			(4		)	1,175
Intersegment revenues:
Three Months Ended March 31, 2018	$	2	$	2	$	1	$	112		$	(113	)	$	4
Three Months Ended March 31, 2017	1		2		1		13			(5		)	12
Net income (loss):
Three Months Ended March 31, 2018	$	31	$	31	$	7	$	(8	)	$	4		$	65
Three Months Ended March 31, 2017	58		57		28		(15		)	12			140
Total assets:
March 31, 2018	$	7,896	$	4,383	$	3,530	$	10,514		$	(4,948	)	$	21,375
December 31, 2017	7,832		4,357		3,445		10,600			(4,987		)	21,247

__________


(a)	Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 18 — Supplemental Financial Information for total utility taxes for the three months ended March 31, 2018 and 2017.


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

Analysis and reconciliation of reportable segment revenues for Generation

Competitive Business Revenues (Generation):



	Three Months Ended March 31, 2018
	Revenues from external parties^(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 England	725		68			793		(1		)	792
New York	439		(29		)	410		(1		)	409
ERCOT	149		59			208		1			209
Other Power Regions	210		109			319		(31		)	288
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



	Three Months Ended March 31, 2017
	Revenues from external customers^(a)							Intersegment revenues			Total Revenues
	Contracts with customers		Other^(b)			Total		Intersegment revenues			Total Revenues
Mid-Atlantic	$	1,494	$	(65	)	$	1,429	$	(4	)	$	1,425
Midwest	980		71			1,051		2			1,053
New England	589		(40		)	549		(2		)	547
New York	303		(3		)	300		(3		)	297
ERCOT	168		24			192		(1		)	191
Other Power Regions	128		61			189		(5		)	184
Total Competitive Businesses Electric Revenues	3,662		48			3,710		(13		)	3,697
Competitive Businesses Natural Gas Revenues	768		150			918		12			930
Competitive Businesses Other Revenues^(c)	206		44			250		1			251
Total Generation Consolidated Operating Revenues	$	4,636	$	242		$	4,878	$	—		$	4,878

__________


(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)

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



	Three Months Ended March 31, 2018									Three Months Ended March 31, 2017
	RNF from external customers^(a)			Intersegment RNF			Total RNF			RNF from external customers^(a)		Intersegment RNF			Total RNF
Mid-Atlantic	$	836		$	14		$	850		$	755	$	18		$	773
Midwest	847			13			860			704		11			715
New England	122			(3		)	119			115		(4		)	111
New York	282			1			283			143		—			143
ERCOT	106			(70		)	36			94		(25		)	69
Other Power Regions	157			(40		)	117			108		(44		)	64
Total Revenues net of purchased power and fuel expense for Reportable Segments	2,350			(85		)	2,265			1,919		(44		)	1,875
Other^(b)	(131		)	85			(46		)	161		44			205
Total Generation Revenues net of purchased power and fuel expense	$	2,219		$	—		$	2,219		$	2,080	$	—		$	2,080

__________


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

(b)

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

Electric and Gas Revenue by Customer Class (ComEd, PECO, BGE, PHI, PECO, DPL, ACE):



	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



	Three Months Ended March 31, 2017
Revenues from contracts with customers	ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Rate-regulated electric revenues
Residential	$	611	$	382	$	386	$	554	$	236	$	176	$	142
Small commercial & industrial	328		97		69		114		34		44		36
Large commercial & industrial	107		52		108		257		188		24		45
Public authorities & electric railroads	12		8		7		15		8		4		3
Other^(a)	218		48		68		126		48		38		43
Total rate-regulated electric revenues^(b)	$	1,276	$	587	$	638	$	1,066	$	514	$	286	$	269
Rate-regulated natural gas revenues
Residential	$	—	$	142	$	185	$	40	$	—	$	40	$	—
Small commercial & industrial	—		55		30		17		—		17		—
Large commercial & industrial	—		—		44		2		—		2		—
Transportation	—		6		—		5		—		5		—
Other^(c)	—		3		14		2		—		2		—
Total rate-regulated natural gas revenues^(d)	$	—	$	206	$	273	$	66	$	—	$	66	$	—
Total rate-regulated revenues from contracts with customers	$	1,276	$	793	$	911	$	1,132	$	514	$	352	$	269

Other revenues
Revenues from alternative revenue programs	14		—		35		30		15		9		6
Other rate-regulated electric revenues^(e)	8		3		4		2		1		1		—
Other rate-regulated natural gas revenues^(e)	—		—		1		—		—		—		—
Other revenues^(f)	—		—		—		11		—		—		—
Total other revenues	22		3		40		43		16		10		6
Total rate-regulated revenues for reportable segments	$	1,298	$	796	$	951	$	1,175	$	530	$	362	$	275

__________


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

(b)


(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, for the three months ended March 31, 2018 and less than $1 million and $3 million at PECO and BGE, respectively, for the three months ended March 31, 2017.


(e)	Includes late payment charge revenues.

Significant Accounting Policies Significant Accounting Policies - Narrative (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Net Cash Provided by (Used in) Operating Activities	$ 1,502	$ 1,074
Quantifying Misstatement in Current Year Financial Statements, Amount		(127)
Net Cash Provided by (Used in) Investing Activities	(1,857)	(2,283)
Scenario, Adjustment [Member]
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Net Cash Provided by (Used in) Operating Activities		1,074
Net Cash Provided by (Used in) Investing Activities		2,283
Exelon Generation Co L L C [Member]
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Net Cash Provided by (Used in) Operating Activities	855	420
Quantifying Misstatement in Current Year Financial Statements, Amount		(320)
Net Cash Provided by (Used in) Investing Activities	(615)	(910)
Exelon Generation Co L L C [Member] \| Scenario, Adjustment [Member]
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Net Cash Provided by (Used in) Operating Activities		420
Net Cash Provided by (Used in) Investing Activities		910
Commonwealth Edison Co [Member]
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Net Cash Provided by (Used in) Operating Activities	134	236
Quantifying Misstatement in Current Year Financial Statements, Amount		91
Net Cash Provided by (Used in) Investing Activities	(523)	(619)
Commonwealth Edison Co [Member] \| Scenario, Adjustment [Member]
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Net Cash Provided by (Used in) Operating Activities		236
Net Cash Provided by (Used in) Investing Activities		619
PECO Energy Co [Member]
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Net Cash Provided by (Used in) Operating Activities	19	106
Quantifying Misstatement in Current Year Financial Statements, Amount		42
Net Cash Provided by (Used in) Investing Activities	(215)	(69)
PECO Energy Co [Member] \| Scenario, Adjustment [Member]
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Net Cash Provided by (Used in) Operating Activities		106
Net Cash Provided by (Used in) Investing Activities		69
Baltimore Gas and Electric Company [Member]
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Net Cash Provided by (Used in) Operating Activities	313	208
Quantifying Misstatement in Current Year Financial Statements, Amount		40
Net Cash Provided by (Used in) Investing Activities	$ (223)	(202)
Baltimore Gas and Electric Company [Member] \| Scenario, Adjustment [Member]
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Net Cash Provided by (Used in) Operating Activities		208
Net Cash Provided by (Used in) Investing Activities		$ 202

Variable Interest Entities - Narrative (Details)
$ in Millions

3 Months Ended

Mar. 31, 2018

USD ($)

VIE

Mar. 31, 2017

USD ($)

Dec. 31, 2017

USD ($)

VIE

Apr. 01, 2014

USD ($)

Number Of Variable Interest Entities Consolidated | VIE

Number of Variable Interest Entities not consolidated by equity holders | VIE

Guarantor Obligations, Maximum Exposure, Undiscounted

$ 58

Other Nonconsolidated Variable Interest Entity Ownership Interests

^[1]

618

$ 618

Variable Interest Entity, Reporting Entity Involvement, Maximum Loss Exposure, Amount

Payment Guarantee [Member] | Constellation Energy Nuclear Group [Member]

Guarantor Obligations, Maximum Exposure, Undiscounted

$ 245

Financial Guarantee [Member] | Constellation Energy Nuclear Group [Member]

Guarantor Obligations, Maximum Exposure, Undiscounted

165

Variable Interest Entity, Financial or Other Support, Amount

$ 30

50.01%

Other Nonconsolidated Variable Interest Entity Ownership Interests

$ 9

Exelon Generation Co L L C [Member] | Constellation Energy Nuclear Group [Member]

Receivables from affiliates

337

$ 400

Exelon Generation Co L L C [Member] | Variable Interest Entity, Primary Beneficiary [Member] | Equity Method Investment Variable Interest Entities [Member]

Guarantor Obligations, Current Carrying Value

637

Guarantor Obligations, Maximum Exposure, Undiscounted

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

Variable Interest Entity, Financial or Other Support, Amount

$ 8

$ 19

[1]	These items represent amounts on the unconsolidated VIE balance sheets, not on Exelon’s or Generation’s Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs.

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

Mar. 31, 2018

Dec. 31, 2017

Current assets

^[1]

$ 823

$ 662

Noncurrent assets

^[1]

9,279

9,317

^[1]

10,102

9,979

Current liabilities

^[1]

269

308

^[1]

3,292

3,316

^[1]

3,561

3,624

Current assets

812

652

Noncurrent assets

9,251

9,286

10,063

9,938

Current liabilities

236

272

3,230

3,250

3,466

3,522

^[1]

^[1]

^[1]

^[1]

^[1]

^[1]

102

$ 83

$ 90

[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, 2018

Dec. 31, 2017

Mar. 31, 2017

Dec. 31, 2016

$ 787

$ 898

$ 609

$ 635

209

207

254

253

4,190

4,445

1,103

1,132

978

976

Inventory

1,291

1,311

1,495

1,260

11,533

11,896

74,711

74,202

13,149

13,272

Mark-to-market derivative assets

6,677

527

337

1,333

1,330

^[1]

117,018

116,770

1,203

2,088

3,207

3,532

1,569

1,837

415

232

202

231

956

982

10,153

10,798

32,905

32,176

10,126

10,029

Pension obligation

3,433

3,736

579

609

2,067

2,097

Variable Interest Entity, Primary Beneficiary [Member]

^[1]

84,453

84,583

^[2]

280

126

^[2]

^[2]

154

170

^[2]

Inventory

^[2]

202

205

^[2]

^[2]

793

635

^[2]

6,181

6,186

^[2]

2,483

2,502

^[2]

270

274

^[2]

8,934

8,962

^[2]

9,727

9,597

^[2]

102

^[2]

114

^[2]

^[2]

^[2]

^[2]

269

308

^[2]

1,125

1,154

^[2]

2,062

2,035

^[2]

^[2]

116

^[2]

3,287

3,310

^[2]

3,556

3,618

610

416

400

290

127

138

140

158

2,478

2,697

294

321

978

976

Inventory

916

937

1,122

933

6,884

6,882

24,714

24,906

13,149

13,272

Mark-to-market derivative assets

527

334

657

670

^[3]

48,375

48,457

373

346

1,447

1,773

951

1,022

391

211

288

265

4,156

4,191

7,685

7,734

9,941

9,844

686

658

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

^[3]

32,417

32,498

280

126

154

170

Inventory

202

205

782

625

6,181

6,186

2,483

2,502

242

243

8,906

8,931

9,688

9,556

114

236

272

1,063

1,088

2,062

2,035

116

3,225

3,244

3,461

3,516

394

375

Inventory

755

811

7,725

7,602

9,195

9,104

253

265

162

164

757

760

2,578

2,577

5,978

5,963

109

170

484

486

210

206

Inventory

152

151

1,493

1,551

12,688

12,498

4,005

^[4]

21,375

21,247

385

396

469

348

246

261

162

188

2,067

1,931

5,464

5,478

539

561

377

389

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

^[4]

12,556

12,422

^[2]

^[2]

^[2]

^[2]

Inventory

^[2]

^[2]

^[2]

^[2]

^[2]

^[2]

^[2]

^[2]

^[2]

^[2]

^[2]

^[2]

^[2]

^[2]

^[2]

^[2]

^[2]

^[2]

^[2]

^[2]

102

101

$ 7

$ 9

Inventory

263

258

2,767

2,706

^[5]

3,530

3,445

278

281

166

118

703

619

836

840

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

^[5]

2,489

2,402

Inventory

$ 83

$ 90

[1]	Exelon’s consolidated assets include $9,727 million and $9,597 million at March 31, 2018 and December 31, 2017, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $3,556 million and $3,618 million at March 31, 2018 and December 31, 2017, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 3 — Variable Interest Entities.
[2]	Includes certain purchase accounting adjustments not pushed down to the ACE standalone entity.
[3]	Generation’s consolidated assets include $9,688 million and $9,556 million at March 31, 2018 and December 31, 2017, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $3,461 million and $3,516 million at March 31, 2018 and December 31, 2017, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 3 — Variable Interest Entities.
[4]	PHI’s consolidated total assets include $39 million and $41 million at March 31, 2018 and December 31, 2017, respectively, of PHI's consolidated VIE that can only be used to settle the liabilities of the VIE. PHI’s consolidated total liabilities include $95 million and $102 million at March 31, 2018 and December 31, 2017, respectively, of PHI's consolidated VIE for which the VIE creditors do not have recourse to PHI. See Note 3 — Variable Interest Entities.
[5]	ACE’s consolidated total assets include $27 million and $29 million at March 31, 2018 and December 31, 2017, respectively, of ACE's consolidated VIE that can only be used to settle the liabilities of the VIE. ACE’s consolidated total liabilities include $83 million and $90 million at March 31, 2018 and December 31, 2017, respectively, of ACE's consolidated VIE for which the VIE creditors do not have recourse to ACE. See Note 3 — Variable Interest Entities.

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

Mar. 31, 2018

Dec. 31, 2017

^[1]

$ 1,127

$ 1,134

Exelon's ownership interest in VIE

^[1]

262

265

^[1]

246

251

^[1]

618

Carrying amount of equity method investments

Contract intangible asset

246

251

Net assets pledged for Zion Station decommissioning(b)

Commercial Agreement Variable Interest Entities [Member]

^[2]

^[1]

626

625

Exelon's ownership interest in VIE

^[1]

^[1]

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

^[1]

588

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

Commercial Agreement Variable Interest Entities [Member] | Net assets pledged for Zion Station decommissioning(b)

Equity Investment VIE [Member]

^[2]

^[1]

501

509

Exelon's ownership interest in VIE

^[1]

225

228

^[1]

246

251

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

^[1]

Equity Investment VIE [Member] | Contract intangible asset

246

251

Equity Investment VIE [Member] | Net assets pledged for Zion Station decommissioning(b)

^[2]

Held-to-maturity Securities Pledged as Collateral

^[3]

Accounts Payable, Interest-bearing, Noncurrent

^[4],[5]

$ 28

$ 37

[1]	These items represent amounts on the unconsolidated VIE balance sheets, not on Exelon’s or Generation’s Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs.
[2]	These items represent amounts on Exelon’s and Generation’s Consolidated Balance Sheets related to the asset sale agreement with ZionSolutions, LLC. The net assets pledged for Zion Station decommissioning includes gross pledged assets of $30 million and $39 million as of March 31, 2018 and December 31, 2017, respectively; offset by payables to ZionSolutions, LLC of $28 million and $37 million as of March 31, 2018 and December 31, 2017, respectively. These items are included to provide information regarding the relative size of the ZionSolutions, LLC unconsolidated VIE. See Note 13 — Nuclear Decommissioning for additional details.
[3]	Included in Other current assets within Exelon's and Generation's Consolidated Balance sheets.
[4]	Excludes a liability recorded within Exelon’s and Generation’s Consolidated Balance Sheets related to the tax obligation on the unrealized activity associated with the Zion Station NDT funds. The NDT funds will be utilized to satisfy the tax obligations as gains and losses are realized.
[5]	Included in Other current liabilities within Exelon’s and Generation’s Consolidated Balance Sheets.

Mergers, Acquisitions, and Dispositions - Narrative (Details) - USD ($) $ in Millions				3 Months Ended			12 Months Ended
	Apr. 04, 2018	Feb. 28, 2018	Mar. 31, 2017	Mar. 31, 2018	Sep. 30, 2017	Mar. 31, 2017	Dec. 31, 2017
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross				$ 0		$ 212
Bargain Purchase Gain				0		226
Fitzpatrick [Member]
Business Acquisition [Line Items]
Bargain Purchase Gain					$ 7	226	$ 233
Business Combination, Integration Related Costs						32
Exelon Generation Co L L C [Member]
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross		$ 87		0		212
Bargain Purchase Gain				$ 0		226
Exelon Generation Co L L C [Member] \| Subsequent Event [Member]
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross	$ 62
Exelon Generation Co L L C [Member] \| Fitzpatrick [Member]
Business Acquisition [Line Items]
Business Combination, Consideration Transferred			$ 289				289
Business Combination, Consideration Transferred, Other			179
Bargain Purchase Gain					$ 7	226	233
Business Combination, Integration Related Costs						$ 32
Exelon Generation Co L L C [Member] \| Fitzpatrick [Member] \| Cash and Cash Equivalents [Member]
Business Acquisition [Line Items]
Business Combination, Consideration Transferred			$ 110				110
Business Combination, Consideration Transferred, Other							$ 125

Mergers, Acquisitions, and Dispositions Purchase Price Allocation Table - FitzPatrick (Details) - USD ($)
$ in Millions

3 Months Ended

12 Months Ended

Mar. 31, 2017

Mar. 31, 2018

Sep. 30, 2017

Mar. 31, 2017

Dec. 31, 2017

$ 0

$ 226

Fitzpatrick [Member]

$ 7

226

$ 233

Exelon Generation Co L L C [Member] | Fitzpatrick [Member]

$ 0

226

Business Combination, Consideration Transferred

$ 289

289

Business Combination, Consideration Transferred, Other

179

Current assets

Property, plant and equipment

298

807

Other assets

^[1]

114

Nuclear decommissioning ARO

1,279

Current liabilities

444

Pension and OPEB obligations

Deferred income taxes

149

Spent nuclear fuel obligation

110

Other liabilities

Total net identifiable assets, at fair value

757

522

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Other Noncurrent Assets

$ 7

$ 226

233

110

Exelon Generation Co L L C [Member] | Fitzpatrick [Member] | Cash and Cash Equivalents [Member]

Business Combination, Consideration Transferred

$ 110

110

Business Combination, Consideration Transferred, Other

125

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

Business Combination, Consideration Transferred, Other

$ 54

[1]

Includes a $110 million asset associated with a contractual right to reimbursement from the New York Power Authority (NYPA), a prior owner of FitzPatrick, associated with the DOE one-time fee obligation. See Note 23-Commitments and Contingencies of the Exelon 2017 Form 10-K for additional background regarding SNF obligations to the DOE.

Revenue from Contracts with Customers Contract Assets and Liabilites (Details) - Exelon Generation Co L L C [Member] - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Change in Contract with Customer, Asset and Liability [Abstract]
Contract with Customer, Asset, Net, Current	$ 302		$ 283
Contract with Customer, Asset, Cumulative Catch-up Adjustment to Revenue, Change in Measure of Progress	28
Contract with Customer, Liability, Change in Timeframe, Performance Obligation Satisfied, Revenue Recognized	(216)
Contract with Customer, Liability, Cumulative Catch-up Adjustment to Revenue, Change in Measure of Progress	227
Contract with Customer, Liability, Current	46		35
Contract with Customer, Asset, Reclassified to Receivable	(9)
Capitalized Contract Cost, Net [Abstract]
Capitalized Contract Cost, Gross	25		$ 26
Capitalized Contract Cost, Amortization	$ 5	$ 9

Regulatory Matters - Narrative (Details) - USD ($) $ in Millions																						3 Months Ended		12 Months Ended	48 Months Ended
	Apr. 20, 2018	Apr. 17, 2018	Mar. 29, 2018	Mar. 26, 2018	Mar. 17, 2018	Mar. 08, 2018	Mar. 02, 2018	Feb. 09, 2018	Feb. 06, 2018	Feb. 05, 2018	Jan. 31, 2018	Jan. 18, 2018	Jan. 02, 2018	Dec. 19, 2017	Dec. 18, 2017	Nov. 16, 2017	Nov. 07, 2017	Oct. 18, 2017	Aug. 17, 2017	Jul. 14, 2017	May 01, 2017	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2022	Dec. 31, 2017	Apr. 21, 2016
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Assets																						$ 9,308.0				$ 9,288.0
Regulatory Liabilities																						10,246.0				10,388.0
Revenues																						9,693.0	$ 8,747.0
Payments to Acquire Property, Plant, and Equipment																						1,880.0	2,009.0
Maximum [Member] \| One-Time Revenue Adjustment [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Amount of Impairment to Carrying Amount of Regulatory Assets																						82.0
Exelon Generation Co L L C [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Revenues																						5,512.0	4,878.0
Payments to Acquire Property, Plant, and Equipment																						628.0	625.0
License Costs																						32.0
Exelon Generation Co L L C [Member] \| Minimum [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Purchase Obligation																											$ 3.0
Exelon Generation Co L L C [Member] \| Maximum [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Purchase Obligation																											$ 7.0
Commonwealth Edison Co [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Assets																						1,351.0				1,279.0
Regulatory Liabilities																						6,424.0				6,577.0
Tax Savings From Tax Cuts and Jobs Act												$ 201.0
Revenues																						1,512.0	1,298.0
Payments to Acquire Property, Plant, and Equipment																						531.0	626.0
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																						41.0
Commonwealth Edison Co [Member] \| Subsequent Event [Member] \| Electric Distribution [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount																								$ 23.0
Public Utilities, Requested Increase (Decrease), Amount																								58.0
Public Utilities, Approved Rate Increase (Decrease), Amount																								$ 35.0
Public Utilities, Requested Equity Capital Structure, Percentage																								6.52%
Public Utilities, Requested Rate Increase (Decrease), Percentage																								8.69%
Public Utilities, Approved Equity Capital Structure, Percentage																								6.52%
Public Utilities, Approved Rate Increase (Decrease), Percentage																								8.69%
PECO Energy Co [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Assets																						486.0				410.0
Regulatory Liabilities																						646.0				690.0
Tax Savings From Tax Cuts and Jobs Act			$ 71.0
Revenues																						866.0	796.0
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount																					$ 22.0
Public Utilities, Requested Equity Capital Structure, Percentage																					11.00%
Payments to Acquire Property, Plant, and Equipment																						217.0	201.0
PECO Energy Co [Member] \| Gas Distribution [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Tax Savings From Tax Cuts and Jobs Act											$ 4.0
PECO Energy Co [Member] \| Electric Distribution [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Tax Savings From Tax Cuts and Jobs Act											68.0
Public Utilities, Requested Increase (Decrease), Amount			$ 82.0
Public Utilities, Requested Equity Capital Structure, Percentage			10.95%
Baltimore Gas and Electric Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Assets																						540.0				571.0
Regulatory Liabilities																						1,185.0				1,163.0
Tax Savings From Tax Cuts and Jobs Act											103.0
Revenues																						977.0	951.0
Payments to Acquire Property, Plant, and Equipment																						224.0	206.0
Baltimore Gas and Electric Company [Member] \| Gas Distribution [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Tax Savings From Tax Cuts and Jobs Act											31.0
Baltimore Gas and Electric Company [Member] \| Electric Distribution [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Tax Savings From Tax Cuts and Jobs Act											$ 72.0
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																						22.0
Pepco Holdings LLC [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Assets																						2,960.0				3,047.0
Regulatory Liabilities																						1,965.0				1,928.0
Revenues																						1,251.0	1,175.0
Payments to Acquire Property, Plant, and Equipment																						258.0	320.0
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																						19.0
Potomac Electric Power Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Assets																						863.0				891.0
Regulatory Liabilities																						845.0				832.0
Revenues																						557.0	530.0
Payments to Acquire Property, Plant, and Equipment																						127.0	139.0
Potomac Electric Power Company [Member] \| Electric Distribution [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Tax Savings From Tax Cuts and Jobs Act									$ 39.0
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount						$ 3.0
Public Utilities, Requested Increase (Decrease), Amount										$ 11.0			$ 41.0	$ 66.0
Public Utilities, Requested Return on Equity, Percentage														10.10%
Public Utilities, Requested Rate Increase (Decrease), Percentage													10.10%
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																						9.0
Potomac Electric Power Company [Member] \| Subsequent Event [Member] \| Electric Distribution [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Tax Savings From Tax Cuts and Jobs Act Through Effective Date		$ 19.0
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount	$ 15.0	$ 24.0
Public Utilities, Requested Return on Equity, Percentage		9.50%
Public Utilities, Requested Rate Increase (Decrease), Percentage	9.50%
Public Utilities, Rate Credit	$ 10.0
Delmarva Power and Light Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Assets																						305.0				314.0
Regulatory Liabilities																						646.0				635.0
Tax Savings From Tax Cuts and Jobs Act								$ 26.0
Revenues																						384.0	362.0
Public Utilities, Requested Return on Equity, Percentage																			10.10%
Public Utilities, Interim Rate Increase (Decrease), Amount																		$ 2.5
Payments to Acquire Property, Plant, and Equipment																						65.0	82.0
Delmarva Power and Light Company [Member] \| Gas Distribution [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Tax Savings From Tax Cuts and Jobs Act								7.0
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount																	$ 11.0
Public Utilities, Requested Increase (Decrease), Amount																			$ 13.0
Public Utilities, Interim Rate Increase (Decrease), Amount					$ 1.0
Delmarva Power and Light Company [Member] \| Electric Distribution [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Tax Savings From Tax Cuts and Jobs Act								19.0
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount																$ 19.0		$ 31.0
Public Utilities, Requested Increase (Decrease), Amount																			$ 24.0	$ 27.0
Public Utilities, Approved Rate Increase (Decrease), Amount															$ 13.0
Public Utilities, Requested Return on Equity, Percentage																				10.10%
Public Utilities, Approved Return on Equity, Percentage															9.50%
Public Utilities, Interim Rate Increase (Decrease), Amount					$ 3.0
Delmarva Power and Light Company [Member] \| Electric Distribution [Member] \| Maryland Service Territory [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Tax Savings From Tax Cuts and Jobs Act								$ 13.0		31.0												14.0
Public Utilities, Rate Credit																						2.0
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																						7.0
Atlantic City Electric Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Assets																						441.0				430.0
Regulatory Liabilities																						437.0				422.0
Tax Savings From Tax Cuts and Jobs Act							$ 23.0
Revenues																						310.0	275.0
Payments to Acquire Property, Plant, and Equipment																						63.0	$ 88.0
Atlantic City Electric Company [Member] \| Electric Distribution [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount				$ 13.0						$ 19.0
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																						3.0
Atlantic City Electric Company [Member] \| Subsequent Event [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Payments to Acquire Property, Plant, and Equipment																									$ 338.0
Zero Emission Standard [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Liabilities																						8.0				112.0
Zero Emission Standard [Member] \| Exelon Generation Co L L C [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Revenues																						202.0
Other Revenue, Net																						150.0
Zero Emission Standard [Member] \| Commonwealth Edison Co [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Liabilities																						8.0				112.0
Zero Emission Standard [Member] \| PECO Energy Co [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Liabilities																						0.0				0.0
Zero Emission Standard [Member] \| Baltimore Gas and Electric Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Liabilities																						0.0				0.0
Zero Emission Standard [Member] \| Pepco Holdings LLC [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Liabilities																						0.0				0.0
Zero Emission Standard [Member] \| Potomac Electric Power Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Liabilities																						0.0				0.0
Zero Emission Standard [Member] \| Delmarva Power and Light Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Liabilities																						0.0				0.0
Zero Emission Standard [Member] \| Atlantic City Electric Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Liabilities																						$ 0.0				$ 0.0

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

Mar. 31, 2018

Dec. 31, 2017

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

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

$ 69

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 Regulatory Matters - Purchase of Receivables Programs (Details) - USD ($)
$ in Millions

3 Months Ended

12 Months Ended

Mar. 31, 2018

Dec. 31, 2017

$ 317

$ 298

^[1]

(35)

(31)

282

267

^[1]

(16)

(14)

^[1]

(6)

(5)

^[1]

(4)

(3)

^[1]

(9)

^[1]

(5)

^[1]

(1)

^[1]

(3)

$ 17

$ 15

[1]	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 its Purchase of Receivables with Consolidated Billing tariff.

Impairment of Long-Lived Assets (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Capital Leases, Net Investment in Direct Financing Leases [Abstract]
Property, plant and equipment, net	$ 74,711		$ 74,202
Impairment of long-lived assets and losses on regulatory assets	$ 0	$ 10

Early Nuclear Plant Retirements Early Nuclear Plant Retirements - Narrative (Details) - USD ($)
$ in Millions

3 Months Ended

12 Months Ended

Mar. 31, 2018

Dec. 31, 2017

Sep. 30, 2017

Jun. 30, 2017

Dec. 31, 2017

Facility Closing [Member] | Mystic Generating Station [Member]

$ 74,711

$ 74,202

Inventory, Raw Materials, Gross

Nuclear Fuel, Net of Amortization

Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress

896

Prepaid Expense

^[1]

Asset Retirement Obligation

(5)

Accrued Liabilities

^[1]

(2)

Facility Closing [Member] | Salem [Member]

Inventory, Raw Materials, Gross

Nuclear Fuel, Net of Amortization

102

Asset Retirement Obligation

618

(446)

Facility Closing [Member] | Three Mile Island [Member]

Facility Closing [Member] | TMI,OysterCreek [Member]

114

$ 117

$ 108

339

178

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

$ 24,714

$ 24,906

Jointly Owned Utility Plant, Proportionate Ownership Share

42.59%

[1]	(a)Reflects ending balances only as they relate to Mystic's Long-term Service Agreement.

Early Nuclear Plant Retirements Early Nuclear Plant Retirement - Pretax Expense (Details) - USD ($)
$ in Millions

3 Months Ended

12 Months Ended

Mar. 31, 2018

Dec. 31, 2017

Sep. 30, 2017

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2017

$ 74,711

$ 74,202

Facility Closing [Member] | Salem [Member]

(28)

$ 257

Inventory, Raw Materials, Gross

Nuclear Fuel, Net of Amortization

102

Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress

618

Asset Retirement Obligation

(446)

Facility Closing [Member] | Three Mile Island [Member]

Restructuring and Related Cost, Accelerated Depreciation

^[1],[2]

109

$ 106

$ 35

250

Nuclear Fuel Amortization

^[2]

Other Cost and Expense, Operating

^[3]

Facility Closing [Member] | TMI,OysterCreek [Member]

$ 114

$ 117

$ 108

$ 339

Restructuring and Related Cost, Accelerated Depreciation

^[4],[5]

137

Nuclear Fuel Amortization

^[4]

Other Cost and Expense, Operating

^[6]

Fair Value, Inputs, Level 3 [Member]

$ 178

[1]	Reflects incremental accelerated depreciation of plant assets, including any ARC.
[2]	Reflects incremental charges for TMI including incremental accelerated depreciation and amortization from May 30, 2017 through December 31, 2017.
[3]	Primarily includes materials and supplies inventory reserve adjustments, employee related costs and CWIP impairments.
[4]	Reflects incremental accelerated depreciation and amortization for TMI for the quarter ended March 31, 2018, and for Oyster Creek from February 2, 2018 through March 31, 2018.
[5]	Reflects incremental accelerated depreciation of plant assets, including any ARC.
[6]	Primarily includes materials and supplies inventory reserve adjustments, employee related costs and CWIP impairments.

Intangibles Intangibles - Narrative (Details) - USD ($) $ in Millions	Mar. 31, 2018	Sep. 30, 2015
Finite-Lived Intangible Assets, Gross [Abstract]
Finite-Lived Intangible Assets, Gross	$ 25	$ 25

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, 2018

Mar. 31, 2017

Dec. 31, 2017

Dec. 31, 2016

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

$ (1,335)

$ (1,046)

$ (1,015)

$ (993)

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Earnings

186

(38)

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Noncurrent Payables To Affiliates

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Gain Loss Included In Nuclear Decommissioning Payable

(4)

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Regulatory assets

(4)

(15)

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Gain Loss Change In Collateral

105

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

(90)

(89)

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

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

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

(48)

(23)

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Transfers Into Level 3

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers out of Level 3

(2)

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

(258)

(62)

Fair Value, Inputs, Level 3 [Member] | Consolidation, Eliminations [Member]

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Noncurrent Payables To Affiliates

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Regulatory assets

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

(72)

(102)

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

(1,579)

(1,308)

(1,249)

(1,231)

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Earnings

185

(39)

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Noncurrent Payables To Affiliates

(7)

(9)

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Gain Loss Included In Nuclear Decommissioning Payable

(4)

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Regulatory assets

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Gain Loss Change In Collateral

105

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

(90)

(89)

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

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

(48)

(23)

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Transfers Into Level 3

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers out of Level 3

(2)

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

(257)

(61)

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

(609)

(683)

(648)

(677)

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Earnings

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Noncurrent Payables To Affiliates

(7)

(9)

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Gain Loss Included In Nuclear Decommissioning Payable

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Regulatory assets

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Gain Loss Change In Collateral

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

(2)

(17)

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

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

(48)

(23)

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Transfers Into Level 3

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers out of Level 3

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

(2)

Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Pledged Assets For Zion Station Decommissioning [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

(16)

(20)

(12)

(19)

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Earnings

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Noncurrent Payables To Affiliates

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Gain Loss Included In Nuclear Decommissioning Payable

(4)

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Regulatory assets

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Gain Loss Change In Collateral

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

(1)

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

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

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Transfers Into Level 3

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers out of Level 3

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

(918)

(565)

(552)

(493)

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Earnings

^[1]

184

(43)

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Noncurrent Payables To Affiliates

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Gain Loss Included In Nuclear Decommissioning Payable

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Regulatory assets

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Gain Loss Change In Collateral

105

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

(88)

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

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

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Transfers Into Level 3

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers out of Level 3

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

(256)

(59)

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

(36)

(40)

(37)

(42)

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Earnings

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Noncurrent Payables To Affiliates

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Gain Loss Included In Nuclear Decommissioning Payable

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Regulatory assets

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Gain Loss Change In Collateral

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

(2)

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

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

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Transfers Into Level 3

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers out of Level 3

(2)

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

(1)

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)

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

267

(282)

256

(258)

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Earnings

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Noncurrent Payables To Affiliates

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Gain Loss Included In Nuclear Decommissioning Payable

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Regulatory assets

^[2]

(11)

(24)

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Gain Loss Change In Collateral

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

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

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

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Transfers Into Level 3

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers out of Level 3

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)

(17)

(30)

Pepco Holdings LLC [Member] | Fair Value, Inputs, Level 3 [Member] | 6311 Life Insurance [Member] | Successor [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

^[3]

(23)

(20)

$ (22)

$ (20)

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Earnings

^[3]

(1)

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Noncurrent Payables To Affiliates

^[3]

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Gain Loss Included In Nuclear Decommissioning Payable

^[3]

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Regulatory assets

^[3]

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Gain Loss Change In Collateral

^[3]

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

^[3]

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

^[3]

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

^[3]

(1)

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

^[3]

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Transfers Into Level 3

^[3]

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers out of Level 3

^[3]

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

^[3]

$ (1)

[1]	Includes a reduction for the reclassification of $72 million and $102 million of realized gains due to the settlement of derivative contracts for the three months ended March 31, 2018 and March 31, 2017, respectively.
[2]	Includes $17 million of decreases 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. Includes $30 million of decreases 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, 2017.
[3]	The amounts represented are life insurance contracts at Pepco.

Fair Value of Financial Assets and Liabilities Fair Value of Financial Assets and Liabilities - Narrative (Details) - USD ($)	Mar. 31, 2018	Dec. 31, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
EquitySecuritiesWithoutReadilyDeterminableFairValueAmount	$ 68,000,000
Derivative Instruments Not Designated as Hedging Instruments, Asset, at Fair Value	(2,000,000)	$ (1,000,000)
Spent Nuclear Fuel Obligation, Noncurrent	1,151,000,000	1,147,000,000
Forward Power Basis	2.99
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]
Spent Nuclear Fuel Obligation, Noncurrent	1,151,000,000	$ 1,147,000,000
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	208,000,000
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	65,000,000
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	386,000,000
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	194,000,000
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	$ 107,000,000

Fair Value of Financial Assets and Liabilities - Fair Value Assets And Liabilities Measured On Recurring Basis Gain Loss Included In Earnings (Details) - Fair Value, Inputs, Level 3 [Member] - USD ($)
$ in Millions

3 Months Ended

Mar. 31, 2018

Mar. 31, 2017

Fair Value Assets And Liabilities Measured On Recurring Basis Gain Loss Included In Earnings [Line Items]

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Earnings

$ (186)

$ 38

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

258

Operating Revenue [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis Gain Loss Included In Earnings [Line Items]

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Earnings

335

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

309

140

Purchased Power And Fuel [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis Gain Loss Included In Earnings [Line Items]

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Earnings

(151)

(131)

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

(53)

(81)

Other, net [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis Gain Loss Included In Earnings [Line Items]

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Earnings

^[1]

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

^[1]

Fair Value Assets And Liabilities Measured On Recurring Basis Gain Loss Included In Earnings [Line Items]

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Earnings

(185)

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

257

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

Fair Value Assets And Liabilities Measured On Recurring Basis Gain Loss Included In Earnings [Line Items]

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Earnings

335

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

309

140

Exelon Generation Co L L C [Member] | Purchased Power And Fuel [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis Gain Loss Included In Earnings [Line Items]

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Earnings

(151)

(131)

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

(53)

(81)

Exelon Generation Co L L C [Member] | Other, net [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis Gain Loss Included In Earnings [Line Items]

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Earnings

^[1]

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

^[1]

Pepco Holdings LLC [Member] | Other, net [Member] | Successor [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis Gain Loss Included In Earnings [Line Items]

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Earnings

^[1]

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

^[1]

6311 Life Insurance [Member] | Pepco Holdings LLC [Member] | Successor [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis Gain Loss Included In Earnings [Line Items]

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Earnings

^[2]

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

^[2]

$ 1

[1]	Other, net activity consists of realized and unrealized gains (losses) included in income for the NDT funds held by Generation, accrued interest on a convertible promissory note at Generation and the life insurance contracts held by PHI and Pepco.
[2]	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, 2018

Dec. 31, 2016

Dec. 31, 2017

$ 41,000,000

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

742,000,000

$ 497,000,000

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

186,000,000

81,000,000

Derivative Asset, Fair Value, Amount Not Offset Against Collateral

^[1],[2]

689,000,000

445,000,000

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

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

Forward gas price assets

1.12

1.27

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

202

124

Forward gas price assets

$ 12.80

12.80

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

Volatility percentage

9.67%

11.00%

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

Volatility percentage

226.91%

139.00%

Derivative Liability, Fair Value, Amount Not Offset Against Collateral

^[1],[2]

$ 43,000,000

(26,000,000)

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]

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

202

Derivative Asset, Fair Value, Amount Not Offset Against Collateral

$ (267,000,000)

$ (256,000,000)

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

Derivatives Fair Value Footnotes [Abstract]

Forward heat rate

900.00%

800.00%

^[3]

Fair Value Inputs, Discount for Lack of Marketability

4.00%

Fair Value Inputs Renewable Factor

87.00%

88.00%

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

Derivatives Fair Value Footnotes [Abstract]

Forward heat rate

1000.00%

900.00%

^[3]

Fair Value Inputs, Discount for Lack of Marketability

8.00%

Fair Value Inputs Renewable Factor

122.00%

120.00%

[1]	The fair values do not include cash collateral posted on level three positions of $186 million and $81 million as of March 31, 2018 and December 31, 2017, 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 Derivative Financial Instruments - Summary of Derivative Fair Value Balances (Details) - USD ($)
$ in Millions

Mar. 31, 2018

Dec. 31, 2017

$ 978

$ 976

527

337

(415)

(232)

Derivative, Collateral, Right to Reclaim Cash

(468)

(409)

Margin Deposit Assets

(156)

117

Commodity Contract [Member]

976

973

515

331

1,491

1,304

(415)

(230)

(463)

(407)

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

(878)

(637)

613

667

978

976

527

334

(391)

(211)

Derivative Liability, Fair Value, Amount Offset Against Collateral

(221)

(174)

^[1]

(1,562)

(577)

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

976

^[2]

973

^[3]

515

^[2]

331

^[3]

1,491

^[2]

1,304

^[3]

(391)

^[2]

(209)

^[3]

(220)

^[2]

(172)

^[3]

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

(611)

^[2]

(381)

^[3]

880

^[2]

923

^[3]

(24)

(21)

Delmarva Power and Light Company [Member] | Commodity Contract [Member]

(243)

(235)

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

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

^[4]

(2,533)

^[5]

(2,144)

^[6]

^[4]

(1,286)

^[5]

(845)

^[6]

^[4]

(3,819)

^[5]

(2,989)

^[6]

^[4]

2,945

^[5]

2,480

^[6]

^[4]

1,558

^[5]

975

^[6]

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

^[4]

4,503

^[5]

3,455

^[6]

^[4]

684

^[5]

466

^[6]

Collateral And Netting [Member] | Delmarva Power and Light Company [Member] | Commodity Contract [Member]

^[4]

^[4]

^[4]

^[4]

^[4]

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

^[4]

^[4]

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

3,343

3,061

1,758

1,164

5,101

4,225

(3,185)

(2,646)

(1,750)

(1,137)

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

(4,935)

(3,783)

166

442

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

^[7]

^[7]

^[7]

^[7]

(24)

(21)

^[7]

(243)

(235)

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

^[7]

(267)

(256)

^[7]

(267)

(256)

Not Designated as Hedging Instrument, Economic Hedge [Member] | Delmarva Power and Light Company [Member] | Commodity Contract [Member]

^[8]

^[8]

^[8]

^[8]

(1)

^[8]

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

^[8]

(1)

^[8]

(1)

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

166

209

(151)

(43)

(28)

(10)

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

(179)

(53)

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

Derivative Liability, Collateral, Right to Reclaim Cash, Offset

(684)

(466)

Current liabilities collateral offset

220

167

Noncurrent liabilities collateral offset

169

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

Derivative, Collateral, Right to Reclaim Cash

192

169

Margin Deposit Assets

156

Derivative Liability, Fair Value, Amount Offset Against Collateral

(117)

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

Derivative, Collateral, Right to Reclaim Cash

$ 103

$ 53

[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 $192 million and $103 million, respectively, and current and noncurrent liabilities are shown net of collateral of $220 million and $169 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $684 million at March 31, 2018.
[3]	Current and noncurrent assets are shown net of collateral of $169 million and $53 million, respectively, and current and noncurrent liabilities are shown net of collateral of $167 million and $77 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $466 million at December 31, 2017.
[4]	Exelon, Generation and DPL net all available amounts allowed under the derivative authoritative guidance on 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), $156 million represents variation margin on the exchanges.
[6]	Of the collateral posted/(received), $(117) million represents variation margin on the exchanges.
[7]	Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.
[8]	Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC.

Derivative Financial Instruments - Summary of Economic Hedges (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	$ (259)	$ (47)
Exelon Generation Co L L C [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	(264)	(51)
Not Designated as Hedging Instrument, Economic Hedge [Member] \| Foreign Exchange Contract [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	1	(2)
Not Designated as Hedging Instrument, Economic Hedge [Member] \| Foreign Exchange Contract [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	1	(2)
Not Designated as Hedging Instrument, Economic Hedge [Member] \| Foreign Exchange Contract [Member] \| Operating Revenue [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	2	(2)
Not Designated as Hedging Instrument, Economic Hedge [Member] \| Foreign Exchange Contract [Member] \| Purchased Power And Fuel [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	(1)	0
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	(267)	(47)
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	(100)	46
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	$ (167)	$ (93)

Derivative Financial Instruments - Summary of Proprietary Trading Activities (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	$ (259)	$ (47)
Exelon Generation Co L L C [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	(264)	(51)
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	(1)
Not Designated as Hedging Instrument [Member] \| Operating Revenue [Member] \| Exelon Generation Co L L C [Member] \| Foreign Exchange Contract [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	$ 0	$ (1)

Derivative Financial Instruments - Summary of Interest Rate and Foreign Currency Hedges (Details) - USD ($)
$ in Millions

Mar. 31, 2018

Dec. 31, 2017

$ 978

$ 976

527

337

(415)

(232)

(468)

(409)

978

976

527

334

(391)

(211)

InterestRateAndForeignExchangeContract [Member]

(221)

(174)

(2)

(5)

(2)

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

(5)

(4)

InterestRateAndForeignExchangeContract [Member] | Exelon Generation Co L L C [Member]

(2)

(1)

(2)

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

(1)

(4)

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

^[1]

(3)

(7)

^[1]

(1)

^[1]

(4)

(7)

^[1]

^[1]

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

^[1]

^[1]

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

(2)

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

(2)

Designated as Hedging Instrument [Member] | InterestRateAndForeignExchangeContract [Member] | Corporate, Non-Segment [Member]

(4)

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

(4)

(4)

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

(3)

(7)

(2)

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

(5)

(9)

$ 1

[1]

Derivative Financial Instruments - Summary of AOCI related to Cash Flow Hedges (Details) - USD ($)
$ in Millions

3 Months Ended

Mar. 31, 2018

Mar. 31, 2017

$ (3,026)

(2,965)

$ 211

Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member]

(44)

(40)

Cash Flow Hedging [Member]

^[1],[2]

(4)

(14)

(17)

Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net

(6)

(11)

(37)

(34)

123

Exelon Generation Co L L C [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member]

(4)

Exelon Generation Co L L C [Member] | Cash Flow Hedging [Member]

^[1],[2]

(4)

(16)

(19)

Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net

(9)

(13)

$ 7

Interest Expense [Member] | Cash Flow Hedging [Member]

Interest Expense [Member] | Exelon Generation Co L L C [Member] | Cash Flow Hedging [Member]

^[3]

Reclassification out of Accumulated Other Comprehensive Income [Member] | Cash Flow Hedging [Member]

^[3]

Reclassification out of Accumulated Other Comprehensive Income [Member] | Cash Flow Hedging [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member]

Reclassification out of Accumulated Other Comprehensive Income [Member] | Exelon Generation Co L L C [Member] | Cash Flow Hedging [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member]

^[4]

^[4]

$ 3

[1]	All amounts are net of tax and noncontrolling interest. Amounts in parenthesis represent a decrease in AOCI.
[2]	See next tables for details about these reclassifications.
[3]	Amount is net of related income tax expense of $3 million for the three months ended March 31, 2017.
[4]	Amounts in parenthesis represent a decrease in net income.

Derivative Financial Instruments - Summary of Gains and Losses on Hedges (Details) - Interest Expense [Member] - Fair Value Hedging [Member] - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Interest Rate Swap [Member]
Derivative [Line Items]
Gain (loss) on Swaps	$ (7)	$ (4)
Price Risk Derivative [Member]
Derivative [Line Items]
Gain (loss) on Borrowings	$ 13	$ 8

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

Mar. 31, 2018

Dec. 31, 2017

$ 41

Letters Of Credit Posted

Investor-owned utilities, marketers and power producers

Financial institutions

189

656

Energy Cooperatives And Municipalities

438

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

742

$ 497

Letters Of Credit Posted

493

$ 293

986

No external ratings - internally rated - investment grade

112

223

No external ratings - internally rated - non-investment grade

100

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

1,421

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]

985

No external ratings - internally rated - investment grade

223

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]

1,357

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]

412

No external ratings - internally rated - investment grade

No external ratings - internally rated - non-investment grade

$ 412

[1]	As of March 31, 2018, credit collateral held from counterparties where Generation had credit exposure included $41 million of cash and $23 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, 2018

Dec. 31, 2017

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

^[1]

$ (2,141)

$ (926)

Contractual right of offset related to derivative assets

^[2]

1,562

577

Net liability position after contractual right of offset

^[3]

$ (579)

$ (349)

[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, 2018	Mar. 31, 2017	Dec. 31, 2017
Derivative [Line Items]
Ineffective portion recognized in income	$ 6,000	$ 4,000
Cash collateral posted	41,000
Letters of credit posted	23,000
Exelon Generation Co L L C [Member]
Derivative [Line Items]
Cash collateral received not offset against net derivative positions	(8,000)		$ 4,000
Cash collateral posted	742,000		497,000
Letters of credit held	46,000		33,000
Letters of credit posted	493,000		293,000
Cash collateral held	66,000		35,000
Incremental collateral for loss of investment grade credit rating	1,900,000		1,800,000
Interest Rate Fair Value Hedge Asset at Fair Value	13,000
Commonwealth Edison Co [Member]
Derivative [Line Items]
Incremental collateral for loss of investment grade credit rating	10,000
Credit Exposure Under Off System Sales	$ 1,000
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	$ 33,000
Baltimore Gas and Electric Company [Member]
Derivative [Line Items]
Incremental collateral for loss of investment grade credit rating	49,000
Credit Exposure Under Off System Sales	12,000
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	91.00%
Expected Generation Hedged In Year Two	63.00%
Expected generation hedged in year three	33.00%
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	94.00%
Expected Generation Hedged In Year Two	66.00%
Expected generation hedged in year three	36.00%
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	19
Foreign Exchange Contract [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Derivative, Notional Amount	$ 87,000		94,000
Energy Related Derivative [Member] \| Commonwealth Edison Company [Member]
Derivative [Line Items]
Credit Derivative, Collateral Held Directly or by Third Parties	9
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	14
InterestRateAndForeignExchangeContract [Member]
Derivative [Line Items]
Derivative, Fair Value, Net	$ 9,000		5,000
InterestRateAndForeignExchangeContract [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Derivative, Fair Value, Net	13,000		2,000
Fair Value Hedging [Member] \| Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	800,000		800,000
Commonwealth Edison Co Affiliate [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Net receivable from electric utility	31,000
PECO Energy Co Affiliate [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Net receivable from affiliated electric and gas utility	21,000
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	25,000
Potomac Electric Power Company [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Net receivable from electric utility	34,000
Delmarva Power and Light Company [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Net receivable from electric utility	9,000
Atlantic City Electric Company [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Net receivable from electric utility	5,000
Designated as Hedging Instrument [Member] \| InterestRateAndForeignExchangeContract [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Derivative, Fair Value, Net	12,000		1,000
Designated as Hedging Instrument [Member] \| Cash Flow Hedging [Member] \| Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	$ 636,000		$ 636,000

Derivative Financial Instruments Schedule of Notional Amounts Outstanding (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Cash Flow Hedging [Member] \| Designated as Hedging Instrument [Member] \| Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	$ 636	$ 636
Fair Value Hedging [Member] \| Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	800	800
Exelon Generation Co L L C [Member] \| Foreign Exchange Contract [Member]
Derivative [Line Items]
Derivative, Notional Amount	$ 87	$ 94

Debt and Credit Agreements - Commercial Paper Borrowings (Details) - USD ($)
$ in Millions

Mar. 31, 2018

Dec. 31, 2017

$ 1,154

$ 427

165

317

220

^[1]

407

350

211

216

Effective Income Tax Rate Reconciliation, Percent [Abstract]

$ 136

$ 108

[1]	PHI reflects the commercial paper borrowings outstanding of Pepco, DPL and ACE.

Debt and Credit Agreements - Issuance of Long-Term Debt (Details)	Mar. 31, 2018 USD ($)
Exelon Generation Co L L C [Member] \| EEPF372Apr2018 [Member] \| Long-term Debt [Member]
Debt Instrument [Line Items]
Interest Rate	3.72%
Debt Instrument, Face Amount	$ 1,000,000
Exelon Generation Co L L C [Member] \| EEPF317Apr2018 [Member] \| Long-term Debt [Member]
Debt Instrument [Line Items]
Interest Rate	3.17%
Debt Instrument, Face Amount	$ 1,000,000
Exelon Generation Co L L C [Member] \| EEPF261Sep2018 [Member] \| Long-term Debt [Member]
Debt Instrument [Line Items]
Interest Rate	2.61%
Debt Instrument, Face Amount	$ 2,000,000
Commonwealth Edison Co [Member] \| FMB400Mar2048Member \| First Mortgage [Member]
Debt Instrument [Line Items]
Interest Rate	4.00%
Debt Instrument, Face Amount	$ 800,000,000
PECO Energy Co [Member] \| FRMB390Mar2048 [Member] \| First Mortgage [Member]
Debt Instrument [Line Items]
Interest Rate	3.90%
Debt Instrument, Face Amount	$ 325,000,000

Debt and Credit Agreements - Narrative (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 15, 2018	Mar. 23, 2017	Jan. 13, 2016
Corporate, Non-Segment [Member]
Debt Instrument [Line Items]
Short-term Bank Loans and Notes Payable			$ 500
Debt Instrument, Interest Rate Terms	LIBOR plus 1%
Exelon Generation Co L L C [Member] \| Line of Credit [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity		$ 30
Line of Credit Facility, Maximum Borrowing Capacity		$ 95
Pepco Holdings LLC [Member]
Debt Instrument [Line Items]
Short-term Bank Loans and Notes Payable				$ 500
Debt Instrument, Interest Rate Terms	LIBOR plus 1%

Income Taxes - Reconciliation to Effective Tax Rate (Details)

3 Months Ended

12 Months Ended

Mar. 31, 2018

Mar. 31, 2017

Dec. 31, 2018

Dec. 31, 2017

21.00%

35.00%

21.00%

35.00%

State income taxes, net of Federal income tax benefit

4.10%

0.90%

Qualified nuclear decommissioning trust fund income

(0.40%)

3.50%

Amortization of investment tax credit, including deferred taxes on basis difference

(1.30%)

(0.40%)

(2.70%)

(2.40%)

(2.80%)

(0.70%)

Effective Income Tax Rate Reconciliation, Tax Settlement, Other, Percent

(0.70%)

0.00%

(6.00%)

^[1]

(11.50%)

(6.60%)

(2.80%)

(0.10%)

8.40%

17.70%

Effective Income Tax Rate Reconciliation, Percent [Abstract]

21.00%

35.00%

State income taxes, net of Federal income tax benefit

2.40%

1.00%

Qualified nuclear decommissioning trust fund income

(1.30%)

7.80%

Amortization of investment tax credit, including deferred taxes on basis difference

(4.30%)

(0.70%)

0.00%

(9.50%)

(1.50%)

Effective Income Tax Rate Reconciliation, Tax Settlement, Other, Percent

(2.50%)

0.10%

0.00%

^[1]

(3.40%)

(14.80%)

(1.30%)

(0.40%)

4.50%

23.10%

Effective Income Tax Rate Reconciliation, Percent [Abstract]

21.00%

35.00%

State income taxes, net of Federal income tax benefit

8.20%

4.90%

Qualified nuclear decommissioning trust fund income

(0.00%)

Amortization of investment tax credit, including deferred taxes on basis difference

(0.20%)

0.10%

(0.20%)

(0.10%)

0.00%

Effective Income Tax Rate Reconciliation, Tax Settlement, Other, Percent

0.00%

(7.50%)

^[1]

0.00%

0.00%

0.30%

(0.00%)

21.80%

39.50%

Effective Income Tax Rate Reconciliation, Percent [Abstract]

21.00%

35.00%

State income taxes, net of Federal income tax benefit

(3.90%)

0.10%

Qualified nuclear decommissioning trust fund income

(0.00%)

Amortization of investment tax credit, including deferred taxes on basis difference

(0.10%)

(14.20%)

(13.20%)

0.00%

Effective Income Tax Rate Reconciliation, Tax Settlement, Other, Percent

0.00%

(4.80%)

^[1]

0.00%

0.00%

0.20%

0.30%

(1.80%)

22.10%

Effective Income Tax Rate Reconciliation, Percent [Abstract]

21.00%

35.00%

State income taxes, net of Federal income tax benefit

6.30%

5.20%

Qualified nuclear decommissioning trust fund income

(0.00%)

Amortization of investment tax credit, including deferred taxes on basis difference

(0.10%)

(0.70%)

(0.90%)

0.00%

Effective Income Tax Rate Reconciliation, Tax Settlement, Other, Percent

0.00%

(8.60%)

^[1]

0.00%

0.00%

(0.00%)

(0.20%)

17.90%

39.00%

Effective Income Tax Rate Reconciliation, Percent [Abstract]

21.00%

35.00%

State income taxes, net of Federal income tax benefit

1.70%

4.60%

Qualified nuclear decommissioning trust fund income

(0.00%)

Amortization of investment tax credit, including deferred taxes on basis difference

(0.10%)

(3.40%)

(5.80%)

0.00%

Effective Income Tax Rate Reconciliation, Tax Settlement, Other, Percent

0.00%

(12.80%)

^[1]

(34.20%)

0.00%

(0.30%)

0.50%

6.10%

0.00%

Effective Income Tax Rate Reconciliation, Percent [Abstract]

21.00%

35.00%

State income taxes, net of Federal income tax benefit

6.30%

5.30%

Qualified nuclear decommissioning trust fund income

(0.00%)

Amortization of investment tax credit, including deferred taxes on basis difference

(0.20%)

(0.30%)

(1.30%)

(1.90%)

0.00%

Effective Income Tax Rate Reconciliation, Tax Settlement, Other, Percent

0.00%

(7.90%)

^[1]

(21.90%)

0.00%

0.50%

(0.00%)

18.40%

16.20%

Effective Income Tax Rate Reconciliation, Percent [Abstract]

21.00%

35.00%

State income taxes, net of Federal income tax benefit

6.60%

5.60%

Qualified nuclear decommissioning trust fund income

(0.00%)

Amortization of investment tax credit, including deferred taxes on basis difference

(0.30%)

(0.40%)

(2.60%)

(3.40%)

0.00%

Effective Income Tax Rate Reconciliation, Tax Settlement, Other, Percent

0.00%

(8.70%)

^[1]

(167.10%)

0.00%

(3.50%)

(3.00%)

12.50%

(133.30%)

Effective Income Tax Rate Reconciliation, Percent [Abstract]

21.00%

35.00%

State income taxes, net of Federal income tax benefit

4.60%

4.90%

Qualified nuclear decommissioning trust fund income

(0.00%)

Amortization of investment tax credit, including deferred taxes on basis difference

(0.20%)

(2.60%)

(3.80%)

0.00%

Effective Income Tax Rate Reconciliation, Tax Settlement, Other, Percent

0.00%

(10.60%)

^[1]

(42.40%)

0.00%

(0.00%)

(0.40%)

12.20%

(6.90%)

[1]	Includes a remeasurement of uncertain state income tax positions for Pepco and DPL.

Income Taxes Income Tax Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Income Tax Contingency [Line Items]
Unrecognized Tax Benefits	$ 733	$ 743
Exelon Generation Co L L C [Member]
Income Tax Contingency [Line Items]
Unrecognized Tax Benefits	464	468
Commonwealth Edison Co [Member]
Income Tax Contingency [Line Items]
Unrecognized Tax Benefits	2	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	120	120
Pepco Holdings LLC [Member]
Income Tax Contingency [Line Items]
Unrecognized Tax Benefits	125	125
Potomac Electric Power Company [Member]
Income Tax Contingency [Line Items]
Unrecognized Tax Benefits	59	59
Delmarva Power and Light Company [Member]
Income Tax Contingency [Line Items]
Unrecognized Tax Benefits	21	21
Atlantic City Electric Company [Member]
Income Tax Contingency [Line Items]
Unrecognized Tax Benefits	$ 14	$ 14

Income Taxes Deferred Tax Revision (Details) - USD ($)
$ in Millions

3 Months Ended

Mar. 31, 2018

Dec. 31, 2017

$ 10,246

$ 10,388

6,424

6,577

646

690

1,185

1,163

1,965

1,928

845

832

646

635

RemeasurementOfDeferredIncomeTaxesDueToTaxReform [Member]

437

422

^[1]

8,624

^[1]

1,309

RemeasurementOfDeferredIncomeTaxesDueToTaxReform [Member] | Exelon Generation Co L L C [Member]

^[2]

7,315

1,895

RemeasurementOfDeferredIncomeTaxesDueToTaxReform [Member] | Commonwealth Edison Co [Member]

1,895

2,819

RemeasurementOfDeferredIncomeTaxesDueToTaxReform [Member] | PECO Energy Co [Member]

^[2]

2,818

1,407

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

^[2],[3]

1,394

1,120

(4)

RemeasurementOfDeferredIncomeTaxesDueToTaxReform [Member] | Pepco Holdings LLC [Member]

^[2]

1,124

1,944

(35)

RemeasurementOfDeferredIncomeTaxesDueToTaxReform [Member] | Potomac Electric Power Company [Member]

^[2]

1,979

968

(8)

RemeasurementOfDeferredIncomeTaxesDueToTaxReform [Member] | Delmarva Power and Light Company [Member]

^[2]

976

540

(5)

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

^[2]

545

456

(2)

NetRegulatoryLiabilitiesAssociatedWithUltimateSettlementToCustomersSubjectToIRSNormalizationRules [Member]

^[2]

$ 458

NetRegulatoryLiabilitiesAssociatedWithUltimateSettlementToCustomersSubjectToIRSNormalizationRules [Member] | Commonwealth Edison Co [Member]

3,040

NetRegulatoryLiabilitiesAssociatedWithUltimateSettlementToCustomersSubjectToIRSNormalizationRules [Member] | PECO Energy Co [Member]

1,400

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

^[4]

533

NetRegulatoryLiabilitiesAssociatedWithUltimateSettlementToCustomersSubjectToIRSNormalizationRules [Member] | Pepco Holdings LLC [Member]

459

NetRegulatoryLiabilitiesAssociatedWithUltimateSettlementToCustomersSubjectToIRSNormalizationRules [Member] | Potomac Electric Power Company [Member]

648

NetRegulatoryLiabilitiesAssociatedWithUltimateSettlementToCustomersSubjectToIRSNormalizationRules [Member] | Delmarva Power and Light Company [Member]

299

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

195

NetRegulatoryLiabilitiesAssociatedWithUltimateSettlementToCustomersSubjectToRateRegulatorDeterminations [Member]

153

NetRegulatoryLiabilitiesAssociatedWithUltimateSettlementToCustomersSubjectToRateRegulatorDeterminations [Member] | Commonwealth Edison Co [Member]

1,694

NetRegulatoryLiabilitiesAssociatedWithUltimateSettlementToCustomersSubjectToRateRegulatorDeterminations [Member] | PECO Energy Co [Member]

^[4]

573

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

^[4]

NetRegulatoryLiabilitiesAssociatedWithUltimateSettlementToCustomersSubjectToRateRegulatorDeterminations [Member] | Pepco Holdings LLC [Member]

324

NetRegulatoryLiabilitiesAssociatedWithUltimateSettlementToCustomersSubjectToRateRegulatorDeterminations [Member] | Potomac Electric Power Company [Member]

754

NetRegulatoryLiabilitiesAssociatedWithUltimateSettlementToCustomersSubjectToRateRegulatorDeterminations [Member] | Delmarva Power and Light Company [Member]

391

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

194

NetRegulatoryLiabilitiesAssociatedWithUltimateSettlementToCustomers [Member]

170

NetRegulatoryLiabilitiesAssociatedWithUltimateSettlementToCustomers [Member] | Commonwealth Edison Co [Member]

4,734

NetRegulatoryLiabilitiesAssociatedWithUltimateSettlementToCustomers [Member] | PECO Energy Co [Member]

1,973

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

^[4]

576

NetRegulatoryLiabilitiesAssociatedWithUltimateSettlementToCustomers [Member] | Pepco Holdings LLC [Member]

783

NetRegulatoryLiabilitiesAssociatedWithUltimateSettlementToCustomers [Member] | Potomac Electric Power Company [Member]

1,402

NetRegulatoryLiabilitiesAssociatedWithUltimateSettlementToCustomers [Member] | Delmarva Power and Light Company [Member]

690

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

389

Asset Retirement Obligation Roll Forward Analysis [Line Items]

$ 323

[1]	Amounts do not sum across due to deferred tax adjustments recorded at the Exelon Corporation parent company, primarily related to certain employee compensation plans.
[2]	Reflects the net regulatory liabilities recorded on a pre-tax basis before taking into consideration the income tax benefits associated with the ultimate settlement with customers.
[3]	Given the regulatory treatment of income tax benefits related to electric and gas distribution repairs, PECO remains in an overall net regulatory asset position as of December 31, 2017 after recording the impacts related to the TCJA. Refer to Note 3 - Regulatory Matters for additional information.
[4]	Given the regulatory treatment of income tax benefits related to electric and gas distribution repairs, PECO remains in an overall net regulatory asset position as of December 31, 2017 after recording the impacts related to the TCJA. As a result, the amount of customer benefits resulting from the TCJA subject to the discretion of PECO's rate regulators are lower relative to the other Utility Registrants. Refer to Note 3 - Regulatory Matters for additional information.

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

1 Months Ended

3 Months Ended

Mar. 31, 2017

Mar. 31, 2018

Mar. 31, 2017

Dec. 31, 2017

^[1]

$ 120

$ 112

Asset Retirement Obligation Roll Forward Analysis [Line Items]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

^[1]

120

$ 110

Asset Retirement Obligation, Period Increase (Decrease)

145

Recovery Stranded Costs

$ 4

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

Asset Retirement Obligation Roll Forward Analysis [Line Items]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

117

Asset Retirement Obligation, Period Increase (Decrease)

Asset Retirement Obligation, Liabilities Settled

9,807

Asset Retirement Obligation, Revision of Estimate

(4)

Current portion of ARO

$ 64

$ 13

[1]	Included in Operating and maintenance expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.

Nuclear Decommissioning (Details) - USD ($)
$ in Millions

1 Months Ended

3 Months Ended

Mar. 31, 2017

Mar. 31, 2018

Dec. 31, 2017

Nuclear Decommissioning Additional Narrative Information [Line Items]

Decommissioning Fund Investments

$ 13,149

$ 13,272

Nuclear Decommissioning Additional Narrative Information [Line Items]

Recovery Stranded Costs

$ 4

Asset Retirement Obligation, Period Increase (Decrease)

145

Decommissioning Fund Investments

13,149

13,272

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

Nuclear Decommissioning Additional Narrative Information [Line Items]

Asset Retirement Obligation, Period Increase (Decrease)

Proceeds from Customers

^[1]

9,662

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

Nuclear Decommissioning Additional Narrative Information [Line Items]

Decommissioning Liability, Noncurrent

115

Assets, Total [Member] | Exelon Generation Co L L C [Member]

Nuclear Decommissioning Additional Narrative Information [Line Items]

Decommissioning Fund Investments

$ 13,275

$ 13,349

[1]	Includes $64 million and $13 million for the current portion of the ARO at March 31, 2018 and December 31, 2017, respectively, which is included in Other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets.

Nuclear Decommissioning - Unrealized Gains on NDT Funds (Details) - Exelon Generation Co L L C [Member] - USD ($)
$ in Millions

3 Months Ended

Mar. 31, 2018

Mar. 31, 2017

Unrealized Losses On Nuclear Decommissioning Trust Fund Investment [Line Items]

Unrealized Gain (Loss) on Investments

$ (2)

$ (1)

Collateral Pledged [Member] | Regulated Operation [Member]

Unrealized Losses On Nuclear Decommissioning Trust Fund Investment [Line Items]

Unrealized Gain (Loss) on Investments

^[1]

(75)

222

Collateral Pledged [Member] | Unregulated Operation [Member]

Unrealized Losses On Nuclear Decommissioning Trust Fund Investment [Line Items]

Unrealized Gain (Loss) on Investments

^[2],[3]

$ (96)

$ 166

[1]	Net unrealized gains (losses) related to Generation’s NDT funds associated with Regulatory Agreement Units are included in Regulatory liabilities on Exelon’s Consolidated Balance Sheets and Noncurrent payables to affiliates on Generation’s Consolidated Balance Sheets.
[2]	Excludes $(2) million and $(1) million of net unrealized losses related to the Zion Station pledged assets for the three months ended March 31, 2018 and 2017, respectively. Net unrealized losses related to Zion Station pledged assets are included in Other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets in 2018 and 2017, respectively.
[3]	Net unrealized gains (losses) related to Generation’s NDT funds with Non-Regulatory Agreement Units are included in Other, net on Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

Nuclear Decommissioning - Assets, Payables and Withdrawals by ZionSolutions (Details) - Exelon Generation Co L L C [Member] - USD ($)
$ in Millions

Mar. 31, 2018

Dec. 31, 2017

Nuclear Decommissioning Additional Narrative Information [Line Items]

Held-to-maturity Securities Pledged as Collateral

^[1]

$ 30

$ 39

Accounts Payable, Interest-bearing, Noncurrent

^[2],[3]

Accounts Payable, Interest-bearing, Current

^[4]

$ 949

$ 942

[1]	Included in Other current assets within Exelon's and Generation's Consolidated Balance sheets.
[2]	Excludes a liability recorded within Exelon’s and Generation’s Consolidated Balance Sheets related to the tax obligation on the unrealized activity associated with the Zion Station NDT funds. The NDT funds will be utilized to satisfy the tax obligations as gains and losses are realized.
[3]	Included in Other current liabilities within Exelon’s and Generation’s Consolidated Balance Sheets.
[4]	Includes project expenses to decommission Zion Station and estimated tax payments on Zion Station NDT fund earnings

Retirement Benefits - Narrative (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Increase (Decrease) in Obligation, Pension Benefits		$ 23
Increase (Decrease) in Obligation, Other Postretirement Benefits		14
Accumulated Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss), after Tax		(18)
Defined Benefit Plan Amounts Recognized In Regulatory Assets Before Tax		61
Defined Benefit Plan Amounts Recognized In Regulatory Liabilities Before Tax		1
Pension Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected return on assets	7.00%
Discount rate	3.62%
Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected return on assets	6.60%
Discount rate	3.61%
Fitzpatrick [Member]
Defined Benefit Plan Disclosure [Line Items]
Increase (Decrease) in Obligation, Pension Benefits	$ 16	38
Increase (Decrease) in Obligation, Other Postretirement Benefits	$ 17	$ 11

Retirement Benefits - Calculation of Net Periodic Benefit Cost (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Amortization of:
Net periodic benefit cost	$ (10)	$ (26)
Pension Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	101	95
Interest cost	201	210
Expected return on assets	(312)	(299)
Amortization of:
Prior service benefit	0	0
Actuarial loss	157	152
Net periodic benefit cost	147	158
Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	28	26
Interest cost	43	45
Expected return on assets	(43)	(41)
Amortization of:
Prior service benefit	(46)	(47)
Actuarial loss	16	16
Net periodic benefit cost	(2)	(1)
Pepco Holdings LLC [Member]
Amortization of:
Net periodic benefit cost	$ 0	$ 0

Retirement Benefits - Allocated Portion of Pension and Postretirement Benefit Plan Costs (Details) - USD ($)
$ in Millions

3 Months Ended

Mar. 31, 2018

Mar. 31, 2017

Pension and Other Postretirement Benefits Cost (Reversal of Cost)

$ 145

$ 157

Pension and other post retirement benefit [Member]

Pension and Other Postretirement Benefits Cost (Reversal of Cost)

^[1],[2]

145

157

Corporate, Non-Segment [Member] | Pension and other post retirement benefit [Member]

Pension and Other Postretirement Benefits Cost (Reversal of Cost)

^[3]

Pension and Other Postretirement Benefits Cost (Reversal of Cost)

Exelon Generation Co L L C [Member] | Pension and other post retirement benefit [Member]

Pension and Other Postretirement Benefits Cost (Reversal of Cost)

^[2]

Pension and Other Postretirement Benefits Cost (Reversal of Cost)

Commonwealth Edison Co [Member] | Pension and other post retirement benefit [Member]

Pension and Other Postretirement Benefits Cost (Reversal of Cost)

Pension and Other Postretirement Benefits Cost (Reversal of Cost)

PECO Energy Co [Member] | Pension and other post retirement benefit [Member]

Pension and Other Postretirement Benefits Cost (Reversal of Cost)

Pension and Other Postretirement Benefits Cost (Reversal of Cost)

Baltimore Gas and Electric Company [Member] | Pension and other post retirement benefit [Member]

Pension and Other Postretirement Benefits Cost (Reversal of Cost)

Pension and Other Postretirement Benefits Cost (Reversal of Cost)

Potomac Electric Power Company [Member] | Pension and other post retirement benefit [Member]

Pension and Other Postretirement Benefits Cost (Reversal of Cost)

Pension and Other Postretirement Benefits Cost (Reversal of Cost)

Delmarva Power and Light Company [Member] | Pension and other post retirement benefit [Member]

Pension and Other Postretirement Benefits Cost (Reversal of Cost)

Pension and Other Postretirement Benefits Cost (Reversal of Cost)

Atlantic City Electric Company [Member] | Pension and other post retirement benefit [Member]

Pension and Other Postretirement Benefits Cost (Reversal of Cost)

Pension and Other Postretirement Benefits Cost (Reversal of Cost)

Pepco Holdings LLC [Member] | Pension and other post retirement benefit [Member]

Pension and Other Postretirement Benefits Cost (Reversal of Cost)

^[1]

^[4]

Pepco Holdings LLC [Member] | Corporate, Non-Segment [Member] | Pension and other post retirement benefit [Member]

Pension and Other Postretirement Benefits Cost (Reversal of Cost)

^[4]

$ 8

$ 11

[1]	Exelon reflects the consolidated pension and other postretirement benefit costs of Generation, ComEd, PECO, BGE, BSC, and PHI. PHI reflects the consolidated pension and other postretirement benefit costs of Pepco, DPL, ACE, and PHISCO.
[2]	FitzPatrick net benefit costs are included for the period after the acquisition date of March 31, 2017.
[3]	These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO, BGE, PHI, Pepco, DPL or ACE amounts above.
[4]	These amounts represent amounts billed to Pepco, DPL and ACE through intercompany allocations. These amounts are not included in Pepco, DPL or ACE amounts above.

Retirement Benefits - Defined Contribution Savings Plans (Details) - USD ($)
$ in Millions

3 Months Ended

Mar. 31, 2018

Mar. 31, 2017

Corporate, Non-Segment [Member]

^[1],[2]

$ 32

$ 30

^[3]

^[2]

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

^[1],[4]

^[4]

$ 1

[1]	Exelon reflects the consolidated savings plan matching contributions of Generation, ComEd, PECO, BGE, BSC, and PHI. PHI reflects the consolidated savings plan matching contributions of Pepco, DPL, and PHISCO.
[2]	FitzPatrick net benefit costs are included for the period after the acquisition date of March 31, 2017.
[3]	These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO, BGE, PHI, Pepco or DPL amounts above.
[4]	These amounts represent amounts billed to Pepco and DPL through intercompany allocations. These amounts are not included in Pepco or DPL amounts above.

Severance - Ongoing Severance Plans (Details) - USD ($)
$ in Millions

3 Months Ended

Mar. 31, 2018

Mar. 31, 2017

$ 8

$ 4

^[1]

^[1]

^[1]

^[1]

^[1]

^[1]

^[1]

$ 1

$ 0

[1]	The amounts above for Generation, ComEd, PECO, BGE, and PHI include immaterial amounts billed by BSC the three months ended March 31, 2018 and 2017. Pepco, DPL and ACE include immaterial amounts billed by PHISCO for the three months ended March 31, 2018 and 2017.

Severance Severance - Cost Management Program-Related (Details) - USD ($)
$ in Millions

3 Months Ended

Mar. 31, 2018

Mar. 31, 2017

$ 8

$ 4

^[1]

^[1]

^[1]

^[1]

$ 1

$ 0

[1]	The amounts above for Generation, ComEd, PECO, BGE, and PHI include immaterial amounts billed by BSC the three months ended March 31, 2018 and 2017. Pepco, DPL and ACE include immaterial amounts billed by PHISCO for the three months ended March 31, 2018 and 2017.

Severance - PHI Merger (Details) - USD ($)
$ in Millions

3 Months Ended

Mar. 31, 2018

Mar. 31, 2017

$ 8

$ 4

^[1]

^[1]

^[1]

^[1]

^[1]

^[1]

^[1]

$ 1

$ 0

[1]	The amounts above for Generation, ComEd, PECO, BGE, and PHI include immaterial amounts billed by BSC the three months ended March 31, 2018 and 2017. Pepco, DPL and ACE include immaterial amounts billed by PHISCO for the three months ended March 31, 2018 and 2017.

Severance - Severance Liabilities (Details) - USD ($)
$ in Millions

3 Months Ended

Mar. 31, 2018

Mar. 31, 2017

Employee Severance [Member]

$ 8

$ 4

^[1]

(16)

Exelon Generation Co L L C [Member] | Employee Severance [Member]

^[2]

^[1]

(5)

Commonwealth Edison Co [Member] | Employee Severance [Member]

^[2]

^[1]

(1)

PECO Energy Co [Member] | Employee Severance [Member]

^[2]

^[1]

Baltimore Gas and Electric Company [Member] | Employee Severance [Member]

^[2]

^[1]

Pepco Holdings LLC [Member] | Employee Severance [Member]

^[1]

(6)

Potomac Electric Power Company [Member] | Employee Severance [Member]

^[2]

^[1]

(1)

(1)

Delmarva Power and Light Company [Member] | Employee Severance [Member]

^[2]

^[1]

Atlantic City Electric Company [Member] | Employee Severance [Member]

^[2]

$ 0

^[1]

$ 0

[1]	Includes salary continuance and health and welfare severance benefits.
[2]	The amounts above for Generation, ComEd, PECO, BGE, and PHI include immaterial amounts billed by BSC the three months ended March 31, 2018 and 2017. Pepco, DPL and ACE include immaterial amounts billed by PHISCO for the three months ended March 31, 2018 and 2017.

Severance Severance - Narrative (Details) - USD ($)
$ in Millions

1 Months Ended

3 Months Ended

Nov. 30, 2017

Jun. 30, 2017

Aug. 31, 2015

Mar. 31, 2018

Mar. 31, 2017

Cost Management Project [Member]

$ 8

$ 4

Effect on Future Earnings, Amount

$ 250

$ 400

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

^[1]

$ 2

$ 3

Movement in Accumulated Other Comprehensive Income [Roll Forward]

$ 17

[1]	The amounts above for Generation, ComEd, PECO, BGE, and PHI include immaterial amounts billed by BSC the three months ended March 31, 2018 and 2017. Pepco, DPL and ACE include immaterial amounts billed by PHISCO for the three months ended March 31, 2018 and 2017.

Mezzanine Equity Mezzanine Equity (Details) - USD ($) $ in Millions		3 Months Ended
	Feb. 28, 2018	Mar. 31, 2018	Mar. 31, 2017
Preferred Stock, Shares Subscribed but Unissued, Value [Abstract]
Payments to Acquire Businesses, Gross		$ 0	$ 212
Exelon Generation Co L L C [Member]
Preferred Stock, Shares Subscribed but Unissued, Value [Abstract]
Payments to Acquire Businesses, Gross	$ 87	$ 0	$ 212

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

3 Months Ended

Mar. 31, 2018

Mar. 31, 2017

$ 32,187

29,896

$ 40

(12)

32,565

Gains and (losses) on Cash Flow Hedges

30,231

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[1]

(14)

(17)

^[1]

^[1],[2]

^[1]

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

^[1]

(6)

(11)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

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

^[1]

Unrealized Gains and (losses) on Marketable Securities

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[1]

^[1]

^[1],[2]

^[1]

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

^[1]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

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

^[1],[3]

(10)

Pension and Non-Pension Postretirement Benefit Plan Items

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[1]

(2,998)

^[4]

(2,610)

^[1]

(59)

^[1],[2],[5]

^[1]

(23)

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

^[1]

(2,936)

(2,633)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

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

^[1]

Foreign Currency Items

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[1]

(23)

(30)

^[1]

^[1],[2]

^[1]

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

^[1]

(22)

(29)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

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

^[1]

AOCI of Investments in Unconsolidated Affiliates

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[1]

(1)

(7)

^[1]

^[1],[2]

^[1]

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

^[1]

(1)

(2)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

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

^[1]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[1]

(3,026)

(2,660)

^[1]

(50)

^[1],[2]

^[1]

(10)

Total | Accounting Standards Update 2016-01 [Member]

^[1]

(2,965)

(2,670)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

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

^[1]

(10)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

15,959

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

15,958

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[1]

(16)

(19)

^[1]

^[1],[2]

^[1]

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

^[1]

(9)

(13)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

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

^[1]

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

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[1]

^[1]

^[1],[2]

^[1]

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

^[1]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

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

^[1],[3]

(3)

Exelon Generation Co L L C [Member] | Pension and Non-Pension Postretirement Benefit Plan Items

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[1]

^[1]

^[1],[2]

^[5]

^[1]

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

^[1]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

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

^[1]

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

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[1]

(23)

(30)

^[1]

(1)

^[1],[2]

^[1]

(1)

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

^[1]

(24)

(29)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

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

^[1]

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

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[1]

(1)

(7)

^[1]

^[1],[2]

^[1]

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

^[1]

(1)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

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

^[1]

Exelon Generation Co L L C [Member] | Total

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[1]

(37)

(54)

^[1]

^[1],[2]

^[1]

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

^[1]

(34)

(41)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

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

^[1]

(3)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

3,577

PECO Energy Co [Member] | Gains and (losses) on Cash Flow Hedges

3,403

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[1]

^[1]

^[1],[2]

^[1]

PECO Energy Co [Member] | Gains and (losses) on Cash Flow Hedges | Accounting Standards Update 2016-01 [Member]

^[1]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

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

^[1]

PECO Energy Co [Member] | Unrealized Gains and (losses) on Marketable Securities

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[1]

^[1]

^[1],[2]

^[1]

PECO Energy Co [Member] | Unrealized Gains and (losses) on Marketable Securities | Accounting Standards Update 2016-01 [Member]

^[1]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

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

^[1],[3]

(1)

PECO Energy Co [Member] | Pension and Non-Pension Postretirement Benefit Plan Items

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[1]

^[1]

^[1],[2]

^[1]

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

^[1]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

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

^[1]

PECO Energy Co [Member] | Foreign Currency Items

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[1]

^[1]

^[1],[2]

^[1]

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

^[1]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

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

^[1]

PECO Energy Co [Member] | AOCI of Investments in Unconsolidated Affiliates

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[1]

^[1]

^[1],[2]

^[1]

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

^[1]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

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

^[1]

PECO Energy Co [Member] | Total

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[1]

^[1]

^[1],[2]

^[1]

PECO Energy Co [Member] | Total | Accounting Standards Update 2016-01 [Member]

^[1]

$ 1

Movement in Accumulated Other Comprehensive Income [Roll Forward]

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

^[1]

$ (1)

[1]	All amounts are net of tax and noncontrolling interest. Amounts in parenthesis represent a decrease in AOCI.
[2]	See next tables for details about these reclassifications.
[3]	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, $3 million and $1 million for Exelon, Generation and PECO, respectively. The amounts reclassified related to Rabbi Trusts. See Note 2 — New Accounting Standards for additional information.
[4]	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 2 — New Accounting Standards for additional information.
[5]	Amounts in parenthesis represent a decrease in net income.

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

3 Months Ended

Mar. 31, 2018

Mar. 31, 2017

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

Amortization of pension and other postretirement benefit plan items

$ 59

$ 211

Gains and (losses) on Cash Flow Hedges

(44)

(40)

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

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

^[1],[2]

(4)

Prior service costs

Amortization of pension and other postretirement benefit plan items

^[3],[4]

Actuarial losses

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

Amortization of pension and other postretirement benefit plan items

^[3],[4]

(83)

(81)

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

^[3]

(60)

(58)

Tax benefit

^[3]

Cash Flow Hedging [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]

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

(44)

(36)

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

Cash Flow Hedging [Member] | Gains and (losses) on Cash Flow Hedges | Reclassification out of Accumulated Other Comprehensive Income [Member]

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

Other cash flow hedges

^[3]

(7)

Total before tax

^[3]

(7)

^[3]

Net of tax

^[3]

(4)

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

Amortization of pension and other postretirement benefit plan items

123

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

(4)

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

Exelon Generation Co L L C [Member] | Prior service costs

^[1],[2]

(4)

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

Amortization of pension and other postretirement benefit plan items

^[3],[4]

Exelon Generation Co L L C [Member] | Actuarial losses

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

Amortization of pension and other postretirement benefit plan items

^[3],[4]

Exelon Generation Co L L C [Member] | 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

^[3]

Tax benefit

^[3]

Exelon Generation Co L L C [Member] | Cash Flow Hedging [Member] | Gains and (losses) on Cash Flow Hedges | Reclassification out of Accumulated Other Comprehensive Income [Member]

^[1],[2]

$ 0

^[3]

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

Other cash flow hedges

^[3]

(7)

Total before tax

^[3]

(7)

^[3]

Net of tax

^[3]

$ (4)

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

Changes in Accumulated Other Comprehensive Income - Components of Other Comprehensive Income (Loss) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), Tax	$ (27)	$ (28)
Prior service costs
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), Tax	6	10
Actuarial losses
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), Tax	(22)	(32)
Pension and Non-Pension Postretirement Benefit Plan Items
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), Tax	(7)	0
Gains and (losses) on Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), Tax	(3)	(1)
Unrealized Gains and (losses) on Marketable Securities
Accumulated Other Comprehensive Income (Loss) [Line Items]
Change in unrealized (loss) on investments in unconsolidated affiliates	(1)	(4)
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	(4)	(4)
Exelon Generation Co L L C [Member] \| Gains and (losses) on Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), Tax	(3)	(1)
Exelon Generation Co L L C [Member] \| Unrealized Gains and (losses) on Marketable Securities
Accumulated Other Comprehensive Income (Loss) [Line Items]
Change in unrealized (loss) on investments in unconsolidated affiliates	$ (1)	$ (3)

Earnings Per Share and Equity - Schedule of Earnings per Share (Details) - USD ($) shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Earnings Per Share [Abstract]
Net income attributable to common shareholders	$ 585	$ 990
Weighted average common shares outstanding — basic	966	928
Assumed exercise and/or distributions of stock-based awards	2	2
Weighted average common shares outstanding — diluted	968	930

Earnings Per Share and Equity - Narrative (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Statement Of Equity Line Item [Line Items]
Treasury Stock, Shares	1,832,457		1,832,457
Treasury Stock, Value	$ 123		$ 123
Employee Stock Option [Member]
Statement Of Equity Line Item [Line Items]
Stock options not included in the calculation of diluted common shares outstanding	5,000,000	9,000,000
Pepco Holdings [Member]
Statement Of Equity Line Item [Line Items]
Stock options not included in the calculation of diluted common shares outstanding	0	0

Commitments and Contingencies - Schedule of Commercial Commitments (Details)
$ in Millions

Mar. 31, 2018

USD ($)

Guarantor Obligations, Maximum Exposure, Undiscounted

$ 3,637

Financial Standby Letter of Credit [Member]

Guarantee of Indebtedness of Others [Member]

1,586

^[1]

378

Surety Bond [Member]

Guarantee Obligations [Member]

1,651

^[2]

^[3]

Exelon Generation Co L L C [Member] | Financial Standby Letter of Credit [Member]

2,996

Exelon Generation Co L L C [Member] | Guarantee of Indebtedness of Others [Member]

1,533

^[1]

Exelon Generation Co L L C [Member] | Surety Bond [Member]

1,463

^[2]

Commonwealth Edison Co [Member] | Financial Standby Letter of Credit [Member]

211

Commonwealth Edison Co [Member] | Guarantee of Indebtedness of Others [Member]

^[1]

Commonwealth Edison Co [Member] | Surety Bond [Member]

200

^[2]

PECO Energy Co [Member] | Financial Standby Letter of Credit [Member]

188

PECO Energy Co [Member] | Guarantee of Indebtedness of Others [Member]

^[1]

PECO Energy Co [Member] | Surety Bond [Member]

178

^[2]

Baltimore Gas and Electric Company [Member] | Financial Standby Letter of Credit [Member]

Baltimore Gas and Electric Company [Member] | Guarantee of Indebtedness of Others [Member]

^[1]

Baltimore Gas and Electric Company [Member] | Surety Bond [Member]

PEPCO Holdings Inc [Member]

^[2]

PEPCO Holdings Inc [Member] | Financial Standby Letter of Credit [Member]

PEPCO Holdings Inc [Member] | Guarantee of Indebtedness of Others [Member]

^[1]

PEPCO Holdings Inc [Member] | Surety Bond [Member]

PEPCO Holdings Inc [Member] | Guarantee Obligations [Member]

^[2]

^[3]

Guarantor Obligations, Maximum Exposure, Undiscounted

Potomac Electric Power Company [Member] | Financial Standby Letter of Credit [Member]

Potomac Electric Power Company [Member] | Guarantee of Indebtedness of Others [Member]

^[1]

Potomac Electric Power Company [Member] | Surety Bond [Member]

Potomac Electric Power Company [Member] | Guarantee Obligations [Member]

^[2]

^[3]

Guarantor Obligations, Maximum Exposure, Undiscounted

Delmarva Power and Light Company [Member] | Financial Standby Letter of Credit [Member]

Delmarva Power and Light Company [Member] | Guarantee of Indebtedness of Others [Member]

^[1]

Delmarva Power and Light Company [Member] | Surety Bond [Member]

Delmarva Power and Light Company [Member] | Guarantee Obligations [Member]

^[2]

^[3]

Guarantor Obligations, Maximum Exposure, Undiscounted

Atlantic City Electric Company [Member] | Financial Standby Letter of Credit [Member]

Atlantic City Electric Company [Member] | Guarantee of Indebtedness of Others [Member]

^[1]

Atlantic City Electric Company [Member] | Surety Bond [Member]

Atlantic City Electric Company [Member] | Guarantee Obligations [Member]

^[2]

Supplemental Income Statement Information [Line Items]

$ 6

^[3]

[1]	(a)Letters of credit (non-debt) - Exelon and certain of its subsidiaries maintain non-debt letters of credit to provide credit support for certain transactions as requested by third parties.
[2]	(b)Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.
[3]	(c)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 $58 million, $17 million of which is a guarantee by Pepco, $24 million by DPL and $16 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.

Commitments and Contingencies - Narrative (Details) shares in Millions, number in Millions, $ in Millions	3 Months Ended			12 Months Ended
	Mar. 31, 2018 USD ($) Open_claim MW shares	Mar. 31, 2017 shares	Dec. 31, 2016 MW	Dec. 31, 2017 USD ($) Open_claim	Mar. 31, 2018	Mar. 31, 2018 MGPSite	Mar. 31, 2018 gal	Sep. 30, 2017 USD ($) MGPSite
Commitments And Contingencies Additional Narrative Information [Line Items]
Commitments and Contingencies
BusinessAcquisitionResidualcommitment \| MW	55
Guarantor Obligations, Maximum Exposure, Undiscounted	$ 58
Loss Contingency, Loss in Period	$ 50
Power Volume \| MW	220		10
Open Asbestos Related Personal Injury Claims \| Open_claim				232
Exelon Generation Co L L C [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Commitments and Contingencies
Estimated Insurance Recoveries	3,200
Accrued Insurance, Current	13,200
Prepaid Reinsurance Premiums	360
Loss Contingency, Undiscounted Amount of Insurance-related Assessment Liability	450
Maximum liability per nuclear incident	13,000
Costs Incurred, Development Costs	458
Accrual for Environmental Loss Contingencies, Component Amount								$ 90
Liability for Asbestos and Environmental Claims, Gross	76			78
Liability for Asbestos and Environmental Claims, Net	21
Liability for Asbestos and Environmental Claims, Net, Payment for Claims	55
Pepco Holdings LLC [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Environmental Remediation Expense	10
Number of Real Estate Properties \| MGPSite								9
Commonwealth Edison Co [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Mgp Site Contingency Approved Cleanup Count \| MGPSite						42
Mgp Site Contingency Count \| MGPSite						20
Mgp Site Contingency Monitoring Count \| MGPSite						22
Potomac Electric Power Company [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	17
Accrued Liabilities and Other Liabilities	30			$ 28
PECO Energy Co [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Mgp Site Contingency Approved Cleanup Count \| MGPSite						26
Mgp Site Contingency Count \| MGPSite						17
Mgp Site Contingency Monitoring Count \| MGPSite						9
Baltimore Gas and Electric Company [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Mgp Site Contingency Approved Cleanup Count \| MGPSite						13
Mgp Site Contingency Monitoring Count					13	4
Delmarva Power and Light Company [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	24
Mgp Site Contingency Approved Cleanup Count \| gal							3
Mgp Site Contingency Count \| MGPSite						2
Maximum [Member] \| Exelon Generation Co L L C [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Loss Contingency, New Claims Filed, Number \| Open_claim				20,000,000
Maximum [Member] \| Pepco Holdings LLC [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Loss Contingency, Estimate of Possible Loss								$ 18
Maximum [Member] \| Calpine Corporation [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Loss Contingency, Estimate of Possible Loss								10
Minimum [Member] \| Pepco Holdings LLC [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Loss Contingency, Estimate of Possible Loss								$ 7
Nuclear Insurance Premiums [Member] \| Exelon Generation Co L L C [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Nuclear financial protection pool value	2,800
Nuclear Insurance Premiums [Member] \| Maximum [Member] \| Exelon Generation Co L L C [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Nuclear financial protection pool value	$ 420
Pepco Holdings [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount \| shares	0	0
West Lake [Member] \| Minimum [Member] \| Exelon Generation Co L L C [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Loss Contingency, New Claims Filed, Number \| Open_claim	340,000,000

Supplemental Financial Information - Operations (Detail) - USD ($)
$ in Millions

3 Months Ended

Mar. 31, 2018

Mar. 31, 2017

$ 235

$ 224

Net realized income on decommissioning trust funds - Regulatory Agreement Units

^[1]

Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units

^[1]

Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units

(75)

222

Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement

(96)

166

Regulatory offset to decommissioning trust fund-related activities

(2)

(1)

(234)

^[2]

(253)

Defined Benefit Plan, Net Periodic Benefit Cost (Credit)

(28)

257

Supplemental Income Statement Information [Line Items]

Net realized income on decommissioning trust funds - Regulatory Agreement Units

^[1]

Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units

^[1]

Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units

(75)

222

Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement

(96)

166

Regulatory offset to decommissioning trust fund-related activities

(2)

(1)

^[2]

(234)

(253)

Defined Benefit Plan, Net Periodic Benefit Cost (Credit)

(44)

259

Supplemental Income Statement Information [Line Items]

Net realized income on decommissioning trust funds - Regulatory Agreement Units

^[1]

Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units

^[1]

Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units

Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement

Regulatory offset to decommissioning trust fund-related activities

^[2]

Defined Benefit Plan, Net Periodic Benefit Cost (Credit)

Supplemental Income Statement Information [Line Items]

Net realized income on decommissioning trust funds - Regulatory Agreement Units

^[1]

Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units

^[1]

Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units

Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement

Regulatory offset to decommissioning trust fund-related activities

^[2]

Defined Benefit Plan, Net Periodic Benefit Cost (Credit)

Supplemental Income Statement Information [Line Items]

Net realized income on decommissioning trust funds - Regulatory Agreement Units

^[1]

Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units

^[1]

Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units

Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement

Regulatory offset to decommissioning trust fund-related activities

^[2]

Defined Benefit Plan, Net Periodic Benefit Cost (Credit)

Supplemental Income Statement Information [Line Items]

Net realized income on decommissioning trust funds - Regulatory Agreement Units

^[1]

Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units

^[1]

Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units

Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement

Regulatory offset to decommissioning trust fund-related activities

^[2]

Defined Benefit Plan, Net Periodic Benefit Cost (Credit)

Supplemental Income Statement Information [Line Items]

Net realized income on decommissioning trust funds - Regulatory Agreement Units

^[1]

Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units

^[1]

Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units

Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement

Regulatory offset to decommissioning trust fund-related activities

^[2]

Defined Benefit Plan, Net Periodic Benefit Cost (Credit)

Supplemental Income Statement Information [Line Items]

Net realized income on decommissioning trust funds - Regulatory Agreement Units

^[1]

Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units

^[1]

Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units

Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement

Regulatory offset to decommissioning trust fund-related activities

^[2]

Defined Benefit Plan, Net Periodic Benefit Cost (Credit)

Supplemental Income Statement Information [Line Items]

Net realized income on decommissioning trust funds - Regulatory Agreement Units

^[1]

Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units

^[1]

Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units

Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement

Regulatory offset to decommissioning trust fund-related activities

^[2]

Defined Benefit Plan, Net Periodic Benefit Cost (Credit)

Depreciation, Amortization and Accretion [Abstract]

$ 1

$ 2

[1]	Includes investment income and realized gains and losses on sales of investments of the trust funds.
[2]	Includes the elimination of NDT fund activity 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 2017 Form 10-K for additional information regarding the accounting for nuclear decommissioning.

Supplemental Financial Information Supplemental Financial Information - Utility Taxes (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Supplemental Income Statement Information [Line Items]
Utilities Operating Expense, Taxes	$ 235	$ 224
Exelon Generation Co L L C [Member]
Supplemental Income Statement Information [Line Items]
Utilities Operating Expense, Taxes	32	32
Commonwealth Edison Co [Member]
Supplemental Income Statement Information [Line Items]
Utilities Operating Expense, Taxes	61	59
PECO Energy Co [Member]
Supplemental Income Statement Information [Line Items]
Utilities Operating Expense, Taxes	33	31
Baltimore Gas and Electric Company [Member]
Supplemental Income Statement Information [Line Items]
Utilities Operating Expense, Taxes	26	26
Pepco Holdings LLC [Member]
Supplemental Income Statement Information [Line Items]
Utilities Operating Expense, Taxes	83	76
Potomac Electric Power Company [Member]
Supplemental Income Statement Information [Line Items]
Utilities Operating Expense, Taxes	77	71
Delmarva Power and Light Company [Member]
Supplemental Income Statement Information [Line Items]
Utilities Operating Expense, Taxes	6	5
Atlantic City Electric Company [Member]
Supplemental Income Statement Information [Line Items]
Utilities Operating Expense, Taxes	$ 0	$ 0

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

3 Months Ended

Feb. 28, 2018

Mar. 31, 2018

Mar. 31, 2017

^[1]

$ 926

$ 754

^[1]

152

128

^[1]

^[2]

^[3]

287

264

^[4]

120

112

1,501

1,274

Pension and Other Postretirement Benefits Cost (Reversal of Cost)

145

157

^[5]

(31)

(84)

Amortization of regulatory asset related to debt costs

^[6]

(7)

(4)

(14)

(3)

(5)

^[7]

(4)

(24)

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

240

118

Payments to Acquire Businesses, Gross

(177)

(193)

212

Noncash or Part Noncash Acquisition, Fixed Assets Acquired

Depreciation, Amortization and Accretion [Abstract]

^[1]

436

289

^[1]

^[1]

^[2]

^[3]

287

264

^[4]

120

110

858

678

Pension and Other Postretirement Benefits Cost (Reversal of Cost)

^[5]

(31)

(84)

Amortization of regulatory asset related to debt costs

^[6]

(7)

(4)

(3)

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

(10)

Payments to Acquire Businesses, Gross

(131)

(56)

$ 87

212

Noncash or Part Noncash Acquisition, Fixed Assets Acquired

Depreciation, Amortization and Accretion [Abstract]

^[1]

201

190

^[1]

^[1]

^[2]

^[3]

^[4]

228

208

Pension and Other Postretirement Benefits Cost (Reversal of Cost)

Amortization of regulatory asset related to debt costs

^[7]

(4)

(24)

(6)

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

(48)

(66)

Noncash or Part Noncash Acquisition, Fixed Assets Acquired

Depreciation, Amortization and Accretion [Abstract]

^[1]

^[1]

^[1]

^[2]

^[3]

^[4]

Pension and Other Postretirement Benefits Cost (Reversal of Cost)

Amortization of regulatory asset related to debt costs

(1)

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

(25)

(42)

Noncash or Part Noncash Acquisition, Fixed Assets Acquired

Depreciation, Amortization and Accretion [Abstract]

^[1]

^[1]

^[1]

^[2]

^[3]

^[4]

134

128

Pension and Other Postretirement Benefits Cost (Reversal of Cost)

Amortization of regulatory asset related to debt costs

(2)

(4)

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

(11)

Noncash or Part Noncash Acquisition, Fixed Assets Acquired

Depreciation, Amortization and Accretion [Abstract]

^[1]

^[1]

^[1]

^[2]

^[3]

^[4]

Pension and Other Postretirement Benefits Cost (Reversal of Cost)

(5)

Amortization of regulatory asset related to debt costs

(15)

(1)

(2)

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

(15)

(19)

(6)

Noncash or Part Noncash Acquisition, Fixed Assets Acquired

Depreciation, Amortization and Accretion [Abstract]

^[1]

^[1]

^[1]

^[2]

^[3]

^[4]

Pension and Other Postretirement Benefits Cost (Reversal of Cost)

(1)

Amortization of regulatory asset related to debt costs

(6)

(3)

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

(7)

Noncash or Part Noncash Acquisition, Fixed Assets Acquired

Depreciation, Amortization and Accretion [Abstract]

^[1]

^[1]

^[1]

^[2]

^[3]

^[4]

Pension and Other Postretirement Benefits Cost (Reversal of Cost)

Amortization of regulatory asset related to debt costs

(2)

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

Noncash or Part Noncash Acquisition, Fixed Assets Acquired

Depreciation, Amortization and Accretion [Abstract]

117

112

183

167

Pension and Other Postretirement Benefits Cost (Reversal of Cost)

(4)

Amortization of regulatory asset related to debt costs

(21)

(2)

(6)

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

(8)

(5)

Noncash or Part Noncash Acquisition, Fixed Assets Acquired

$ 0

[1]	Included in Depreciation and amortization on the Registrants' Consolidated Statements of Operations and Comprehensive Income.
[2]	Included in Operating revenues or Purchased power and fuel expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
[3]	Included in Purchased power and fuel expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
[4]	Included in Operating and maintenance expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
[5]	Includes the elimination of NDT fund 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 2017 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.
[7]	Reflects the change in distribution rates pursuant to EIMA and FEJA, which allows for the recovery of distribution costs by a utility through a pre-established performance-based formula rate tariff. Beginning June 1, 2017, also reflects the change in energy efficiency rates pursuant to FEJA, which allows for the recovery of energy efficiency costs by a utility through a pre-established performance-based formula rate tariff. See Note 6 — Regulatory Matters for more information.

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

Mar. 31, 2018

Dec. 31, 2017

Mar. 31, 2017

Dec. 31, 2016

Sep. 30, 2016

Dec. 31, 2015

$ 21,905

^[1]

$ 21,064

^[2]

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

369

322

Cash, Cash Equivalents and Restricted Cash at End of Period

1,099

1,190

$ 889

$ 914

$ 889

$ 914

787

898

609

635

103

209

207

254

253

11,936

^[1]

11,428

^[2]

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

115

114

Cash, Cash Equivalents and Restricted Cash at End of Period

737

554

540

448

610

416

400

290

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

127

138

140

158

3,263

3,159

4,391

4,269

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

Cash, Cash Equivalents and Restricted Cash at End of Period

162

144

3,445

3,411

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

Cash, Cash Equivalents and Restricted Cash at End of Period

275

271

3,471

3,405

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

Cash, Cash Equivalents and Restricted Cash at End of Period

575

487

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

Cash, Cash Equivalents and Restricted Cash at End of Period

103

173

236

109

170

3,224

3,177

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

Cash, Cash Equivalents and Restricted Cash at End of Period

1,273

1,247

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

Cash, Cash Equivalents and Restricted Cash at End of Period

1,086

1,066

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

Cash, Cash Equivalents and Restricted Cash at End of Period

133

101

$ 7

$ 6

$ 7

$ 9

[1]	Includes accumulated amortization of nuclear fuel in the reactor core of $3,263 million.
[2]	Includes accumulated amortization of nuclear fuel in the reactor core of $3,159 million.

Supplemental Financial Information - Narrative (Details) - PECO Energy Co [Member] - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Supplemental Financial Information Tables [Line Items]
Financing Receivable, Net	$ 8	$ 11
Financing Receivable, Allowance for Credit Losses	10	11
Risk Level, Medium [Member]
Supplemental Financial Information Tables [Line Items]
Financing Receivable, Allowance for Credit Losses	3	3
Risk Level, High [Member]
Supplemental Financial Information Tables [Line Items]
Financing Receivable, Allowance for Credit Losses	$ 7	$ 8

Segment Information - Narrative (Details)	3 Months Ended
Segment Information - Narrative (Details)	Mar. 31, 2018 Reportable_segment
Segment Reporting Information [Line Items]
Number of reportable segments	12
Exelon Generation Co L L C [Member]
Segment Reporting Information [Line Items]
Number of reportable segments	6
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, 2018

Mar. 31, 2017

Dec. 31, 2017

$ 0

$ 9,693

8,747

^[1]

636

971

^[2]

117,018

$ 116,770

1,151

1,067

1,251

1,175

140

^[3]

21,375

21,247

5,512

4,878

398

330

186

399

Operating Segments [Member]

^[4]

48,375

48,457

^[5]

4,118

3,382

^[5]

947

918

^[5]

250

^[5]

3,955

3,644

^[5]

625

553

^[5]

^[5]

9,693

8,747

636

971

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

117,018

116,770

Intersegment Eliminations [Member]

^[6]

^[5]

(391)

(328)

^[5]

(8)

^[5]

^[5]

(18)

(8)

^[5]

(4)

(3)

^[5]

(455)

(431)

^[5]

(876)

(770)

^[1]

(876)

(770)

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

(10,980)

(10,552)

^[7]

(4)

^[7]

^[7]

(109)

^[7]

(113)

(4)

(113)

(5)

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

(4,948)

(4,987)

^[5],[8]

4,509

3,710

^[5],[8]

955

918

^[5],[8]

250

^[5],[8]

^[5],[8]

^[5],[8]

^[5],[8]

5,512

4,878

^[8]

186

399

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

^[8]

48,375

48,457

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

^[1],[8]

400

328

^[5]

^[5]

^[5]

^[5]

1,512

1,298

^[5]

^[5]

^[5]

1,512

1,298

165

141

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

30,002

29,726

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

^[1]

^[5]

^[5]

^[5]

^[5]

634

590

^[5]

232

206

^[5]

^[5]

866

796

113

127

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

10,218

10,170

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

^[1]

^[5]

^[5]

^[5]

^[5]

658

667

^[5]

319

284

^[5]

^[5]

977

951

128

125

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

9,195

9,104

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

^[1]

^[5]

^[5]

^[5]

^[5],[7]

1,169

1,097

^[5],[7]

^[5],[7]

^[5],[7]

1,251

1,175

140

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

21,375

21,247

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

^[1]

^[7]

557

530

^[7]

^[7]

^[7]

557

530

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

7,896

7,832

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

^[7]

306

296

^[7]

^[7]

^[7]

384

362

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

4,383

4,357

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

^[7]

310

275

^[7]

^[7]

^[7]

310

275

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

3,530

3,445

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

^[5],[9]

^[5],[9]

^[5],[9]

^[5],[9]

^[5],[9]

^[5],[9]

451

419

^[5],[9]

451

419

^[9]

(21)

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

^[9]

8,833

8,618

^[7],[10]

^[7],[10]

^[7],[10]

113

^[7],[10]

113

^[10]

(8)

(15)

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

^[10]

10,514

$ 10,600

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

^[1],[9]

450

419

Generation Mid Atlantic [Member]

^[10]

112

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

1,440

1,425

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]

134

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]

^[11]

1,435

1,429

Generation Midwest [Member]

(4)

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

1,346

1,053

Generation Midwest [Member] | Operating Segments [Member]

194

Generation Midwest [Member] | Intersegment Eliminations [Member]

^[11]

1,344

1,051

$ 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 $9,727 million and $9,597 million at March 31, 2018 and December 31, 2017, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $3,556 million and $3,618 million at March 31, 2018 and December 31, 2017, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 3 — Variable Interest Entities.
[3]	PHI’s consolidated total assets include $39 million and $41 million at March 31, 2018 and December 31, 2017, respectively, of PHI's consolidated VIE that can only be used to settle the liabilities of the VIE. PHI’s consolidated total liabilities include $95 million and $102 million at March 31, 2018 and December 31, 2017, respectively, of PHI's consolidated VIE for which the VIE creditors do not have recourse to PHI. See Note 3 — Variable Interest Entities.
[4]	Generation’s consolidated assets include $9,688 million and $9,556 million at March 31, 2018 and December 31, 2017, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $3,461 million and $3,516 million at March 31, 2018 and December 31, 2017, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 3 — Variable Interest Entities.
[5]	Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 18 — Supplemental Financial Information for total utility taxes for the three months ended March 31, 2018 and 2017.
[6]	Includes late payment charge revenues.
[7]	Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 18 — Supplemental Financial Information for total utility taxes for the three months ended March 31, 2018 and 2017.
[8]	Generation includes the six reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions. Intersegment revenues for Generation for the three months ended March 31, 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. For the three months ended March 31, 2017, intersegment revenues for Generation include revenue from sales to PECO of $45 million, sales to BGE of $134 million, sales to Pepco of $83 million, sales to DPL of $51 million and sales to ACE of $9 million in the Mid-Atlantic region, and sales to ComEd of $5 million in the Midwest region, which eliminate upon consolidation.
[9]	Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities.
[10]	Other primarily includes PHI’s corporate operations, shared service entities and other financing and investment activities
[11]	Includes all wholesale and retail electric sales to third parties and affiliated sales to the Utility Registrants.

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

3 Months Ended

Mar. 31, 2018

Mar. 31, 2017

$ 9,693

$ 8,747

Generation Mid Atlantic [Member]

^[1]

Generation Midwest [Member]

1,440

1,425

Generation New England [Member]

1,346

1,053

Generation New York [Member]

792

547

Generation ERCOT [Member]

409

297

Generation Other Regions [Member]

209

191

Generation Reportable Segments Total [Member]

288

184

Generation Natural Gas [Member]

4,484

3,697

Generation All Other Segments [Member]

980

930

^[2]

251

Generation Total Consolidated Group [Member]

(98)

Operating Segments [Member]

5,512

4,878

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

^[3]

9,693

8,747

Operating Segments [Member] | Generation Midwest [Member]

^[4]

1,435

1,429

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

^[4]

1,344

1,051

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

^[4]

793

549

Operating Segments [Member] | Generation ERCOT [Member]

^[4]

410

300

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

^[4]

208

192

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

^[4]

319

189

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

^[4]

4,509

3,710

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

^[4]

955

918

Amortization of intangible assets related to commodity contracts

(3)

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

(266)

(49)

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

^[4]

5,512

4,878

Intersegment Eliminations [Member]

^[2],[4]

250

^[3]

(876)

(770)

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

^[1]

(876)

(770)

Intersegment Eliminations [Member] | Generation Midwest [Member]

(4)

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

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

(1)

(2)

Intersegment Eliminations [Member] | Generation ERCOT [Member]

(1)

(3)

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

(1)

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

(31)

(5)

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

(25)

(13)

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]

1,355

1,494

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

^[4]

1,273

980

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

^[4]

725

589

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

^[4]

439

303

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

^[4]

149

168

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

^[4]

210

128

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

^[4]

4,151

3,662

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

^[4]

522

768

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

^[4]

4,807

4,636

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

^[2],[4]

134

206

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

^[4],[5]

(65)

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

^[4],[5]

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

^[4],[5]

(40)

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

^[4],[5]

(29)

(3)

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

^[4],[5]

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

^[4],[5]

109

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

^[4],[5]

358

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

^[4],[5]

433

150

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

^[4],[5]

705

242

Generation Mid Atlantic [Member]

^[2],[4],[5]

$ (86)

$ 44

[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]	Other represents activities not allocated to a region. See text above for a description of included activities. Includes a $3 million decrease to revenues for the amortization of intangible assets and liabilities related to commodity contracts recorded at fair value for the three months ended March 31, 2017, unrealized mark-to-market losses of $98 million and gains of $44 million for the three months ended March 31, 2018 and 2017, respectively, and elimination of intersegment revenues.
[3]	Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 18 — Supplemental Financial Information for total utility taxes for the three months ended March 31, 2018 and 2017.
[4]	Includes all wholesale and retail electric sales to third parties and affiliated sales to the Utility Registrants.
[5]	Includes revenues from derivatives and leases.

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

3 Months Ended

Mar. 31, 2018

Mar. 31, 2017

Generation Midwest [Member]

$ 850

$ 773

Generation New England [Member]

860

715

Generation New York [Member]

119

111

Generation ERCOT [Member]

283

143

Generation Other Regions [Member]

Generation Reportable Segments Total [Member]

117

Generation All Other Segments [Member]

2,265

1,875

^[1]

(46)

205

Generation Total Consolidated Group [Member]

(98)

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

2,219

2,080

Revenue Net Of Purchase Power And Fuel From External Customers

^[2]

836

755

Operating Segments [Member] | Generation Midwest [Member]

Revenue Net Of Purchase Power And Fuel From External Customers

^[2]

847

704

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

Revenue Net Of Purchase Power And Fuel From External Customers

^[2]

122

115

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

Revenue Net Of Purchase Power And Fuel From External Customers

^[2]

282

143

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]

157

108

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

Revenue Net Of Purchase Power And Fuel From External Customers

^[2]

2,350

1,919

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

Revenue Net Of Purchase Power And Fuel From External Customers

^[1],[2]

(131)

161

Amortization Of Intangible Assets Related To Commodity Contracts For Revenue Net Purchased Power And Fuel

(3)

Nuclear Fuel Amortization

(266)

(49)

(15)

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

Revenue Net Of Purchase Power And Fuel From External Customers

^[2]

2,219

2,080

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 England [Member]

Intersegment Revenue Net Of Purchase Power And Fuel

(3)

(4)

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

(70)

(25)

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

Intersegment Revenue Net Of Purchase Power And Fuel

(40)

(44)

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

Intersegment Revenue Net Of Purchase Power And Fuel

(85)

(44)

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]